Handbook of Multiphase Flow Assurance

By Taras Y. Makogon

Handbook of Multiphase Flow Assurance allows readers to progress in their understanding of basic phenomena and complex operating challenges. The book starts with the fundamentals, but then goes on to discuss phase behavior, fluid sampling, fluid flow properties and fluid characterization. It also covers flow assurance impedance, deliverability, stability and integrity issues, as well as hydraulic, thermal and risk analysis. The inclusion of case studies and references helps provide an industrial focus and practical application that makes the book a novel resource for flow assurance management and an introductory reference for engineers just entering the field of flow assurance.

• Starts with flow assurance fundamentals, but also includes more complex operating challenges
• Brings together cross-disciplinary discussions and solutions of flow assurance in a single text
• Offers case studies and reference guidelines for practical applications

• Language: English
• Publisher: Elsevier Science
• Release date: Jun 4, 2019
• ISBN: 9780128130636

Taras Y. Makogon

Taras Makogon is currently a Principal Flow Assurance Consultant with the Wood Group. He is a technical contributor and manager with over twenty years in upstream petroleum industry and technology primarily in flow assurance and production chemistry in Deepwater, onshore and unconventional shale. He has strong project management, international operations, and commercial delivery of results and patents in process optimization, multiphase flow and molecular modeling chemical design to control solids crystallization and deposition in conduits. He has a Doctorate in Chemical Engineering and Petroleum Refining from the Colorado School of Mines, U.S.A., and an MBA in Finance from the Houston Baptist University.

Book preview

Handbook of Multiphase Flow Assurance

First Edition

Taras Y. Makogon

Table of Contents

Cover image

Title page

Copyright

Dedication

Preface

Chapter 1: Introduction

Abstract

Multiphase production problems: Blockages and restrictions

Savings from using flow assurance

Examples of flow assurance problems

How flow assurance and production chemistry work together

When is flow assurance applied

Knowledge required in flow assurance

Why flow assurance failures happen

Flow assurance background

Flow assurance requirements

Introduction to flow assurance risk analysis

Hardware cost

Monitoring and data mining

Flow assurance in operations

Systematic approach to solving flow assurance problems

Process safety

System of measures for flow assurance

Outlook for flow assurance

Chapter 2: Initial diagnosis and solution of flow assurance production problems in operations

Abstract

Field or laboratory tests for initial solid samples identification

Typical blockage remediation plan

Chapter 3: PVT and rheology investigation

Abstract

Phase behavior

Fluid sampling

Quality of fluid samples

Drilling and wellwork fluids formulation and safety

Fluid characterization

Fluid physical properties

Non-Newtonian behavior

Emulsion characteristics

Biodegradation

Chapter 4: Hydraulic and thermal analysis

Abstract

Introduction

Hydraulic restrictions boundaries and management

Hydrodynamics of multiphase flow

Thermal effects

Flow modeling

Operation online monitoring for pipeline

Operation online monitoring for well liquids loading and forming blockages/restrictions

Design of oil/gas development project

Machine learning and artificial intelligence in flow network optimization

Chapter 5: Flow restrictions and blockages in operations

Frequency of blockages

Frequency of blockage remediations

Blockage remediation

Hydrate of natural gas

Asphaltenes

Bacterial growth

Corrosion products

Diamondoids

Ice

Liquid holdup

Multiphase flow

Sand transport

Paraffin wax

Reservoir souring

Scale

Interaction of flow assurance issues with and effects on produced fluids and flow

Seven suggestions from operations in deepwater and onshore

Chapter 6: Production chemistry and fluid quality

Abstract

Sampling fluids

Quality: 4Cs of production chemicals

Laboratory verification of chemical performance

Chemical injection systems

Comparative economics of production chemicals

Product fluid quality

Emulsions, foam, topsides separation, water treatment management

Naphthenate management

Heavy oil management

Viscous oil management

Mercury management

Sulfur deposition

DRA

Chemical characteristics

Chemical tubing blockage

Dosage selection and optimization

Chemical data

Chapter 7: Flow assurance deliverability issues

Abstract

Flowline design process

Optimization of flowline sizes

Artificial lifting

Topsides equipment and arrival pressures

Cold flow and emulsion

Chapter 8: Flow assurance stability issues

Abstract

Severe slugging

Transient operation

Slugging in gathering lines

Calculation of slug impact force on Tees and Elbows

Calculation of pressure surge on sudden flow shut-in

Vacuum condition in flow

Chapter 9: Flow assurance integrity issues

Abstract

Corrosion

Erosion

Chapter 10: Research methods in flow assurance

Abstract

Hydrate stability and crystal growth

Molecular modeling

Experimental and computer study of the effect of kinetic inhibitors on clathrate hydrates

Experimental study of hydrate crystal growth

Computer modeling of interaction between a hydrate surface and an inhibitor

Flow loop tests

Bench scale tests

Computer code (Makogon, 1994, 1997)

Chapter 11: Toolkit

Abstract

Free modeling tool for hydrate stability calculation

Free modeling tool for chemical injection distribution system

Free modeling tool for single phase fluid flow use for water injection system

Free modeling tool for scale stability

Free hydrate plug remediation software

Free LNG cryogenic heat exchangers solids deposition

Free gas, gas condensate and LNG thermodynamic property calculator

Chapter 12: Flow assurance modeling

Abstract

Chapter 13: Risk analysis

Abstract

Introduction

Project cost optimization CapEx vs OpEx

Historic frequency of blockages based on remediation

Modeling dynamic behavior

Integration of various precipitation phenomena

Impact on overall planning

Chapter 14: Case studies/reference material

Abstract

PVT gas properties

Abbreviations and definitions

Regulatory requirements and environmental law which may affect flow assurance

Pipe roughness

Sample requirements

Advanced flow assurance fluid properties

Flow correlations

Monitoring and instrumentation for flow assurance

Units and conversions

Standard temperature and pressure

Index

Copyright

Gulf Professional Publishing is an imprint of Elsevier

50 Hampshire Street, 5th Floor, Cambridge, MA 02139, United States

The Boulevard, Langford Lane, Kidlington, Oxford, OX5 1GB, United Kingdom

© 2019 Elsevier Inc. All rights reserved.

No part of this publication may be reproduced or transmitted in any form or by any means, electronic or mechanical, including photocopying, recording, or any information storage and retrieval system, without permission in writing from the publisher. Details on how to seek permission, further information about the Publisher’s permissions policies and our arrangements with organizations such as the Copyright Clearance Center and the Copyright Licensing Agency, can be found at our website: www.elsevier.com/permissions.

This book and the individual contributions contained in it are protected under copyright by the Publisher (other than as may be noted herein).

Notices

Knowledge and best practice in this field are constantly changing. As new research and experience broaden our understanding, changes in research methods, professional practices, or medical treatment may become necessary.

Practitioners and researchers must always rely on their own experience and knowledge in evaluating and using any information, methods, compounds, or experiments described herein. In using such information or methods they should be mindful of their own safety and the safety of others, including parties for whom they have a professional responsibility.

To the fullest extent of the law, neither the Publisher nor the authors, contributors, or editors, assume any liability for any injury and/or damage to persons or property as a matter of products liability, negligence or otherwise, or from any use or operation of any methods, products, instructions, or ideas contained in the material herein.

Library of Congress Cataloging-in-Publication Data

A catalog record for this book is available from the Library of Congress

British Library Cataloguing-in-Publication Data

A catalogue record for this book is available from the British Library

ISBN: 978-0-12-813062-9

For information on all Gulf Professional publications visit our website at https://www.elsevier.com/books-and-journals

Publisher: Brian Romer

Senior Acquisition Editor: Katie Hammon

Editorial Project Manager: Joshua Mearns

Production Project Manager: Anitha Sivaraj

Cover Designer: Christian J. Bilbow

Typeset by SPi Global, India

Dedication

To my teachers Prof. Yuri F. Makogon, Yakov F. Lerner, Prof. E. Dendy Sloan, and Prof. M. Sami Selim.

Preface

This handbook is a compilation of reference materials and experiences related to flow assurance collected over the years. This handbook may help the production operator identify and solve issues faster and also help a project development engineer design the most critical flow assurance issues out of the system more cost-effectively. The intent of this book is to deliver safe, reliable and economic design and operation of multiphase production systems with flow assurance threats. Flow assurance is used in onshore, offshore and subsurface flow of petroleum fluids. This diversity of application of flow assurance control methods motivated the development of this handbook.

Chapter 1

Introduction

Abstract

Flow assurance aims to make sure oil and gas keep flowing. To achieve that goal, flow assurance relies on the analysis of multiphase flow and on the selection and use of production chemicals. Flow assurance engineers commonly analyze the flow of oil and gas in wells, production flowlines, process facilities and export pipelines. Complex networks of gathering lines feeding into trunk flowlines exist in onshore and offshore fields, and the analysis to optimize flow routing through such networks is equally complex.

Keywords

Multiphase; Flow assurance; Risk analysis; Process safety; Product value; Production

Outline

Multiphase production problems: Blockages and restrictions

Savings from using flow assurance

Examples of flow assurance problems

How flow assurance and production chemistry work together

When is flow assurance applied

Knowledge required in flow assurance

Why flow assurance failures happen

Flow assurance background

Flow assurance requirements

Basis of design

Units for fluid characterization

Introduction to flow assurance risk analysis

Threats to flow are normally attributed to flow assurance

Threats to product value or process safety (asset integrity)

Hardware cost

Cost of subsea hardware related to flow assurance

Monitoring and data mining

Flow assurance in operations

Onshore production

Offshore production

Deepwater production

Systematic approach to solving flow assurance problems

Process safety

System of measures for flow assurance

Outlook for flow assurance

References

Flow assurance aims to make sure oil and gas keep flowing. To achieve that goal, flow assurance relies on the analysis of multiphase flow and on the selection and use of production chemicals. Flow assurance engineers commonly analyze the flow of oil and gas in wells, production flowlines, process facilities and export pipelines. Complex networks of gathering lines feeding into trunk flowlines exist in onshore and offshore fields, and the analysis to optimize flow routing through such networks is equally complex.

Definitions of flow assurance are numerous, including this one: Flow Assurance is the analysis of thermal, hydraulic and fluid-related threats to flow and product quality and their mitigation using equipment, chemicals and procedure.

Multiphase production problems: Blockages and restrictions

Oil and gas are currently produced through wells and pipelines. The lack of flow in wells and pipelines may be due to low reservoir pressure or productivity, due to complete blockages or due to partial restrictions.

Flow restrictions may happen in a reservoir, in a well production tubing or a tree, in a jumper between a well and a flowline, in a flowline, in a riser or in an export pipeline. In some cases, restrictions may happen in several locations simultaneously. The largest number I have seen is five blockages in the same production flowline at the same time. Restrictions may also occur in water and gas injection systems as in wells, flowlines or reservoirs.

Restrictions may be hydraulic, such as liquid accumulation also known as a holdup in flowlines and risers, liquid loading in wells, or mechanical such as a partly closed valve or a scraper. Restrictions or blockages may also be solid, including organic (e.g., paraffin wax), inorganic (scale) or particulate (sand). The hydraulic, mechanical or solid restrictions may be stationary such as the liquid holdup or moving such as the slugging. A flow assurance practitioner should be able to recognize the signs of and potential for any type of restriction and either economically design it out of a new system or mitigate it in an existing system.

In some cases, restrictions may lead to other restrictions. There is an early 2000s example from West Africa offshore production where a wax deposit in a flowline got scraped by a formed hydrate plug into a solid paraffin wax blockage. Similarly, combined hydrate-paraffin restrictions have also formed in the North Sea in the early 1990s and asphaltene-hydrate in the Gulf of Mexico in the 2010s. Paraffin-asphaltene-sand restrictions have been common in Siberian pipelines through the decades.

Modeling of multiphase flow can be done to find optimal conditions for a stable production of gas and hydrocarbon liquids with water. When the gas flow rate is not high enough to sweep the liquid hydrocarbons and liquid water from a well or a pipeline, these liquids accumulate in low spots because of gravity.

The liquids can accumulate either downhole in a vertical well or at a heel or a toe, whichever is lower, in a horizontal well which is known as liquid loading. Both deepwater and shale horizontal wells are susceptible to liquid loading.

Severe slugging is one of the issues in multiphase flow also related to gravity. Liquids can accumulate at a subsea riser base and then get periodically produced to a topsides separator after a sufficient gas pressure has built up behind the accumulated liquids as a large sudden gush of liquid preceded by a period of no or limited flow, which is known as severe slugging. Wells keep producing during severe slugging at a steady rate, but backpressure on wells may change noticeably between slug accumulation and displacement. Severe slugs keep repeating, and slug size and momentum are substantial as to cause vibration at pipe bends in flow geometry, overfill the process vessel or both.

Liquids also can accumulate in the low spots of a near-horizontal pipeline and get periodically displaced by a steady flow of gas, which leads to terrain slugging. Terrain slugs keep repeating and are usually smaller in size and don't overfill the process vessel but may cause vibration at pipe bends. Hydrodynamic slugging occurs as liquids holdup is displaced by an increasing flow of gas from a flowline in form of a liquid surge. If the surge volume is significant, the hydrodynamic slugs can be as detrimental as severe slugs. Hydrodynamic slugs occur once per a change in production rate and don't repeat.

In all three cases of liquid loading, severe slugging and terrain slugging gravity plays the key role in overcoming the energy emerging from the expanding gas or a single phase or supercritical fluid (also known as the dense phase) or an aquifer which is less than sufficient to lift the liquids to the separator or a slugcatcher.

Analysis of multiphase fluid flow is in part based on information from reservoir modeling prediction of flow rates and on thermodynamic PVT characterization of produced fluids. Software which tracks and balances masses and velocities of produced fluids is available to help predict and analyze the flow velocities and the quantities of accumulation (also known as holdups) of liquid and other phases in the production system. An accurate prediction allows the design engineer to select proper sizes for the well production tubing and for gathering flow lines, and also to identify which technologies would be necessary and most economically suited to produce gas and oil from a reservoir.

Savings from using flow assurance

Flow, which may be single phase (natural gas, oil, water, CO2) or multiphase (two or more single phases) is the key metric of the main product of petroleum companies. Those companies which have more barrels of flowing product per employee generally do well, and vice versa.

Flow assurance is becoming a critical path discipline when other disciplines such as pipeline engineering, subsea layout, artificial lift equipment, and, in some projects, reservoir engineering, wait for flow assurance to compare and validate the viability of an overall architecture for a concept of field development before proceeding with the design. The accuracy in flow assurance makes a project more, less or not at all profitable. This handbook helps organize and streamline the work in flow assurance, in order to make it more accurate.

The use of flow assurance technology saved billions of dollars for oil companies. There are several examples of how multiphase flow tools have resulted in savings for Statoil, Shell, BP, ENI:

•Multiphase technology & OLGA—Norske Shell—Troll—30 Billion NOK

The flow assurance savings for the Norske Shell—Troll field from multiphase technology and the use of an early version of the OLGA software were 30B NOK which is billions of dollars.

Direct electric heating has saved us billions of kroner on the Norwegian shelf, said Atle Harald Børnes, who is a specialist at Statoil's Technology and New Energy Business Area.

This system has been installed during the laying of pipelines linked to the Åsgard, Huldra, Kristin, Urd, Tyrihans, Alve and Morvin fields. A version of this heating system has also been prepared as a contingency measure for installation on the pipeline leading from the Ormen Lange field to Aukra.

The heating system was also installed at the BP-operated Skarv field, which has been put on stream after 2011.

The Italian company ENI has also opted to utilize the same system for its Goliat field development offshore Finnmark (Nilsson et al., 2010).

•Hydrates and electrical heating—Statoil, BP—N.Sea—Billions of NOK

Construction initiative of the multiphase flow loop at Tiller near Trondheim, Norway was pioneered by Esso Norge looking to evaluate the stability of multiphase oil and gas production from offshore reservoirs, and supported by this and other companies. The cost to construct this flow loop was over 26 million in 1980 US dollars. The choice of location was economically justified because the Norwegian sector of the North Sea showed promising acreage and because the Norwegian law allowed some research cost to be deducted from taxable revenue. Numerous sets of data were collected from this test facility which, to this day, are used to validate multiphase software (Caspersen et al., 2011).

The Tiller multiphase flow loop shown in Fig. 1.1 is perhaps the one most important facility used for development of data sets for validation of several multiphase flow models.

Fig. 1.1 Tiller flow loop and tower for multiphase flow research.

Flow assurance technology development also has its roots in PROCAP 1000, a technology program executed by Petrobras from 1986 to 1991, comprised 109 multidisciplinary projects. The cost of the program was 68 million USD. The projects developed under PROCAP 1000 gave rise to a significant part of the 251 patents obtained by Petrobras between 1987 and 1992. It also allowed access to subsea oil fields in water deeper than 300 m which could not be accessed through diving, and the development of deepwater assets to a water depth of 1000 m, which led to capital investment in fields such as Marlim and Albacora and multi-billion profits from Petrobras' deepwater projects (Morais, 2013).

Examples of flow assurance problems

Solids such as hydrates shown in Fig. 1.2–1.4, wax or scale can form blockages and restrict production. These solids can also affect mechanical integrity of a production system in multiple ways, such as erosion, rupture or collapse of pipelines. For example, hydrates can move as projectiles. In a few instances offshore, a partly dissociated hydrate plug got launched from a platform scraper receiver by gas pressurized behind the hydrate.

Fig. 1.2 Hydrate slush in a flowline after hydrate blockage was dissociated by depressurization in an onshore Teapot Dome oil field.

Fig. 1.3 Hydrate slush accumulated and compacted in service platform scraper receiver during flowline depressurization offshore Brazil, ca 1992.

Fig. 1.4 Hydrate extracted from service platform scraper receiver after subsea line depressurization. The compacted hydrate remained solid and did not break upon falling from the scraper receiver.

Ice blockages also can present a problem. In an onshore operation in Alaska, an ice blockage formed in the smaller of the two flowlines operating in parallel due to differences in flow distribution. Freezing caused a 24-in. long rupture as shown in Fig. 1.5 at the bottom of a three-phase common line carrying a mixture of crude oil, produced water, and natural gas.

Fig. 1.5 Thermal image of Alaska hydrocarbon loss of containment caused by ice blockage ( Alaska, 2010).

Corrosion caused a similar event in 2007 with imagery available at Alaska (2008). A 6-in. long crack (about 1/8 in. wide at the center) formed in the flow line due to external corrosion.

Hydrates can also crush or collapse steel tubing such as a well production tubing as shown in Fig. 1.6 in locations where water and gas accumulate at hydrate conditions in the same way ice can crack an engine block if water is used as a coolant instead of an antifreeze.

Fig. 1.6 Well tubing collapsed by hydrate formation in a shut-in well annulus between tubing and casing. Onshore Siberia, 1965. T = 8°C, P collapse >800 atm, Tubing wall thickness 6 mm, inside diameter 63 mm. Photo by Yuri F. Makogon.

A paraffin wax deposit can form when heavy hydrocarbon molecules with straight chains of carbon atoms, also known as normal paraffins, precipitate on cold surfaces and accumulate, which restricts normal production. In some cases, condensates produced with free gas from deposits may contain heavier hydrocarbon molecules so wax can deposit from condensate during gas production as well as during oil production. In subsea practice, one solid may lead to another.

In the analysis of wax deposition, one should distinguish such fluid characteristics as wax appearance temperature (WAT) when the first visible or detectable solid wax crystal precipitate, and wax dissolution temperature (WDT) when the precipitated wax crystals completely redissolve in the volume of oil from which they crystallized. There is also another term which is important for wax management design: the wax deposit melting temperature (WDMT). The WDMT occurs at a temperature when a wax deposit accumulated over time in a field flowline melts without added oil or solvent. WDT is typically 10–20 °C higher than WAT, whereas WDMT can be 30–40 °C higher than WAT, depending on how long the wax had to age in the field flowline and how much of the heavy fractions it had concentrated.

Crystals of normal paraffin wax, as well as many other crystals, can rotate the plane of light linear polarization and shine. This phenomenon is used in cross-polarized microscopy (CPM) to determine WAT. Networks of waxy crystals called gels, which also shine in a cross-polarized microscope, are therefore composed of wax crystals, not of amorphous non-crystalline material. The term gel is used in relation to wax to signify that the whole bulk of oil converts to a non-flowing material when its temperature drops below pour point and a waxy gel is formed. However, the waxy gel material is not uniform and contains both solid wax and liquid oil trapped between solids. One should recognize when discussing incipient, or initial, wax deposition on a pipe wall that it is wax crystals made up of concentrated normal paraffins or isomerized saturated alkanes that deposit, not a gel which has the same composition as base oil.

A combined hydrate and wax blockage formed in the North Sea in the past in the Staffa field led to costly remediation by depressurization to melt the hydrate. After the first blockage got removed, the second blockage formed, which led to an abandonment of the subsea flowline.

In another case offshore West Africa, an incompletely dissociated hydrate plug started to move in a pipeline and acted as a scraper, compacting the existing paraffin wax deposit into a solid blockage, which could no longer be melted simply by depressurization, and led to a lengthy process of solvent injection past the low-permeability paraffin plug which eventually got removed.

Scale can form as shown in Figs. 1.7 and 1.8 when reservoir water, which may exist near the oil or gas deposit, has some minerals dissolved in it. At reservoir conditions, the formation water is usually partly saturated with salt, or in some cases may be near the equilibrium saturation. As water flows from the reservoir with the produced gas or oil, its pressure and temperature change, which affects the solubility of dissolved ions in water. Saturation limit for some ions may also be reached because water composition changes if the water table rises to the produced zone from another zone. Similarly, waters saturated with different ions from different zones mix, some ions combine and solid scale may form and restrict the pores in reservoir rock or in well tubing, thus limiting the productivity.

Fig. 1.7 Scale buildup inside a heat exchanger tube ( Lebedev, 2010).

Fig. 1.8 Solid salt scale plug in an Orenburg gas-condensate well, 100 mm diameter. Photo by Yuri F. Makogon, Originally published by PennWell Corporation in Hydrates of Hydrocarbons, 1997 and reprinted with permission.

Saturation limit for salt ions in water may also be reached because water molecules get consumed to form a hydrate leading to a concentrated brine, or because of the change of pressure or temperature.

Hydrate formation can also lead to precipitation of solid salt scale in small-volume closed systems (Hu et al. 2017a,b, 2018)

Petroleum industry access to ultra deep reservoirs often has to deal with high-pressure and high-salinity fluids. Reservoirs with fluid pressure over 180 MPa are in appraisal and development. Fluids in the reservoir may also be nearly saturated with salt in pre-salt deposits located under salt domes and diapirs. This combination of high pressure and high salinity of such fluids presents a unique set of challenges for wellwork and production engineers because in order to complete a well or to produce such fluids, formation of solid phases must be avoided. Solid phases may include gas hydrates or scales such as halite. During well completion, heavy brines are used to offset by their hydrostatic pressure the high pressure of reservoir fluids in order to avoid a well blowout. At the same time, completion brines must remain hydrate-free at mudline (seabed) conditions in case light hydrocarbon gases migrate from the bottom of the well up the wellbore to the location where well completion fluid is exposed to cold (approx. 277K) seawater if a well is drilled in offshore environment. Thus, accurate prediction of hydrate equilibria in high salinity brines is important. Similarly, during production of reservoir fluids through a completed well, hydrates must still be avoided, lest the well gets plugged with solids. If a chemical, such as pure methanol or a low dosage hydrate inhibitor formulated in methanol, is used to control hydrate formation, this may cause a salting out effect as scale forms due to colligative properties of water and inability to dissolve both salt and methanol simultaneously beyond the solubility limit. This has led to past incidents such as blockage of a North Sea production line with halite scale [ca.2009]. The ability to account for high salinity brines with respect to high pressure hydrate equilibria and scale formation is also important during production.

Usually, stability of brines decreases with decreasing temperature. This may lead to precipitation and deposition of solid scale such as halite or barium sulfate. In case of carbonate scales, brine stability decreases with increasing temperature, leading, for example to a calcium carbonate scale in hot systems.

How flow assurance and production chemistry work together

Multiphase flow assurance is complemented by production chemistry whose aim is to prevent the reduction of product value and process safety such as water in oil, oil in water, salt in oil, oxygen in water, mercury in fluids, H2S in gas, corrosivity, and/or bacteria. Sour crude is less valuable than sweet, so souring of crude oil in reservoirs may be prevented by using chemistry. Similarly, it is the goal of production chemistry to maintain specified quality of product oil and produced water so they are fit for export to refinery, reinjection into a well or discharge overboard. The chemicals are selected and deployed by chemists in multiple locations including reservoir, wellbore, flowlines, process facilities and export pipelines to help produce oil and gas most economically.

The flow assurance and production chemistry work side by side to achieve related goals, and sometimes that work may be performed by the same person if that person has sufficient experience in both disciplines.

The combined scope of some of the flow assurance and production chemistry items is shown below in Table 1.1:

Table 1.1

Distribution of items varies by operator company.

Many of the items from the above table get summarized in a Basis of Design document for flow assurance work.

The allocation between flow assurance and production chemistry is only suggested depending on whether the issue is more flow-transformation or fluid-transformation related, and may vary from project to project. For example, foaming may be caused either by a fluid containing high amounts of natural surfactant or by high shear of flow through a choke or orifice. Foaming may be prevented by the use of production chemistry to improve separation of oil and gas or it may be sought by flow assurance to help lift fluids from a well with multiphase flow. Both flow assurance and production chemistry specialists should be experienced in all of the above items.

An operator company which neglects or misses to check and quantify any one of these items at the project design stage carries a risk of increased cost or abandonment during operation.

Some companies maintain internal boundaries between flow assurance and production chemistry disciplines, while others combine the two along with materials and corrosion issues, depending on the company size and the depth of available engineering resources.

The American Petroleum Institute have clearly listed nine flow assurance issues as follows:

–hydrate formation,

–wax formation,

–asphaltene formation,

–emulsions,

–foaming,

–scale formation,

–sand production,

–slugging,

–materials-related issues.

The API 17 TR4 list above captures most of the scope and is fairly comprehensive for a typical oil or gas field development.

Flow assurance prevention methods are usually thermal (insulation or a cooling spool) or chemical (inhibitors) whereas mitigation can be mechanical (pumps), chemical (solvents) or thermal (active heating).

Production chemistry prevention is usually chemical (surfactants or inhibitors) or mechanical (segregation of incompatible fluid streams). Mitigation is chemical (chelants, dispersants, dissolvers) or mechanical (milling). Chemical injection dosages are, on average, 100 ppm with typical range of 50–250 ppm, and can be much higher for hydrate inhibitors ranging from 10,000 to 500,000 ppm or much lower at 5–10 ppm for emulsion breakers and corrosion inhibitors.

In some sub-cases such as under-treated severe bacterial accumulation or foaming, flow also gets affected.

Main focus of production chemistry is on product value including: oil quality (water content), water quality (organics content and total dissolved solids, oxygen content, souring and corrosion potential).

Chemicals may be deployed in a variety of locations. Typical ranges of chemical dosages are needed to design a chemical delivery system. Such ranges are shown below in Table 1.2.

Table 1.2

When is flow assurance applied

Flow assurance is commonly applied in project design and/or in operations support. At the project design stage, the engineering talent evaluate several ways of combining different technologies which would allow to extract oil and gas from the reservoir both reliably and economically.

Examples of such technologies range from simple methods, such as passive insulation to keep produced fluids as close to the reservoir temperature as possible, to the complex ones, such as subsea processing equipment to separate and pump fluids to their destinations.

Flow assurance is also applied in operations to optimize the economics of production by tuning the performance of artificial lift, optimizing the routing of the produced fluids through the flowline network, and by solving the problems of restrictions and blockages or surges in reservoirs, wells, flowlines, processing equipment and in export pipelines using a variety of methods.

The tasks for flow assurance and production chemistry in project development design are listed earlier in How flow assurance and production chemistry work together.

Tasks for flow assurance support in operations:

•Production system monitoring for flow assurance model tuning with system data

•System flow assurance condition surveillance for blockages.

•Maintenance implementation.

•Well Start-up temperature insulation performance measurement.

•Chemical Injection residuals' and performance monitoring.

•Shut-in cooldown temperature insulation performance measurement.

•Operator training program implementation and updates.

•Operating procedures updates and verification.

•Verification of chemicals performance.

•Chemicals incompatibility with materials management.

•Chemicals substitution and field trials.

•Verification of chemical vendor performance.

Knowledge required in flow assurance

It is not sufficient to just analyze the flow of fluids, but one must also recognize and predict the temperature and phase transitions as vapor, liquid and solid phases appear at different temperatures and pressures. Therefore, a flow assurance engineer must first be prepared in measuring and calculating fluid properties and phase equilibria, which is commonly taught in chemical engineering, heat transfer, which is taught in mechanical engineering, or chemical engineering, and oilfield process equipment operation which is taught in petroleum engineering, as well as a range of other disciplines such as materials science, biochemistry, chemistry.

It is not possible to get trained in all these specialties at once, so a flow assurance knowledge is acquired over time. Flow assurance is a relatively young discipline and only a few universities recently started to teach flow assurance.

It is not enough to be skillful in setting up a multiphase flow model, but it is important to understand what can happen to the fluids as they flow from the reservoir to the refinery. Equally, it is not sufficient to know how to set up a scale or asphaltene precipitation model, but necessary to understand the underlying lab work and what eventualities may lead to a change in the steady operating conditions and to design chemical injection program with such eventualities taken into account.

Why flow assurance failures happen

Two main reasons which explain the majority of flow assurance related incidents are: incomplete understanding of fluid properties and exceeding the safe operating limits. The first usually happens from lack of training or experience. The second may happen either due to an operator error or from operator's inability to explain to the management how exceeding the designed operating conditions will lead to a failure. Management may be motivated by a short-term incentive to reach a certain production target and request production operations to exceed the pre-determined limits; such operational deviations done without proper laboratory evaluations and technical plan seldom result in sustained improvement but can often lead to production interruptions followed by downtime, costly remediation and/or loss of confidence.

A typical subsea blockage related to flow assurance may cause several months downtime plus cost upwards of $15 million, as of the writing of this book, to hire a technology for clearing it if remediation program is successfully implemented, or lead to an even costlier well workover, flowline replacement or well abandonment if remediation is unsuccessful. In extreme cases, flow assurance failure may lead to contractual sanctions stemming from inability to deliver produced oil or gas, which cost may escalate into hundreds of millions of dollars, or to a complete loss of license to operate in a given country. Usually gas hydrate or paraffin wax blockages may lead to such extreme cases.

In the most extreme cases, blockages may lead to casualties. In an onshore field, a hydrate blockage driven by pressure differential moved inside a pipeline, ruptured the pipe bend and hit an operator. In the Piper Alpha offshore platform, a hydrate blockage in a condensate line was considered among the four likely root causes for the condensate leak and fire which sank the platform (Cullen, 1989), with 167 fatalities.

In other situations, the disaster caused by solid blockages leading to a pipe rupture and a release of hydrocarbons may be narrowly averted. In one FPSO in West African waters, an ice blockage formed in a flare relief line when a cold gas stream and a warm gas stream carrying water moisture combined, which led to a rupture and formation of an explosive gas cloud, but the wind on that day was blowing away from the furnaces.

In another example from US deepwater, nature may intervene to help remove a blockage, such as when a hurricane cleared a hydrate blockage. A deepwater chemical injection system methanol line connected to a scraping crossover valve got plugged as produced fluids hydrocarbon and water back-flowed past a checkvalve into the methanol line and formed a hydrate. The methanol line remained plugged until a hurricane led to an evacuation of the platform. This, in turn, triggered an automated opening of the scraping crossover valve. Warm water, accumulated behind the crossover valve in a dead leg of an actively heated flowline, flowed through the crossover valve and past the methanol line plugged with hydrate. The warm water flow initiated in the automated response to the hurricane heated and cleared the methanol line of hydrate, which was understood upon the restart of the field. This example teaches us to seek sources of energy available and accessible to overcome a blockage.

In a yet another example, an onshore oil field in Siberia experienced multiple hydrate blockages in early summer within months of being put on production because the initial water cut was low (under 5%), and methanol was not being injected. Additional resources were provided to supply methanol to treat the produced fluids. However, this was costly as methanol had to be airlifted by a helicopter during the summer months because the roads were impassable. A storage facility was then constructed to provide methanol supply through the year, but a longer-term ingenious solution was implemented, which came from a local technologist, who suggested to convert one of the several producer wells to a water-producer by re-perforating the well in the aquifer zone. Heat carried by water from one well was sufficient to keep produced fluids from all the wells warm and outside of the hydrate stability region. This was possible because all wells were equipped with ESPs for artificial lift. This example not only induces us to seek the nearby energy sources which can be used for flow assurance but also shows that operators of the field have a better understanding of the field's capability and should be consulted with during concept evaluation.

Blockages in onshore wells and flowlines are more routine and are much less costly to deal with. In one onshore field in North America, partial hydrate blockages occurred in wells nearly daily during the cold season, and were cleared promptly by methanol injection from a pump truck.

Engineers and chemists perform various analyses of properties for reservoir fluids, including hydrocarbons, water and gas. In some cases, the fluids are not sampled adequately, and some properties, such as the presence of H2S or mercury, may be not noticed until after the startup. Retrofitting a facility to take care of such problems, if they are not known at first and discovered later, is both costly and time consuming. Proper sampling is the foundation on which the good flow assurance design and production chemistry selection are based.

Flow assurance background

Prior to petroleum production there was water, and water was produced through wells. There are reports of scale encrustation of water wells in ancient Egypt water production system.

Initial small-scale use of petroleum began in Persia and China. Early oil came from natural seeps, and wells were dug by hand or pierced with a spring pole. One of the uses of petroleum was Early petroleum production in Northern Persia, now Azerbaijan was indicated by Marco Polo and other travelers. By the early 1800s production in the region averaged 80–90 barrels per day.

Large scale production of petroleum did not start until half a century later driven by increasing demand for petroleum. Around 1853, a modern version of the kerosene lamp was invented by a Polish inventor in Lviv, then part of the Russian empire and Poland, and now located in Ukraine. The reliable kerosene lamp created a steady demand for kerosene and for petroleum. Today, kerosene makes up just over 1% of refined oil products whereas 5% goes to jet fuel and 50% to gasoline (DOE, 2017, 2019). Kerosene lamps still consume as much fuel worldwide as all US jet planes combined. Besides the light, heating and transportation, petroleum also helped to reduce the hunting of whales and the dismantling of forests for fuel.

The global production of petroleum kept increasing through the years. The upward inflections as shown in Fig. 1.9 in the cumulative global oil produced observed around 1860, 1910, 1960 represent technology shifts which came in response to the production demand. Below in Figs. 1.10–1.14 are few examples of how the use of technology transformed the industry to make it more efficient.

Fig. 1.9 World oil produced, Billions of barrels ( Azerbaijan, 2017 ; Geohelp, 2017 ; Oil150, 2017 ; TSP, 2017 ; US EIA, 2017 ).

Fig. 1.10 Drilling a well with a spring pole.

Fig. 1.11 Well drilled for oil using an engine.

Fig. 1.12 Geophysical survey of a well.