: Introduction to Offshore Petroleum Production System

Feb. 7, 2012 Yutaek Seo

Course Syllabus

Outcome : To develop broad understanding of fluid properties that determine

the design parameters : To describe in detail a number of different system in terms of

advantages and drawbacks of each facility.

Assessment Attendance (10%) Continuous assessment Assignments (30%) Term project Modeling with provided software (30%) Examination- End-of-Semester examination (30%) Recommended reading Primary Subsea Engineering Handbook Secondary Fields data, Design notes, Reports, etc.

Period Contents

1 Week General introduction, outline, goals, and definition

2 Week Type of reservoir fluids : Dry gas / Wet gas / Gas condensate / Volatile oil / Black oil

3 Week PVT laboratory testing : Constant mass expansion / Differential vaporization / Compositional analysis / : Oil densities and viscosity / SARA, Asphaltenes, WAT

4 Week Fluid sampling : Bottom hole samples / Drill stem test samples

5 Week Thermodynamics and phase behavior : Ideal gas / Peng-Robinson (PR) / Soave-Redlich-Kwong (SRK) : Peneloux liquid density correction / Mixtures / Properties calculated from EoS + molecular data

6 Week Piping systems and process pressure vessels : System design / construction

7 Week Production : Gas production / Oil production / Enhanced oil recovery

8 Week The well components : Christmas tree / surface wellhead

9 Week Subsea structures : Subsea control systems / umbilical / flowlines

10 Week Flow regime : Horizontal and vertical flow / Stratified flow / Annular flow / Dispersed bubble flow / Slug flow

11 Week Flowline pressure drop : Frictional losses / Elevation losses / Acceleration losses / Errors in P calculation / Pipe wall roughness

12 Week Liquid hold up : Cause / Prediction / Field & experimental data / Three phase flow

13 Week Field operation : Operational procedures for offshore petroleum production

14 Week Application Example: Offshore platform (Pluto fields)

15 Week Application Example: Floating production system (Ichthys fields)

16 Week Final Test

Energy Market Status

Global LNG market

LNG production was 210 million tone in 2010 and will grow moderately Two major issues Shale gas and Fukushima disaster Asian LNG demand will grow to 190 million tone in 2020, Fukushima

disaster may result in 9 to 18 mtpa of additional LNG demand by 2020 - The choice of Japan makes in generating electricity will result in differences of

5 mtpa for future LNG demand - Chinese gas supply to 2030 will be composed of several different options:

Conventional (22 bcf/d), Shale gas (1.5 bcf/day), Pipeline (12 bcf/d), LNG (50 million ton)

Australian LNG production capacity is set to increase from 19.5 mpta in 2010 to 38.8 mtpa from 2014.

4.3 mtpa

15 mtpa

Offshore system growth

WA Offshore Gas Fields

CSIRO.

Prelude, Ichthys, Browse

Pluto, Gorgon, Wheatstone

From Petroleum in Western Australia, April 2011

North West Shelf

Timor Sea

Status of Offshore Market

The Offshore Production System

Field Development The Building Blocks

Reservoir Considerations

Hydrocarbon Production Processing

Subsea Production Options

Health, Safety, and Environment

Reservoir Considerations

Reservoir fluids have a huge number of components

Their phase behaviour is complex compared to single components Instead of a single curve separating liquid from vapour phase, there is a

broad region where both vapour and liquid exist together The tow-phase region is bounded on one side by the dew point curve and

on the other side by the bubble point curve PVT analysis and fluid sampling will provide key information for system

design basis

Fluid Type C1 mole% API gravity Character Black oil < 60 30-45 Majority of subsea oil reservoirs

Volatile oil 60 -70 45-70 2-phase region; high gas content Gas

condensate 70 80 70-100 Gas at reservoir conditions.

Retrograde behaviour yields light oil Dry gas 90 -100 NA Low MW hydrocarbon mixture

PVT laboratory testing - Phase behavior as a function

of T & P - Composition - Physical properties: viscosity

& density - Solid analysis: hydrate, wax,

Asphaltenes, scale

Fluid sampling

- Obtaining a representative sample from a deepwater reservoir is the basis for characterization of reservoir fluids; and a big challenge.

- Downhole fluid sampling - Drill stem test

Fluid Phase Behaviour

Gas-condensate system

Thermodynamics Equation of State (EoS)

Ideal gas law

- Molecules have zero volume - No attraction between molecules Soave-Redlich-Kwong (SRK) Peng-Robinson (PR)

VRTP =

)()(bVV

TabV

RTP+

=

)()()(

bVbbVVTa

bVRTP

++

=

Hydrocarbon Production Processing

Separation & Conditioning Facilities - Land based - Platform based - Floating

Production Flowlines

Riser Rigid or Flexible

Chemicals Distribution

Comingled Flow Manifold

Separation

Oil & Gas

Water

100m ~ 100km

Subsea Production Options

Subsea Production Options

Subsea well

Wellhead

Single Cluster

Flowline Modular Template

Production Manifold

Interfield Gathering Line Multiphase PumpsSingle Phase Pumps

Pipelines & Manifolds

Riser Flexible Riser Fixed/Rigid

Process FacilityProcess Facility

Floating StorageExport Shuttle Tanker

Sales Terminal

Export Storage

Bottom Founded Options

Floating Options

Subsea Separation

Typical Field Layout

This is what we are dealing with!!

Norsk Hydro - Ormen Lange Two manifolds (natural gas: 700~2500 million ft3/day)

Primary elements

Trees and Wellheads Manifolds Flowlines and Risers Control systems Umbilicals Topside facilities

- Master control station with operator interface - Electrical power unit for power conditioning & monitoring - Hydraulic power unit for pressure generation, fluid storage - Topside umbilical junction boxes - Chemical injection skid

Construction vessels Divers and ROVs Intervention systems

Onshore vs Offshore trees

Onshore Trees..

Offshore Trees.. can you see??

Xmas Tree

Primary production and safety device for a well Essentially consists of a number of valves to regulate flow and

isolate the tree from the well, and monitor the production fluids

A template is a seabed founded structure that provides a guide for other equipment

A manifold is a system of piping and associated equipment used to gather produced fluids. Associated equipments may include

: Isolation valves : Flowline connectors : Xmas tree connectors : Flow control chokes : Umbilical termination and distribution

Manifold/Template

Manifold/Template for Ormen Lange

PLEM/PLET

PLEM (Pipeline End Manifold) : Used to comingle 2 or more pipelines together and eliminate

the need for additional risers PLET (Pipeline End Termination) : Used to link manifold to the production pipeline

Flowline

Transport reservoir fluid to processing facilities Pipelines : horizontal transfer from wellhead : these may be very long : may be rigid or flexible pipe : commonly called flowlines

Riser

Vertical transfer to above surface processing facilities Either Rigid or Flexible Rigid risers normally for fixed platforms : pre-installed inside jacket frame : cost effective and added riser protection Flexible risers mainly for floating production system : Flexibility and reliability : Easy and rapid installation

Multiphase flow

Multiphase flow patterns depend on the gas and liquid properties and velocities and the angle of inclination of the flowline

There are four basic flow regimes:

Under most pipe flow conditions, the liquid moves more slowly than the gas because it is more dense and viscous.

Both phases would move through the pipe at the same velocity if there were no slip between the gas and liquid.

Liquid holdup is the volume fraction of the pipe that is liquid. Because of slip, this fraction is generally higher than the fraction of liquid entering the pipe.

The flowline pressure gradient consists of three elements: - Friction - Elevation changes (can be + or-) - Fluid acceleration (can be + or -)

Operating production system

Its a lot easier to picture what is happening in onshore system But, understanding what is happening in offshore system

requires experience and inferences Challenges : Hydrates : Corrosion : Wax : Asphaltenes : Scale : Sand (erosion, deposition etc.) : Other issues e.g. emulsion, heavy oil..

Typical subsea developments

Crude oil subsea tieback Crude oil field Wells tied back to existing

platform 10km away Water depth 150m 20,000 bbl/d 2 * 6 flowlines Water injection required into

reservoir Fluid composition : Gas Oil Ratio 1000scf/bbl : water cut 20% : Temperature 35~70 oC : Pressure 30~80 bar : Rates 7000~20000 bbl/d

Gas tieback to LNG plant Gas condensate field Wells tied back to an LNG plant

150km away Water depth 1200m 1000 MMscfd 10~30 flowline Continuous MEG or MeOH

injection required at subsea chokes Fluid composition : Condensate gas ratio 5bbl/MMscf : Water gas ratio 1bbl/MMscf : Temperature 3~130 oC : Pressure 75~300 bar : Rates 500~1000 MMscfd

Operation challenges

Crude oil subsea tieback Steady-state operation : System operated at capacity : Wellhead chokes fully open Shutdown : Followed by flowline depressurization : Keep fluid hot to avoid wax & hydrate Restart : Hot oil circulation is required to warm

enough flowline to prevent hydrates Pigging : may require routine pigging if wax

deposition is an issue

Gas tieback to LNG plant Steady-state operation : Gas offtake at required rate : Subsea choking to maintain pressure Shutdown : Followed by MEG injection, but

maintain pressure and flowline content Restart : May be accompanied by very low

temperature downstream of choke Pigging : Hopefully is not a routine procedure : Rigorous modelling to control speed

Chemical injection

Crude oil subsea tieback Scale, wax, & corrosion inhibitors may

require continuous injection Monitoring of chemical injection

system performance is important both for effectiveness of chemical treatment and cost management

Introduction of new chemical products should only follow lab testing to verify compatibility

Gas tieback to LNG plant Continuous MEG injection can result

in a large complex processing system that may induce operation troubles

MEG needs to be regenerated and reclaimed to remove salts

Case Studies

Woodside Pluto project 100% Woodside-owned gas field Discovered in early 2005 at North West Shelf (NWS) area 190km from the Burrup Peninsula Water depth ranging from 400 to 1000m Potential resource 4.1 trillion ft3 gas and small amount of condensate (42mmbl) Potential revenue boost by AUD 5.5 billion and Job creation of more than 4500

Criteria Key characteristics

Hydrocarbon resource size Approximately 116 000 Mm3 (4.1tcf) recoverable dry gas Approximately 6.7Mm3 (42mmbbl) recoverable condensate

Proposed number of wells Up to 7 wells in 2008 Up to 12 wells in total

Subsea infrastructure Two manifolds with dual flowlines, 32km

Offshore platform Unmanned riser platform located in 80~85m water depth

Offshore gas trunkline A 762~1068 mm (30~42) carbon steel trunkline A 188km length offshore trunkline from platform through Mermaid Sound.

Onshore gas trunkline Trunkline from landfall to processing plant at Burrurp Peninsula

Onshore gas processing plant Up to 12 Mtpa

Gas storage and export facilities

2 * 160 000m3 LNG cryogenic tanks 2-3 condensate tanks with a combined capacity of up to 130000m3

First gas End 2010

Design life Up to 30 years

Woodside Pluto project (contd)

Development concept - Subsea wells tied back, Gas and condensate export pipeline - Onshore LNG gas treatment plant, LNG, LPG and condensate storage tanks - Turning basin and shipping channel, Export jetty - Operational for 20-30 years

Woodside Pluto project (contd)

Gas and condensate to an onshore LNG plant via 35

export line

Onshore LNG plant (4.8 million ton per year)

Subsea wells tied back to an offshore platform via

2*18 flowline

Remote Production System

Avoid!! 120km long tie-back 2700~2900 m

water depth

Emerging issues

Four major changes

1993 Deepwater = 600 m : 3 companies, few wells Hydrate/Wax apprehension Problem magnitude unknown : Wax or Hydrate ? : Time scale unknown Only steady state simulation : Transient was uncertain

2003 Deepwater > 2000 m : Many companies & wells Hydrate/Wax avoidance Problem identified : Hydrate > Wax > Napthenates : Hydrate (min/hr) vs Wax (wks/mths) Steady state & Transient simulation

Flowline/Riser/Service line Design

Reservoir fluid characteristics dominate design : Pressure drop and cooling causes separation - multiphase regime causes irregular flow and vibration - slugging occurs as velocity decays : Hydrate may form as P and T changes : Waxes may precipitate on cooling : Corrosion may occur as water condenses : Sand may cause plugging : Pigging may be required Emergence of Flow Assurance as an Engineering discipline

Flow Assurance

Subsea Design Phases

1. Concept Selection/Feasibility Compare various flowline routes Pipe size and insulation requirements Topsides requirements

2. FEED Determine most viable flowline route & flowline design Chemicals requirements & umbilical design Operability & topsides requirements

3. Detailed Design Flowline design meets life time functional requirements Chemicals requirements & umbilical design Operability and topsides design for production & export

4. Operations Operator training Adjust operating procedures according to reality

Fluid Related Issues

Emulsion / Foam Wax / Asphaltenes

Scale (salts) Corrosion Gas Hydrates Sand / Erosion

Multiphase composition

0

50

100

150

200

0 100 200 300

Multiphase region

Hyd

rate

s

Pre

ssu

re

Temperature

Design Related Issues

Choke design to minimize pressure loss and erosion

Pipeline sizing pressure loss vs slugging

Design of Chemical Injection Systems to minimize risk of hydrates, scale, corrosion etc.

Thermal Insulation Design to keep fluids warm and minimize risk of hydrates and wax

Erosion analysis Erosion wear in complex geometries

Flow assurance is to take precautions to Ensure Deliverability and Operability

Flow Assurance : Interface with Reservoir Evaluation and Topsides Design

Production profiles; FWHP, FWHT, WI rates Reservoir depth, temperature, and pressure Required topside arrival pressure (separator pressure + ~50

psi) and temperature Separator and slug catcher capacities Capacities and pressure ratings of : Export pumps and compressors : Gas lift compressors : Chemicals pumps : Hydraulic fluid pumps

Topside piping/equipment temperature ratings Topside storage capacities for oil, diesel, chemicals and water

Determine Line Size

Most offshore pipelines are sized by use of three design criteria : Available pressure drop, allowable velocities, and slugging Line sizes calculated by use of the steady state simulators The maximum allowable pressure drop is constrained by its

required outlet pressure and available inlet pressure

Wellbore production: oil 10,000 bpd FWHP = 2900 psi

Required arrival pressure = 500 psi

Key Flow Assurance issues - Hydrate

Hydrate : An ice-like solid that forms when i) Sufficient water is present ii)Hydrate former is present (i.e. C1, C2, and C3) iii)Right combination of Pressure and Temperature

Control strategy : maintaining temperature above hydrate formation conditions, by e.g. utilizing DEH : Decreasing the pressure outside the area of possible hydrate formation : Chemical addition or removing the water : Continuous injection of MEG is state of the art for hydrate inhibition of long distance subsea to beach gas-condensate field developments

CSIRO.

Key Flow Assurance Issues - Wax

Wax : A solid paraffinic hydrocarbon which precipitate from a produced fluid : Forms when the fluid temperature drops below the Wax Appearance

Temperature (WAT) : Melts at elevated temperature (20oF above the WAT)

Control strategy : Rate of deposition can be predicted to calculate pigging frequency : Flowline insulation : Wax inhibitor : Major factors - WAT - Fluid temperature - Flowline U-value - n-paraffin content

CSIRO.

Wax deposition

Key Flow Assurance Issues - Slugging

Slugging : Periods of low flow followed by periods of high flow (liquid bomb) : Occurs in multiphase flowlines at low gas velocities : Causes - Low fluid velocity - Seabed bathymetry - Riser type

Control strategy : Increase flowrate (playing with topside valve) : Slug catcher : Gas lift / Gas recirculation

CSIRO.

Key Flow Assurance Issues - Corrosion

Corrosion : Metal loss caused be corrosive water : Fe = Fe++ + 2e- : Variables - Material - H2S and CO2 level in fluids - Water composition

Control strategy : Alter chemical environment - Oxygen scavengers - Sulfide scavengers : Alter reactive surface of metal - Corrosion inhibitors - Polymeric liners to flowlines

Key Flow Assurance issues

Asphaltenes : The heavy polar aromatic fraction : Resulting blockage and formation damage : The main causes are - A decrease in the system pressure - Mixing of incompatible crude oils : Require asphaltene inhibitor injection

Scales : The carbonates or sulphates of calcium, strontium and barium : FeCaCO3, CaCO3 scaling issues in the MEG system : Require scale inhibitor injection

CSIRO.

After de-scaling in separator

Thank you

Contact: Yutaek Seo Phone: 042 350 1521 Email: Yutaek.Seo@kaist.ac.kr

: Introduction to Offshore Petroleum Production SystemCourse Syllabus 3Energy Market StatusGlobal LNG marketOffshore system growth 7WA Offshore Gas FieldsNorth West ShelfTimor SeaStatus of Offshore MarketThe Offshore Production SystemField Development The Building BlocksReservoir Considerations 15Fluid Phase BehaviourThermodynamics Equation of State (EoS)Hydrocarbon Production ProcessingSubsea Production OptionsSubsea Production OptionsTypical Field LayoutThis is what we are dealing with!!Primary elementsOnshore vs Offshore treesXmas TreeManifold/TemplatePLEM/PLETFlowlineRiserMultiphase flow 31Operating production systemTypical subsea developmentsOperation challengesChemical injectionCase StudiesWoodside Pluto projectWoodside Pluto project (contd)Woodside Pluto project (contd)Remote Production SystemEmerging issuesFour major changesFlowline/Riser/Service line DesignFlow AssuranceSubsea Design PhasesFluid Related IssuesDesign Related IssuesFlow Assurance: Interface with Reservoir Evaluation and Topsides Design Determine Line SizeKey Flow Assurance issues - HydrateKey Flow Assurance Issues - WaxKey Flow Assurance Issues - SluggingKey Flow Assurance Issues - CorrosionKey Flow Assurance issues Thank you