flow assurance guide

8/19/2019 Flow Assurance Guide

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TotalFinalElf E&P DGEP/SCR/RD/UGF Ref. : UGF/2001-135

FLOW ASSURANCE GUIDE Rev. : 0 – 01 / 2002

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ULTRA DEEPWATER PROJECT

FLOW ASSURANCE GUIDE

Flow Management


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Page 2 of 128

Table of contents

1. PRESENTATION..........................................................................................................................................5

1.1 GENERAL INTRODUCTION................................................................................................................5

1.2 THE CHALLENGES OF FLOW ASSURANCE ..................................................................................................7

1.3 DEVELOPING A FLOW ASSURANCE STRATEGY (FILE) ...............................................................................8

1.3.1 Data .................................................................................................................................................9

1.3.2 Risk assessment & Pre-sizing...........................................................................................................9

1.3.3 Management.....................................................................................................................................9

1.3.4 Sensitivity Studies...........................................................................................................................10

1.3.5 Project Studies ...............................................................................................................................10

1.3.6 Start-up and Production ................................................................................................................10

1.3.7 Flow Assurance file........................................................................................................................101.4 K EY PERSONNEL INVOLVED IN THE FLOW ASSURANCE GUIDE ................................................................12

PART 1 – PHYSICO-CHEMICAL....................................................................................................................13

2. HYDRATES .................................................................................................................................................15

2.1 THE ISSUES .............................................................................................................................................15

2.2 DATA R EQUIRED.....................................................................................................................................18

2.3 METHODOLOGY ......................................................................................................................................19

2.3.1 Formation Prediction (thermodynamic range)..............................................................................19

2.3.2 Evaluating the Risks of Plugging...................................................................................................21

2.4 SOLUTIONS .............................................................................................................................................23

2.4.1 Prevention......................................................................................................................................23

2.4.2 Hydrate solution and limitations for Dry Trees associated with wellhead platform .....................26

2.4.3 Monitoring .....................................................................................................................................27

2.4.4 Curative Methods...........................................................................................................................28


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Page 3 of 128

3. ORGANIC DEPOSITS................................................................................................................................32

3.1 WAXES.................................................................................................................................................32

3.1.1 The issues.......................................................................................................................................32

3.1.2 Data Required................................................................................................................................33

3.1.3 Methodology ..................................................................................................................................36

3.1.4 Solutions.........................................................................................................................................41

3.2 ASPHALTENES....................................................................................................................................44

3.2.1 The issues.......................................................................................................................................44

3.2.2 Data Required................................................................................................................................45

3.2.3 Methodology ..................................................................................................................................46

3.2.4 Solutions.........................................................................................................................................48

3.3 NAPHTENATES...................................................................................................................................49

3.3.1 The issues.......................................................................................................................................49

3.3.2 Data Required................................................................................................................................493.3.3 Methodology ..................................................................................................................................50

3.3.4 Solutions.........................................................................................................................................52

4. SCALE..........................................................................................................................................................55

4.1 THE ISSUES .............................................................................................................................................55

4.2 DATA R EQUIRED.....................................................................................................................................57

4.3 METHODOLOGY ......................................................................................................................................58

4.4 SOLUTIONS .............................................................................................................................................61

5. MISCELLANEOUS PROBLEMS .............................................................................................................64

5.1 RHEOLOGY........................................................................... ...................................................... .........64

5.1.1 Definitions......................................................................................................................................64

5.1.2 The issues.......................................................................................................................................645.2 RHEOLOGY OF CRUDE OILS ...........................................................................................................65

5.2.1 Data required.................................................................................................................................65

5.2.2 Methodology ..................................................................................................................................65

5.2.3 Solutions.........................................................................................................................................68

5.3 RHEOLOGY OF EMULSIONS............................................................................................................69

5.3.1 Data required.................................................................................................................................69

5.3.2 Methodology ..................................................................................................................................69

5.3.3 Solutions.........................................................................................................................................71

5.4 SEPARATION OF EMULSIONS.........................................................................................................73

5.4.1 General ..........................................................................................................................................73

5.4.2 Required Data................................................................................................................................73

5.4.3 Methodology ..................................................................................................................................73

5.4.4 Solutions.........................................................................................................................................73

PART 2 - MULTIPHASE TRANSPORT..........................................................................................................75

6. HYDRODYNAMICS AND PRODUCTIVITY.........................................................................................77

6.1 THE ISSUES .........................................................................................................................................77

6.1.1 Productivity Calculations : ............................................................................................................77

6.1.2 Stability issues................................................................................................................................78

6.1.3 Flow enhancement .........................................................................................................................79

6.2 REQUIRED DATA ...............................................................................................................................79

6.3 METHODOLOGY ................................................................................................................................80

6.3.1 Steady State calculations ...............................................................................................................81

6.3.2 Stability studies..............................................................................................................................836.3.3 Flow enhancement .........................................................................................................................86

6.4 SOLUTIONS .........................................................................................................................................87


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Page 4 of 128

7. THERMAL MANAGEMENT....................................................................................................................96

7.1 THE ISSUES .........................................................................................................................................96

7.2 REQUIRED DATA ...............................................................................................................................97

7.3 METHODOLOGY ................................................................................................................................97

7.3.1 Under permanent flowing conditions.............................................................................................98

7.3.2 Under shutdown and restart conditions.........................................................................................99

7.4 SOLUTIONS .......................................................................................................................................101

7.4.1 Passive Insulation ........................................................................................................................102

7.4.2 Active Heating Systems ................................................................................................................105

7.4.3 Temperature monitoring ..............................................................................................................110

7.4.4 Hydrate prevention ......................................................................................................................111

8. EROSION / CORROSION .......................................................................................................................113

8.1 TERMINOLOGY......................................................................................................................................1138.2 POSITION OF THE PROBLEM ...................................................................................................................113

8.2.1 Main materials concerned ...........................................................................................................114

8.2.2 Main equipment concerned..........................................................................................................114

8.2.3 Main fluid effects..........................................................................................................................115

8.3 DATA REQUIRED ...................................................................................................................................116

8.4 METHODOLOGIES..................................................................................................................................117

8.4.1 Risk assessment............................................................................................................................117

8.4.2 Erosion-corrosion prevention......................................................................................................122

8.4.3 Erosion-corrosion monitoring .....................................................................................................123

9. WELL METERING ..................................................................................................................................127

9.1 THE ISSUES .......................................................................................................................................127

9.2 SOLUTIONS .......................................................................................................................................127


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Presentation Page 5 of 128

1. PRESENTATION

1.1 GENERAL INTRODUCTION

This guide has been drawn up within the framework of the activities of the PRODUCTIONOPERATION Part of the Ultra Deepwater (UGF) R&D Project. It is based on experience acquiredwithin the R&D activities (UGF and Maîtrise des Dépôts) and within the Deepwater field developmentprojects. The document has involved specialists from TDO/EXP, TDO/TEC, SCR/RD and SCR/ED.

This guide is intended for anyone seeking information on Flow Assurance related to DeepOffshore developments, especially peoples involved in Field development, Design, Construction andProduction phases.

The aim of this guide is to highlight concerns related to multiphase flow production, to give the levelof knowledge and understanding of phenomenon, explain and detail the studies to be carried out tohandle and quantify associated risks and finally describe solutions to be implemented in order toprevent or remediate the problems.

As subsea production is a key element to deepwater production, this document focus on problems

and solutions developed for subsea systems. More traditional developments with dry trees anddirect access meet similar constraints and solutions as those identified in this document.

In the same way, the document is more dedicated to oil dominated system because of our deepwater history. As deepwater production for oil dominated systems is more stringent in terms of Flow Assurance risks and solutions, general strategy can therefore be transposed to gas systems.

Other Flow Assurance documents are available as:

Flow Assurance Design guide developed by DEEPSTAR phase IV.

Internal study “Etude Architecture 3000” identifying technology gaps.

TECHNOSCOOP magazine N° 23 August 2000 “Flow Assurance”.


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For greater clarity and easy reading, the document is divided into two main parts:

PART 1 – PHYSICO-CHEMICAL

Part I deals with physical and chemical aspects of flow problems, broken down into the four followingthemes:

HYDRATES.

ORGANIC DEPOSITS (waxes, asphaltenes and naphtenates).

SCALE DEPOSITS (carbonates, sulphates and halite).

MISCELLANEOUS PROBLEMS (rheology, gels and emulsions).

PART 2 – MULTIPHASE TRANSPORT

Part II covers MULTIPHASE TRANSPORT of fluids, discussed around four themes:

HYDRODYNAMICS and PRODUCTIVITY (friction losses, instabilities and artificial lift),

THERMAL MANAGEMENT

EROSION – CORROSION

WELL METERING & MONITORING

We have tried to use the same presentation in our coverage of the different themes in both parts:

- an introduction to the ISSUES, aimed at defining the nature of the problem,

- an inventory of the DATA needed to conduct the study, in order to understand thephenomena and identify the problems.

- a presentation of the general METHODOLOGY, explaining how the studies proceed andwhat resources are implemented,

- and finally, a description of the SOLUTIONS that can be considered, to prevent or remedy the different problems.


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1.2 The challenges of Flow Assurance

Specific characteristics for Deep offshore and Ultra Deep offshore

Subsea production is seen as a key element to develop deepwater fields from large stand alone tosmall remote single well production. The ability to transport the fluids (oil, water and gas) from the wellsto the host facilities is the major concern for Flow Assurance.

Deep offshore and, to an even greater extent, Ultra Deepwater developments (1500-3000m), arecharacterised by:

Very low ambient temperatures, around 4°C from depths of 500 m down and even less than2°C around 3,000 m.

High pressures in the production lines (flowlines & risers).

Laterally extensive, shallowly buried reservoirs.

Harsh environment, which prevents easy access into the system for remediation..

The economic considerations of these projects mean we can only take an interest in wells that arehighly productive. Accumulations that are widely spread one from another have to be developedtogether, whereas onshore they would be covered by individual developments.

As a result, the subsea evacuation system is an extensive, complex network, combining several highproductivity wells.In this context, any incident is likely to lead to significant losses in production, requiring interventionsthat will be difficult, sometimes even impossible and in all events extremely expensive.

Flow Assurance objective

The emergence of flow assurance as a discipline is driven by the combination of the hostileenvironment, challenging fluid properties, and system reliability targets associated to deepwater production systems.

The overall objective of flow assurance is simply to “keep the flow path open”, to insureuninterrupted flow of production from subsea reservoirs to host facilities at minimum capital andoperating costs.Deepwater production systems must be conservatively designed with high front-end capital equipmentto overcome all perceived flow assurance problems to maintain production.

The Operator's main concern is therefore to focus on “Flow Assurance”. This means taking major

problems such as the following into account: Formation of hydrates,

Deposits,

Gelling point,

Productivity and Pressure drops

Flow Stability.

Deposition and associated plugging by both hydrates or waxes in lines are the largest risks currentlylimiting oil extended reach subsea tieback (in excess of 25-30 Km). Other potential deposits such asscale or asphaltenes are also to be addressed but generally at a lower priority.

Associated with the production of fluids, cooling and reduction in pressure from the reservoir to thehost facility are inescapable. This may induce phase changes including the separation of gas and


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liquid, the phase slippage or the formation of solids. Multiphase transport of fluids presents number of

challenges to be managed in order to assure flow and ensure the integrity of the production system.These issues tend to be fluid and system specific.

Flow Assurance studies strategy

Flow Assurance studies consider hydrodynamic and thermal behaviour, together with thethermodynamic, chemical and physical characteristics of the effluents. They therefore entail thoroughanalysis of the fluid stream, from the reservoir to the surface installations.Their results are used to identify potential problems to be tackled as early as possible in thedevelopment design phase, and to propose solutions in line with the project technical and costobjectives, such as:

- Quantifying and managing production-related risks to avoid costly interventions on wells andsubsea equipment

- Choosing the most appropriate subsea multiphase technology

- Proposing or developing back-up solutions and curative techniques

- Optimising the design specifications for fluid management.

This approach is initiated in the pre-project phase and continues well beyond the construction andinstallation phases throughout the duration of the field's operation.

The preferred current strategy available for dealing with hydrates and waxes is still to insulate andpossibly heat the fluids to prevent them from cooling into the solids formation region during normaloperation and for limited shut-in times.

Remote subsea production in deepwater rely on a combination of prevention and remediation solutionsto guarantee uninterrupted production, flow assurance strategies involve an association of equipmentdesign & selection, operational methodologies and chemical treatments.

Flow Assurance studies focus on developing prediction tools as well as identifying and developingprevention and curative solutions, in order to better quantify the risks of plugging a production systemand in qualifying or improving the performance of prevention, inhibition and remediation technologies.

Flow Assurance mission is to identify, promote and develop new technologies that insure theuninterrupted flow of production from subsea reservoirs to process facilities at minimum capital andoperating costs without undue risks to environment, personnel and installation.

For the current near term (3-5 years) the objective is to optimise current design practices and

operation, to improve prediction software by analysing acquired data during operation and in parallelidentify, evaluate and improve prevention and remediation technologies.

Long term strategy has to provide technologies to allow for the minimal CAPEX/OPEX productionsystem as single un-insulated flowline. Associated with this minimal design the ability to quickly andsafely remediate any potential restriction is crucial (low cost intervention system).

1.3 Developing a Flow Assurance Strategy (File)

Flow Assurance concerns are not unique to deepwater environments but this discipline is recognised

as a critical technical activity, present in all the phases of project execution, operation and

production of deepwater developments. Flow assurance analyses originate during explorationactivities and continue through the entire life cycle of deepwater fields exploitation.


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As a result flow assurance must be integrated into the overall subsea systems engineering effort, to

integrate flow assurance with system/equipment selection, elaboration of operational guidelines anddevelopment of blockage remediation strategies.

1.3.1 Data

The first stage involves listing and assembling the data essential for the different studies. Obtaining

reliable data is one of the keys to evaluation of the risks associated with produced fluids,reservoir behaviour, production profile, but also with the adjacent functions like water and gas injection.

1.3.2 Risk assessment & Pre-sizing

Using the analysis of fluid samples and preliminary data (reservoir, environment), the Flow Assurancestudy will first:

evaluate, from the physical and chemical standpoints, the risks of organic and mineraldeposits and plugging,

preliminary sizing , in hydrodynamic terms, the lines under steady state conditions, on thestrength of preliminary data.

Once the major risks have been identified and the lines pre-sized, we then describe the operationalconstraints. The operating range will be delimited by identifying the nominal and downgraded operatingmodes (i.e. arrival temperature range).

1.3.3 Management

Using the different operating modes (normal and downgraded), Management studies then seeksolutions regarding:

Flow Management for steady state and transient flow, dealing with,

• unstable conditions (hydrodynamics and severe slugging),

• shut-in and restart conditions,

• artificial lift based on the well eruptivity limit,

• erosion-corrosion,

• well metering.

Thermal Management of Behaviour of the streams. The different possibilities (passiveinsulation and heating) are assessed technically and economically. The thermal signaturefor the lines (flowlines & riser) is defined for steady state and transient phase (shutdownand re-start) over the entire operating range.

Deposit Management. Mineral and organic deposits are quantified for the differentoperating modes. Solutions for prevention, and possible curative means are described indetail.

Corrosion management. The different solutions (material selection, prevention, inhibition)

are evaluated technically and economically. Monitoring and inspection means are defined.


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1.3.4 Sensitivity Studies

Sensitivity studies are conducted to assess the adaptability of the selected system to variations incertain production conditions predicted or not by the reservoir studies. As an example, therepercussions of velocity and cooling changes induced by gas or water breakthrough have to be takeninto account.

1.3.5 Project Studies

In accordance with operating philosophy and based on design of wells, pipes, subsea and surfaceequipment, project studies include:

• Verification of the capacity of wells, pipes, subsea and surface equipment to handle preventionand remediation,

• Definition of monitoring to ensure detection of any changes as early as possible,

• Basic and detailed engineering of the production system (subsea and surface) in connection withflow assurance, such as selection of chemicals, chemicals injection system, sampling points…

• Establishment of procedures for normal and downgraded operating modes.

Throughout the project phases, each Project Technical Review (PTR) includes a Flow Assuranceevaluation.

1.3.6 Start-up and Production

During the production start-up phase, fluid samples are collected and analysed. The results arecompared to the previously determined characteristics.

The thermal and hydrodynamic signatures of lines are monitored and checked and compared toforecasted performances.

Following comparison of actual and forecasted performances, corrective actions are determined if needed, and procedures are updated.

During the production phase and throughout field life, continuous monitoring data are collected and

analysed. Trends are noted and used to update the Flow Assurance strategy.

Disruptive and corrective actions are recorded and analysed.

1.3.7 Flow Assurance file

According to the different development phases, in order to consolidate and facilitate feedback all thedata, studies and information obtained in the course of the above parts should be collected and

classified in the “Flow Assurance File”. The figure here after shows a synthetic diagram of the workprocess related to Flow Assurance.


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• Data (Fluids, Reservoir, production profiles…)

• Risk assessment

• Solutions (Deposits, Thermal, Hydraulic)

• Operating Logic

• Sensitivity studies

• Consistency Equipment / Risks

• Monitoring issues

• Detailed Engineering

• Procedures for Normal & Degraded modes

• Sampling

• Thermal behaviour

• Hydrodynamic Behaviour

• Monitoring …

Pre-Project

Project

Start-up

Production

Exploration

Exploitation


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1.4 Key personnel involved in the Flow assurance Guide

The editorial board, chaired by C FOUILLOUT (UGF), comprises the following members, all specialiststaking part in the different specialities of Flow Assurance.

SPECIALITY Name Entity

HYDRATES JL PEYTAVY TDO/EXP

ORGANIC DEPOSITSWaxes, Asphaltenes, Naphtenates

Asphaltenes only Naphtenates only

JL VOLLEC. SCHRANZ

H. ZHOUC. HURTEVENT

TDO/EXPSCR/ED

TDO/EXPTDO/EXP

MISCELLANEOUS PROBLEMS

Rheology, Gels, Emulsion

JL VOLLE TDO/EXP

SCALE DEPOSITS

Carbonates, Sulphates, halite

C. HURTEVENT TDO/EXP

HYDRODYNAMICS and PRODUCTIVITY

Pressure losses, Instabilities, Artificial lift

D. LARREYP. BRANJONNEAU

SCR/EDTDO/EXP

THERMAL MANAGEMENT D. LARREY

P. BRANJONNEAU

SCR/ED

Ex. TDO/EXP

EROSION – CORROSION M. BONIS TDO/TEC

WELL METERING & MONITORING L. THOMAS Ex. SCR/RD/UGF


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TotalFinalElf E&P DGEP/SCR/RD/UGF Ref. : UGF/


Part 1 – Physico-chemical Page 13 of 128

FA Guide rev 02-10-01


Deep Offshore

Flow Management

Part 1 – Physico-chemical

HYDRATES.

ORGANIC DEPOSITS

Waxes

Asphaltenes

Naphtenates

SCALE DEPOSITS

Carbonates

Sulphates

Salts

MISCELLANEOUS PROBLEMS

Rheology

Emulsions

Separation


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Part 1 Physico-chemical Page 14 of 128


Deep Offshore

Flow Management

Hydrates


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2. HYDRATES

2.1 The issues

Natural gas hydrates are solid crystals that resemble compact snow or porous ice.

They are made of crystalline cages of water molecules entrapping gas molecules. They belong tothe clathrates family.

Inside production lines, 3 conditions have to be fulfilled for hydrates to form:

♦ The presence of water, "free", dissolved or emulsified

♦ The presence of light hydrocarbons (from methane to butane), or acid gases (CO2 and H2S),or Nitrogen, "free", dissolved or liquefied

♦ Low temperatures or relatively high pressures e.g. 4°C and 12 bar or 20°C and 100 bar.

Their formation being exothermic, the dissociation of hydrates, conversely, is endothermic, thus iceformation may occur during hydrate dissociation at low ambient temperature.

Fig 5.1 A

General issue: The major difficulty in controlling the risk represented by hydrate formation stemsfrom the fact that only the thermodynamic conditions governing their existence can be satisfactorilypredicted. We are extremely short of knowledge on the kinetics of their formation and growth,especially in the presence of oil, leading to a plug forming.

♦ The first practical consequence is that, when a prevention system fails, we can no longer controlthe formation of hydrates and are thus reduced to counting on huge injections of thermodynamicinhibitor (methanol or glycol) and plenty of good luck!

♦ While the formation of hydrates systematically entails a risk of plugging, this does not necessarilymean that plugging will actually occur. The presence of geometrical or thermal irregularities is inthis respect fairly critical.


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♦ Nor is there any direct relation between the quantity of hydrates formed and the plugging speed. In

a flowline several inches wide, the plugging process may be fairly slow (taking several hours andeven several days). A substantial amount of material is needed for a plug to form.On the other hand, a relatively small quantity of hydrate may be enough to instantly plug a valve(e.g. during re-opening of an SCSSV, if a gas pocket, formed upstream during shutdown, comesinto contact with water segregated downstream).

♦ Finally, as far as prevention methods are concerned, the economic issue hinges above all on theproduced water flow rate. Thus, we can clearly see (figure below) that the continuous injection of chemicals beyond a certain rate of water flow will become crippling. This water flow limit has to bedefined on a case-by-case basis, but, a priori, we can consider:

gas fields (with a low liquid content) where continuous injection of chemicals will beeconomically viable, and

oil fields, where the water flow rate to be inhibited will, sooner or later, become totallyunacceptable; especially when water injection is used to ensure reservoir pressuremaintenance.

Fig 2.1 B

OPEX of hydrate inhibitors(continuous injection)

0

0.5

1

1.5

2

2.5

3

3.5

4

4.5

5

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

watercut (%)

O P E X ( U S $ p e r b b l o f p r o d u c e d o i l )

Methanol-10°C subcooling

new GHI (KI or AA)-10°C subcooling

Methanol-20°C subcooling


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Associated risks: the following merit consideration:

♦ Rapid or even instantaneous plugging of flowlines, leading to significant production losses due tothe difficulties of intervention.

♦ Rupture of the line subsequent to a projectile effect when the plug dissociates with under-balancedpressure (velocity of 18 to 80 m/s).

♦ Bursting of the flowline with local overpressures when evacuation of the gas during dissociation(180 v of gas / v hydrates) is not possible.


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In Deep offshore contexts

For oil fields, despite preventive measures based on thermal insulation, the major risk that subsists liesin the re-start phase after a long unscheduled shutdown. At shutdown, the risk of a plug forming is near to zero. On re-start, a massive, even explosive formation of hydrates may occur, leading to extremelyrapid plugging of flowlines.

Remediation means are limited and time consuming in deepwater context. After plugging the linewith an hydrate plug that has cooled down to ambient (4°C), dissociation time can extend into severalmonths if the pressure cannot be reduced to very low value (< 4 bar). Graph here after shows thepredicted plug dissociation times for an oil system.

Associated costs from production losses and intervention are high.

For gas fields, the difficulty is to implement continuous inhibition economically and reliably. Plugging

does not have the same consequences in curative terms due to possibilities of depressurising thelines.

2.2 Data Required

To predict hydrate formation and associated risks, we need the following information:

the molar composition of the effluents, at least C1, C2, C3, iC4, nC4, N2, CO2 and H2S,

the phase range provided by the PVT study,

the amount and salinity of the actual produced water,

Hydrate Plug dissociation time (cf Shell Global Solution)12'' PIP with hydrate plug cooled down to 4°C prior starting depressurization

0

100

200

300

400

500

600

0 50 100 150 200 250

downstream pressure (psi)

d i s s

o c i a t i o n t i m e ( d a y s )


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0

10

20

30

40

50

60

70

80

0 4 8 12 16 20

Temperature (°C)

P r e s s u r e

( b a r s )

hc bubble curve

hydrate curve

Quadruple point

TiPi

♦ FHYD developed with the help of Professor Peneloux (University of Marseilles)

These software applications are calibrated against experimental measurements and generally deliver similar results.However, we have observed some differences (see curves above), and it is best to systematically

compare the calculation results of at least 2 of them.Where a substantial interval persists (> 2 - 3°C), it is advisable to perform experimental PVT cellmeasurements to define the formation range.

Remark:The intersection Pi, Ti of the hydratecurve (see curve here aside) and thebubble curve (quadruple point) must bedetermined carefully when located in the

operating range conditions.

For operating temperatures above Ti,fluids will be outside the hydrate region,whatever the pressure.

Hydrate formation curves

Shallow case

No Salt

0

25

50

75

10 0

12 5

15 0

17 5

20 0

22 5

25 0

27 5

30 0

32 5

35 0

37 5

40 0

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30

Temperature (°C)

P r e s s u r e ( b a r a )

Shallow Aquasim

Shallow Equiphase

Shal low C SMHYD

Shallow Fhyd


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2.3.2 Evaluating the Risks of Plugging

To identify the problem areas, we have to compare the hydrate formation region and the operatingpressure-temperature pairs.

For gas field application, the risks of plugging by hydrates can be determined reasonably accuratelywith simulation models.

For oil field application, the risk of line plugging is not only related to thermodynamic conditions. Thekinetics of hydrate growth and agglomeration also depend on many factors not yet fully understood.

Recent works on test loops show that some oil/water systems contain natural surfactant componentsthat play the same role as anti-agglomerant additives. Thanks to this property, hydrate crystals can be

transported in the form of slurry, and installations can be re-started without the lines becomingplugged.

To date, two types of oil have been identified as having that property, at least up to a certain level of water content:

Asphaltenic crude oils. The presence of resins and asphaltenes gives them the interfacialproperties to stabilise an emulsion of water in oil. The slurry is thus stabilised when the droplets of water turn into hydrates. Examples of asphaltenic crudes include FROY, TROLL and ALBACORA,which can transport a hydrate slurry with up to 30% water.

Acidic crude oils. The combined presence of naphtenic acids in the oil and sodium and/or calciumsalts in the water, under certain pH conditions, generates naphtenates at the oil/water interface.These components are well known for their surfactant properties and capacity to stabilise theslurry. Among acidic crudes, we could mention that during loop test with HEIDRUN oil we didn’tplug the test line up to 30% water.

To conclude, for oil fields, in addition to the thermodynamic study, an experimental evaluation of thetransportation potential needs to be performed, either on the CSTJF pilot rig or on the IFP loop inSolaize (see photo here after).


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IFP loop in Solaize

Pilot laboratory unit


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2.4 Solutions

2.4.1 Prevention

Various means of prevention can be envisaged. They are classified into four categories:

Dehydration of effluents (gas application), usually by a glycol process. By eliminating water, weremove any risk of hydrate formation. This method is reliable and has been proved, and is usedmainly to protect gas export or injection pipelines.

Keeping the temperature of produced fluids above the hydrate formation threshold. The effluentflows from the wellhead at a temperature higher than that conducive to hydrate formation. Tomaintain this condition in subsea pipelines, with an ambient temperature at 4°C, we need to limitheat exchanges. That means insulation and sometimes heating of the lines (for more details see§ 7 Thermal Management).During a long shutdown, the temperature is maintained above the hydrate formation threshold for a limited period (passive insulation) and even permanently (heating device).But insulation performances have to be carefully checked before implementation, a number of previous experiences having shown them to be poorer than expected due to thermal losses,particularly on singular points with a different thermal signature (manifold, valves, connectors,etc.).

Passive thermal insulation alone is not sufficient for prolonged shutdowns. To avoid plugs, whichcan take a long time and be costly or even impossible to dissociate (several days to severalmonths), we have to consider additional means:

1. Replacing the effluents by dead oil. Start-up then proceeds by circulating (looparrangement) the stock-tank oil to warm up the lines and, further on, by opening the wellswhile massive shots of methanol are injected. Any parts of the system not located on theproduction circulating loop, must be flushed with methanol.

2. Remaining outside the hydrate formation region during shutdown by depressurising

the lines assisted by riser gas-lift, insofar as this is possible. The restart phase is achievedby massively injecting methanol at the wellhead while controlling the pressure in the lines toavoid any incursion into the hydrate region.


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3. Maintaining the fluid temperature outside the hydrate region by permanent heating

activated during shutdown (case A).

Case AMaintaining the temperature outside the hydrate region by electrical heating of lines

4. After a total black-out, if all power generation is lost, the fluid will cool down to ambient

temperature, and then when power generation will be available re-heating the effluents to

quit the hydrate region before any start-up of producers(case B).

Case B

Heating fluids before start-up of wells

These last two active solutions can only be considered for lines equipped with an heating system

(electrical, hot fluid, etc.).

Hydrate Region

PRODUCTION

Temperature

Flowing Temp.

TIME

Critical temp.

4°C

20°C

Start Heating

Re-Start Production

Well opening

Def ault

SHUTDOWN

Stop Heating

Fluids

Stabilization

∆Τ°

Required duration

Hyd rate R eg ion

P R O D U C T I O N

T e m p e r a tu r e

F l o w i n g T e m p .

TIM E

Cr i t ic a l temp.

4°C / 40°F

20°C / 76°F

St art e lect r ic Heat ing

D efault

SHUTDOWN

Sea temp.


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Continuous injection of chemicals:

Continuous injection of chemicals is nowadays only economically viable for fields with low water flowrates (a few hundreds of barrels/day) i.e. gas fields. When the water rate to be inhibited representsseveral thousands of barrels/day and the sub-cooling to be overcome is around 15-20°C, thecontinuous use of any sort of chemical inhibitor becomes unrealistic.

There are 3 families of chemical inhibitors, with different modes of action at different stages of industrial development:

1- Thermodynamic inhibitors: like (non-recycled) methanol and (in principle, regenerated)

glycols. These are antifreeze type products. They act by displacing the hydrate formation region.This is therefore by far the most reliable method and the one most often used. The quantity of

methanol and glycol inhibitor that must be present in the water can be predicted by the modelsmentioned above and will depend directly on the desired drop in temperature with respect tohydrate formation.

Remarks:

- the total quantity of methanol to be injected must take into account losses in the gas and oilphases,

- the presence of salts in the water to be inhibited, although favourable from athermodynamic point of view, can lead to 2 types of limitations:

♦ when methanol is used, the solubility of the salts will be considerably reduced.For example, the solubility of NaCl dwindles from 270 to 150 g/l when the

methanol content increases from 0 to 30% weight. The risk of precipitation of salts can thus increase significantly (salt bridges), thereby impairing inhibitionof hydrate formation,

♦ the fouling, or even corrosion, of boilers with the presence of salts often makesthe re-generation of glycol almost impossible.

2- Low Dosage Hydrate Inhibitors (LDHI): These new additives are not currently used yet indeepwater conditions (subcooling > 15°C or BSW > 50%). Although the active material is relativelyexpensive as compared with methanol, their low dosage may result in significant cost cuts (Fig 2.1B).

Remark: before deciding to use these additives, experimental work is always needed to optimisethe active material formulation and quantify the injection rate.

The LDHI additives are of 2 types:

kinetic Inhibitors (KHI), hydrosoluble polymers, injected at low dosage (generally0.5% weight of active material versus water content). They retard the crystal growthand prevent hydrate formation for the time needed to transport effluents under hydrate region conditions. Their performance is limited, at least for the time being,to relatively mild cases of sub-cooling (< 10°C).

An inhibitor of this type, developed by BP/TROS, was tested industrially in 1997 on

a 12″ pipeline between Pont d’As and Lacq, in mild conditions (sub-cooling ≤ 6°C).The results were positive as far as the additive's capability to inhibit hydrateformation was concerned. However, problems of emulsion and foaming were


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observed on the downstream facilities. Before any use, we need to carefully assess

this issue.

Despite many other tests on fields, these inhibitors are still seldom used incontinuous injection. BP has been using them since 1997 on a North Sea linecovering 70 km from the HYDE field to the Easington terminal to replace themethanol planned in the initial design. On the MUNGO field (ETAP field run by BP),a kinetic inhibitor is injected to prevent hydrate formation when there are longscheduled shutdowns. To date, performance is not fully satisfactory since the sub-cooling is around 10°C. An instance of plugging was reported in 2001.

Anti-Agglomerants (AA) or dispersant additives, hydrocarbon soluble polymers,also injected in low dosage (generally 1% weight of active material versus water content). These do not prevent the formation of hydrate crystals, but limit their size

and keep them in suspension in the liquid phase as slurry. These additives are stillat the development stage. Their scope is limited, at least for the time being, tomoderate BSW (< 30 to 40%). The presence of a liquid hydrocarbon phase isnecessary i.e. these chemicals do not control hydrtates in a gas-water system.They may become economically applicable for many cases once the subsea water separation technique is available.

An additive of this type (Emulfip 102 B), developed by TFE and IFP, was recentlytested on the CANADON Alfa field in Argentina. The relative failure of the test canbe attributed to extremely severe conditions (laminar flow, temperature sometimeslower than 0°C and sub-cooling of around 20°C).

Other tests need to be conducted before concluding as to the feasibility of this

prevention process.

An AA additive ( RE 4394 HIW from Baker Hughes) is presently under test on ShellPopeye field, in a subsea flow line which is operated at 12 °C subcooling.Shell is preparing an other test with an AA chemical Armoclear 2550 on a satelliteof SEAN ( North Sea) This will be the first industrial application of AA.

3- The natural oil surfactant properties: This way of controlling hydrates obviously needs to bevalidated in the field. This is the goal of current JIPs.

But a priori , we can say that it has one sure advantage in that it is free! Its application, as for AA

additives, is limited by the BSW, but here too, the development of subsea water separation couldrender this method viable in a very large number of cases without incurring extra costs.

2.4.2 Hydrate solution and limitations for Dry Trees associated with wellhead platform

The main concern for dry tree risers in deepwater is the hydrate formation leading to plug theproduction tubing during shutdown or associated restart phase.

The classic design for dry tree riser (isolation by nitrogen in the inner annulus) can provide a very shortcooldown (delay) before the fluid enters in hydrate domain. This cooldown time depends upon thepressure of the nitrogen in the annulus (2 hours and lower).


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In mid water depth, operations of WHP do not lead to hydrate plugging controversially in deepwater,

low seabed temperature and high shut in pressures can result to get severe incursion into the hydrateregion (on the order of 20° C in some cases).

As the SCSSV is located as deep as to operate out of hydrate domain, depending on water cut andGOR, depressurisation of riser after closing SCSSV may not reduce significantly the pressure at themud line out of hydrate formation.

On the other hand, remediation of hydrate plug can be handled « easily » with coiled tubing technique.But in the case of multiple wells (more than 10), using coiled tubing to restart after shutdown is notrealistic due to economic impact.

Riser insulation and or active heating techniques have to be improved to give sufficient cooldown for preventive actions.

Production restart with dry trees at high water cuts is also a main issue. During the restart periodMeOH injection will prevent hydrate formation.

This thermodynamic inhibition injection is maintained until a sufficient temperature is reached to giverequired cool down in the case of new shutdown. The design of completion limits the inhibitor injectionline diameter an subsequently methanol or LDHI injection rate to less than 10 gal/mn. (Matterhorn < 5gal/mn w/ 9/16’’ injection line).

At high water cuts, this limitation in injection will impact the production rate at which the well can berestarted.

Lower flowrates during restart phase result in longer warm-up times and consequently in large volumes

of methanol.

2.4.3 Monitoring

As mentioned above, a distinction needs to be drawn between hydrate formation and plugging byhydrates. But detection of the presence of hydrate crystals in effluents should provide warning.

At present, there is no one universal way of detecting the formation of a hydrate plug. The followingfour observations should, however, act as a warning and so trigger or increase the injection of inhibitor as a preventive measure:

- Pressure measurement (pressure drops) and temperature measurement to evaluate the operatingrange as opposed to the hydrate formation region. Temperature measurement throughout the

liquid stream by a non-intrusive optical fibre (DTS Distributed Temperature System) providesmonitoring of fluid temperature all along the lines (see for more details in § 7.4.3).

- the presence of hydrate crystals in the pig receiver,

- reduction in the water flow at the separator on the receiving installations (gas applications),

- gradual increase in pressure drops, especially if punctuated by sudden drops (sign that a plug isbeing formed and partly tearing free from time to time).


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2.4.4 Curative Methods

Theoretically, there are four methods that can be used either together or separately:

− 1- Injection of thermodynamic inhibitors. This method is generally a long and painstaking matter but is reliable provided the inhibitor actually manages to make contact with the plug (with, as acorollary, the problem of multiple plugs!). It therefore can only be used if the plug is perfectly locatedand the inhibitor can migrate to reach it.

Remark: due to its density of 800 kg/m3, methanol may not traverse an oil layer by the effect of gravity to reach the sedimented water part.

− 2- Depressurisation. This should be performed, whenever possible, on both sides of the plug. It isthe most commonly used method, as it is simple and effective and you do not need to know the

precise plug location. However, if you only depressurise on one side, there is a risk of making aplug behave like a cannonball, likely to damage the pipeline system.

A model on radial dissociation has just been developed by the Colorado School of Mines (D. Sloan)within the framework of the DEEPSTAR JIP. This is the first model of its kind and is claimed to becapable of predicting the time needed for radial dissociation of the hydrate plug by depressurisation.

One limitation to this method emerges in Deep Offshore oil production. The residual static pressureafter depressurisation can be higher than the minimum pressure required to quit the Hydratesregion. Furthermore, in a thermally insulated pipe excessively long dissociation times are to beexpected because of the endothermic nature of hydrate dissociation.

− 3- Heating: This method is not recommended when it is impossible to evaluate the length of the

plug (which is often the case in subsea pipes), heating must be banned as a precaution. Indeed,if evacuation of the gas released cannot be ensured due to the plug sealing effect, the pressuremay increase exponentially with temperature (heating mode) and ultimately cause rupture of thepipeline. Conversely, if the pipeline is within the hydrate region during prolonged shutdown but noplug has formed, the heating approach can be recommended to get effluents out of the hydrateregion BEFORE re-starting production (see § 7.4.2 active heated systems).

However, recent study performed by SHELL provided a detailed analysis on hydrate dissociationby electrical heating demonstrating that it is technically feasible, operationally safe and efficientmeans for plug remediation. During dissociation pressure increases is relatively modest comparedto the pipe burst pressure and a very small gap (pipe wall and hydrate plug) is required to dischargea very small mass of gas at large pressure difference. Hydrate dissociation process which isendothermic, will quickly consume heat transferred from the pipe wall. Pipe wall temperatures do

not approach the value required to support pressures near the pipe burst limit. Based on theconclusion of this study Electrical Heating will be used (installation in 2003) for Nakika field (WD:

1900m) for hydrate remediation on the different flowlines (10’’ x 16’’ PIP length 2 to 12.8 Km).

− 4- Mechanical, by drilling or jetting effect. This method can be associated with the injection of thermodynamic inhibitors to combine both (mechanical and chemical) effects.

• Remediating for oil dominated system by the use of intrusive system as an Extended ReachCoiled Tubing Technique going gradually along the riser and the flowline up into contact with thehydrate plug(s) to dissociate them by circulating tank battery oil and/or methanol.

This method is now limited by the size of the coiled tubing available on the market, its weight,tensile limits and mechanical stability, and its ability to slide into bends.

Usual diameters range from ½’’ OD up to 3 ½”OD.


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Classic drums available have lengths of between 450 and 600m of steel tubing, the limit being due

to the maximum diameter and weight.

One limit to the range of action for CT stems from the buckling effect, which can cause spiralwinding on the internal wall of the pipe after too high a thrust. The buckling effect will depend on theratio between the internal diameter of the pipe and the outer diameter of the Coiled Tubing.

To use this technique, you need to take into account geometrical specifications in terms of bendingradius and change in direction during the design phase.

Recommended curve radii range from around 6 to 18 m.

Recent works conducted over 1997-1998 within the framework of the DEEPSTAR JIP highlightedthe advantage of combining a crawler and hydraulics (Jet and piston effect developed by RADOIL

providing 15T traction for 70 bars ∆P at the CT head to pull the coiled tubing rather than push it.

A skate system developed by AMBAR ensures partial contact between the CT and the pipe wall tolimit friction.

After tests combining the crawler and skates, the maximum range for this technique has beenextended to about 8 – 10 kilometres.

Other crawlers are also available from WELLTEC, ASTEC and DACON.

Another means of improvement is to use composite coiled tubing. Here, the main advantages arereduced weight (1/4 to 1/3 the weight of steel CT) and mechanical resistance to fatigue. The FIBERSPAR Company offers this type of equipment (OD from ½ to 6’’).

Typical functional requirements for hydrate plug removal systems (HPRS):

1. Deploy in the production riser a means of circulating a chemical inhibitor (methanol)associated with a jetting effect. The hydrate plug has to be destroyed and dissociated byoverbalance in order to avoid cannonball effect.

2. Deploy in the production riser a depressurising means (gas or nitrogen lift) to re-startproduction without any risk –pressure & temperature) of a new hydrate plug.

3. Run-in and out without causing any damage to production equipment.

4. All parts of the HPRS have to be “fishable” in order to retrieve any loosen part.

A generic study on “Hydrate Removal in flowline & riser” has been generated by UGF R&D

project and is performed by Halliburton Deepwater, conclusions should be available beginning

2002. The aim of this study is first to establish the feasibility of hydrate removal in deepwater oilproduction lines (Risers & Flowlines) and then define the general specification to incorporate in thedevelopment design phase to facilitate hydrate removal interventions. Also the study will identify todaylimitation (technology gaps) and will propose development plan to achieve the goal. This study will becompleted by beginning 2002.

Hydrate plug removal guidelines:

This set of guidelines is an extension of recommendations listed in the Offshore Hydrate

Engineering Handbook (Sloan 1998).

1. Hydrate plugs are always dissociated, but the time scale is usually days to weeks. Deliberatechanges and patience are required. Hourly changes are ineffectual.


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2. Multiple hydrate plugs should always be assumed and treated as a safety hazard.

3. Many hydrate plugs are porous and transmit pressure easily while acting to obstruct flow. Someplugs are permeable to gas, but less so to condensate or black oil. This concept controls manyaspects of hydrate dissociation, including radial depressurisation, Joule-Thomson cooling throughthe plug, and the fact that depressurisation may cause the temperature downstream of the plug todecrease below the hydrate equilibrium temperature.

4. Methods are not well defined for locating hydrate plugs and determining their length. However,knowledge of the precise location and length of a plug would be a vital help in dissociation. Thecurrent model does not require a plug length, but this information is necessary to determine how thepipeline can be depressurised safely.

5. Attempts to "blow the plug out of the line" via high pressure upstream always result in a larger, more

compacted plug.

6. Depressurisation from both sides of hydrate plugs is the preferred method of removal, from bothsafety and technical viewpoints. This implies access points at both plug ends through dualproduction lines, service lines, etc.

7. If the pressure is decreased too much, the hydrate plug will rapidly form an ice plug which mayactually be easier to remove than the original hydrate plug.

8. In a deepwater line, a liquid head on a hydrate plug may be sufficient to prevent depressurisation.Liquid head removal is a current challenge to flow assurance.

9. In some cases, depressurisation from one side of the plug has been safely achieved.

10.Heating is not recommended for hydrate plugs without a means for relieving the excess gaspressure when hydrates dissociate.

11.Coiled tubing represents the primary mechanical means for dissociating hydrates.

12.Usually methanol or glycol is injected into plugged flow lines, but this is seldom effective due to thedifficulty of bringing the inhibitor into contact with the face of the plug. This method is most effectivewhen used in conjunction with depressurisation and the hydrate plug has had a chance to recedesufficiently from the pipe wall to allow the flow of inhibitor around the remaining plug.

13.Inhibitor injection and de-pressurising techniques are available for system shut-in and start-up – twopotentially hazardous periods as regards the formation of hydrate plugs.

14.Insulated pipelines can represent a serious hindrance to hydrate dissociation. Modelling indicatesthat the resistance to heat transfer through the pipe wall increases the hydrate dissociation time byseveral orders of magnitude. Care should be taken when designing an insulated pipeline.

e.g. A typical overall heat transfer resistance is about 1 BTU/hr/ft/°F (Sloan 1998)This heat transfer resistance corresponds to a Biot number of about 0.02The time it takes for the hydrate plug to completely dissociate is about 100 times greater.

At an ambient temperature of 4°C, the dimensionless dissociation time changes from 75, withno resistance to heat transfer, to 660 at a Biot number of 0.02.


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Deep Offshore

Flow Management

Organic Deposits


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The position and the speed of the wax deposits in the lines depend on the properties of the fluid, the

thermal conditions (wall temperature & gradient) and the flow rate. For Single-phase liquid systems,the mechanisms involved are almost fully explained .

They are less completely understood for multiphase systems.

In all cases, the ageing effect (change in consistency) and influence of internal pipe surface are never taken into account.

Deposition is a lengthy phenomenon. The speed of growth is generally slow and must be considered

as an equilibrium related to the steady flow. Deposition under short transient situations is never an

issue as the return to steady state conditions will eliminate its consequences.The proportion of waxes deposited and adhering to the walls is small in comparison with the waxesthat crystallise in the crude oil.

For there to be a deposit, the wall temperature needs to be lower than both the Wax Appearance

Temperature (WAT) and the flowing temperature.This is a requisite condition but is not sufficient insofar as some lines operated in this situation show nodeposits. The phenomenon has not yet been explained.

Three mechanisms can contribute to the transfer of waxes to the pipe wall:

♦ Molecular diffusion

♦ Turbulent diffusion of crystals (shear diffusion)

♦ Sedimentation.

On the other hand, turbulence in the flow regime produces shearing stresses likely to tear away thewax deposits.

As a first approximation, the rate of deposition in a pipe will depend mainly on molecular diffusion andthus be closely related to the thermal gradient on the wall.

In addition:

a low temperature gradient will lead to a hard deposit forming over a long period while,

a high gradient will lead to a rapidly accumulated soft deposit.

3.1.2 Data Required

Sampling

A representative sample of the fluids in reservoir conditions. It is important to make sure that the well iscleaned before sampling to avoid polluting samples with drilling mud.

For surface sampling (test separator), a drop in the temperature of the fluid can result in crystallisationand the formation of wax deposits in the separator. The fluid sampled at the outlet will be depleted of part of the waxes that have precipitated, and give rise to an erroneous WAT value and crystallisationcurve.

Sampling is the key to good prediction.

On the first Girassol well, samples from an MDT (modular drilling test) gave a WAT value of 25°C.Subsequently, the WAT values determined from surface samples taken during clean-up phasefluctuated over time from 29°C to 38°C.


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We concluded that both surface and downhole samples had been polluted by the drilling mud (oil

based).

Paraffin distribution

0

0.05

0.1

0.15

0.2

0.25

0.3

Carbon number

% W e i g h t

MDT sampling:

MDT samples can be polluted by oil-based mud. The extent of the pollution of the oil sample can beassessed from a sample of the mud itself.

As an example, the graph above shows the paraffin distribution obtained on a Dalia 5 MDT sample.We know that the Dalia crude contains no paraffin. The left part of the graph represents the paraffindistribution of the base oil used for the drilling. The right part represents the distribution of heavyparaffin, probably a deposit from previous drilling on a well where the crude contained a significantamount of paraffin. The WAT measured on the sample was 26°C instead of the usual 7-10°C value for the Dalia crude.

Surface samples are acceptable, providing the clean-up phase is sufficient to eliminate the mudpollution.

Analysis

In addition to "conventional" PVT analyses, the evaluation of the wax potential of a crude oil requiresadditional information:


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• detailed compositional analysis by Gas Chromatography (GC) up to C10+ or C20+ (about 300 crude

oil components are identified),

• distribution of n-alkanes (n-paraffins) from C15 to about C50 by HTGC (High Temperature GasChromatography).

The general appearance of the HTGC curve shown below allows a first evaluation of the risksrelated to crude oil.

A crude oil with a lot of "light" paraffins (< C30) is likely to give rise to rheological problems that cango as far as gelling in the shut-down phase.

A crude oil with few light paraffins but a significant number (more than 0.5% weight) of "heavy"paraffins (> C30) will be more likely to form deposits.

The distribution of) super heavy n-paraffins (up to C80) can, in most cases,be calculated by applying an exponentialcorrelation in order to reproduce thegeneral distribution trend given bymeasurements (see calculated curve onthe right). Sometimes the n-paraffindistributions do not exhibit anexponential decay with increasing

carbon number ( i.e. AKPO crude). Inthat case extrapolation is not possible.

n-Paraffin distribution

0

0,1

0,2

0,3

0,4

0,5

0,6

0,7

13 15 17 19 21 23 25 27 29 31 33 35 37carbon number

%

weight

%weight

calculatedfig 1fig

N paraffin wt %

• The measurement of the WAT, is currently under procedure of normalisation.

• WAT and the crystallised fraction are measured by Differential Scanning Calorimetry (DSC). Thesevalues are obtained in the laboratory on stock tank hydrocarbons. Results can be extrapolated toactual pressurised fluids with appropriate models (e.g. TU-WAX). The WAT measurements areinfluenced by the kinetic. Therefore, it is strongly recommended to determine the WAT using thelowest possible cooling rate. Other technique are available( Cross Polar Microscopy, Filtration…).WAT is determined with an accuracy of +/- 2°C.

• Viscosity versus temperature and shear rate curves

• Temperature profile of the production stream.


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An example of WAT evolution vs. pressure, asgiven by model, is shown (right). Note: WAT value is lowest at the bubble point.

WAX FORMATION EVOLUTION

0

20

40

60

80

100

120

140

160

180

32 34 36 38 40 42WAT °C

Bubble

Wax

No Wax

Pressure (Bar)

One useful measurement is the amount of wax precipitated as a function of temperature (see right).

This type of information is used in waxdeposition models to predict rates.

The measurement is performed by DSC,applying a specific, internally developedcorrelation.

SOLID WAX CONTENT AS A FUNCTION OF TEMPERATURE

-2

0

2

4

68

10

12

14

16

18

-25 -5 15 35 55 75 95 115 135

Temperature °F

Solid Wax Fraction %wt

Waxy

Light

3.1.3 Methodology

Based on the previous data recovered, evaluation of the wax deposition risk generally involves twosteps:

1. Use of a thermodynamic model to determine the WAT and the crystallised fraction inrelation to temperature. The model is generally based on a measurement at atmosphericpressure and allows the prediction to be extended to all pressures and compositions.However, the validation of input and output data is still a developing science. It is thereforerecommended to seek expert advice.

2. Use of a kinetic model to evaluate the thickness and location of the deposit in the pipelines(cold wall deposits) versus time. It has to be stressed that this type of model is moreproviding a trend of profile and magnitude of the problem.


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Models

Most market models are based on the assumption that the deposit builds up by molecular diffusion.

The software used in studies is:

• An integrated (thermodynamic + thermal + multiphase flow + deposition kinetics) model, TU-WAX, developed within the framework of a JIP by the University of TULSA. This is a two-phase oiland gas model and does not take the water phase (assimilated to oil) into account. From a givencomposition, it will determine:

1 the phase envelope, to be tuned on PVT data,

2 the change in viscosity vs. temperature, to be tuned with laboratory measurements,

3 WAT, to be tuned on the value given by DSC,

4 After validation / calibration of the 3 measurements, the thickness of the depositversus time along the production line.

Kinetic models only concern cold wall deposits.

Sedimentation occurring in stock tanks is considered to be systematic when the crude oil is stored at atemperature lower than its WAT. This assumption is likely to be extremely conservative.

Theory on wax deposition

The equation representing the Molecular diffusion is shown below:

dy

dT

dT

dF

dt

dQc

υ

λ = where:

– dQ/dt represents the deposit kinetics – λλλλ diffusion coefficient – µ crude oil viscosity – Fc the crystallised fraction – T temperature – dy boundary layer limit


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Validations performed show that for a

single-phase fluid, molecular diffusionis actually the driving force behinddeposits.

The mechanism for deposition on thewall can be compared with the formationof condensation on a glass panel, whichonly settles when there is a thermalgradient.

PI

PE

AL

L

Velocity profile

Turbulent core

Laminar

Boundary

Layer

Heat Loss

Dissolved wax

Rippling only plays a preponderant role when shearing is significant, that is generally the case whenthe pipeline is close to plugging. TU-WAX makes allowance for this effect with a “shear factor”. But itshould be noted that the shear influence has never been validated by experimental data.

The practical consequences of these assumptions are as follows:

Wax deposition only occurs when wall temperature is below WAT,

Deposition will not occur if the external temperature is greater than or equal to the crude oil

temperature,

If the wall temperature is close to that of the crude oil, the kinetics for deposits will berelatively insignificant (case of an insulated pipe),

Plugging is theoretically impossible with a pipe in continuous operation (because of the

increase of the shear effect). Any plugging usually arises from transient operation (pigging,

significant change in flow conditions, change in temperature, etc.).


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An example of a simulation result isgiven (see on right):

These curves show that waxdeposits mainly accumulate alongthe first kilometres owing to the fact

that the temperature of the wall isless than the WAT.

At a given point, provided thefluid temperature remainsbelow the WAT, the molecular distribution of the waxesdeposited will depend on thetemperature of the pipe-wall(see diagram on right).

Carbon Number

10°C

Distribution of Carbon Number in Wax deposit at

different pipewall temperatures

20°C30°C

0

0,5

1

1,5

3530 40

The higher the temperature (but < WAT), the greater the molecular weight of the deposit will be. SinceParaffin deposits as a solid solution, the composition of the deposit at high temperature will be differentfrom that for deposits generated at temperatures close to ambient temperature.

% weight

0

2

4

6

8

10

12

0 5000 10000 15000 20000 25000 30000 35000

Distance fromwells (m)

T h i c k n e s s ( m m )

6 hours1 day2 days3 days4 days5 days6 days7 days

Inlet T°C=25°C

Inlet T°C=54°C


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Shearing effects due to flow turbulence will also be preponderant in the formation of deposits. The

mechanical forces generated by flow act on the pipe wall and affect the quantity of waxes that adhereand remain in the deposit layer. Under a turbulent regime, the most "tenacious" waxes will adhere toform a hard deposit.

However it is highly important to note, for practical operation, that commercial software does

not provide any information on the quality of wax deposits.

Finally, the flowrate influences the thermal gradient and the shear effect. The general trend can berepresented as below:

Flow/ Shear Rate

Deposition rate

Laminar

Turbulent

Effect of flowrate on Deposition rate


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3.1.4 Solutions

Wax is generally assumed to be easily prevented or removed by a combination of thermal andmechanical solutions.

As pointed out above, the driving factor in wax deposition is pipe wall temperature, and its kinetics aremainly dependent on existing gradient and shear effect.

Prevention

2 types of action can be implemented to prevent wax deposits on cold walls:

♦ chemical

♦ thermal.

Chemical solutionsChemical additives act by limiting the agglomeration and growth of crystals (dispersing effect). Theyare never completely effective and are mostly used to assist mechanical removal (pigging or scraping).

Their cost is not to be underestimated, due to the high concentrations that have to be injected.

Another chemical means worthy of mention is film-forming additives (Anticor, CECA), which work onprinciples similar to those of a corrosion inhibitor, forming a film on the pipe wall deterring the waxcrystals from adhering to it. This type of product is currently being evaluated. Suppliers claim near toabsolute efficiency but this remains to be proved.

Today, due to the limited efficiency of present additives, chemical treatment cannot be envisaged assole prevention method. Chemical means are mainly injected in order to decrease the curativetreatment frequency.

Thermal solutionsSimple (passive) or more complex thermal insulation is used to maintain temperature above the WAT.

There are a variety of thermal insulation solutions, like bundles, pipe in pipe, pipe coated with insulatingfoam, etc.

Monitoring

In-situ monitoring of wax deposits has so far not been industrially proved. However, differentparameters can be monitored and analysed to deduce how the deposit will evolve:

♦ pressure losses in the different sections, from monitoring of discrete pressure measurements(well head, manifold, riser and top side arrival). ). It has to be highlighted that pressure lossescould be mainly affected by the increase in roughness which will dominate the frictionalpressures long before any consequent reduction in pipe diameter.

♦ temperature along the line, which can be measured using an optical fibre in contact with thepipe wall

♦ spot measurements of thermal flux through the pipeline (under development).


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Curative treatment

1- Thermal

To melt deposits, rapid cleaning of the lines with heat is not realistic because it requires much higher temperatures (generally around 70°C) than the WAT.

However, heating the wall to a temperature slightly higher than the WAT can change the structure of the edges of the deposit, rendering it more prone to tear-off by turbulence. This solution is beingevaluated within the framework of a JIP aimed at qualifying a PIP insulation system, equipped with anelectrical heating device.

2- Mechanical

Pigging has two functions:

mechanical destruction and elimination of wax and any other deposits that have settled in the lowpoints (i.e. corrosion products)

separation of fluids for hydrate preservation procedures applied with respect to hydrates bycirculation of stock-tank oil.

Pigging frequency can be determined from simulation results and data acquired during piggingoperations (delta P, quantity recovered at the pig receiver, number and length of productionshutdowns, etc.).

Intervention No.

Costs Optimisation of operating costs

Optimal

0 3 9 126

Plugging Risks

Cost of lost production dueto reduced productivity

Cost of Intervention incl.lost production

One absolute requisite for Deep Offshore pigging is control over the speed and position of the pipeline

scraper in the lines. Cleaning may be improved by the jet effect (Spider nose type bypass system), bycontrol over the pig speed (Vmin. 1.3 to 1.5 m/s) and by the choice of a suitable design (two-way,detectable and destructible).


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Two configurations can be considered in this context:

♦ Loop arrangement, with both departure and arrival trap located on topsides and two productionlines connected together to form a loop. During the pigging phase, one of the two branchesproduces in rever

flow assurance guide

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