SABP-Z-033

Best Practice SABP-Z-033

1 January 2013

Flow Assurance Document Responsibility: Responsibility: Flow Assurance Standards Committee

Saudi Aramco DeskTop Standards Table of Contents 1.

Scope ............................................ ........................................................................ ............................ 3

2.

Conflict and Deviation .............................................. ................................................ .. 3

3.

References ............................................ ................................................................ .................... 3 3.1. Saudi Aramco References................................ 3 3.2. International Standards and Codes .................. 4

4.

Definition and Abbreviation ........................................ 5

5.

Introduction ............................................ ................................................................ .................... 5 5.1. General ............................................................ ............................................................ 5 5.2. Flow Assurance Importance ............................. 6

6.

Flow Assurance Analysis ........................................... 7

7.

Flow Assurance Design Basis ................................... 8 7.1. Thermohydraulic Design ................................... 8 7.2. Transient Thermohydraulic Behavior ................ 9 7.3. Solids Formation/Deposition ............................. 9 7.4. Operating Strategies....................................... Strategies....................................... 10 7.5. Facility Requirements ..................................... 10 7.6. System Economics ......................................... 10

Previous Issue: New

Next Planned Update: TBD Page 1 of 24

Primary contact: Al-Rasheed, Mahmood Ayish on 966-3-8809460 Copyright©Saudi Aramco 2013. All rights reserved.

Document Responsibility: Flow Assurance Standards Committee Issue Date: 1 January 2013 Next Planned Update: TBD

SABP-Z-033 Flow Assurance

Table of Contents (Cont’d) (Cont’d) 8.

Pipeline Hydraulic Analysis Design .......................... 10 8.1. Design Inputs ................................................. 10 8.2. Design Procedures ......................................... 12 8.2.1 Pressure Drop Design Criterion .......... 12 8.2.2 Erosional Erosional Velocity .................................. 13 8.2.3 Minimum Velocity Velocity .................................. 14 8.3. Thermal Requirements Requirements ...................................... 14 8.4. Analysis Procedure Procedure............................................ 15 8.5 Recommended Recommended Practices.................................... 16

9.

Flow Assurance and Modeling Strategy ...................... 17

10.

Pipeline Hydraulic Simulation ..................................... 18 10.1. Pipeline Analysis Analysis Inputs ................................... 19 10.2. Steady State State .................................................... 20 10.3. Dynamic Steady Steady State ..................................... 20 10.4. Dynamics......................................................... 21 10.5. Applying Applying Analysis to Pipelines Pipelines ......................... 21

11.

Fluid Properties and Phase Envelopes Envelopes ....................... 22 11.1. Wax ................................................................. 24 11.2. Hydrates .......................................................... 24 11.3. Commercial Commercial Multiphase Simulators.................. 24

12.

Contributor Contributor Authors..................................................... 24

Page 2 of 24


1


Scope This flow assurance Best Practice provides general guidelines for basic en gineering requirements and recommended practice necessary to establish reliable and cost effective design and operation for multiphase production and pipeline systems. The major flow assurance issues covered in the Flow Assurance Best Practice are: • Flow Assurance Analysis and Design Basis • Flow Assurance Modeling Strategy • Pipeline Simulation Design and Analysis • Fluid Properties and Phase Envelopes • Hydrate, Wax, Corrosion and Erosion

2

Conflict and Deviation This Best Practice was written to be consistent with Saudi Aramco and applicable international standards. If there is a conflict between this Best Practice and other standards or specifications, please contact the Flow Assurance Standards Committee Chairman of UPED/P&CSD for resolution.

3

References The following list shows the recommended flow assurance reference do cuments: 3.1

Saudi Aramco References Saudi Aramco Engineering Procedures

SAEP-14

Project Proposal

SAEP-27

Pipelines/Piping Hydraulic Surge Analysis

SAEP-302

Instructions for Obtaining a Waiver of a Mandatory Saudi Aramco Engineering Requirement

SAEP-303

Engineering Reviews of Project Proposal and Detail Design Documentation

SAEP-354

High Integrity Protective Systems Design Requirements

SAEP-363

Pipeline Simulation Model Development and Support

SAEP-501

Drag Reducing Agent (DRA) Chemicals

Page 3 of 24



Saudi Aramco Engineering Standards

SAES-B-017

Fire Water System Design

SAES-B-058

Emergency Shutdown, Isolation, and Depressuring

SAES-B-060

Fire Protection for Piers, Wharves and Sea Islands

SAES-B-064

Onshore and Nearshore Pipeline Safety

SAES-B-070

Fire and Safety Requirements for Bulk Plants

SAES-J-600

Pressure Relief Devices

SAES-J-601

Emergency Shutdown and Isolation Systems

SAES-J-605

Surge Relief Protection Systems

SAES-J-700

Control Valves

SAES-L-100

Applicable Codes and Standards for Pressure Piping Systems

SAES-L-132

Material Selection of Piping Systems

SAES-L-310

Design of Plant Piping

SAES-L-410

Design of Pipelines

SAES-L-850

Design of Submarine and Risers

Saudi Aramco Engineering Reports

SAER-5437

Guidelines for Conducting HAZOP Studies

SAER-6043

High Integrity Protection System (HIPS) Evaluation Team Report

Saudi Aramco Best Practice

SABP-A-019 3.2

Pipeline Corrosion Control

International Standards and Codes ANSI/ASME Code “Process Piping” Chemical plant and petroleum refinery pipeline for in-plant piping

ANSI/ASME B16.5

Pipe Flanges and Flanged Fittings

ANSI/ASME B31.1

Power Piping

ANSI/ASME B31.3

Chemical Plant and Petroleum Refinery Pipeline or In-Plant Piping

ANSI/ASME B31.4

Liquid Petroleum Transportation Piping Systems for Cross-Country Liquid Pipelines Page 4 of 24


ANSI/ASME B31.8


Gas Transmission and Distribution Piping Systems

American Petroleum Institute

API RP 14E

Erosion Criterion

API RP 14C

ESD Valves Shutdown

API STD 521

Pressure-Relieving and Depressuring Systems

American Water Works Association

AWWA M45

American Water Works Association, Fiberglass Pipe Design

National Fire Protection Association

4

NFPA 24

Installation of Private Fire Services Mains and their Appurtenances

NFPA 25

Inspection, Testing and Maintenance of Water based Fire Protection Systems

Definitions and Abbreviations Dynamic Steady State: Dynamic Steady State is a term used to describe dynamic analysis when the bounding conditions are either not changing or are changing in a repeated cyclic manner (pseudo-steady state).

5

HIPPS

High Integrity Pressure Protection System

OPPS

Over-Pressure Protection System

SS

Steady State

DSS

Dynamic Steady State

FWHP

Flowing Well Head Pressure

Introduction 5.1

General

‘Flow Assurance’ guarantees that the pipeline can be operated as per specifications, ensures the design is robust and fits for purpose in terms of flow delivery. Flow assurance analysis and design involve all aspects of chemical and mechanical disciplines, which are not all included in this Best Practice.

Page 5 of 24


5.2


Flow Assurance Importance

Reservoir fluids are very complex. Reservoir oils consist of thousands of hydrocarbon compounds. The produced fluids may exist as gas, liquid or both, depending on the pressure and temperature at a given point in the flow system. In a reservoir, the hydrocarbons may have extensive contact with water in the formation and an equilibrium state is established. In the production process, the equilibrium state is broken due to pressure and temperature chan ges. This results in phase changes and a redistribution of components among the phases. The reduced pressure results in released gas from live oil. Lowering the temperature can result in possible solids depositions and blockages in the production system. The temperature and pressure changes in a gas system can result in liquid hydrocarbon and water dropout in the flowlines. These fluid changes may reduce production and increase development costs. Flow assurance therefore becomes one of the critical expertise to effectively develop deepwater prospects. The basic principles for flow assurance design are: ●

Operate the production system outside the pressure/temperature region where hydrates are stable and/or use hydrate inhibitors. Also, prevent hydrate formation during the specified cool-down time by thermal management (generally insulation design).

●

Develop shutdown/startup procedures to: avoid hydrates, initiate flow (gel/wax, gas lift availability, etc.), reduce slugging and operate within the capacities of topsides equipment.

●

Prevent or reduce wax deposition in the wellbore and flowlines by thermal management or using chemical inhibitors.

●

Remove wax from the flowline by periodic scraping.

●

Use inhibitors to prevent asphaltene deposition and solvents/scraping to remove them.

●

Understand water chemistry and manage scale through production optimization and chemical treatment.

●

Develop corrosion/erosion management and sand control procedures.

The major flow assurance analysis issues are: ●

Fluid characterization under the full range of temperature and pressure.

●

Steady state and transient flow modeling that provides the basis for analyzing operation issues such as pipeline size, scraping, start-up, rampingup, turn-down and shutdown.

Page 6 of 24


6


●

Hydrate, paraffin, and asphaltenes prediction, prevention and remediation.

●

Corrosion, erosion, sand and scale control.

●

Integration of flow assurance design with system design through active interface with the reservoir, drilling/completion, pipeline and process engineers.

Flow Assurance Analysis The ultimate purpose of a flow assurance anal ysis is to develop a reliable, cost effective production system and operating philosophy. The flow assurance design process involves several major steps outlined below. ●

Establish the design basis

●

Reservoir and production conditions

●

Fluid compositions and measured/predicted properties

●

Flow line routing and ambient temperatures

●

Facility equipment specifications

●

Fluids modeling

●

Tune the EOS (Equation of State) using reservoir fluid compositions and measured properties.

●

Assess fluid phase behaviors and predict physical properties. Besides the produced fluids, this includes injected chemicals, injected water and gas, and export gas and oil.

●

Conduct Thermo-hydraulic analysis

●

Perform hydraulic analysis and pipeline sizing using preliminary insulation design

●

Perform thermal analysis to specify insulation design

●

Assess transient thermo-hydraulic behaviors: shutdown, startup and slugging

●

Determine compatibility with facility requirements

●

Establish operating strategies

●

Assess system economics

●

Comparison of options, and system optimization and integration

All steps will be considered collectively in practice and seve ral of the steps will need to be addressed simultaneously. The flow assurance design process starts early in the field development effort when the type and reserves of a field are identified, and often before any development wells are drilled. In general, design begins with development of a design basis, followed by Page 7 of 24



assessment of fluid behavior and analysis of thermohydraulics. During the thermohydraulic design phase, the flow assurance engineer begins interfacing with other design engineers, such as pipeline/flowline and facilities engineers. Typically, as parallel efforts, the flow assurance engineer will develop operating strategies and determine facility requirements together with subsea mechanical designers, facility engineers and other engineers. The numerous interfaces necessitate effective project management. A major consideration in the design process is the system economics and risks. The design process will be iterative due to inevitable changes in the design basis, interim results during the design, changes in system economics, and other changes. Three design phases usually proceed in Saudi Aramco development project: conceptual study, project proposal and detailed engineering designs. These three phases have a time sequence and different data availability and different deliverables, depending on proponent requirements.

7

Flow Assurance Design Basis The first major effort in the design process is to establish a design basis. Flow assurance engineers will be directly involved in determining and documenting the fluid characteristics, PVT behaviors and the potentials for solids formation. For the other aspects of the design basis, such as reservoir behavior, site characteristics, and facilities, the flow assurance engineer will need to ensure that the data needed for the flow assurance analysis are included in the design basis. Thus, the flow assurance engineers will interface with those responsible for reservoir engineering and surface facilities. These interfaces will continue throughout the project. It is important to note that the design basis needs to consider the impact of poor or missing data. This step in the design process assumes that fluid samples have b een collected. A substantial amount of laboratory work may be required to determine the characteristics of the fluid samples. Standard PVT measurements should be performed on the fluids, and then fluid characterizations should be developed for use in thermohydraulic and other modeling (reservoir and process). The fluids should also be tested for potential solids formation such as sulfur, wax and asphaltenes. If no data from samples are available, fluid properties must be inferred from analogous fields or reservoirs. This may present considerable risk that must be taken into account in the overall system design. 7.1

Thermohydraulic Design

The thermohydraulic analysis evaluates the lifecycle pressure and temp erature performance of the entire production system. This effort should also include assessment of flow reduction potential due to solids formation or others in the pipelines. Page 8 of 24



At the beginning, basic design and operating principles should be set. Such principles help guide the design process; however, these principles should be continuously evaluated in light of system operability and economics where practical, the preliminary design should keep the production system out of hydrate formation region. For oil systems, this could mean insulation and for gas system this might require hydrate inhibitors. It may also be necessary to establish a lower limit on well production rate and/or to use insulated tubing to prevent wax deposition in wellbore during normal operation. Wax may be managed in the wellbore with chemical injection and in the flowline with chemicals and scraping. Most system design attributes can be set on the b asis of steady state analysis, such as the sizes of the production tubing, production flowlines, injection flowlines, and transport pipelines. Criteria for line sizing include pressure constraints, flow rates, and erosion limits. As part of the line sizing and hydraulic assessment, changes in production rates, water cut, and gas to oil ratio over the field life need to be evaluated. In most cases, subsea tiebacks include dual production flowlines. This serves two purposes. It allows scraping for wax, asphaltenes, sand, etc., deposition an d it allows flow in only one line when rates are reduced to reduce slugging. Artificial lift may also be considered to increase flow; and flowline pressure may need to be re-evaluated over time. Thermal modeling is typically combined with hydraulic modeling b ecause temperature has a significant influence on fluid physical properties. Operating temperatures are analyzed as a function of insulation level and other parameters initially via steady state analysis. 7.2

Transient Thermohydraulic Behavior Assessment

The operation of subsea production flowlines involves transient processes, e.g., shutdowns, startups, and rate changes. It is during these transient operations that issues like hydrate control and liquid han dling become important drivers for system design and operability. Transient thermohydraulic modeling includes slugging, warm-up with restart, cool down upon shutdown, and depressurization in wellbores and flowlines/risers. In deepwater systems, cool down time to hydrate conditions has typically driven the insulation level. Slugging normally impacts operating procedures/limitations and topsides equipment design, and flowline size selection can impact selection of flowline size. 7.3

Solids Formation/Deposition Assessment

To assure design criteria are met, hydrate dissociation curves, and wax and asphaltene formation envelopes are determined for the production fluids. Page 9 of 24



The operating temperatures and pressures are compared with these envelopes to predict when and where solids may form. Solids control is responsible for many of the features of subsea design and operation including insulation, chemical injection, scraping facilities, and special operating procedures for shutdown. Methods for remediation of deposited solids need to be developed. These methods may require specific facilities such as downhole chemical injection lines for prevention/remediation of wellbore deposits, and/or the development of special procedures. 7.4

Operating Strategies

Operating strategies must be developed in accordance with the flow assurance design and consistent with the system design. The adaptability should be assessed to account for the uncertainties of fluid characteristics in the design basis. 7.5

Facility Requirements

The requirements, capabilities and control of the facilities are ke y parts of a production system design. The key topside facilities are slug catchers, separators, surge tanks, flare capacity, flare knockout drums, chemical storage and pumping, scraping equipment, normal and emergency power, and the control system. Instrumentation, controls, and facility capabilities have to be completely integrated into the overall system design and op erability. 7.6

System Economics

There are numerous design options, manufacturing considerations and installation activities in a production system design that result in different economics. The various options should be studied for their impact on system economics and risk.

8

Pipeline Hydraulic Analysis Design This section of the Flow Assurance Best Practice covers basic en gineering requirements and recommended practices for sizing multiphase production pipelines, water and gas injection pipelines and transport pipelines. 8.1

Design Input

The production rates (oil, gas, and water) over the design life of the development and the reservoir fluids properties should be obtained from the reservoir engineering team. In different design phases, available data can differ. The uncertainties in the data become less as more studies are performed by reservoir engineering and well completion teams. The design basis data used in

Page 10 of 24



the design of a multiphase production flowline system are listed in Tables 1 and 2. Reservoir fluid analysis and characterization are required to determine fluid properties at different pressures and temperatures, and to determine water chemistry and compatibility. Input data should also include standards applied to the mechanical design of a pipeline, MAOP, maximum and minimum temperatures, etc. The thermal conductivity of water-saturated concrete should be used for subsea pipelines with concrete coating, and is much higher than that for dry concrete. Table 1 - Design Basis Data for Sizing Flow Lines – 1/2 Item

Comments

Field Layout, water depths/topography – Production & Injection wells and flowlines Seawater, soil and air temperature profiles Seawater and air currents/velocities Soil: thermal conductivity, heat capacity & density and mechanical properties vs. depth Reservoir depth, temperature and pressure Produced, Injected and Exported Fluids: properties/compositions: Prod. wells: tubing size, geometry, etc. Prod. wells: ambient temperature profile Prod. wells: productivity index

In lieu of well data, the flowing wellhead temperatures, pressures and flowrates can be supplied.

Production profiles SCSSV location in wellbore Gas lift injection point, rate limits, etc. Mechanical pressure boosting Hydrate dissociation curves

May be determined as part of the FA analysis.

Cooldown and no-touch times (hydrates) Hydrate inhibitor and inhibitor injection points

Table 2 - Design Basis Data for Sizing Flow Lines – 2/2 Item

Comments

WAT and Gel Point Treating chemicals densities, viscosities, rates & injection points: scale, corrosion, paraffins, asphaltenes, naphthenates and emulsions Sand level limit, sand level in produced fluids, sand grain size distribution Erosion criteria Water Injection wells: rates

Page 11 of 24

Document Responsibility: Flow Assurance Standards Committee Issue Date: 1 January 2013 Next Planned Update: TBD Item

SABP-Z-033 Flow Assurance Comments

Water Injection wells: geometry, tubing size, casings (unless FWHP is provided) Water Injection wells: injectivity index, frac pressure, etc., or FWHP at rate Gas injection wells: rates Gas injection wells: geometry, tubing size, casings (unless FWHP is provided) Gas injection wells: Injectivity Index or FWHP Topsides: separator/slug catcher and flare: system capacities and required arrival Temperature & Pressure Topsides: Injection pumps and compressors Topsides ESD depressurization time & volumes Export flowlines layout/topography and arrival pressures Remediation of flowline plugs Operational philosophy/constraints Additional Functional Requirements

8.2

Design Procedures

Thermal-hydraulic analysis will address the minimum pipe inside diameter (ID) and insulation requirements (overall heat transfer coefficient). Sizing a pipeline consists of three primary design criteria: pressure drop, maximum velocity (erosion) and minimum velocity (slugging). 8.2.1

Pressure Drop Design Criterion

The maximum allowable pressure drop in a pipeline is determined by its required outlet pressure and available inlet pressure. Some guidelines for specific systems are shown below: ●

●

For plant piping, rule-of-thumb values for pressure gradients are a frictional gradient of 0.2-0.5 psi per 100 ft. For a gathering system, the ideal way to check for allowable pressure drops is to simulate the whole system, from the reservoir to the separator, over the design life of the field. This approach will account for the changes in reservoir pressure, flow rate and compositions in the gathering system over the field life. If rigorous simulations cannot be conducted on a gathering system, the allowable pressure drop is estimated from the flowing wellhead pressure and a specified separator pressure. A conservative rule of thumb is to take ⅓ of the difference between the initial wellhead pressure and the separator pressure as the allowable pressure drop in the pipeline.

Page 12 of 24


8.2.2


●

As a rule of thumb, allowable frictional pressure drop for long distance gas-condensate pipelines is 10-20 psi per mile at design rates.

●

The pressure in a pipeline should always be less than the MAOP. In a multiphase pipeline pressure drop is not always the maximum at the highest flow rate. If a pipeline contains significant “hills and valleys”, it is possible that the highest pressure drop occurs at a lower flow rate. This is due to increased liquid ho ldup at lower flow rates.

Erosional Velocity

A production stream is considered “solid-free” if the solid concentration is less than 1 pound per thousand barrels of liquid in a liquid stream or less than 0.1 pound per MMSCFD in a gas stream. Normally, any solids concentrations above these levels (or the level spe cified by Engineering) will involve shutting in the problem well until it can b e recompleted. Erosion is defined as the material loss by physical wear of liquid droplets and/or solid particles. The maximum mixture velocity without noticeable erosion is called erosion velocity. The mixture velocity in multiphase pipelines should be kept below erosion velocity to prevent excessive erosion loss of the pipe wall. For a solid-free production system, API RP 14E (1991) Section 2.5 recommends the following formula: Vmax

C 

 m

where:

Vmax = erosional mixture velocity, ft/sec m

= mixture density at flowing temperature and pressure, lb/ft 3  m

 g =



(  g V sg )  (  l V sl ) V m



(  g V sg )  (  l V sl ) V sg  V sl

Gas Density, lb/ft

l = Liquid Density, lb/ft

C = Constant 



C=100 for continuous service and 125 for intermittent service with a carbon steel pipeline. These are considered conservative by industry. For solid-free liquids without corrosion or when corrosion is controlled by using corrosion inhibitors or corrosion resistant alloys, values of C between 150 and 200 may be used for Page 13 of 24



continuous service, and values up to 250 have been successfully used for intermittent service. Different companies have assumed different values for C. The client should be queried for the acceptable value.

If the flow velocity is above the erosional v elocity, erosion can increase rapidly. For wells without sand production, C could be as high as 300 without significant erosion. For flowlines with significant amounts of sand, there has been considerable erosion for lines operating below C = 100. Unfortunately, no other proposed equation has gained acceptance in the industry as an alternative to the API equation. The velocity in a pipeline should be kept within a limited range. The erosional velocity ratio should be less than one according to API RP 14E. It is advised that a pipeline design should be checked at off-design points because worst-case conditions for liquid holdup and flow regime occur at turndown conditions. A designer can change pipeline diameter and operating pressure to mitigate flow pattern or flow characteristics. A designer should study the slug characteristics, and facility capability to safely operate the system. Today, many pipelines operate successfully in slug flow, if slugging is not too severe. 8.2.3

Minimum Velocity

The minimum velocity for a pipeline should be considered in multiphase pipeline design. If the pipe diameter is increased above the optimum value, severe slugging may occur. This can upset the separator system. Too low velocities may cause sand and water dropout in the pipeline. Water will also accumulate at low spots in the pipeline. If there is an appreciable amount of CO2 or H2S in the production stream, this water may cause severe corrosion. The minimum velocity depends on many variables including: topography, pipeline diameter, gas-liquid ratio, and operating conditions of the line. An approximate value for the minimum mixture velocity would be 5-8 ft/sec (velocity in multiphase flow pipelines should be kept above 10 ft/sec as indicated by API RP 14E to ensure proper operation). The actual minimum velocity can onl y be quantified by system modeling with a multiphase simulator. 8.3

Thermal Requirements

The temperature of the flowing fluids has direct influence on its physical properties. This impacts the deposition potentials of wax, asphaltenes and Page 14 of 24



hydrates. Fluid temperature determines the phase equilibrium of liquids and gas. Therefore, it affects pressure loss and liquid holdup in a pipeline. For the flow of produced fluids from oil wells, higher temperature is generally better. However, corrosion increases rapidly with temperature. To size a pipeline, several insulation scenarios should be studied. Table 3 provides typical ranges for overall heat transfer coefficients (OHTC or U-value) for insulated pipelines. With the typical values, pressure drop can be calculated with acceptable accuracy and the required U-value can be determined. Table 3 - Overall Heat Transfer Coefficients for Insulated Pipes

8.4

2

Insulation

U-Value [BTU/hr/ft / F]

Well bores without insulation

1-2

Bare risers

50 - 200

Buried pipelines

1-3

Concrete coated non-buried pipelines

3-5

Non-buried pipelines without concrete

20 - 100

Foam insulation coated pipe

0.4 – 3.0

Pipe-in-Pipe with foam insulation

0.2 – 2.0

Pipe-in-Pipe with micro sphere insulation

0.1 – 1.0

Analysis Procedure

The purpose of hydraulic analysis is to obtain pressures, temperatures and velocities along a pipeline. Due to the complexity of a multiphase system, a multiphase simulator is required to perform such analysis. A steady state multiphase simulator is enough for normal operation study especially in conceptual or DBSP stage. Several typical insulation conditions (bare pipe, coated or others) should be evaluated. In detail design, using a transient simulator may be more efficient because transient issues need to be also studied. The following shows the recommended procedure: a.

Select a pipeline diameter and a typical insulation U-value.

b.

Input detailed pipeline profile.

c.

Input ambient temperature profile.

d.

Input fluid composition or black oil system PVT data; input liquid rate, gas rate, and water cut, typically for early life.

e.

Select correlations for fluid property calculations. Page 15 of 24


8.5


f.

Check the liquid viscosity.

g.

Select the fluid flow correlation.

h.

Perform the preliminary calculation.

i.

Check pressure and temperature. If the pressure drop is too high, increase the pipeline size; if the pressure drop is too small, select a smaller pipeline size. Then, go to Step h.

j.

Check erosional velocity ratios. If the erosional velocity ratio is greater than one, select a larger diameter, then go to Step h.

k.

Select another insulation U-value, if warranted, then go to Step h.

l.

Check if slug flow is present. If yes, check riser slug severity number, slug frequency, slug length and slug volume.

m.

Report pressure and temperature profile along a pipeline, report scraping liquid volume.

n.

Usually 3-5 pipe diameters are used to generate a capacity versus pipe ID curve and a minimum size is used for mechanical design considerations.

o.

Repeat the above procedure with typical year productions from early, mid and late life of the field, and check the applicability of each pipeline size.

p.

Examine the flow patterns in the pipeline and the riser. If in the riser flow is not slug flow, generally the pipe size should be the smallest size with which the erosional velocity is less than 1.0 for a sand-free pipeline and the pressure loss is less than the specified value. If the flow is stratified flow in the pipeline and slug flow in the arrival riser, severe slugging may occur. The pipe size should be selected after transient results are evaluated.

Recommended Practices

This section contains collective practices learned from past experiences. 







The Barnea (1987) modified Taitel-Duckler flow pattern map is recommended for prediction of flow pattern. The Beggs-Brill pressure drop method incorporating the Beggs-Brill holdup correlations is generally the most conservative among the co mmonly used methods. It normally over predicts pressure drop by 0-30%, and hence, it provides a degree of conservation. The OLGA-S model is good for gas-condensate pipelines. For typical oil systems, OLGA-S is reported to under-predict pressure drop. Due to the complexity of multiphase flow, uncertainties associated with pressure drop calculations are significantly greater than those in single-phase Page 16 of 24



flow, and errors in excess of ±20% must be anticipated. 



9

A sensitivity analysis on the pressure drop from different multiphase correlations is desirable to have more confidence i n the results. Uncertainties in pressures and flow rate calculations from the hydraulic simulation are reported.

Flow Assurance and Modeling Strategy ‘Flow Assurance’ guarantees that the pipeline can be operated as per specifications, ensures the design is robust and fits for purpose in terms of flow delivery. At steady state flow assurance is most likely to be concerned with the following aspects: ●

When flowing at the intended rates, the required inlet pressure is less than the available wellhead pressure (production lines). Alternatively, the available outlet pressure is greater than required wellhead delivery pressure (gas lift, water injection, chemical injection lines).

●

Fluid arrival temperature is higher than the wax appearance temperature, or alternatively continuous wax inhibition will be needed.

●

Fluid arrival temperature is higher than the h ydrate temperature, or alternatively continuous hydrate inhibition will be needed.

●

Flow pattern (multiphase lines) or transition from single to two-phase flow. Offset from two-phase region (dense phase lines).

●

Corrosion: water condensation and separation. Required degree of reduction in corrosion rate by inhibitor, likelihood of distributing a corrosion inhibitor (by slugs or droplets).

Analysis is likely to include either maximum & minimum flow rates or a proposed through-life profile (e.g., year-on-year). Turndown operation should also be considered (e.g., 25% or 50% of design rate). Sensitivities to test the robustness of the design decision to variations in the input parameters may also be completed (e.g., to inlet temperature, water cut, fluid composition/Gas Oil Ratio, or to ambient conditions). During Dynamic Steady State Analysis, flow assurance is most likely to b e concerned with flow stability, slug size or surge volume and mitigation of slugs which cann ot be accommodated within the process. Using dynamic analysis, flow assurance can determine the ex tent to which wax, hydrate and slug/liquid surge aspects are generated, and d emonstrate that the operating Page 17 of 24



procedures are robust, and that any possible upset in the process can avoided or managed within the acceptable process range.

10

Pipeline Hydraulic Simulation The purpose of completing pipeline simulation analysis is to provide information which allows well-informed design decisions to be taken. These decisions may or may not be taken by the originator of the pipeline simulation analysis, and ultimately may be financially driven decisions (i.e., taken outside of the design team). However, the pipeline simulation analysis proves much of the information that is a key in qualifying options as being viable, and in understanding any unequal balance of risk between them. Although all aspects need to be agreed upon across the design team, the following are primarily decided by the pipeline simulation analysis: Table 4 Aspect Size Type Degree of insulation

Pipeline Analysis Controlling Variable Constraint Internal Diameter Available pressure drop vs. intended Rigid or Flexible, production rate Roughness Wall make-up, Minimum and Burial maximum fluid arrival temperatures

Most Relevant Issues Construction/Installation method. Likely cost Avoidance of continuous chemical treatment for wax, hydrates, emulsions. Construction method (pipe-inpipe, bundle, conventional insulated, buried).

The following aspects are outputs from the pipeline anal ysis which are likely to be used by other disciplines: Table 5 Discipline Mechanical design

Reception process engineer

Aspect

Most Relevant Pipeline Analysis Output

Type of Pipeline Analysis

Upheaval buckling

Temperature profile

Steady state

On-bottom stability

Contents density

Steady state

Fatigue loading

Slugging cycles

Steady state operations

Arrival temperature, Flow stability

Dynamic Steady State Steady state Dynamic Steady State Page 18 of 24


Discipline

Reservoir Engineering, Wells design & Production optimization Operations

Materials and corrosion

Aspect Non steady state operations Deliverability

Non steady state operations

Corrosion

Erosion Material specification Safety

System limits

Pipeline planned depressurization

Pipeline rupture

Controls (Valves)

Measurement

10.1

Minimum and maximum valve closure times Flow metering

Most Relevant Pipeline Analysis Output Liquid surge (on rate change, start-up). Required vs. available pipeline inlet pressure Available gas lift, or water injection pressure Shut-in/cooldown, intervention time, start-up. Scraping Commissioning (dewatering). Temperature, pressure, flow pattern, velocities, droplets.


Type of Pipeline Analysis Dynamic Steady state

Dynamic

Steady state

API RP 14E or quantitative erosion model Maximum wall temperatures

Steady state

Minimum wall temperature Maximum possible flow rate (specifically valve fails to fully open).

Dynamic Steady state or dynamic

Pressure build-up time on inadvertent valve closure. Within constraints such as flare limit, liquid handling, minimum pipeline wall temperatures Maximum release rates. Total released inventory of oil and gas phases. Specifically HIPPS, OPPS and surge (water hammer) cases.

Dynamic

Maximum and minimum temperature at the location of the meter

Steady State and Dynamic

Steady State

Dynamic

Dynamic

Dynamic

Pipeline Analysis Inputs

A pipeline model comprises the following elements: ●

Route length, including elevation profile and risers

●

Fluid properties, probably derived from a composition, possibly including water

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10.2


●

Pipeline description: diameter, roughness, etc.

●

Thermal description: U-value or wall construction/insulation, burial, external ambient conditions

●

Boundary condition

●

Relevant equipment and controllers

Steady State

To complete a steady state analysis, the boundary conditions are the inlet temperature and any pair of: ●

Flow rate and outlet pressure: Calculate inlet pressure

●

Flow rate and inlet pressure: Calculate outlet pressure

●

Inlet Pressure and Outlet Pressure: Calculate flow rate

At steady state outputs include temperature, pressure, phase properties and phase flow rates/velocities as they vary with pipe length. For multiphase pipelines, flow pattern may be indicated, and where slug flow is suspected an indication of expected severity is given by multiphase simulation software. Constraints which are not directly applied may be implemented using parametric studies to span a relevant range (e.g., pipe diameter, U-value). 10.3

Dynamic Steady State

A dynamic steady state analysis can be completed by defining the time period over which to conduct the simulation (which must be long enough to demonstrate that dynamic steady state conditions have been attained), and by specifying the inlet temperature and either: ●

Flow rate and outlet pressure: Calculate inlet pressure

●

Inlet Pressure and Outlet Pressure: Calculate flow rate

At dynamic steady state the main output is likely to be the phase flow rates at the outlet (or other fixed locations of interest) as a function of time. In the case that the inlet pressure was not specified as a boun dary condition, then this will be calculated, showing cyclic variation with time. Data capture frequency must also be defined for the variables of interest. Constraints may be implemented using controllers acting on process equipment such as valves, heaters. It is important to recognize that profiles of variables with length along the pipeline are snapshots a t an instant in time and interpretation can then be difficult.

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10.4


Dynamics

A dynamic analysis can be completed by specifying a starting condition (e.g., the steady state), the duration of the simulation, and defining any events which act on the pipeline, such as valve positions, controller set-points, inlet temperature, flow rate changes, scraper launch, and boundary pressure. It should also be noted that where thermal transients are to be modeled, the pipe wall construction (and burial where relevant) must be specified in place of an overall heat transfer coefficient (U-value). Certain aspects of dynamic simulation can be time-step dependent and the results may change depending on the time step chosen. For key design decisions, it may be important to demonstrate that the results are insensitive to time-step. 10.5

Applying Analysis to Pipelines

Pipeline analysis must be tailored to be relevant to the type of pipeline. Steady State (SS) analysis is likely to be applied t o all pipeline design. Dynamic Steady State (DSS) analysis is primarily used to assess flow stability of multiphase lines. Dynamic Steady State analysis is less likely to be applied to single phase lines but is relevant if the bounda ry conditions are changing (e.g., day-night) or throughput is changing on a cyclic basis (e.g., packing and un-packing gas pipelines. Dynamic analysis is applicable whenever there is a need to quantify a threat which increases during operating events. A large number of events can be defined, but a range of routine foreseeable events are likely to include: ●

Shut-in: Pressure will equalize within the pipeline subject to variation in static head, and, if not isolated at both ends, the pipeline pressure will equalize with the open boundary. Rapid pressurization (of gas lines) may lead initially to the fluid temperature rising. Rapid shut-in of water lines may lead to water hammer. The temperature of the contents will tend to approach ambient conditions as time progresses, and liquids may condense from the gas. Multiphase pipelines will experience liquid drainage to low points (possibly one end). After some time, conditions may approach those at which wax or hydrates starts to form. Operational intervention may be needed to mitigate this threat through depressurization or displacement. If the shut-in was planned, the pipeline contents may have been pre-conditioned (e.g., hydrate inhibitor) to mitigate such threats for the long-term.

●

Restart : Resumption of flow causes the pressure to build in the pipeline and any liquid to be mobilized through the pipeline to the outlet, possibly as intact bodies of liquid (e.g., 5 km slug). For offshore pipelines the outlet is Page 21 of 24



physically located some height above the main length of the pipeline, for example a vertical riser. If the liquid body is sufficient to fill the riser, then the pressure in the pipeline will initially rise to equal the boundary pressure plus the hydrostatic head of the riser. Once this is achieved, liquid will flow out of the top of the riser, gas will follow, and the steady state flowing condition can be re-established. Fluid temperature is slowest to be reestablished at the steady state condition.

11

●

Rate change: Typically, rate reduction (turndown) leads to an increase in liquid inventory in multiphase lines. Rate increase then expels the excess liquid inventory, possibly as a slug.

●

Scraping : Where facilities exist, scrapers may be sent through the pipeline for cleaning or inspection purposes. Scraping may be undertaken routinely to limit the accumulation of liquids or solids in the pipeline and thereby prevent the pipeline operating at an undesirable steady state. Velocity limits and liquid surge handling constraints may be relevant to the scraping operation and compliance with these can be verified by pipeline analysis.

●

Depressurization/blow down/rupture: The main difference between these scenarios is the degree to which the outflow is controlled or regulated within plant or pipeline constraints. Dense phase lines may enter the two-phase hydrocarbon region. During slow depressurization of offshore pipelines, the velocity may be insufficient to drag liquid up the riser. The outflow may therefore be gas phase only, resulting in the remaining contents becoming rich in heavier components. For dense phase pipelines re-combination of the remaining (heavy) liquid composition with fresh feed on re-pressurization may be an important factor.

Fluid Properties and Phase Envelopes Hydrocarbon fluids are mixtures of components with a wide range of molecular weights, from methane, CO2 and Nitrogen, to long chain molecules (C80 and above). The state of these fluids depends on the prevailing conditions of pressure and temperature. Typical phase envelopes are shown in Figure 1 for a composition which might be referred to as oil and for a gas used for well lifting.

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Fluid phase envelopes 150 Dense phase Condensate r a b , e r u s s e r P

Dense phase (Oil)

Dense phase (Gas)

Dense phase (Gas)

100

50

0 -100

0

100

200

300

400

500

600

o

Lift Gas

Temperature, C Oil reservoir

C ri ti ca l P oi nt (g as)

C ri ti ca l P oi nt (o il)

Figure 1 - Phase Envelopes for Two Compositions (Oil and Lift-Gas)

Outside of the two-phase region a single phase is present. At low pressures the distinction between oil or gas seems clear and is understood. At pressures above the cricondenbar, the fluid is dense phase but may still be referred to as gas or oil, for ease of communication. Somewhat arbitrarily, the critical point temperature may be used as a dividing line for referring to ‘gas’ or ‘oil’ when in the dense phase region. Pipeline Simulation Analysis uses the fluid properties and phase fraction as they vary with operating conditions of pressure and temperature. The fluid behavior can be generate by thermodynamic software (PVT packages) on the basis of an equation of state (e.g., Peng-Robinson or SRK) and a compositional description, often lumping heavier components into one (or more) un-characterized group known as a pseudocomponent for which artificial properties are given. Clearly the accuracy of the fluid model and the pipeline analysis depends to some extent on the proportion which has been left in the pseudo-components and the extent to which the fluid model has been tuned against laboratory data for measured properties such as the gas oil ratio, bubble point, or oil viscosity. For pipeline simulation analysis, the fluid properties are often defined across a grid of temperature and pressure points by the PVT pack age and remain constant throughout the pipeline simulation. Where the composition changes with time (or with position at steady state), the composition can be taken within the pipeline analysis, and fluid (phase) properties then depend on pressure, temperature and local composition as a function of time/position. The main impact of this is computational efficiency.

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11.1


Wax

At low temperatures heavier n-paraffins solidify to form a wax phase. This is a phase in exactly the same way as liquid is a phase. It is the role of pipeline analysis to either avoid conditions which allow wax to form (usually by applying sufficient insulation) or to quantify the rate or wax formation / build-up on the pipe walls. Wax removal by scraping or heating may also be relevant. 11.2

Hydrates

If water is present, light molecules such as methane combine with water molecules to form a solid phase, hydrate, which can plug lines. Again, this can be predicted as a thermodynamic phase, and can be stable for low temperatures. Within the context of pipelines, these temperatures occur if the fluid approaches sea-bed temperature, either due to shut-in, long distance or poor insulation. Hydrates formation can be inhibited chemically with gl ycol, methanol, or brinesalt concentration. Hydrate formation may also be delayed using kinetic hydrate inhibitors (KHI). At low pressure, the hydrate phase is not thermodynamically stable at sea-bed temperature, and hence depressurization can be used to inhibit hydrate formation during long-term shut-down. 11.3

Commercial Multiphase Simulators

Commercially available simulators capable of modeling multiphase systems are listed in SAEP-363, PIPEPHASE is often used for steady state simulations. OLGA is by far the most popular transient simulator.

12

Contributor Authors Name

Affiliation

Rasheed, Mahmood A.

Process & Control Systems Department

Ge, Jianzhi X.


Jain, A.


Espedal, Mikal X.

PROD & FAC DEV Department

1 January 2013

Revision Summary New Saudi Aramco Best Practice.

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SABP-Z-033

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