Tie back guideline Field Development Architecture Selection

The schematic diagram shown above presents the majority of the issues which need to be considered in developing a multiphase tieback. These issues are divided into the colour coded subgroups Energy, Integrity, Delivery, and Overall. If you wish more information directly on corrosion, for example, click on the word ‘Corrosion’ to take you to the guidelines on this subject. Click on the titles ‘Energy’, ‘Integrity’, ‘Delivery’, and ‘Overall’ in the diagram above to move you to the relevant page which lists the related issues.

Energy Integrity

slugging (steady state) slugging(transient) flowrate change

interaction with facilities performance

severe slugging prevention

scale desposition

well testing pvt sampling pvt characterisation

slugcatcher design

relief and blowdown

oil & condensate export

gas & dense phase export

The schematic diagram shown above presents the majority

of the issues which need to be considered in developing a

multiphase tieback These issues are divided into the colour

coded subgroups Energy, Integrity , Delivery, and Overall

If you wish more information directly on corrosion, for

example, click on the word ‘Corrosion’ to take you to the

guidelines on this subject Click on the titles ‘Energy’,

‘ Integrity ’, ‘Delivery’, and ‘ Overall ’ in the diagram above to

move you to the relevant page which lists the related issues.

gas lift system stability corrosion

The schematic diagram shown above presents the majority of the issues which need to be considered in developing a multiphase tieback These issues are

divided into the colour coded subgroups Energy , Integrity , Delivery , and Overall.

If you wish more information directly on corrosion, for example, click on the word

‘ Corrosion ’ to take you to the guidelines on this subject.

Click on the titles ‘ Energy ’, ‘ Integrity ’, ‘ Delivery ’, and ‘Overall’ in the diagram above

to move you to the relevant page which lists the related issues.

Use of these guidelines

Provision of sufficient pressure to transport required flow rates

of hydrocarbons from reservoir to process

Energy Issues

• Drag reduction

• Slugging in horizontal wells

• Gas lift system stability

• Interaction with reservoir performance

• Pressure loss in flowlines

• Separator pressure setpoint

• Pressure loss in wells

• Artificial lift method selection

• Remote multiphase boosting

Pressure Loss in Flowlines

Appraise, select, define

Key data requirements:

• flowrate vs BHFP through life data; completion data;

PVT data (black oil - bubble point, oil viscosity, three

stage flash data; condensate - full compositional

description); proposed slugcatcher/first stage separator

pressure; specification of any artificial lift devices; route

dimensions (length, topography)

Key work activities:

• use a steady-state multiphase simulator to model well

and flowline network to give pressure loss and velocity

data as a function of flowrates

Key output:

• recommendations of line size[s] for the field flow line

network

Principal reasons for investigating: to ensure the basic flowline system design is adequately sized to cover the

range and uncertainty of flows over field life

Secondary reasons for investigating :

• to ensure that revisions to design to manage changes in reservoir predictions, temperature management, and

additions from other fields, are checked for adequate size

Upstream Technology Group contacts:

Phil Sugarman (Sunbury), Norm McMullen (Houston)

Business Unit contacts:

Nathan Barrett, Peter Bradley (Wytch Farm)

Contractors/consultants with relevant experience:

Software packages:

MULTIFLO (inhouse BP Amoco VAX), PIPESIM,PIPEPHASE, PROSPER/GAP

Information on Intranet:

Separator Pressure Setpoint

Appraise, select, define

Key data requirements:

• reservoir pressure and production rate as a function of

time; gas-oil ratio as a function of pressure and

temperature; range of expected pressure drop from

sand face to separator as a function of flow rates,

tubing and line sizes; compression costs as a function

of flowrates, separator pressure and required export or

reinjection pressure

Key work activities:

• use iteration, preferably in a software package, to

investigate the influence of separator pressure set

point on system equipment requirements, export

compression, and thereby the influence on costs,

production rates, and recovery

Principal reasons for investigating: to ensure an adequate pressure drop is available from sand face, through the

wells and flowlines [and risers], to the first stage separator, for the required flow rates through field life

Secondary reasons for investigating :

• to optimize this pressure, taking into account both reservoir performance and processing efficiency

Upstream Technology Group contacts:

Phil Sugarman, Bryn Stenhouse (Sunbury), George Shoup(Houston)

Business Unit contacts:

Contractors/consultants with relevant experience:

Software packages:

HYSIS, PROSPER/GAP/MBAL

Information on Intranet:

Pressure Loss in Wells

Appraise, select, define

Key data requirements:

• flowrate vs BHFP through life data; completion data;

PVT data (black oil - bubble point, oil viscosity, three

stage flash data; condensate - full compositional

description); proposed slugcatcher/first stage separator

pressure; specification of any artificial lift devices

Key work activities:

• use a steady-state multiphase simulator to model well

and flowline network to give pressure loss data as a

function of flowrates

Key output:

• recommendations of line size[s] for well tubing and the

field flow line network

Principal reasons for investigating: to ensure the basic well/flowline system design is adequately sized to cover

the range and uncertainty of flows over field life

Secondary reasons for investigating :

• check revisions to system design following changes in reservoir predictions, and possible additions from other fielddevelopments

Upstream Technology Group contacts:

Phil Sugarman, Simon Bishop (Sunbury),Norm McMullen (Houston)

Business Unit contacts:

Contractors/consultants with relevant experience:

Software packages:

MULTIFLO (inhouse BP Amoco VAX), PIPESIM,PIPEPHASE, PROSPER/GAP

Information on Intranet:

Key data requirements:

• flowrate vs BHFP through life data; completion data;

PVT data (black oil - bubble point, oil viscosity, three

stage flash data; condensate - full compositional

description); proposed slugcatcher/first stage separator

pressure; full specification of artificial lift devices

and chemicals

Key work activities:

• screen the wide variety of possible artificial lift options

for those which may genuinely be applicable to the

conditions of the system under investigation

• use a steady-state multiphase simulator to model well

and flowline network to give pressure loss data as a

function of flowrates with the inclusion of various

combinations of ‘artificial lift’ systems, including, but not

limited to gas lift, electric submersible pumps,

multiphase boosters, drag reducing agents, partial

processing

• evaluate the economic benefits of the various

Principal reasons for investigating: to identify the most appropriate option(s) for adding energy to, or reducing

the pressure drop through, the well/flowline system

Secondary reasons for investigating :

• ensure revisions to design due to changes in reservoir predictions and facilities design, are also compatible with theselected artificial lift options

Upstream Technology Group contacts:

Phil Sugarman, Paul Fairhurst, Simon Bishop (Sunbury),Norm McMullen, Dan Yee (Houston)

Business Unit contacts:

Schiehallion (Doug Wood, Dyce), Angola (Leofric Studd,Sunbury )

Contractors/consultants with relevant experience:

Software packages:

MULTIFLO (inhouse BP Amoco VAX), PIPESIM,PIPEPHASE, PROSPER/GAP, REO, BOAST

Information on Intranet:

UTG Enhanced Productivity team

Artificial Lift Method Selection

Select, define

Enhanced Productivity

Key data requirements:

• gas, oil and water flowrates through life data; required

pressure increase; gas volume fraction at pump inlet

conditions; likelihood and magnitude of slugging

upstream of the booster

Key work activities:

• determine which of the multiphase boosting schemes

are liable for the application, as affected by flow rates,

gas volume fraction at inlet, pressure addition

requirement, and work into the field development

architecture considerations

• present the range of required operating characteristics

to the multiphase boosting vendors

Principal reasons for investigating: to determine whether remote multiphase boosting [with or without phase separation] is a potential alternative to more conventional energy addition or pressure drop reduction schemes

Secondary reasons for investigating :

Upstream Technology Group contacts:

Andrew Humphrey (Sunbury), George Shoup (Houston)

Business Unit contacts:

ETAP, Cusiana

Contractors/consultants with relevant experience:

Bornemann, Leistrizt, R&M Tri-Phase, Framo, Sulzer,Ingersoll-Dresser

Software packages:

Information on Intranet:

http://ut.bpweb.bp.com/pf/multiphase/mpb/default.htm

Multiphase Boosting

Appraise, select, define

Copy of BP Amoco Net.url

Multiphase Boosting

Drag Reduction

Select

Key data requirements:

• gas and liquid hydrocarbons composition; water cut as

a function of time; flow line predicted flowing velocity,

pressure loss, and required reduction in pressure loss;

flow regime if multiphase

Key work activities:

• use a multiphase simulation software package to

assess the possible reduction in line size, or increase

in flow rate, associated with the performance of the

available drag reducing chemicals

• assess the influence on the value of the produced

hydrocarbons if the drag reducing chemicals stay in the

product

Principal reasons for investigating: to determine the potential for drag reducing agents to be used to reduce pipe size specifications, or de-bottleneck existing systems

Secondary reasons for investigating :

Upstream Technology Group contacts:

Helen Kerr, Lawrence Tebboth (Sunbury)

Business Unit contacts:

Contractors/consultants with relevant experience:

Conoco Du Pont

Software packages:

Information on Intranet:

http://upstream.bpweb.bp.com/ut/default.asp?id=195

Copy of BP Amoco Net.url

Drag Reducing Additives

Slugging in Horizontal Wells

Define

Key data requirements:

• well inflow performance as a function of length;

horizontal well section topography, and deviated well

section geometry

Key work activities:

• determine the mean and likely maximum slug sizes

which could be generated in a horizontal well section,

and determine the possible pressure/flow rate

variations at the wellhead as a result Use data to

evaluate separator/slugcatcher requirements

• ensure the specification for any electric submersible

pumps includes an estimate of the frequency of

slugging, the magnitude of the fluid density change,

and the proportion of field life over which such a flow

regime is expected

Principal reasons for investigating: to estimate the effect on productivity from long slugs generated in horizontal

wells propagating up the more highly inclined sections

Secondary reasons for investigating :

• to manage the risk of damage to electric submersible pumps from varying loads during slug flow

Upstream Technology Group contacts:

Phil Sugarman, Paul Fairhurst (Sunbury), JJ Xiao (Houston)

Business Unit contacts:

Matthew King (Wytch Farm)

Contractors/consultants with relevant experience:

Multiphase Solutions Inc (Houston)

Software packages:

OLGA

Information on Intranet:

Key data requirements:

• flowrates through life data; gas and liquid hydrocarbons

composition; water cut as a function of time;

completion details; gas lift valve performance

characteristics

Key work activities:

• use a multiphase simulator to design the steady state

gas lift system

• use a gas lift program to determine the unloading

characteristics, and adjust gas lift valve size and

spacings until a steady production rate can be reached

after initial start up of the system

• if there is any doubt as to the specification of the valve,

carry out a test rig study to determine its performance

Principal reasons for investigating: to ensure the design and implementation of a gas lift system gives a steady

production rate

Secondary reasons for investigating :

• to optimize the use of available gas lift supply

Upstream Technology Group contacts:

Phil Sugarman (Sunbury), Curtis Bennett (Houston)

Business Unit contacts:

Contractors/consultants with relevant experience:

Edinburgh Petroleum Services

Key data requirements:

• availability of reservoir model

Key work activities:

• obtain the flowrate data for the P10, P50 and P90

flowrate cases

Principal reasons for investigating: to ensure reliable data is available on predicted oil, water and gas production

rates to pass on to flowline sizing and pressure loss calculations

Secondary reasons for investigating :

• to ensure the system design is robust against the uncertainty in the flowrate predictions (upside and downside cases)

Upstream Technology Group contacts:

Phil Sugarman, Simon Bishop (Sunbury),Norm McMullen (Houston)

Business Unit contacts:

Contractors/consultants with relevant experience:

Software packages:

PROSPER/GAP/MBAL, ECLIPSE

Information on Intranet:

Interaction with Reservoir Performance

Appraise, select, define

Designing and operating to ensure required flow rates are contained and not impeded.

• Interaction of slugging and pipe fittings

• Interaction of slugging and risers

• Relief and blowdown

• Pigging

• Liquid inventory management

• Well shut-in pressures

Hydrate Control

Select

Key data requirements:

• flowrates through life data; gas and liquid hydrocarbons

composition; operating pressures; water cut and salts

content as a function of time; flow line insulation

possibilities; flowing temperature predictions; inhibition

options; heating options Also consider start-up and

shut-down scenarios

Key work activities:

• use a Hydrate model to predict the hydrate dissociation

curve as a function of pressure and temperature, with

and without inhibition Assess hydrate severity

(subcooling) and risk of blockage

• assess options for Hydrate Control; e.g adding

methano or glycol, low dose hydrate inhibitors (LDHI),

insulation, flow line heating, depressurization on

shutdown

• recommend the optimum solution in conjunction with

the assessment of other flow assurance issues,

especially management of wax

Principal reasons for investigating: to ensure the well/flowline system design is suitable for the

prevention/management of hydrate formation over field life

Secondary reasons for investigating :

Upstream Technology Group contacts:

Carl Argo (Sunbury), George Shoup (Houston),Richard Chapman (Sunbury

Business Unit contacts:

Ian Priestley, Tony Edwards (SNS),Alan Henderson, Simon Merrett (CNS Gas)

Contractors/consultants with relevant experience:

Hydrate Predictions: Multiphase Solutions Inc (Houston);Infochem (London)

Key data requirements:

• flowrates through life data; extended and detailed liquid

hydrocarbons composition; dynamic fluid viscosity as a

function of temperature; applied shear rate and

following standard pre-treatments; pour point data

following standard pre-treatments; wax content; wax

appearance temperature; water cut as a function of

time; flow line insulation possibilities; flowing

temperature predictions; inhibition options; pigging

options; heating options

Key work activities:

• use a wax deposition model to assess wax deposition

rate with and without inhibition, as a function of

flowrates

• assess options for managing wax deposition, and

recommend the optimum solution in conjunction with

the assessment of other production chemistry issues

• establish appropriate viscosity data for pipeline design

for normal flow and transient conditions

Wax Deposition

Select

Principal reasons for investigating: to ensure the well/flowline system design is suitable for the management of

wax deposition over field life

Secondary reasons for investigating :

Upstream Technology Group contacts:

Ian McCracken (Sunbury), George Shoup (Houston)

Business Unit contacts:

Contractors/consultants with relevant experience:

Multiphase Solutions Inc (Houston);

Select

Key data requirements:

• flowrates through life data; gas and liquid hydrocarbons

composition, bubble point, reservoir pressure; well

pressure profile as a function of time; requirements for

gas lift

Principal reasons for investigating: to ensure the well/flowline system design is suitable for the

prevention/management of ashphaltene deposition over field life

Secondary reasons for investigating :

Upstream Technology Group contacts:

Ian McCracken (Sunbury), George Shoup (Houston)

Business Unit contacts:

Contractors/consultants with relevant experience:

Software packages:

Information on Intranet:

Flow Assurance Team

Sand and Solids Transport

Select, define

Key data requirements:

• flowrates through life data; gas and liquid hydrocarbons

composition; water cut as a function of time; predicted

sand or solids production [weight of sand per barrel of

hydrocarbon] as a function of flow rates; sand/solids

size distribution, and water wetability

Key work activities:

• use a solids transport model to determine the flow

rates above which the solids will be transported along

the flow line

• assess options for managing sand/solids accumulation

if flow rates are insufficient for transport [regular

pigging, water flushing, upstream send removal]

Principal reasons for investigating: to ensure the flowline system design can accommodate transport of

predicted reservoir and proppant solids without blockage or erosion

Secondary reasons for investigating :

Upstream Technology Group contacts:

Phil Sugarman, Paul Fairhurst, Craig Dempsey (Sunbury)

Business Unit contacts:

Venezuela, Foinaven

Contractors/consultants with relevant experience:

Cambridge University chemical engineering department

Software packages:

In house spreadsheets

Information on Intranet:

Copy of BP Amoco Net.url

Sand and Solids Transport

Select

Key data requirements:

• flowrates through life data; flow line pressure; CO2 and

H2S content of the gas, water cut, chemistry as a

function of time; Other chemical treatments (scale,

hydrate, etc), flow line material possibilities; flowing

temperature predictions

Key work activities:

• use corrosion models to assess metal wastage rates /

type with and without inhibition as a function of

flowrates

• assess any possibilities for enhanced metal wastage

rate due to slugging flow, or geometrical effects

• assess corrosion control options, and recommend the

optimum solution in conjunction with the assessment of

other production chemistry issues

• assess the need for sour service grade materials

• due to possibility of erosion-corrosion, strong links to

erosion (see Erosion slide)

Principal reasons for investigating: to ensure the flowline system design is adequately protected against

corrosion over field life

Secondary reasons for investigating :

hydrates, wax and drag reduction

Upstream Technology Group contacts:

Don Harrop, Bill Hedges (Sunbury), John Alkire (Houston)

Business Unit contacts:

Richard Woollam, Dominic Paisley - Prudhoe BaySteve Ciaraldi - GUPCO

Contractors/consultants with relevant experience:

IFE (Norway), CAPCIS, AEA Technology, U/Tulsa, OhioUniversity, Shell Global Solutions

Select, Define, Execute

Key data requirements:

• flowrates through life data; gas and liquid hydrocarbons

composition; water cut as a function of time; predicted

sand or solids production rate as a function of flow

rates and time; sand/solids type and size distribution;

flowline material possibilities; flowline size

Key work activities:

• use a steady state multiphase simulator to determine

the mixture velocity/properties likely to be encountered

during normal production and the flow regime

• compare this with the erosion velocity limit for solids

free or erosion wastage rate for solids laden fluids

using the Erosion Guidelines and relevant erosion

wastage rate models

• minimize the time at which the erosion velocity or

allowable erosion rate is exceeded, or modify flowline

system configuration (e.g increase pipe size)

• due to possibility of erosion-corrosion, strong links to

corrosion (see Corrosion slide)

Principal reasons for investigating: to ensure the flowline system integrity is not compromised by the possibility

of erosion from suspended solids over field life

Secondary reasons for investigating :

Upstream Technology Group contacts:

Erosion Assessment: John Martin, Don Harrop (Sunbury),Flow Assessment: Phil Sugarman (Sunbury), George Shoup(Houston)

Business Unit contacts:

Dominic Paisley (Prudhoe Bay)

Contractors/consultants with relevant experience:

AEA Technology, ECRC (University of Tulsa), MultiphaseSolutions Inc (Houston);

Scale Deposition

Select

Key data requirements:

• flowrates through field life data; gas and liquid

hydrocarbons composition (including CO2); water cut

and produced water composition as a function of time;

flowing temperature predictions; shut-in and flowing

pressure predictions; requirement for sea or river water

injection into the reservoir, and salt content

(composition) of any such water; proposed scale

management options

Key work activities:

• assess the potential for scale formation as a function of

produced and injected water salt compositions over the

entire well/flowline system

• assess the risk and magnitude of scale deposition and

develop risk-based control and management options

• recommend the optimum solution in conjunction with

the assessment of other production chemistry issues

Principal reasons for investigating: to ensure the well/flowline system design is suitable for the

prevention/management of scale deposition over field life

Secondary reasons for investigating :

Upstream Technology Group contacts:

Ian Collins, Ian McCracken (Sunbury)

Business Unit contacts:

Magnus (Charlie Michel)

Contractors/consultants with relevant experience:

OilField Scale Research Group, Heriot-Watt University

RF Rogoland Research (Stavanger)

Interaction of Slugging and Pipe Fittings

Select

Key data requirements:

• flowrates through life data; gas and liquid hydrocarbons

composition; water cut; foaming tendency of the crude

as a function of water cut

Key work activities:

• use a steady-state multiphase simulator to determine

the occurrence of slug flow, and the resultant slug

velocity

• use a slug flow model to predict slug frequency, and

slug hold up taking into account the foaming tendency

of the crude as a function of water cut

• calculate the forces exerted by slug flow as a function

of flow rate

• refer the frequency of slugging and the associated

forces to piping design experts for consideration of

mechanical strength and fatigue

Principal reasons for investigating: to ensure the flowline, any riser, and process pipework can handle the forces

associated with slug flow

Secondary reasons for investigating :

Upstream Technology Group contacts:

Phil Sugarman (Sunbury), George Shoup (Houston)

Business Unit contacts:

Contractors/consultants with relevant experience:

Multiphase Solutions Inc (Houston);

Software packages:

MULTIFO, PIPESIM, PROSPER

Information on Intranet:

Interaction of Slugging and Risers

Select

Key data requirements:

• gas to liquid ratios through field life; expected average

production rates through field life; flow line length,

diameter, and geometry; riser height and diameter;

specifications of severe slugging prevention options

Key work activities:

• use a steady-state multiphase simulator to determine

the flow regime map for the system

• assess likelihood of severe slugging occurring at any

stage of field life by marking the gas and liquid flow

rates on the flow regime map

• evaluate the amount of gas injection required to

eliminate severe slugging

• evaluate to the amount of rise of top choking required

to eliminate severe slugging

• use a dynamic model of the severe slugging cycle to

assess acceleration of the end of the slug and resultant

forces exerted on pipe work or vessel internals

Principal reasons for investigating: to ensure the flowline-riser and process system design can prevent or

handle the flow surges associated with riser induced slugging

Secondary reasons for investigating :

• to manage the risk of damage to flowlines and vessel internals from forces exerted during severe slugging cycles

Upstream Technology Group contacts:

Phil Sugarman (Sunbury), Norm McMullen (Houston)

Business Unit contacts:

Schiehallion (Doug Wood)

Contractors/consultants with relevant experience:

Multiphase Solutions Inc (Houston);

Software packages:

MULTIFLO, PIPESIM, OLGA

Information on Intranet: