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CHEMISTRY IN THE
OIL INDUSTRY I
Chemicals in the Oil Industry
22–23 March 1983
ENTER
TITLE
AUTHOR
INSTITUTION
Select one of theButtons on the
left to locate the requiredPresentation
Special Publication No 45
Chemicals in the Oil
Industry
The Proceedings of a Symposium Organised by the NorthWest Region of the Industrial Division of the Royal Societyof Chemistry
University of Manchester, 22nd-23rd March 1983
Edited byP. H. OgdenAkzo Chemie UK Ltd.
The Royal Society of ChemistryBurlington House, London W1 V OBN
Copyright © 1983The Royal Society of Chemistry
All Rights ReservedNo part of this book may be reproduced or transmitted in any form or by anymeans-graphic, electronic, including photocopying, recording, taping or informationstorage and retrieval systems-without written permission from the Royal Society ofChemistry
British Library Cataloguing in Publication DataChemicals in the oil industry.-(Special publication/Royal
Society of Chemistry, ISSN 0260-6291; 45)1. Petroleum industry and trade-Congresses2. Chemicals-CongressesI. Ogden, P. H. 11. Series33.2'7282 HD9560.5
ISBN 0-85186-885-1
Printed in Great Britain by Henry Ling Ltd., at the Dorset Press, Dorchester, Dorset
Introduction
The technicalities of oil production are heavily oriented towards engineeringand as a result are probably fully appreciated by only a small segment of thechemical industry. Indeed the average practising chemist is likely to beuninformed concerning the industries' simplest technicalities such as thephysical structure of an oil-bearing rock formation or the role of muds inthe drilling operation. Nor might he appreciate the massive scale ofoperations which are required in order to reach, extract and transport crudeoil to a point of refinery. Yet, each of the processes involved in thisoperation, i.e. drilling, stimulation, production and transportation is oftendependent upon the use of chemical additives.
The volume of chemical additives used may be rather small when compared withthe total quantity of oil produced, the proportion usually being expressedas parts per million; however, it represents a considerable quantity ofchemical, frequently specialty and often expensive.
The importance of the chemical additive is particularly evident when explorationand production occur in a hostile environmen~ such as that which confrontsoperators in the North Sea. In such a location, drilling costs are extremelyhigh and the cost effectiveness of oil-based drilling muds in directionaldrilling is obvious. Initial crude oil treatment is limited by severe spacerestrictions, and the disastrous effect upon crude oil transportation causedby corrosion or wax plugging of sub-sea pipelines can readily be understood.
On the other hand, because the use of chemicals is relatively small comparedwith the volume of crude oil, production operatives, with a few exceptions,have been unaware of the fundamental aspects of their chemical additives.The term specialty chemical is frequently used as a misnomer for a formulatedproduct, such as a corrosion inhibitor ,or scale dissolver, which might be amixture of several active ingredients with selected solvents or surfactantsin order to allow easy application and effective transportation to the siteof operation.
If a technology gap exists between the oil producer and the chemical manufacturer,this has been filled by the chemical service company. Such organisations combinea kpowledge of the chemistry involved with a good understanding of oil productiontechnology. Their role has been extremely important but their interestswould not be served by widespread dissemination of their knowledge and it couldbe argued that they sell service and expertise rather than a chemical product.
The objective of the symposium of which the proceedings follow was to drawtogether representatives of the oil producing industry, the chemical servicecompanies, and the general chemical industry in order to describe some of theproblems associated with oil production; to define those problems which can besolved through the use of chemical additives; the type of chemical currently
111
favoured; the level of service required to supply such chemicals effectivelyto the oil industry; the volume of chemicals used; and the financial outlayrequired of the oil producer. As such, the sympOSiU1D was to be technicallyinformative and also to enable participants to gauge the level at which theirrespective organisations might reasonably participate in the future of thisgrowth business.
The-North West Region of the Royal Society of Chemistry wishes to record itsgratitude to all of the contributors to these proceedings through which wehave been able to cover many of the chemical aspects of drilling, stimulation,production and transportation. Enhanced Oil RecoverY,which is an extremelyimportant aspect of future oil production and is a subject which possiblyholds the highest promise for future chemical sales to the industry, will bedescribed in a future symposium.
In addition, the R.S.C. is grateful to Britoil and the British PetroleumCompany for their generous sponsorship of the event and for the valued supportof my fellow fuembers of the organising committee
P. Brookes, Britoil; A. Gerrard, Ciba-Geigy; R. Mitchell, B.P.;J. Moorfield, Petrolite; A. Todd, Heriot-Watt University; andE. Vase, Shell EXPRO.
Paul H. Ogden
Akzo Chemie U.K. Ltd.,Littleborough,Lancashire
IV
Contents
Application of Chemistry to the Drilling Operation
By G.H. Smith
Chemicals for Water-based Drilling Fluids and Their
Temperature Limitations
By M.E. Hille
The Development and Application of Oil-base Muds
By G. Brownson and J.M. Peden
Chemical Aspects of Oilwell Cementing
By J. Bensted, P.E. Haynes, E. Henderson, A. Jones,
and T.B. Smallwood
The Role of Chemicals in Oil and Gas Production
By E.J. Vase
1
11
22
42
61
Chemical Demulsification of Produced Crude Oil Emulsions 73
By IhE_., Graham, A. StoakJ.JJell, and D. G. Thompson
Oily Wastewater Treatment in the Production of Crude Oil 92
By G.E. Jaakson
The Use of Ethylene-Vinyl Acetate Copolymers as Flow
Improvers and Wax Deposition Inhibitors in Waxy Crude
Oil 108
By G.W. Gilby
Water Scaling Problems in the Oil Production Industry 125
By K.S. Johnson
The Chemistry of Corrosion Inhibitors Used in Oil
Production 150
By J.A. Kelley
v
Quaternary Ammonium Compounds: Evaluation and
Application in the Control of Sulphate-reducing
Bacteria
By E. Bessems and A.F. CZemmit
The Role of the Service Company in Offshore Operations
By G.E. Payne
The Market for Chemicals in the Oil Industry
By R. C. Parker
vi
159
171
179
Application of Chemistry to the Drilling Operation
By G. H. Smith
BP RESEARCH CENTRE, SUNBURY-ON-THAMES, MIDDLESEX TW16 7LN, U.K.
Before considering where chemicals are applied inthe drilling operation, it will probably be profitable tooutline the mechanical processes involved in drilling a borehole. Naturally in the context of this paper it will only bepossible to develop a very simplistic outline of a verycomplex operation.
With the energy spotlight falling on the North Seain recent years many people have become familiar with themassive structures that are designed to work miles offshorein hostile environments. In fact once connection to the seabed has been established through a 'riser' tube, drillingfrom an offshore platform is essentially the same as drillingfrom a land rig.
From the surface (or sea-bed) a hole, often 36" indiameter is drilled to a depth of 50ft and a steel casing 30"in diameter is lowered into this hole and cemented into place,filling the entire annular space with cement slurry if possible.At ground level a wellhead is fitted to the top of this casingand all subsequent operations take place through the wellhead.
If troubles develop during the drilling operation,and pressure of fluid in the formation causes the well to flow,rams in the wellhead can be closed, even with pipe in the hole,so that the well can be shut-in safely.
Working through the wellhead and the casing alreadyin the ground, the hole will be deepened to lOOO-1500ft usinga 26" bit and l8i" or 20" casing run to bottom and hung fromthe wellhead. As before the annular space is filled with cement.
Drilling proceeds in stages in this manner. Frominside the l8i" casing l7~" bits extend the well to 4-5000ftwhen another casing string l3i" diameter is run and cemented.Then with l2~" bits to 8-l0000ft when 9\" casing is set andso on down the hole using progressively smaller bits and casingstrings. Each string of casing is hung from the wellhead,inside its predecessor and cemented into place, with the exceptionthat often the deepest, narrowest strings are not run back tothe surface but terminate just inside the previous string;these short strings are termed 'liners'.
A longitudinal section through a borehole will takethe form of Fig. 1.
10000' 7"
2 Chemicals in the Oil Industry
50'
~~~ ~ll~ 30"
~1000' I I I~ 18%"
Cement
4000'O~
l3~"
8000' 9%"
FIG. 2. SCHEMATIC SECTION THROUGH A BOREHOLE
Eventually the borehole will reach target depth hopefully in hydrocarbon-bearing formation - and the drillingphase of the operation is completed. If hydrocarbons areencountered the well now enters a complicated testing andevaluation phase to assess commercial viability.
Bits are run on the end of a hollow drill string.This string is formed from a series of pipes 5" in diameterand about 30ft long coupled with screw connectors. Asdrilling proceeds and the bit penetrates a further 30fta new joint of drill pipe has to be screwed on at the surface.The process is then resumed and new joints are constantlybeing added as required.
The uppermost joint of the drill string "the Kelly",differs from the others in having flat faces on its outersurface. These flats mate with bushings in a rotating tableon the rig floor, so that,as power is applied to turn therotary table, torque is transmitted to the drill string toturn the bit. At the same time the kelly is free to slidedown through the bushings as the bit advances.
As each connection is made the kelly has to beremoved from the string, the new joint added and the kellyscrewed back into the top of this new joint.
The whole string is supported from a travellingblock suspended in the drilling mast. When for any reasona bit has to be pulled the whole string has to be hoistedfrom the hole. It is broken out 3 joints (90ft) at a timeand racked in the derreck.
As presented above this is a very elementary outlineof the drilling process; I have not attempted to discuss theproblems that can arise when carrying out an operation that
Application ofChemistry to the Drilling Operation
is taking place some two or three miles below ground withonly a 5" diameter steel tube providing contact with thesurface and where the total mass of the drill string canexceed a million pounds.
This session is concerned more with the chemicalthan with the mechanical aspects of the drilling operation.
In any drilling activity a recurring problem isthe removal of debris formed by the drill. Whereas this isrelatively simple to overcome in activities taking place onthe surface, it is more complex when the debris are generatedat the bottom of a borehole. The solution to the removalproblem is the drilling fluid or mud.
Drilling fluid is held in mud pits or storagetanks on the rig. It is pumped down the hollow drill stringby high-capacity positive displacement pumps which arelinked to the top of the kelly by a flexible hose.
At the bottom of the string the fluid passes outthrough ports in the bit, and returns up to the surface inthe annulus formed between the borehole wall and the drillstring, carrying with it the debris created by the bit. Onthe surface the fluid passes over shaker screens and throughhydrocyclones where the debris are extracted and the fluidreturned to the pits to resume its cycle.
Large volumes of fluid are required to fill thehole and surface system - 50-60000 gallons is by no meansunusual. Consequently substantial quantities of chemicalsare used in preparing and maintaining this fluid.
In addition to cuttings removal a drilling fluidhas to serve several other functions Fig. 2.
A drilling fluid should:
3
Seal the hole to preventfluid loss
Provide a conductivemedium for logging tools
Lubricate the drill stringand bit
Clean the hole and bit
Encapsulate reactiveparticles.
Prevent fluids enteringthe hole
Strengthen the hole toprevent collapse
Lift cuttings and suspendsolids
Remain stable at hightemperature
FIG. 2. FUNCTIONS OF A DRILLING FLUID
4 Chemicals in the Oil Industry
In order to achieve these sometimes conflictingfunctions a drilling mud has progressed over the years froma simple clay/water mix prepared in a convenient pond, to asophisticated mixture using considerable quantities ofexpensive chemicals and forming the basis of a major serviceindustry; extending from the prime suppliers of bulk rawmaterials to the service companies providing a total packageof materials and engineering and design services.
Drilling fluids may be classified according to thebase fluid as 'Water Based' and 'Oil Based', and both willbe discussed in this session.
Water based fluids may be further classified depending upon the nature of the water used into fresh-water, seawater or salt-saturated systems.
To enable the fluid to carry cuttings the oftenconsiderable distance up to the surface, a certain amountof viscosity has to be developed. Essentially there aretwo means of doing this, either by the addition of clay(bentonite or attapulgite) or by the addition of a longchained water-soluble polymer (xanthan or polyacrylamide) .In addition to viscosity however the fluid must exhibitthixotrophy to prevent cuttings en route to the surfacefalling back when for any reason circulation stops; thisis why bentonite has proved such a useful medium in the past.
Whilst a borehole is being drilled the formationpenetrated might contain fluid under pressure and it isessential that this fluid does not enter the wellbore. Inmany instances the normal hydrostatic head of the fluidcolumn will suffice, but there are times when the drillingfluid weight has to be increased. This is almost invariablyachieved by the addition of finely ground barytes (bariumsulphate) to the fluid. Fluid density in excess of 2.2gm/mlcan readily be achieved in this way, and in recent years theuse of ilmenite and haematite has permitted the attainmentof even higher weights in water based fluids.
Clay and barytes are the principal bulk materials,used in very substantial tonnages in drilling. Althoughproduced to meet API (American Petroleum Institute) and OCMA(Oil Companies Materials Association - now known as EngineeringEquipment & Materials Users Association) standards 2.3 theseare essentially natural products and require very littleprocessing in their production.
Many other more specific chemicals are also addedto a drilling fluid to enable it to achieve its essentialfunctions and probably these are of more interest to thisSymposium.
Application o/Chemistry to the Drilling Operation
Earlier I mentioned that viscosity could beimparted either by the use of clay, or by a long-chainedpolymer. In recent years considerable interest has beentaken in the latter technique, with the development ofthe so called "no-solids" systems. This started with theintroduction a few years ago of the biopolymers, xanthangums and shortly afterwards of the polyacrylamides. Inaddition to imparting viscosity to the system it was claimedthat these materials by "encapsulating" clay and shale particlesas they were drilled inhibited the dispersion of formationin an aqueous medium. Potassium chloride was,frequentlyadded to inhibit shale hydration even further.
These polymer based systems are still usedextensively and on the whole perform very well. Some havelimitations of temperature and lack mechanical stabilityand others do not perform well with electrolytes in the water,but in the r~ght circumstances polymer fluids do an excellentjob.
Cellulosic polymers (sodium carboxymethylcellulose)and starch are used in considerable quantity in the drillingfluid. These are added to control the loss of the fluid phaseto the formation which tends to occur because of the pressureexerted by the hydrostatic head of the fluid column.
Many of the formations being drilled containhydratable clays and shales, and there is always a tendencyfor these to develop viscosity within the drilling fluid.To some extent this can be controlled by continuous dilutionbut this may be expensive if other chemicals, particularlybarytes, are being used. Frequently excess viscosity isbetter controlled chemically by the use of complex phosphates(such as sodium hydrogen pyrophosphate) or by lignites andlignosulphonates, usually with a heavy metal substitution.The first paper in this session will show that all of thesechemicals have temperature limitations, and to meet therequirements of deeper, hotter holes a new series of chemicaldispersants is becoming available to the drilling fluidsengineer.
High downhole temperature is one of the mainproblems confronting a mud engineer. Bentonite in suspensionflocculates and many chemicals used today degrade at thetemperatures frequently encountered in a normal borehole.
5
6 Chemicals in the Oil Industry
Unless the well is being drilled in a specificgeothe~al grea, temperature gradients of between 110F (60C)and 17 F (9 C) per thousand feet of depth are normallyoencountered so that at lSOOOft temperatures around 300 F(lSOoC) can be anticipated, and in some areas even highertemperatures are reported. New chemicals, the subject ofthe next paper, are enabling us to extend the economiclimits of water based muds at temperature but there areobvious constraints beyond which it will always be impracticalto use a water based mud.
When this situation is reached we have to resortto oil based fluids with concomitant environmental anddisposal problems. Oil muds are not a recent phenomenon:they have been is use for some twenty years but hithertoeither crude oil or diesel oil has been used as a base.
Recently oils with a low aromatic content havebeen introduced to the industry and because of theirinher~ntly low toxicity these are gaining very wideacceptance particularly in marine locations.
The use of oil muds and the various chemicalsrequired to produce stable emulsions, with the hole cleaningcharacteristics that the mud engineer demands, is discussedvery fully in the second paper of this session. It isinteresting to comment here however that with increasingusage of low-toxicity systems, cuttings disposal has becomeless rigorously controlled by the environmental agenciesand in consequence there will probably be a reduction inthe usage of chemicals designed for use in cuttings washsystems.
The drilling industry has a demand for largequantities of chemicals, not usually of particularly highquality but of ready availability. Almost invariably thesechemicals will be obtained through one of the service companyorganisations who provide a total package of engineeringand chemical supply.
Such companies maintain a full inventory ofchemicals - mostly under their own brand name - and operatingcompanies expect, and generally receive, an immediate responsewhen service is required.
Certain of the commonly used chemicals, bentonite,attapulgite and barytes, are prepared to conform to the API 2
and OCMA 3 standards, and the OCMA also issue standardscovering starch, CMC and thinners.
Application ofChemistry to the Drilling Operation
Other more specialised materials are purchased bythe service companies to their own specifications so thatvariation in quality is sometimes apparent.
These more specialised chemicals are mostly usedin systems for specific purposes such as completion brinesand non-damaging fluids. In certain circumstances potentialhydrocarbon reservoirs may contain clays or other mineralsthat would tend to hydrate if contacted by a normal drillingfluid and possibly cause blockages within the reservoir,whilst in other situations clays and weighting agent in thedrilling fluid might be the cause of production impairment ifthey blocked reservoir pores.
Completion brines are frequently used in place ofdrilling fluid under these conditions. A completion brineis essentially solids free. Necessary weight is imparted bya soluble ,salt, usually sodium or calcium chloride, but ifhigh weight is required zinc salts may be used although costthen becomes significant. Because carrying capacity is alsorequired in a completion brine a suitable polymer,hydroxyethylcellulose, may have to be added and the temperaturerange of the polymer may be extended using a polyamine.
Flourosurfactants are sometimes recommended toreduce the surface tension of a fluid and thereby preventwater wetting of an oil reservoir.
Surface active agents are widely used in drillingfluids to influence or control viscosity, fluid loss, emulsionstability, wettability and drill string friction. These varyfrom simple petroleum sulphonates to the high-temperature claystabilising agent which is a mixture of ethylene oxide adductsof phenol and nonyl phenol.
Defoamers are not normally added unless foamingbecomes a major problem. Various chemicals are used;tri-n-butylphosphate, aluminium stearate, higher alcohols,polyethers etc. have all been applied in the past dependingupon the nature of the foam encountered.
I have not attempted to produce a comprehensivecatalogue of chemicals that may be used by the mud engineerattempting to reconcile the conflicting demands made upon thedrilling fluid, but I hope that I have given an indication ofthe range of materials, from the crude bulk minerals to thesophisticated, and expensive, co-polymers, found in a moderndrilling mud.
7
8 Chemicals in the Oil Industry
Turning now to the cem~nting process. The lastpaper in this session will discuss in some detail thechemistry of oil~well elements and additives. As anintroduction to this I would like to outline the mechanismof cementing casing in a borehole.
Cement in a borehole serves three prime functions 4
1. To support and strengthen the casing string
2. To protect the casing string from corrosivefluids
3. To prevent fluid communication betweendifferent parts of the borehole
As illustrated at the beginning of this paper once asection of hole has been drilled, the drill string is pulledfrom the hole and an appropriate casing string is run. Inthe way that drill pipe is screwed together from 30ft jointsthe casing is also picked up a length at a time and screwedtogether. A joint of casing is usually about 40ft long andfor example will probably weigh between 30lb and SOlb per foot(depending on grade and wall thickness) for a string 9%" indiameter.
The casing is slowly lowered into the hole, whichshould of course be standing full of drilling fluid, untilthe string almost reaches the bottom. The length of stringis tailored, by using different length joints, so that thetop joint of casing protrudes onto the drill floor. Acementing head is attached to this upper joint and using highpressure, quick coupling pipe, connection made to the cementingunit normally some distance from the rig floor.
After fluid circulation has been established and thehole cleaned up the cementing operation commences.
Before displacing any cement a 'pre-flush l isnormally pumped into the hole to act as a spacer betweenthe drilling fluid and the cement slurry, and to removemud and debris ahead of t~e cement.
Normally 300-500 gallons of pre-flush are pumped.Often fresh water will suffice, but surfactants and/ordispersants (acid phosphates) are sometimes added to providebetter hole cleaning.
Once the spacer fluid has been displaced the cementslurry is prepared and pumped downhole.
Application ofChemistry to the Drilling Operation
Cement from a storage silo is drawn into amixing hopper where it is intimately mixed with waterpassing through a venturi jet in the base of the hopper.The slurry thus formed passes to a small holding orre-circulating tank where minor adjustments can bemade to the density.
Mixing and pumping is a continuous process.As soon as the slurry is at the correct weight it ispumped to the hole. As the slurry reaches the cementinghead a wiper plug is released and precedes the slurrydown the inside of the casing. This plug is circularin section with vanes the same diameter as the insideof the casing, and serves to wipe the casing free of mudfilm and debris as it is forced downwards.
Mixing and pumping continues until a volume ofslurry equal to the volume of the annular space betweenthe casing and the borehole wall has been prepared. Asecond plug is then inserted into the top of the casingand the cement slurry, sandwiched between the bottom andtop plugs, is now pumped down to the bottom of the casing.This is usually achieved by connecting the mud lines tothe cementing head and pumping mud into the casing.Eventually the bottom plug latches into the shoe at thebottom of the casing string and there is a momentaryincrease in pump pressure, causing a diaphragm in the plugbody to rupture. The cement slurry now floods out intothe borehole and round the casing shoe to begin fillingthe annulus, displacing drilling fluid and preflush aheadof it.
As pumping continues the remaining slurry isforced out of the casing until eventually the top plugalso reaches the shoe. This plug will not rupture andthe pressure increase indicates that displacement has beencompleted, and given reasonable luck the annulus is nowfull of cement slurry. Slight pressure is maintained onthe casing to prevent any leak back and after twelve hoursor so sufficient strength should have developed in thecement to permit operations being resumed.
Again I have only attempted to develop a verysimplified outline of a very complex operation. It isnot difficult to imagine the highly specialised knowledgethat is required to produce a cement slurry that is readilypumpable, remains pumpable for three or more hours whilstbeing forced a couple of miles down steel pipe, is subjectedto very high temperatures and pressures, and returned to thesurface and yet will have developed sufficient strength after
9
10
8 or 12 hours to permit drilling to resume.
Chemicals in the Oil Industry
The mud engineer and the cementation engineerboth need a good working knowledge of the chemistry oftheir products, and both depend upon the chemical industryextending the range of materials available to them, asdrilling operations become progressively more complex andmore costly. Happily the chemical industry has never letthem down; solutions have been found as rapidly as problemshave arisen.
ACKNOWLEDGEMENT
The author wishes to thank the British Petroleumplc for permission to publish this paper.
REFERENCES
1. Gray, G.R., Darley, H.C.H., Rogers, W.F.Composition and Properties of Oil Well DrillingFluids, Fourth Edition, Gulf Publishing Co.
2. API Specification for Oil Well Drilling FluidMaterials API Specification l3A Ninth EditionAmerican Petroleum Institute. Washington DC.
3. OCMA Specifications for Salt Water Clay (DFCP-l),Low Viscosity CMC (DFCP-2), Barytes (DFCP-3),Bentonite (DFCP-4), Starch (DFCP-S), High ViscosityCMC (DFCP17) and Torcian and LignosulphonateThinners (DFCP-8). October 1973Oil Companies Materials AssociationHayden & Son Ltd.
4. Smith, Dwight K.Cementing. SPE Monograph Volume 4Second printing. Society of Petroleum Engineers of AIME.
Chemicals for Water- based Drilling Fluids and TheirTemperature Limitations
By M. E. Hille
HOECHST AG., D-6230 FRANKFURT-AM-MAIN, WEST GERMANY
In drilling for petroleum and natural gas the drilling mud is an
important parameter. It is intended to ensure that the target
depth is reached in the shortest possible time.
Efficient drilling muds have been developed in the past for many
different geological formations through which wells had to be
drilled. l ,2
Approximately 90% of them are water-based drilling muds. In the
course of its relatively short history drilling mud technology
has been repeatedly confronted with development tasks which
presented themselves mainly because drilling had to be done at
ever greater depths and through formations that had not previously
been encountered. So long as drilling was carried out in
relatively shallow depths, drilling muds made of clay suspensions
were adequate; these were either diluted as required with water
or fluidized with polyphosphates or quebracho.
With increasing well depth, and particularly when drilling through
electrolyte-releasing formations such as gypsum or salt formations,
these drilling muds become too unstable and they have to be
continuously replenished.
One soon learnt to master this problem by introducing colloids
into drilling mud technology. The most widely used protective
colloids used for stabilization of drilling muds nowadays are as
follows:
starch and starch derivatives
cellulose ethers such as CMC, HEC, CMHEC
biopolymers
acrylate/acrylamide polymers
vinyl sulfonate/vinylamide polymers
12 Chemicals in the Oil Industry
In addition to the stabilizing action imparted by these protective
colloids to drilling muds they also regulate the flow properties
and water loss very specifically. The water loss is generally
measured according to the API method, but increasing importance
is being attached to the HT/HP water loss which characterizes the
real infiltration rate better under borehole conditions. The
protective colloids for wauer-based drilling muds are water-soluble
polymers with a certain critical molecular weight.
Water-based drilling muds, depending on the additives used, can
be employed up to certain borehole temperatures. Thus the
effectiveness of starch and starch derivatives declines markedly
in drilling muds at 100 - 120 °C. As from these temperatures
the consumption of these substances increases considerably because
reconditioning of the drilling mud to control the necessary
properties has -to take place at ever shorter intervals.
In the case of carboxymethyl celluloses this temperature interval
is approximately 130 - 160 °C. This applies also to hydroxyethyl
celluloses and carboxymethylhydroxyethyl celluloses.
During recent years biopolymers have been widely introduced into
drilling mud technology. They give to the water-based drilling
muds very good rheological properties and they are not susceptible
to bivalent ions. There are various types, the best of which
possess the thermostability of cellulose ethers.
No sharply defined temperature limit, but only temperature interval,
can be stated for the decline of the effectiveness of different
polymer types, because this is not the same in different drilling
mud systems and the individual functions of the polymers decline
within different temperature intervals; this is explained with
the aid of the example of CMC. The viscosity of a drilling mud
conditioned with high viscosity CMC, for example, declines
noticeably above 100 °c, although the water loss hardly shows a
reduction. As from approximately 135 °c the HT/HP water loss
increases noticeably, and rapidly as from 150 °c, whilst the API
water loss and the stability of the flow properties only deteriorate
significantly at a further 20°C above this temperature. These
data relate to water-based salt-saturated drilling muds.
Practically, it has to be decided from case to case when the
polymer bases will be changed. The reason for it may be, for
Chemicals for Water-based Drilling Fluids
example, to strong rising reconditioning rates, high technical
difficulties as a result of a too thick filter cake under
formation conditions or possible formation damage due to high
HT/HP water loss.
13
Besides polymers, thinning agents are widely used in drilling muds:
Type of thinning agent application limit
Polyphosphates 60 - 80 °cQuebracho 100 - 120 °cLignosulfonates 140 - 170 °cHuminates/Lignites up to over 200 °cStyrene sulfonate/maleic acid
°canhydride polymers up to over 200
For the above mentioned temperature limits the same as for the
polymers is valid. There are intervals which only specify the
approximate upper limits by which the temperatures are the
limitant factor for their use. Below these intervals there are
numerous other reasons which are determining for the application
of another mud system.
The most important thinning agents are the lignosulfonates and
lignites.
These additives are dispersants which stabilize drilling muds on~y
to a limited extent against electrolytes and elevated temperatures.
In freshwater drilling muds practically free from electrolytes
the reconditioning rates increase rapidly already at temperatures
over 100 °C. This high-temperature jelling can be kept low up to
over 200 °c with copolymers of styrene sulfonate and maleic
anhydride. 3
However, the water loss is unsatisfactory in freshwater drilling
rnuds and generally increases significantly within a short time in
saltwater thinning agent rnuds with rising temperature. It is
then only possible to keep the water loss low by the additional
use of the protective colloids mentioned above.
Naturally products from both additive groups, polymers and thinners,
are frequently used over the above mentioned limits. This is
possible without big disadvantages when the mud circulates, because
the mud stream operates like a cooling device for the well and dis
places the isotherm downwards. The experience of numerous wells
shows, however, that often difficulties appear during standstill
14 Chemicals in the Oil Industry
periods when the bottom hole temperatures stabilize. The
additives become inactive and thereby the viscosity and the HT/HP
water loss increase considerably. The fixation of the drill
string is retarded and becomes complicated and the well logging
tools do not reach the bottom. The high HT/HP water loss leads
to pipe sticking, the initial pumping pressures increase and the
recovered mud from the bottom hole has to be reconditioned or
partically rejected. 4 Furthermore, particularly detrimental
will be the decomposition of mud chemicals during the drilling
of the formations.
The high HT/HP water loss often leads to formation damage which
decreases ~he production rates. High gelled muds are frequently
the cause of deficient cementation. Particularly at high mud
densities, the cement sludges will not completely displace the
mud and the cement will build preferential flow channels in the
highly viscous mud of the annulus. By this means the hydrocarbon
bearing formations will not be entirely sealed and, especially
at high formation pressures and differential pressure, the gas
will flow to other porous layers through the annulus.
The application of mud additives above their stability limits is
mostly uneconomical: at least during the drilling of the
formations, a qualitative good mud should be used.
Generally the costs of the damage produced by an unstable mud are
substantially higher than a thermostable mud system.
The largest gap in drilling mud technology until now has been
the lack of highly effective additives for conditioning saltwater
containing drilling muds which are exposed to high temperatures
during drilling at great depths. 5
However, it has to be relatively considered, because an improvement
of the present available thinners for very high temperatures may
be also economical.
Acrylatejacrylamide and vinylsulfonate/vinylarnide were until now
practically the only copolymers of importance for conditioning
water-based drilling muds as from about 150 °c to over 200 °C.Copolymers of the acrylate/acrylamide type, which have been used
in drilling rouds for over 30 years, have only found limited
application. The reason is the sensitivity of these products
even to relatively low concentrations of calcium ions which very
Chemicals for Water-based Drilling Fluids
often cannot be excluded in practice, for example, in the form of
gypsum or cement.
15
Table 1 shows the laboratory tests which demonstrate the
sensitivity of the polymers of the acrylate/acrylamide type to
calcium ions. In freshwater-based drilling muds these additives
are effective under normal conditions and also at 200 °C. However,
if the drilling mud contains gypsum and thus calcium ions due to
the solubility of gypsum, the polymers of the acrylate/acrylamide
type provide good results under normal conditions, but on account
of exposure to heat lose their effectiveness.
The reason is increasing saponification of the acrylamide groups
according to the following formula:
H HI I
(-c - c-)I I nH C=O
6-Na+
H HI I H2 0
(-C - C-)I I mH C=O
INH
2
H HI f
(-c- c-)I f nH C=O
,- +o Na
H HI ,
(-c-c-)I I mH C=O
b-NH+4
The additional carboxyl groups formed on the carbon atom chain
increase the sensitivity to calcium. Higher pH values and temper
atures accelerate this saponification process. If higher concen
trations of calcium ions are present in a drilling mud, such as
may occur on account of the influx of brine, the low concentration
of the original carboxyl groups in the polymer is sufficient to
precipitate these ions and to render them ineffective as drilling
muds.
When using copolymers of the acrylate/acrylamide type in practice
one endeavours to keep the calcium ion content low by means of an
excess of soda or alkali. However, these drilling muds are
strongly alkaline, a fact which makes it difficult to control the
flow properties and may lead to obstructions in oil-bearing
formations and gas-bearing formations. At high pH values and
elevated temperatures the solubility of the pay zone material
is occasionally considerable. The pay zone material
dissolves in the alkaline filtrate during drilling and is
precipitated when the pH drops on further penetration of the
filtrate into the formation; th~s occurs at the start of production
at the latest. This may result in a considerable reduction of the
Table 1
Under normal conditions After Ageing
15 h at 200°C
0'.
Additive
I 11 III I II III
1 L Water 1 L Water 1 L Water
40 g Bentonite 40 g Bentonite 40 g Bentonite
10 g Additive 250 g NaC1 100 g NaC1
10 g CaS04 100 g caC1 210 g Additive 20 g Additive
Water losses according to API in cm3
Acry1ate/acry1amide
mg approx. 3 x 106
Viny1su1fonate/viny1
amide
mg approx. 0.8-1.0 x 106
9.0
8.5
8.8 100 9.2 46 100
(J~~
~
9.0 4.8 8.8 10.4 5.5 ~'~r;;--5'So~
~~
~
~~V:J
~
Chemicals for Water-based Drilling Fluids
recovery rate of oil or gas. A further disadvantage of the
acrylate/acrylamide polymers is that they precipitate in acid
solutions such as are used in the acidization of pay zones which
in turn may lead to fu~ther plugging.
17
For the stated reasons these products have only found limited
acceptance as additives in drilling mud systems for deep wells.
They inhibit swelling clays very well and are therefore used in
the formulation of drilling muds in which the calcium concentration
has to be kept low.
These are, foreKample, drilling muds based on KC1. 6 ,7 In concen
tration as low as approximately 0.1%, acrylate/acrylamide polymers
have a good inhibitory effect on swelling clays in thinning type
drilling muds based on lignosulfonates and/or lignites.
Copolymers based on vinylsulfonate/vinylamide do not possess these
disadvantages. They tolerate calcium ions up to saturation point,
that is to say, they stabilize drilling muds also if there is an
influx of calcium and magnesium salt brines.
With partially saponified polyacrylamides, the existing and the
later formed carboxyl groups by saponification are the reason for
the sensitivity limits to calcium ions. Polymers of the type
vinylsulfonate with vinylamide have negative sulfo-groups which
are insensitive against calcium ions. During saponification of
the amide groups, which is a function of the pH and temperature,
secondary amine groups are built in the polymer chain, which are
also not affected by calcium ions.
R HI IC=CI I H 20B N-R ---~
Ir=OR
H HI Ic=c +I IH N- R,
H
R COOH
This saponification takes place with technical velocities over 120
°c, also in neutral range. Besides, the very weak basic amide
groups will be converted to weak basic secondary amine groups. For
the performance of these polymers, those basic groups are very
significant. They adsorb on the lattice sites on the surface of
the clay and thereby reduce the adsorption of the cations of the
18 Chemicals in the Oil Industry
water phase, such as calcium, magnesium, sodium and potassium.
Also at increasing concentrations of electrolytes, the cations
cannot displace the polymers in the clay surface, reducing
significantly the negative charge of the clay particles. The
reduction of the charges of the clay particles caused by the
adsorption of cations on the free lattice sites will be compen
sated by the negative sulfo-groups of the polymer. In order to
reach the optimal mud quality, the polymers of vinylsulfonates
and vinylamides must have determined molecular weights and
specified ratios between the cationic and anionic groups. The
whole polymer has to have negative charge surplus, and a high
ratio of vinylamide will lead to a drilling mud with high viscos
ities. Owing to their high molecular weights of approximately
1 - 2 x 106 , those polymers inhibit the swelling of the clay.
With the vinylsulfonate/vinylamide polymers conditioned muds it is
possible to minimize the environmental problems in comparison to
water-based chrome-containing thinner muds or oil-based muds.
Their clay and solids content can be kept low, which results in
higher penetration rates and lower energy consumption for the
circulation.
Polymers of the vinylsulfonate/vinylamide type make it possible
nowadays to drill safely to depths of over 200 °c with water
based drilling muds. In this case the HT/HP water loss can be
kept low in order to cause no damage to the pay zone and avoid
difficulties in drilling, also at all the electrolyte concentrat
ions occurring in drilling muds. Influxes can be controlled
relatively well with the aid of these drilling muds. Influx of
water of brines into the drilling muds practically causes only
dilution which can be corrected easily. Through their action as
protective colloids, polymers of the vinylsulfonate/vinylamide
type prevent considerable deviation of the drilling mud properties
initially set, such as flow properties and water loss, in the
case of influx of brines with high concentrations of bivalent ions
such as calcium and magnesium. Influx of crude oil into the
drilling mud is homogeneously emulsified and gas that is entrained
can be separated relatively safely and then flared.
The properties of drilling muds conditioned with polymers of the
vinylsulfonatejvinylamide type have been proved in practical
application with the aid of the following examples.
Chemicals for Water-based Drilling Fluids
Table 2 shows the result of measurements on a field mud condit
ioned with CMC/CMHEC. The API water losses were acceptable, but
the technical difficulties met with in drilling were found to
have been due to the high HT/HP water losses. By means of 1%
polymer it was possible at 150 °c and 35 bar, after ageing for
15 hours at 150 °c, to reduce the water loss to about 10 cm3 ,
whereas it had previously been 62.0 cm3 .
19
Table 3 demonstrates the drilling mud data of a non-damaging
drilling mud based on chalk for the solids content, with about
2.6% polymer. I Despite the low gel values the chalk remained well
dispersed also above ground whilst the solid cuttings were separ
ated practi~ally completely in the settling tank. This drilling
mud was introduced into the circulation of a bore-hole with a
temperature at the bottom of about 160 °c and was found to be
extremely stable during the subsequent drilling operation.
Table 4 shows the means of the slightly saline drilling mud (NaCl
7-8%, ca++ 2000 to 6000 ppm) of a deep bore-hole with a final
depth of about 5600 m and a temperature of 195 °c at the bottom.
At a depth of about 4900 m this drilling mud has been changed from
a CMC conditioning to polymer. The planned final depth was
safely reached after unproblematical drilling, with only small
drilling mud replenishments being required.
These three practical examples show the manifold application
possibilities of the vinylsulfonate/vinylamide polymer types and
the field experience largely confirms the laboratory findings.
The very special advantage of these products is that, independently
of the electrolyte content, the HT/HP water loss can be kept low
at temperatures up to over 200 °c, i.e. at 15 cm3 and below. This
makes it possible to drill through oil-bearing pay zones and
particularly gas-bearing pay zones without causing damage and to
minimize the permeability reduction caused by the drilling mud,
in order to obtain maximum production.
The results mentioned were obtained with ®Hostadrill 2825
vinylsulfonatejvinylamide polymer. If very high concentrations
of bivalent ions of calcium or magnesium, which may go right up to
saturation, are employed, ®Hostadrill 3118 is more effective.
®Registered trademark
20
Table 2
Chemicals in the Oil Industry
API water loss (cm3 )
HT/HP water loss (cm3)
35 bar/150°C
Field mud plus 1% polymer VS/VA
API water loss (cm3 )
HT/HP water loss (cm3 )
35 bar/l500C
Before ageing
3.8
44.4
1.8
12.0
After ageing15 h at 150 C
4.8
62.0
2.0
10.2
Field mud: Chalk, approx, 200 g KCl/l, density 1.40 g/cm3
conditioned with CMC and CMHEC and plus 1% polymer
VS/VA
Table 3
Density
Marsh
WV API
Filter cake
WV HT/HP
pH
SV
PV
FL
10" gel
10' gel
g/cm3
cp
cp
Ibs/lOO ft 2
1.46
59/48
2.4
0.5
22.0
7
at 50°C
28.5
26
5
1.5
1.5
at 90°C
20
18
4
2.5
3
Drilling mud: per 1 m3 water: 30 kg bentonite, 338 kg NaCl, 640
kg chalk, 35 kg polymer, 0.8 kg defoamer
HT/HP water 10ss/35 bar/150°c
Chemicals for Water-based Drilling Fluids
Drilling mud means of a bore-hole with 5600 m final depth;
temperature at bottom 1950 C
Density g/cm3 1. 6 - 1. 66
Marsh sec 45 - 50
WV API 35 - 8cm
WV HT/HP cm3 approx. 20
25 bar, 1600 C
Filter cake mm 0.5 - 0.6
pH 9 - 10
SV cp 40 - 50
PV cp 30 - 40
Yield point lbs/100 ft 25 - 15
10" gel 6 - 10
10' gel 18 - 30
Drilling mud: Bentonite heavy spar, NaCl 7-8%, Ca++ 2000 - 6000
ppm, approx. 1% VS/VA polymer plus a little CMC
References
21
1
2
3
4
5
6
7
G.R. Gray, H.C.H. Darley, and W.F. Rogers, 'Composition and
Properties of Oil Well Drilling Fluids', Fourth Edition, Gulf
Publishing Co., Houston, Texas, 1980.
K.H. Grodde, 'Bohrspulung und Zementschlamme in der Tiefbohr
technik', Verlag Otto Vieth, Hamburg, 1963.
W.G. Chesser, and D.P. Enright, J. Petrol. Technol., June,
1980, 950 - 956.
C.E. Chadwick, Oil and Gas J. Oct. 1981, 251 - 257.
P. Simpson, World Oil, April 1967, 135 - 139.
D.E. O'Brien and M.E. Chenevert, J. Petrol Technol., Sept.
1973," 1089 - 1100.
R.K. Clark, R.F. Scheuermann, H. Rath, and H. van Laar,
J. Petrol. Technol., June 1976, 719 - 727.
The Development and Application of Oil- base Muds
By G. Brownson and J. M. Peden
DEPARTMENT OF PETROLEUM ENGINEERING, HERIOT-WATT UNIVERSITY,EDINBURGH EHl lHX, U.K.
Introduction
The onset of World War 11 dramatically increased the
demand for petroleum products. As deeper wells were drilled,
it was found that water based muds were often not performing
satisfactorily and more attention had to be paid to the drilling
fluid used.
A conventional water based mud consists of the
following components:
(1) A clay which provides filter cake and suspension
properties.
(2) A polymer which provides suspension and fluid
loss characteristics.
(3) Speciality chemicals to:
(a) reduce corrosion
(b) absorb dangerous gases CO 2 , H2S
(c) eliminate foam
(d) reduce torque
(e) inhibit clays
(f) kill bacteria.
(4) Minerals such as barite and iron oxide to
control density.
(5) Plugging materials to control lost
circulation.
The Development and Application ofOil-base Muds
The continuous phase is of course water often
saturated with salts to prevent wash Guts when drilling through
salt sections. Economics usually dictate that the polymer is
naturally occurring, e.g. starch, guar gum, XC polymer,
alginates, or solubilised from a natural base CMC, CMHEC (base
cellulose) .
I. Advantages and Disadvantages of Water Base Muds
A. Advantages of Water Base Muds
(1)- 110\'7 cost
(2) Non-polluting, ease of disposal.
(3) Treatments can be effective in a single
circulation.
(4) The conductive nature of the continuous
phase allows resistivity and SP logs
to be run.
B. Disadvantages of Water Based Muds in Order ofImportance
(1) Temperature Instability
At high temperatures the polymer chain breaks at
its weakest link and the viscosifying and fluid loss
properties are lost. If gel strength is also lost
and circulation stops, barite settling and stuck
pipe can occur. Much of the research into water
based muds is into producing a high temperature
stable polymer.
(2) Formation Damage
Where water swelling clays are present, fluid
invasion can cause the formation to become less
permeable to the reservoir fluid.
(3) Chemical Instability
(a) Clays
Swelling clays entering the mud system can
give excessive viscosities and high fluid
losses (permeable filter cake and wrong
polymer/clay ratio) which ultimately leads
to hole erosion and collapse.
23
24 Chemicals in the Oil Industry
Formation waters often contain high
concentrations of ca2+/Mg 2+ which reduce
the thermal stability of starch and CMCS.
Water is conductive and hence a corrosive
medium. Scaling can also be serious under
certain conditions.
If the continuous phase (water) is replaced by another liquid
(oil) and the colloidal dispersed fluid loss additive (polymer)
is replaceq by an alternative (emulsified water, colloidal
asphalt or bentone) it is possible to develop a drilling fluid
which overcomes some of the above problems.
Miller 1, in 1951, discussed the advantages of oil
base muds.
11. Advantages and Disadvantages of Oil Base Muds
A. Advantages of Oil Base Muds
(1) Excellent fluid loss control at high
temperatures. Oil base mud
formulations can have API HT/HP
(350 0 F/500 psi) fluid loss values of
0.5 ml. This results in a very thin
filter cake.
(2) The continuous phase (filtrate) is oil so
even if it enters the formation, damage
should be less.
(3) Corrosion and scaling problems are minimal.
(4) The local fluid loss and high lubricity mean
that stuck pipe problems are infrequent.
(5) Once the components that make up the mud
have reacted together and it has aged, it
can be stored in tanks for long periods.
One little known application of oil base
muds is as a ships ballast material.
For such applications the mud can be
weighted up with PbO to give densities of
3.5 - 4.0 g/ce3 .
The Development and Application ofOil-base Muds
(6) Correctly formulated muds do not disturb
shales. Shales adsorb water in two ways:
(a) By surface adsorption
(b) By osmosis (because of high ionic
concentration).
Oil muds,having oil as a continuous phase, stop surface
water-adsorption by making them oil-wet. By maintaining higher
salinity in the water phase (by adding CaCl2 ), oil muds not only
prevent osmotic migration of water but also can dehydrate shale
by reverse osmotic migration. Thus, water-sensitive shales
remain stable. The layer of emulsifier at the interface acts as
a semi-permeable membrane, and, provided the vapour pressure of
the aqueous phase is less than the vapour pressure of the
formation water, transfer from the emulsion fluid to the shale
will not occur. This frequently requires the aqueous vapour
pressure of the drilling fluid to be less than that of a
saturated sodium chloride solution and often it is desirable to
saturate the aqueous phase of the drilling fluid with calcium
chloride. Where formations are particularly water sensitive
solutions containing ZnBr 2 , ZnCl 2 , LiBr and LiCl can be used.
B. Disadvantages of Oil Base Muds
(1) Cost
Oil base muds are much more expensive than
water based muds. The major costs are
the oil phase base, normally diesel oil,
and the emulsifiers used.
(2) Drilling Fluid Disposal
The aromatics in diesel oil are carcinogenic
and cuttings and mud disposal pose real
problems. A number of methods have been
tested none of which are considered totally
satisfactory2 The used mud itself is
usually sold back to the mud company.
25
26 Chemicals in the Oil Industry
(a) Incineration
Expensive wi th problems of air pollution.
(b) Microorganism Processing
Theoretically possible.
(c) Distillation, Liquid Extraction and
Chemical Treatment
Distillation in an electric kiln. The
kiln and heating costs are high and
problems occur with blocked filters.
Chemical fixation converts the heavy
metals present into inert silicates
or hydrous oxides by reacting the
drilling fluid with a mixture of sodium/
potassium silicate and portland cement.
The process works with fluids containing
up to 20% oil17 .
(d) Burial
Where local regulations permit the cuttings
are washed with a suitable solvent.
Mondshine13 recommends a wash with a fluid
mixture of alcohols, acetates and glycols
and subsequently burial.
(e) Reuse as a Filler for Roads
One company in Europe claims,to have a
process to use the cuttings as a filler
for roads.
(3) Handling Difficulties
Due to the dirty slippery nature of oil
muds the working conditions on the rig
floor are difficult.
(4) ~2S Solubility Under Pressure
Gas solubility in oil is far greater than
in water; as a result dangerous levels of
gas may be carried undetected up the hole
in a mud column and released unexpectedly
at the surface3 .
The Development and Application ofOil-base Muds
(5) Permeability Reduction in Gas Reservoirs
In gas sands containing water, an oil mud
may do more damage than a water base mud
due to trapped water reducing the gas
permeability. Mud companies claim the oil
is vaporised during production.
(6) Damage caused by Emulsifer Contamination
in Filtrate
(a) Oil with emulsifiers can change the
wettability of the rock.
(b) Emulsifiers can cause emulsion blockage
in the presence of formation water.
From the above brief discussion it can be seen that it
is very difficult to generalise on the optimum mud formulation
until all the reservoir parameters have been taken into
consideration.
Ill. Historical Development of Oil Base Muds
The first patent was issued in 1923 to SwanS who
suggested a solution of asphalt in benzene. Moore and Cannon6
27
(1936) patented an oil base drilling fluid in which the weighting
material was oil wet. Van campen7 (1940) used a peptising agent
consisting of a higher carboxylic acid and an amine soap. Miller
(1940-50) in a series of patents used a composition based on
blown asphalt, calcium oxide and naphthenic acid. Fischer9
used the soaps of "disproportionated" rosin (dihydroabietic and
dehydroabietic acids). Fischer10 also patented an electrically
conductive drilling fluid using uranium nitrate.
Lummus 11 (1957) patented an oil base drilling fluid
consisting of an oil base, fatty acid residue containing poly-
basic acid having at least 12 carbon atoms per acid radical, an
alkali metal base, a strong oxidising agent such as sodium
dichromate, lecithin and calcium chloride.
28 Chemicals in the Oil Industry
Wilson12 , (1963), used blown asphalt, diesel oil and
an anionic surface active material from the group consisting of
alkyl aryl sulfonic acid and alkyl aryl sulfonates.
The early oil base muds were difficult to maintain if
their water content exceeded 10% - 15%; this led to research
into muds with a water content of greater than 50% whilst main-
taining oil as the external phase. These muds are known as
inverts. Before discussing oil mud formulations it is worthwhile
briefly d~scussing the basic theory of emulsions.
IV Basic Emulsion Theory
A surfactant is a molecule containing both polar and
non-polar parts (amphiphilic). These molecules sit at inter-
faces because the polar portion is attracted to the polar medium
and the non-polar to the non-polar medium. Surfactants are
classified as anionic, cationic, non-ionic or amphoteric
according to the charge carried by the surface-active part of
the molecule.
Anionic
Sodium stearate
Sodium oleate
- +CH3 (CH2 ) 16COO Na
CH3 (CH2 ) 7CH = CH (CH2 ) 7
COO-Na+- +
Sodium dodecyl sulphate CH3(CH2)11S04 Na
- +Sodium dodecyl benzene sulphonate CH3 (CH 2 ) 11C6H4S0sNa
Cationic
Dodecylamine hydrochloride
+CH3 (CH2 ) 11 NH3Cl
Hexadecyltrimethylammonium bromide
+CH3(CH2)15N(CH3)3Br
Trimethyl dodecyl ammonium chloride
+C12H25N(CH3)3Cl
The Development and Application ofOil-base Muds
N-alkyl trimethylene diamine chloride
H H H H H 2+
I I I I I -R N C C C N -H Cl Cl
I I I I IH H H H H
Non-ionic
Polyethylene oxides
Spans (sorbitan esters)
Tweens (polyoxyethylene sorbitan esters)
Phenol 3D-mol ethylene oxide (DMS)
C6HS 0 -- (CH2 -- CH2 -- O)30H
Amphoteric
29
Dodecyl betaine+ (CH
3) 2
C H N12 25 ----- CH CO
2 2
Alkali metal soaps favour O/W emulsions whilst heavy
metal soaps favour W/O emulsions. The type of emulsion which
forms depends on the balance between the hydrophilic and lipo-
philic properties of the emulsifier. Alkali metal soaps favour
O/W emulsions because they arernorehydrophilic than lipophilic
whereas the reverse holds for heavy metal soaps.
HLB VALUES 13 are an empirical scale which indicate how
an emulsifier will behave.
Applications
3-6 W/O emulsions
7-9 Wetting agents
8-15 O/W emulsions
13-15 Detergent
15-18 Solubiliser
Dispersibility in Water
1-4 Nil
3-6 Poor
6-8 Unstable milky dispersion
8-10 Stable milky dispersion
10-13 Translucent dispersion/soln
13- Clear solution
30 Chemicals in the Oil Industry
The interfacial tension between oil and water is
about 50 dynes/cm, so they separate to minimise interfacial
area. An emulsifier lowers the interfacial tension « 10
dynes/cm) and forms a protective skin round the droplets. An
O/W emulsion can be broken by adding a small amount of a W/O
emulsifier, and vice versa.
Particles can stabilise emulsions when they are
partly oil wet and partly water wet - contact angle = 90 0•
This is the principle behind the use of asphalt as a filter
cake material in water based muds. The asphalt is mixed
together with a mineral, fused and then ground up. The particles
of mineral partly coated with asphalt can now be water wet in
the mud system.
Most emulsions become unstable at high temperatures
as a result of changes in solubility of the emulsifiers in one
or other of the phases,thus altering its distribution and
affecting the interface. Since emulsifiers are organic compounds
it is difficult to find effective emulsifiers above 600 0 F.
Oil Wetting Agent
If the attractive force between oil molecules and
some solid surface is not sufficient to overcome the surface
tension of oil, oil does not wet the surface.
Since most metal and mineral surfaces are negatively
charged,cationic surfactants are oil wetting agents. N-alkyl
trimethylene diamine chloride is a typical example.
Lecithin14 is used to oil-wet barite. The positively
polarised nitrogen is attracted to the barite surface leaving
the hydrocarbon tail to dissolve in the oil phase.
Oil Dispersible Bentonite (Bentones)
Bentonites can be made to swell and disperse in oil by
The Development and Application o/Oil-base Muds
replacing the alkali metal cations with an onium salt14
, e.g.
(C14H29NH3)+Cl-. White16 claims that better results are obtained
when the bentone is mixed with finely divided particles of
glyceryl tri-12-hydroxystearate and an amide wax.
Onium salts can also be used to make lignites oil
dispersing.
Other Filter Cake Materials for Oil Base Muds
The mechanism by which fluid loss is reduced appears
31
to be adsorpt~on of the continuous phase which produces swelling.
The swollen particle is thus more compressible and the filter
cake becomes more and more impermeable as the differential
pressure across it is increased. Browning et al16 patented an
oil adsorbing vinyl toluene-acrylate copolymer as a fluid loss
control material for oil base muds.
v. Drilling Fluid Formulations
Considerable skill and experience is needed to
formulate a drilling fluid composition. This should be followed
by a series of empirical tests with added drill solids which
are representative of the formation being drilled. Two
formulations will be discussed which illustrate the application
of oil muds.
(1) An Oil Base Mud
A true oil base mud does not require water to
function yet it can function with water18 .
Filter cake and rheology are controlled using
a special air blown asphalt. A non-ionic
surfactant is introduced to act as a wetting
agent to oil-wet solids present. An emulsifier
emulsifies water present and calcium hydroxide
adsorbs CO 2 or H2S contaminants.
Blown asphalt can only be used in a narrow cut
of oil. (Aniline point 140 ± SOF). If the
aromatic content is too low, the asphalt
32 Chemicals in the Oil Industry
flocculates giving an adverse effect on
viscosity. If the aromatic content is too
high the asphalt may be dissolved by the other
components giving a black filtrate (possibly
formation damaging).
The soap class of materials such as calcium
stearate soaps and heavy metal rosinates are
satisfactory at low and moderate temperatures
but go into undesirable solution at high
temperatures. Their use is generally limited
to temperatures of less than 3000 F.
In oil muds the relatively weak hydrogen bonding
forces between the asphaltenes are readily broken
by heating, so that viscosity and gels tend to be
substantially reduced by temperature rises. To
obtain satisfactory gels the blown asphalt must
have a reasonably high penetration and a high
MP (260-2800 F)19. The addition of small
quantities of metal oxides (iron, titanium,
manganese, molybdenum, tungsten, lead, etc.)
also reduces filtration rates 20 . A good oil base
mud can tolerate about 5400 F without degradation.
(2) An Invert Mud
An invert emulsion must have water in the interior
phase. Modified clays and sometimes lignite are
used in their formulation to provide rheological
and fluid loss characteristics. The oil wetting
is achieved using a cationic surfactant,usually
quaternary amines. The surfactant must be
compatible with the quaternary amine and so is
usually also a quaternary amine. This surfactant
also replaces the clay oil-wetting agent which
degrades with time and temperature.
Bauman and Methven18 observed a high temperature
gellation problem at 410 0 F which may occur from
thermal degradation of the organophilic clays.
High molecular weight alkaline metal soaps are
used for emulsifying the water in the oil and to
improve rheological parameters and even filtration
loss in some systems 21 . Sharmur et a1 22 replaced
The Development and Application ofOil-base Muds
the soap by a sulphonated bitumen. Aluminium
stearate improved the gels after hot rolling.
Tests were carried out at 1400 C. A high
temperature emulsifier for invert muds is claimed
to be a mixture of oleyl amide and dimerised
oleic acid 25 • The dimerised oleic acid functions
to impart thixotropic properties.
VI Recent Developments in Oil Base Muds
Oil base muds have traditionally had two drawbacks;
these are slow drilling rate and pollution. These problems have
been partial-Iy solved with relaxed fluid loss muds and "clean
oil" muds.
Relaxed Fluid Loss Muds
Simpson 23 showed that a low viscosity invert oil
base mud with bentone for gels gave a much improved drilling
rate. Desired characteristics would be:
(1) low viscosity for continuous oil phase
(2) low concentration of emulsified solids
(3) low concentration of dissolved solids.
33
A low colloid oil base mud, API HT/HP 41 ccs, gave
a 40% faster drilling rate in carbonate rock than a conventional
invert oil base mud using a rock bit. It was found that,
provided sufficient CaC1 2 was present in the water phase, the
low colloid oil base mud was just as effective as the high
salinity conventional invert oil base mud in preventing shale
hydration.
According to O'Brien24 et aI, relaxing filtration
control provided drilling rates in shale/lime sequences equal
to or better than those attained by water based muds. Further-
more the filtrate from the HT/HP for an oil mud gives a
misleadingly high result because:
34 Chemicals in the Oil Industry
(1) The high pressures downhole gives a higher
oil viscosity and slower fluid loss.
(2) The HT/HP filter press models cake filtration
with no allowance for internal filter cake.
Only where filtrate losses are large in highly
permeable formations does it seem more economical to drill with
a high colloid oil mud.
"Clean Oil" Muds
It has long been known that oils other than diesel
could be used as a drilling fluid. Lack of pollution controls
and economics dictated until recently the use of diesel oil.
The UK Department of Energy laid down the following guidelines
relating to the use of low toxicity oil muds.
(1) Toxicity tests must have been carried out on the
base oil and/or mud formulation to the
satisfaction of the Ministry of Agriculture and
Fisheries (MAFF) and Department of Agriculture and
Fisheries for Scotland (DAFS).
(2) No whole mud shall be discharged.
(3) Adequate screen area should be available to cope
with the volumes of cuttings anticipated.
(4) Representative samples of the cuttings discharged
shall be taken each shift and analysed for oil
content. The results shall be submitted to the
DoE on completion of the well.
(5) The depth of hole drilled and the hole diameter
shall be reported for the period between each
sample.
(6) If this mud is to be used on the large diameter
(17~") hole,cuttings from the shale shakers
should have an oil content which does not exceed
16g of oil per 100g of dry solid averaged over
the whole drilling period.
The Development and Application ofOil-base Muds
(7) Samples of mud and/or cuttings shall be supplied on
request to the DoE.
(8) Special consultation with MAFF and DAFS shall take
place if it is proposed to use these muds within
30 miles of the UK coast.
Toxicity Tests on Clean Oil
Toxicity tests consist of recording the drilling
fluid concentration in sea water to kill 50% of fauna, and by
recording the drilling fluid concentration in sea water to
reduce by 50% the growth of phytoplancton.
Typical fauna used in a test are:
Anguilla Anguilla
Littorima Littorea
Mythilus Edulis
Scrubicularia Plana
Palaemon SP
Artemia Salina
Phaeodacrylum Tricornutum
Dunaliella Tertiolacta.
Biodegradability tests consist of recording the
percentage of biodegradability of mud in sea water after a
period of time.
If the drilling fluid at concentrations of 1000 ppm
is non-toxic to fauna and the mud is as biodegradable as a
water-based system this is regarded as acceptable. With flcl ean "
oil muds the cuttings may be discharged directly into the sea.
The oil used is a special refinery product,with the
aromatic fraction removed of a food grade quality. It is less
destructive to rubber components than diesel. Mud companies
claim the "clean fl oil retained on the cuttings is much less
than from the diesel oil base mud (being less polar, clean oil
gives less adhesion).
35
36 Chemicals in the Oil Industry
However the cost of a clean oil mud is 2-3 times
that of a normal oil base mud and where lost circulation occurs
costs can soar to a prohibitive level.
The other chemicals in the "c l ean " oil mud are
typical chemicals to make an invert mud.
VII. Future Requirements
To assess this one must first consider the various
fluid constituents and properties required with an oil base mud.
Secondly_one must then consider the way in which we assess fluid
performance and properties.
(1) Flu~d properties and Constituents
(a) Base Fluid
One obvious question is why aren't natural
vegetable oils used as the oil base. The
prices of crude vegetable oils in US $/lb26are :
Coconut oil NY 0.26
Coconut oil Pacific 0.235
Corn oil Midwest 0.26
Cottonseed oil Valley 0.19
Linseed oil 0.28
Peanut oil 0.30
Soyabean oil 0.18
Rape seed oil 0.18 (approx.)
Unfortunately, fats and oils are esters of the
trihydric alcohol glycerol and one would
expect that, under the conditions of high
temperature and pressure encountered in an oil
base mud system, they would hydrolyse back to
free fatty acids or their salts and glycerol.
Soyabean and rape seed oils appear to be the
cheapest of the naturally occurring oils.
If a natural cheap clean oil exists this would
have great value as a drilling fluid.
The Development and Application ofOil-base Muds
(b) Filter Cake Material
Some improvement in the grades of asphalts
available are possible. Ideally the asphalt
should have a high MP (2500 C - 3000 C), swell
and adsorb oil and be available in gelling
and non-gelling forms. The asphalt should be
available in "stick" form for ease of grinding.
Some research into high MP non-polluting waxes
(natural and synthetic) that swell in oil and
give good filter cake material would be of
value. Ideally the wax should dissolve slowly
in the crude oil so that when the well comes
on production any damage done to the formation
is removed.
(c) Emulsifiers and Wetting Agents
More research is needed into emulsifiers and
oil wetting agents that are stable at high
temperatures. At present no adequate
completion fluid exists for geothermal wells
(800 0 p). The emulsifier should be a solid so
that it can be blended into a sack material,
non-ionic so that it is stable to ca2+/Mg 2+
and ideally temperature stable to 800 0 P.
Usually, the emulsifier is temperature degraded
by the "bridge" breaking which links the hydro
philic and lipophilic parts of the molecule.
Work at present is underway into looking for
temperature stable bridges.
A sulfonyl derivative of diethanolamine has been
patented recently which seems to be stable to
6000 p27; the bridge is stabilised by
hyperconjugation.
~.. ~CH2CH20H
C12H25~S - N~
CH 2CH20H
The emulsifier should also be non-toxic and
biodegradable.
37
38 Chemicals in the Oil Industry
(d) Gelling Agents
At temperatures above 4500 F bentones undergo
degradation and are unsatisfactory. Asphalts
give a slow drilling rate. Work is needed into
improving agents to provide suspension properties
at high temperatures. Bentonite in water seems
to have no temperature limitations; it is also
a naturally occurring inorganic polymer.
Theoretically it should be possible to control
fluid loss with filter cake alone; some effort
should be made into producing a drilling fluid
with inorganic chemicals alone.
(e) Additives to Remove CO 2 and H2~
Better additives are needed to adsorb CO 2 and
H2S (which usually occur together). If ~
H2S is detected chemicals such as diethanol
amine should be added to remove it, otherwise
reactions will occur between the steel casing
and drill pipe. This can lead to the disastrous
situation of hydrogen embrittlement and casing
failure.
(2) Testing
The equipment needed to test drilling fluids at high
temperatures and pressures is becoming increasingly
complicated and expensive. Dynamic fluid loss is
still not properly understood and no standard is
available. Better standards for evaluating torque,
lubricity, drag are also needed. Standards for
abrasion are under review. The Universities have an
important role to play in carrying out independent
tests on oil field chemicals and acting as a link
between the oil and chemical industries.
Better methods of analysis for emulsifiers are
also important to understand fully the mechanisms
involved and reduce costly overtreatments.
Finally, more work is needed into the mechanisms
governing pollution by drilling fluids, how much
damage is done to the sea bed by physical smothering
The Development and Application ofOil-base Muds
of marine life by drill cuttings, how long does
it take adsorbed oil to diffuse away from the
cuttings into the surrounding waters?
REFERENCES
39
1. G. Miller, 3rd World Pet. Congress, Sect 11, The Hague, 1951.
2. L. E. Nesbitt, J. A. Sanders, J. Pet. Tech., 1981, 2377.
3. T. B. O'Brien, World Oil, 1981, 83.
4. R. Matherly, J. Pet. Tech., 1981, 1389.
5. J. C. Swan, US 1,455,010, Method of Drilling Wells.
6. T. V~ Moore, G. E. Cannon, US 2,055,666, Weighted OilBase Fluid.
7. P. van Campen, US 2,217,926, Non Aqueous Drilling Fluids.
8. G. Miller, US 2,316,967, Oil Base Drilling Fluid andMethod of Regenerating the Same.
US 2,316,968, Oil Base Drilling Fluid
US 2,356,776, Composition for Preparation of OilBase Drilling Fluid
US 2,475,713, Oil Base Drilling Fluid and MixingOil for Same
9. P. Fischer, US 2,542,019, Drilling Fluids
US 225,054, Treatment of Oil Base Drilling Fluids
US 2,573,959, Drilling Fluids
US 2,573,960, Drilling Fluid Concentrates
US 2,573,961, Low Resistance Drilling Fluids
US 2,612,471, Oil Base Drilling Fluids
US 2,617,767, Oil Base Drilling Fluids
10. P. Fischer, US 2,696,468, Conductive Oil Base Drilling Fluid
US 2,717,239, Electrically Conductive Oil BaseDrilling Fluid
US 2,721,841, Conductive Drilling Fluids
US 2,739,120, Electrically Conductive Drilling Fluids
US 3,111,491, Electrically Conductive Drilling Fluids
US 2,793,187, Conductive Oil Base Fluids
40 Chemicals in the Oil Industry
11. J. L. Lumrnus, US 2,793,996, Oil Base Drilling Fluids.
12. D. L. Wilson, US 3,099,624, Oil Base Drilling Fluidand Method of Use.
13. D. J. Shaw, Introduction to Colloid and Surface Chemistry,Butterworth, 237.
14. J. P. Simpson, J. C. Cowan, A. E. Beasley, J. Pet. Tech.,1961, 1177-1183.
15. E. A. Hauser, USP 2,531,427.
16. R. W. White, A. Franco, USP 3,977,894.
17. W. C. Browning, B. G. Chesser, J.L. Wood, USP 3,738,934.
18. N. E._Methven, R. Bauman, Petroleum and PetrochemicalInt'ernational, 1973, 13, ~, 50.
19. G. Miller, USP, 3,622,513, 1971.
20. R. E. McGlothlin, J. C. Bagget, R. L. Schultz, USP3,658,701.
21. G. R. Gray, S. Grioni, J. Pet. Tech., 21 (3), 261.
22. S. M. Sharma, K. K. Girdhar and R. M. Mathur, Bul. ONGC,1978, ~, 65-72.
23. J. P. Simpson, J. Pet. Tech., 1979, 643-650.
24. T. B. O'Brien, J. P. Stinson and F. Brownson, World Oil,(Aug 1977, March 1978), 75.
25. Halliburton Company British Patent 1,467,841.
26. Chemical Marketing Report, March 1, 1982.
27. Private Communication C. Scoggins, 11.
Lecithin
The Development and Application ofOil-base Muds
APPENDIX
Molecular Formulae
Oils
Lecithin
It consists of glycerol combined with two fatty acid
radicals, phosphoric acid and choline.
Choline is:
H2COOCR,H COOCR'
I ~oH2CO - p,---O-CH2CH2~(CH3) 30H-
OH
Castor oil is the triglyceride of ricinoleic acid.
Ricinoleic acid is 12-hydroxy - 9 - octadecenoic acid
CH3 (CH 2 ) SCH (OH) CH 2CH = CH (CH 2 ) 7C02H
Fatty Acids
Lauric acid CH3(CH2)10C02H
Stearic acid CH3 (CH 2 ) 16C02H
Oleic acid CH3(CH2)7CH=CH(CH2)7C02H
Waxes
Amide Wax
H" /HSA
N- (CH) - N
/ 2n '"R H
n is from 2 - 18
HSA is the acyl radical of 12-hydroxy stearic acid.
R is hydrogen or HSA.
41
Chemical Aspects of Oilwell Cementing
By l. Bensted, P. E. Haynes, E. Henderson, A. lanes andT. B. Smallwood
BLUE CIRCLE INDUSTRIES PLC, LONDON ROAD, GREENHITHE, KENT DA9 9JQ, U.K.
Abstract
Oilwell cementing is described from a chemical viewpoint.Standards and 'classification systems used for oilwell cements arediscussed. A brief survey of hydration is given, including those aspectslinked with the strength development that follows setting. The maintypes of chemical materials added to oilwell cements are considered.These include accelerators, retarders, friction reducers, lightweightadditives, densifiers, lost circulation controllers and strengthregression inhibitors. Reasons for making such additions are considered.
Portland cements, upon which oilwell cements are normally based,are composed of four principal clinker mineral phases - tricalciumsilicate, dicalcium silicate, tricalcium aluminate and a calcium aluminoferrite of more variable composition - to which some gypsum CaS042H20 (orits derivatives like hemihydrate CaS04\H20 or natural anhydrite CaS04)has been incorporated during manufacture to regulate the settingprocess. Where sulphate-resistance is required, the level of tricalciumaluminate must be reduced, since this phase is the most susceptible tosulphate attack. The rate of reaction of these mineral phases rises withincreasing temperature and so therefore does the rate of setting andhardening of a cement paste, as hydration products are formed between theclinker grains. In very severe conditions, set retarders such as calciumlignosulphonate are employed and, for the specially high temperatures andpressures and the extended pumpability times required in oilwellcementing grouts, the contents of the most reactive phases must belimited. This requires the manufacture of a special oilwell cementclinker.
An account of some observations of the early hydration behaviourof a Class G oilwell cement and the effects of retardation upon thehydration is given.
Chemical Aspects ofOi/well Cementing
Standards for Oilwell Cement
There are two principal standards for oilwell cement in use inthe world, the American Petroleum Institute (API) Spec 10 1 and theUSSR Standard GOST 1581-78 2 Different classification systems foroilwell cements are used ~n the two Standards.
The USSR Standard defines two basic grades of oilwell cement, onefor "cold" wells and the other for "hot" wells. The tests on cement mustbe made at 22± 2°C and 75 ± 3°C. For improving the properties of oilwellcements for both "cold" and "hot" wells, GOST 1581-78 permits up to 15%active and up to 10% inert mineral additives provided that they beground. In addition some special oilwell cements are produced undervarious technical specifications, e.g. sulphate-resistant types. Initial set for the "cold" well cements must be notless than 2 hours and for the "hot" well cements not less than 1.75hours. The retardation of the setting times of the "hot" well cements iseffected largely by the use of clinker low in alumina. The "hot" wellc~ment is designed for utilising at a temperature of about 75°C. Oilwellcements with 3-4% tricalcium aluminate content are produced both for"hot" and "cold" wells.
The API Standard, which is widely used in many countriesincluding the U.K., specifies nine classes of oilwell cements for use atdifferent well depths (see Table 1). Oilwell cement is defined by theAPI(l) for Classes A-H as the product obtained by grinding clinker,consisting essentially of hydraulic calcium silicates, to which noadditions other than set-modifying agents have been interground orblended during manufacture. Class J cement is defined as the productwhich conforms to performance specifications shown in the applicablephysical requirements of the API Standard. A suitable set-modifying agentis defined as one which has no deleterious effect on the durability ofthe hardened cement and causes no retrogression in strength. Wellcements include any class of cement defined above and may also includeoptional additives to obtain necessary performance. No specificationsare written for blends of well cement and optional additives. Certainoptional additives are covered by these specifications.
The API have collected considerable data about well conditionsfrom borehole logs and have used it to produce "average" conditions forgiven depths. These average conditions have been arranged into testingschedules for running standard specification tests 1. In the teststhe "static" bottom hole temperature (BRT) is the temperature achievedwhen the log is left in the hole for a length of time and approximates tothe actual stratum temperature. The "circulating" BRT is the temperatureattained at the bottom by drilling mud circulating down through the pipeand returning to the surface - it is lower because it does not come toequilibrium with the ground temperature. The cement at the bottom of thehole during circulation will be subjected to a pressure equal to the pumping pressure plus the hydrostatic head of mud or slurry in the hole, andhence total pressure also increases with depth of hole. For example, ifthe fluid h~8 a density of 100 Ib.jcu.ft., it will exert a pressure of695 lb.f/in. for each 1000 ft. depth.
43
44
Class
A
B
C
D
E
F
G and H
J
Chemicals in the Oil Industry
TABLE 1
API CLASSES OF OILWELL CEMENTS
Typical use
Surface to 6000 ft where special properties are notrequired. Ordinary type Portland cement only (ASTMType 1, BS12 Ordinary Portland cement).
Surface to 6000 ft where conditions require moderateor high resistance to sulphates.
Surface to 6000 ft where high early strength developmentis required. Ordinary type or moderate or high sulphateresistant types.
For depths between 6000 and 10,000 ft under conditionsof moderately high temperatures and pressures. Moderateor high sulphate resistant types.
For depths between 10,000 and 14,000 ft under conditionsof high temperatures and pressures. Moderate or highsulphate resistant types.
For depths between 10,000 and 16,000 ft under conditIonsof extremely high temperatures and pressures. MOderateor high sulphate resistant types.
Surface to 8000 ft as manufactured or can be used withaccelerators or retarders to cover a wide range of welldepths. Class H was introduced for us~ in higher teMperature holes than Class G cement.Moderate or high sulphate resistant types (the HSRspecification for H is only tentative).
Both classes are defined as basic cements in which noadditives other than calcium sulphate or water or bothshall be interground or blended with the clinker duringmanufacture. Class H differs from Class G typically inbeing coarser ground cement.
For depths between 12,000 and 16,000 ft as manufacturedwhere extremely high temperatures and pressures existor can be used with accelerators or retarders to covera wider range of well depths. No additions other thancalcium sulphate or water or both shall be intergroundor blended with the clinker during manufacture. This isnot a true Portland cement, being based largely on adicalcium silicate composition.
Chemical Aspects ofOi/well Cementing
Manufacture of oilwell cements
The normal raw materials and processes are used to make both theClass A (ordinary type) or other classes of moderate or high sulphateresisting clinkers of Portland cement which form the basis of oilwellcements, and which comply, with the chemical requirements. The compoundcomposition will of course vary within the set limits depending on thetargets set by the manufacturer bearing in mind the materials and plantavailable to him, and also the route which gives him the best control ofhis quality. Oilwell cements are used in geothermal wells for both oiland gas extraction.
Testing of oilwell cements
Normal analytical procedures, whether classical gravimetric ormodern instrumental, are satisfactory for controlling the chemistry of theproducts, while standard methods of determining soundness and finenessare well known.
The cementing properties however, require specialised apparatusfor testing compressive strength and thickening time under conditionssimulating those found in a well.
The API accumulated much data on temperature and pressureconditions at various depths in many wells. Using this data approximatesimulations of average conditions were worked out for testing purposes,and generally applied to the minimum and maximum conditions for use of agiven class of cement; for example a retarded Class D cement would beexpected to comply with tests simulating 6000 ft and also 10 000 ftconditions, the range of depths at which this cement would be used.
Cement slurries
The cements are used in the form of aqueous slurries made byinjecting cement into a fast moving stream of water.
The specimen for test is therefore made in the laboratory in aspecified high speed blender to the appropriate density. The requiredwater/cement ratios are given in API Spec 10 thus:
TABLE 2
REQUIRED WATER/CEMENT RATIOS
45
Cement class
A, B
C
D,E,F,H
G
J
W/C ratio (US gals water per 94 lb sackof cement)
0.46 5.19
0.56 6.32
0.38 4.29
0.44 4.97
As recommended by manufacturer
46
Strength tests
Chemicals in the Oil Industry
The slurry as prepared is poured into 2 inch cube moulds in aspecified way, and the moulds are then subjected to a regime of curingappropriate to the simulated well temperature conditions. For shallowwell tests simple water bath curing at atmospheric pressure and lOO°F(38°C) is used. For other tests, the bottom hole static temperature isobtained by adjusting the heating rate over a four hour period andmaintaining this until about 45 minutes before the end of the testperiod. In all cases the cubes are cooled to 80°F (27°C) beforedetermining the compressive strength in an appropriate hydraulic testingmachine.
In these tests the maximum pressure applied during curing is3000 Ib/in2 and not the bottom hole total pressure. This follows fromwork which showed that increasing the curing pressure from atmospheric toabout 2000 Ibs/in2 increased the compressive strength appreciably butapplied pressures higher than 2000 Ibs/in2 had little further effect.
Thickening time
This term is applied to the change of viscosity with time after acement has been slurried with water, and hence has an important bearingon the time for which a cement slurry remains in a pumpable state. Theviscosity is measured in Bearden units of consistence (Bc) so called inhonour of the late Bill Bearden who had served for many years as chairmanof the Cement Committee of the API.
Fig. 1 shows a typical curve shape of viscosity against timewhich indicates the ideal low viscosity (easy pumpability over a periodof time suitable for placing the cement slurry in the annulus, followedby a steep curve corresponding to the slurry stiffening prior to finalhardening) •
100
ThickeningTime
Time
Figure 1
TYPICAL CURVE SHAPE FOR THICKENING TIME
Chemical Aspects ofOi/well Cementing
Operating conditions
The API testing schedules mentioned above can of course beadapted for actual down hole conditions found in a well, but rather moreis required to ensure that an oilwell cement can be successfully used forcementing the hole. The borehole will not of course run through perfectstrata. There will be layers of varying mechanical strength, some hard,some friable, some subject to sloughing, the permeability will vary andindeed some strata will be fissured to a greater or lesser extent. Thesefaults will be observed by the experienced drilling team and measureswill be taken to ensure that a good cementing job will be carried out.These include the use of various additives.
Additives
As with ordinary cements for construction jobs the chemicalreactions occurring during hydration of oilwell cement can be modified bythe use of additives such as calcium chloride, lignosulphonates etc.
Lignosulphates are by-products from the paper pulp industry.They are impure materials, variable in composition, whose completestructures are not precisely known. Lignosulphonates are polymeric,based upon substituted phenylpropane units containing -OH, -C02H, -OCH3and -S03H groupings. These polymers have typical average molecularweights of -20,000 - 30,000 in a typical distribution range -300100,000. They are not linear but take the form of spherical microgelswith charges predominating on the outside of the spheroids - the internalcarboxyl and sulphonate groups are non-ionised. Lignosulphonates tend tobe only 20-30% ionised. Calcium and sodium lignosulphonates are the mostfrequently encountered commercial forms. They contain sugar impurities~1-30%, mostly pentoses 3. Bacteria can feed on the sugar content andin so doing can degrade the lignosulphonates, which thereby lose theirdesirable properties like retardability. Under these conditions theeffective active life of lignosulphonates may not be very long.For this reason lignosulphonates are either treated with anti-bacterialformulations, or suitably modified to minimise the sugar content and thentreated with a suitable bactericide, so as to extend active lifeindefinitely.
For given well conditions a service company will normallyrecommend and supply the cement and proportions of additives to produce asatisfactory cementing job. Most service companies have their own "brandnames" for such materials which are commonly of similar composition forsimilar use. Over the years improvements have occurred to produce therequired cement slurry properties and to extend the range of use as depthand temperature have increased.
a) Accelerators
Accelerators are normally used in cementing shallow holes orsurface casings at low temperatures where thickening time wouldbe long and strength low. It is generally accepted that astrength of about 500 psi is needed to support a casing and the
47
48 Chemicals in the Oil Industry
use of accelerators allows this to be achieved in a comparativelyshort time, possibly in 4 hours. The thickening time could beapproximately halved but, since pumping times for such shallowholes are short, this does not matter.
The most commonly used accelerator is calcium chloride CaC12;a dosage of 2% by weight on cement would be satisfactory in mostcases. Sodium chloride NaC1 in doses of about 2 to 4% is alsoused but large doses retard. Sea water is thus also anaccelerator and since in offshore work the cement slurry isusually made with sea water, this must be taken into account indesigning the mix. Sometimes a mixture of cement and hemihydrate plaster is used for producing short thickening time andrapid strength development.
b) Retarders
Retarder.s are required to lengthen the thickening time.
These are already present in manufactured retarded cements APIclasses D, E and F, being added at the cement plant in quantitiesadjusted to give thickening times greater than the API minimumfor the given class of cement.Current practice however is to use basic oi1wel1 cements (Class Gand Class H) and a retarding additive sufficient to cope with theparticular well conditions in holes deeper than about 8000 ft.
The most frequently used retarder is probably a calcium 1ignosulphonate which is generally satisfactory for cementing to12 j OOO to 14,000 ft. However, some 1ignosulphonates modifiedwith other organic cOlnpounds such as hydroxycarboxylic acids areused for higher-temperature conditions. Other organic substancessuch as gums and starches have been used. One of the mosteffective for high-temperature work is carboxymethylhydroxyethyl cellulose. Amongst inorganic retarders,borax Na2B40710H20 and sodium chloride NaCl (highconcentrations) have been employed 4.
As stated above high concentration (> 20% by weight of cement) ofsodium chloride will retard oilwel1 cements and will also reducestrength. It is sometimes necessary in drilling through saltbeds to pre-saturate the cement slurry with salt to preventformation salt being dissolved into the slurry.
c) Friction reducers
These are dispersants which improve the flow properties of theslurry by breaking up cement agglomerates and freeing the waterfor its proper function. They produce lower-viscosity slurriesand allow turbulent flow conditions to be reached at lower pumppressures. Substances used as dispersants include lignosulphonates, salt and polymers such as acrylamides andnaphthalene condensation products.
Chemical Aspects ofOi/well Cementing
d) Lightweight additives
In cases where lower-density cement slurries are required, somereduction can be brought about by increasing the water content.However, if too much water is added separation will occur. Thematerials added to produce lower-density slurries allow theaddition of greater amounts of water without segregation and,having relative densities less than that of cement, reduce thedensity of the solid phase as well.
The most frequently used material is bentonite (specificationsfor which are given in API Spec 10). An approximate formulationis Al5/3M81/3[(OH)2/Si4010]173Na1/3(H20)4. A sodiumbentonite, often called "gel", was used in the early days todecrease weight and increase the volume of cement slurry sinceit absorbs water and swells. Depending on requirements anythingfrom 2% to 12% (by weight of cement) can be used. For each 1%added, the-water can be increased by about 5.3% and slurrydensities of 12-13 lb per US gallon can be achieved yielding anextra 60% of volume of slurry. Higher additions of bentonite maybe used, but only if dispersants are used to reduce the viscosityof these high gel slurries. Salt is also sometimes used in theseslurries.
Diatomaceous earth Si02 x H20 and attapulgite, approximateformulation (Mg,Al)2 [OH/Si4010]2H20, behave similarly but may costmore. Their only advantage may be that their viscosities arelower than those of bentonite slurries.
Other materials used are gilsonite, a naturally occurringasphaltite consisting of high molecular weight hydrocarbons, orexpanded perlite, a volcanic siliceous glass (though the latteris less stable mechanically when used in high pressure areas),pulverised fuel ash (pfa), anhydrous sodium metasil~ate Na2Si03,crushed coal and a special calcined shale - cement •
e) Densifying additives
These are required where high formation pressures are encountered, so that blowout of the cement slurry might be prevented.High-density materials such as barite BaS04 and haematite Fe203are the commonest densifying additives. They do not generallyappear to have a significant effect on the cement properties.Sand Si02 may also be used.
f) Lost circulation control additives
Strata that are highly porous or fissured give rise to "lostcirculation", i.e. the cement slurry is lost into the stratainstead of circulating to the surface. This can be overcome byusing a low density slurry (to reduce pressure on a weak zone)and adding materials which may be blocky granules (walnut shells,gilsonite, crushed coal, expanded and semi-expanded perlite) that
49
50 Chemicals in the Oil Industry
form bridges and lamellated materials like cellophane flakes thatform flake type mats 4. The bridges or mats are of sufficientlylarge particle sizes to cover the fissures and build up a layerof cement to seal the thief zone. Fibrous materials like nylonfibres are effective in drilling fluid for sealing largeopenings, but are not normally employed in oilwell cementingbecause of the tendency to plug surface and downhole cementingequipment. Also, most other fibrous materials contain organiccompounds which can seriously retard cement thickening time.
g) Strength r~gression inhibitors - pozzolan or silica flour
A pozzolan is defined 1 as a siliceous or siliceous andalwninous material which in itself possesses little or nocementitious value, but will, in finely-divided form and in thepresence of moisture, chemically react with calcium hydroxide atordinary temperatures to form compounds possessing cementitiousproperties. Glassy volcanic material and diatomaceous earthSi02 x H20 are examples of natural pozzolans, whilst pfa is anexample of an artificial pozzolan.
At temperatures above about 230-250°F (-110-120°C), Portlandcements suffer from regression of strength, i.e. instead ofthe usual increase in strength with time, loss of strength andalso of permeability occurs due to the formation of largecrystals of a -dicalcium silicate hydrate Ca2 (HSi04)OH. Thisphenomenon is at least partly prevented by the addition of activesilica from pozzolan or silica flour, for example, which willreact with lime released by the change in crystalline form of thecalcium silicate hydrates that causes the loss in strength.Additions of, say,-35% silica flour (Si02) prevent formation of
a - dicalcium silicate hydrate at these temperatures and give aCaO/SiOZ ratio of ~0.8, which is favourable for the formationof tobermorite Ca6(H2Si6018)4H20, a good strong binder, thathas a smaller crystal size.
Class J cement, which can be employed to depths of 16 000 feetwithout containing retarders, does not need additions of silicaflour.
General
One of the requirements for oilwel1 cements is that they shouldbe compatible with the additives likely to be used for modifying theirproperties for given conditions. The service companies therefore tend towork beyond the API Spec 10 for cement properties, and require cementsthat show consistent properties from batch to batch, so that their job offormulating satisfactory mixtures of cement and additives is thereby madeeasier.
Hydration Behaviour
The essential criterion for oi1we1l cementing is that the slurryof cement and water should remain capable of being pumped down to its
Chemical Aspects ofOi/well Cementing
required position before stiffening takes place.
Oilwell cements are normally based upon Portland cementcompositions, which comprise four principal clinker mineral phases trica1cium silicate Ca3SiOS, dica1cium silicate Ca2Si04, trica1ciuma1uminate CaJA!206 and a calcium a1uminoferrite of more variablecomposition approximately Ca2A1FeOs - to which some gypsum CaS042H20 (orits derivatives like hemihydrate CaS04~H20 or natural anhydrite CaS04)has been incorporated during manufacture to regulate the settingprocess. Where sulphate-resistance is required, the level of tricalciuma1uminate must be reduced, since this phase is the most susceptible tosulphate attack 5 . The detailed hydration of ordinary and su1phateresisting Portland cements has been described 6 . Strength is obtainedprincipally from the reaction of the silicate phases to form calciumsilicate hydrate. Trica1cium silicate is the main cementing phase, withdica1cium silicate (normally in the B-form) reacting at a much slowerrate to form similar hydration products. Early strength is largelyobtained from~trica1cium silicate, but at later ages (e.g. 28 days andbeyond) the contribution from B-dicalcium silicate becomes veryimportant.
At surface temperatures or just above, the silicates react withwater to form an amorphous calcium silicate hydrate, which can berepresented approximately as follows:
Ca3SiOs + 6 H20 ~ Ca3Si2073H20 + 3 Ca(OH)2
Ca2Si04 + 4 H20 ---) Ca3Si2073H20 + Ca(OH)2
These reactions are not of the dissolution and precipitation type, butoccur topochemica11y at the silicate surfaces. The equations are onlyapproximate, because the calcium silicate hydrate formed, known asC-S-H(I), is in reality a very poorly crystalline non-stoichiometricmaterial consisting principally of dimeric units at first, butsubsequently slowly polYmerising after a few days to give higher linearunits like pentamer and thence octamer with the passing of time.
Up to NIOO°C the hydration products from the tri- and B-dicalciumsilicate phases do not differ essentially from those formed at ambienttemperature, although there may be some differences in morphology andmicrostructure. No changes in the mechanism of hydration have beenreported in the temperature range from ambient to 90°C, but morepolysilicate hydrate in relation to dimer was found in calcium silicatehydrate pastes at 65°C than at 25°C 7. The hydration of B-dicalciumsilicate is accelerated in relation to that of tricalcium silicate atelevated temperatures, which may be related to the increased solubilityof silica and decreased solubility of calcium hydroxide under thesecondi tions 8 •
Different products are formed when Portland cements are hydratedunder geothermal conditions, where high temperatures and pressuresexist. Hydrated aluminate and a1uminoferrite phases have not generallybeen observed under these conditions, so presumably the Al 3+, Fe3+ andS042- ions have become incorporated in the calcium silicate hydrate
51
52 Chemicals in the Oil Industry
phase(s). The calcium silicate hydrates formed under such conditionsrange from X-ray amorphous t~_y~ghlY crystalline phases. A number ofstudies have been reported •
Oilwell cements are normally used with-35% of strengthregression inhibitor, e.g. silica flour, to prevent formation of adicalcium silicate hydrate Ca2(HSi04)OH, a dense orthorhombic phase whichis deleterious to strength and permeability. Under these conditionstobermorite Ca5(H2Si601a)4H20 is the first crystalline phase to form.Formation of tobermorite is associated with good strength andpermeability. Above about 150°C it will transform to xonotliteCa6Si6017(OH)2 and gyrolite Caa(Si4010)(OH)4-6H20. Gyrolite willsubsequently transform at,., 250°C to truscottite Ca7(Si4010)(Sia019)(OH)4H20. The temperatures in deep wells can easily reach~400°C andtruscottite and xonotlite have been detected. At higher temperaturestruscottite decomposes and a residue containing quartz may remain.Xonotlite and gyrolite generally have good strength and moderatepermeability. -Truscottite has a lower permeability than xonotlite.
It should be remembered that conditions in oilwells are far fromideal 14. Geothermal waters are rarely fresh and their dynamic natureprobably precludes equilibrium conditions. Geothermal zones areinherently porous or highly fractured. Extenders and other additives areall likely to affect cementitious behaviour to a greater or lesserdegree. Such widespread variations mean that standard conditions forequilibrium transformations do not exist. Accordingly, the actualproducts formed in a given oilwell will depend on the precise conditionspertaining in that particular oilwell and may include calcium silicatehydrates and related mineral compositions of different types from theaforementioned.
Mechanism of Retardation
Until fairly recently it was thought that retarders of cementhydration, which commonly contain -OH, -C02H groups or both, functionedby adsorption onto the surfaces of the cement particles to formmonolayers and thus physically impede hydration. However, examinationof the hydrated systems in the presence of retarders has shown thatwhilst hydration of the tri- and dicalcium silicate phases is indeedretarded, the hydration of the tricalcium aluminate and tetracalciumaluminoferrite phases to form ettringite is enhanced, often substantiallyso. Clearly, the idea of an all-embracing monolayer physically thwartinghydration can no longer be entertained. Where adsorption takes place, aswith lignosulphonates, there is clearly a selective element involved inthe process, which has the effect of accelerating early aluminate andaluminoferrite hydration. The precise mechanism is not to date clearlyunderstood and requires further investigation.
In the less deep wells, where the normal hydration productscalcium silicate hydrate C-S-H(I) and ettringite are formed duringhydration, a possible mechanism involves the following.
It appears that when the clinker silicate phases (primarilytricalcium silicate, or alite) begin to hydrate, the calcium ions reactpreferentially to form ettringite, rather than assisting with the initial
Chemical Aspects ofOilwell Cementing
formation of C-S-H. This results in the transient formation of amorphoushydrated silica at the clinker silicate surfaces. These latter surfaces,particularly alite, are still reacting, but are not initially formingC-S-H in quantities comparable to those being formed in the absence ofretarders like sugars and lignosulphonates. Scanning electron microscopyshows no evidence for the existence of "skin" barriers. Indeed, aprotectionist barrier is inconceivable because more, not less, ettringiteis formed during early hydration. It is possible that the retarder couldlocally reduce the pH in the vicinity of exposed alite particles inparticular. As a result of this, calcium ions at the alite surfaceswould be caused to migrate to aluminate (and, to a lesser degree, toaluminoferrite) phase surfaces and preferentially react there to formettringite. There would thus be a relative deficiency of calcium ions atthe alite surfaces, as a result of which C-S-H formation there would beimpeded.
Therefore, when retardation and retarders are spoken of, it isnecessary to b~ precise concerning the meaning. Retardation refers tothe effect upon setting or thickening of the cement and not necessarilyto particular chemical reactions that take place during cementation.
Investigation of the Early Hydration Chemistry in Schedule 5 ThickeningTests
a) Background
An examination of the early hydration behaviour of a Class Goi1well cement subjected to API Schedule 5 treatment 1 wascarried out under standard and retarded conditions. Thisinvestigation was undertaken in order to understand more fullythe nature of the oilwe1l cement hydration process.
API Schedule 5 for thickening time is for casing cementing downto a depth of 8000 feet. The final temperature reached is125°F (52°C). The mixing water (distilled water) is 44%. Forretarded cements tested under Schedule 5 conditions, no gelationshould occur and the retarding effect at a given retarder dosageshould be approximately constant from batch to batch.
b) Experimental Part
API Schedule 5 thickening time experiments (1) were undertakenusing a production Class G oilwel1 cement a) alone, b) with 0.3%of a commercial calcium lignosulphonate retarder, c) with 0.4% ofthis retarder. Thickening time curves were drawn (Figure 2).The tests were repeated to appropriate inflection points and theactual thickening times on the thickening time curves. The testruns to each of these stages were immediately followed bystopping the hydration by acetone drying in a glove box under anatmosphere of nitrogen gas to prevent aeration of the relativelysmall partially hydrated samples obtained 17 . This meantthat(i) for the cement without retarder, hydration proceeded to20, 60 and 103 minutes respectively; (ii) for the cement with0.3% retarder, hydration was stopped at 90, 130 and 142 minutesrespectively; (iii) for the cement with 0.4% retarder, the
53
54 Chemicals in the Oil Industry
Figure 2 THICKENING TIME CURVES
100 103 142 222
90
80
70
u 60CO
~ 50Vl0uVl
> 40
30
20
10
o 50 100 150 200 250
Time (minutes)
Chemical Aspects ofOilwell Cementing
corresponding times at which hydration was stopped were 160, 200and 222 minutes respectively. After drying out with acetone, thesamples were all stored in a desiccator over silica gel.
These partially hydrated cement specimens were examined by avariety of experimental techniques - IR, XRD, SEM, TG and DSC. IR(Figure 3) was performed on a Perkin-Elmer 577 infrared spectrophotometer over the wavenumber range 200-4000cm- 1 using KBrdiscs, XRD with a Philips' X-ray diffractometer, SEM with an IS1DS 130 scanning electron microscope, TG with a Stanton's TR-02thermobalance and DSC using a Setaram differential scanningcalorimeter.
c) Results and Discussion
The unhydrated cement contained alite, belite, ferrite and alittle aluminate as well as calcium sulphate and some calciumhydroxide. A large part of the calcium sulphate was in the formof hemihydrate CaS04~H20 as a consequence of some dehydration ofgypsum by the grinding of the clinker with gypsum during themanufacturing process:
55
+ 1\ H20
c)(i)
The presence of some calcium hydroxide was due to themoisturisation of some of the free lime content of the clinker:
CaO + H20 ~ Ca(OH)2
Unretarded Cement
For the unretarded cement, after 20 minutes of Schedule 5hydration, some gypsum was observed, which would have formed fromhydration of the hemihydrate:
Some ettringite was also formed. This would have arisen byreaction of the ferrite phase and calcium hydroxide and also ofthe small quantities of aluminate phase present with calciumsulphate and water. Simplified chemical equations to representthese chemical reactions are given thus:
Ca2(Al,Fe)05 + Ca(OH)2 + 3 {CaS042H20} + 25 H20 ~
Ca6[(A1,Fe)(OH)6]2(S04)326H20
Ca3Al206 + 3 {CaS042H20) + 26 H20 -+ Ca6[Al(OH)6]2(S04) 326H20
Because of the impure nature of the phases and the fact thatAl(II1) readily enters into solid solution with Fe(III), it isnot possible in practice to apportion how much ettringite arisesfrom the ferrite phase and how much arises from the a1uminatephase. Small amounts of calcium hydroxide, as present in theunhydrated cement, were also observed here. No calcium silicate
56 Chemicals in the Oil Industry
ricure ,Infrared Spectra ot (1) tJ~ratecl Cl... G Oil..11 C...Il't, (2) CeaentB7d.ratecl UDretard" to !hick.aiae Tt. of 10' JIIillut•• , (3) Ce.ent Hydrated with 0•• Retarder to Thick.Bin« '1'i_ ot 222 JIIillutell •
i800
,1000
I1200
i1400
i1600
i3000 2700 180035004000
•0....::
wuz
~~z<C(
~
i4000 3500 3000 2700 1800 1600 1400 1200 1000 800 600 LOO 200
WAVENUMBER Icm- 1 )
2
.~
~z
~
~<C(
~
i i i i i i i i I4000 3500 3000 2700 1800 1600 1400 1200 1000 800 600 LOO 200
WAVENUMBER (cm-I)
3
~
WAVENUMBER (cm -1 )
Chemical Aspects ofOilwell Cementing
hydrate was observed.
At 60 minutes hydration the gypsum content had decreased and theettringite had increased compared with 20 minutes hydration. Nocalcium silicate hydrate was observed and there was no furtherperceptible rise in the quantity of calcium hydroxide present.
At the thickening time of 103 minutes, similar quantities ofgypsum as at 60 minutes hydration were found to be present.Ettringite had significantly increased. Calcium silicate hydrateC-S-H(I) was detected as was some additional calcium hydroxidefrom the onset of significant hydration of the silicate phases(principally alite):
c)(ii) 0.3% calcium lignosulphonate retarder
At 90 minutes hydration very small quantities of gypsum wereobserved. The quantities of ettringite present were greater thanfor the unretarded cement at its thickening time. Calciumhydroxide was found in similar amounts to those contained in theunhydrated cement and no calcium silicate hydrate was detected.The lignosulphonate affects the thickening behaviour byfunctioning as a dispersant or friction reducer, as well as aretarder, as a result of which the development of thickening isless than for the unretarded system.
After 130 minutes hydration the quantities of gypsum present werestill very small. Ettringite had increased in amount. Calciumhydroxide was still present in similar quantities and again nocalcium silicate hydrate could be detected.
At the thickening time of 142 minutes small quantities of calciumsilicate hydrate C-S-H(I) became apparent along with some extracalcium hydroxide from alite phase hydration. Ettringite waspresent in similar quantities to those observed at 130 minutes.Gypsum was no longer detected, suggesting that at least some ofthe sulphate ions were entering into solid solution with silicateions in C-S-H(I).
c)(iii) 0.4% calcium lignosulphonate retarder
At 160 minutes hydration larger quantities of ettringite werefound than at the thickening time for the Class G cement with0.3% retarder. Gypsum was not detected, presumably because ofits rapid consumption to form ettringite. Calcium hydroxide waspresent in similar quantities to those found in the unhydratedcement. No calcium silicate hydrate was experienced.
After 200 minutes hydration ettringite had slightly increasedover that present at 160 minutes. Neither gypsum nor calciumsilicate hydrate were recorded, and similar quantities of calciumhydroxide to those found at 160 minutes and in the unhydratedcement were apparent.
57
58 Chemicals "in the Oil Industry
At the thickening time of 222 minutes, quantities of ettringitehad increased somewhat over those present at 200 minutes, butlikewise no dihydrate gypsum was detected. Calcium silicatehydrate C-S-H(I) was just detected along with some calciumhydroxide from alite hydration by S~~. More ~ttrin~ite was foundhere than h.t the thickeninp- time with O. 3~cJ retarder present.
c)(iv) General Points
These results are of interest in that they show the thickeningtimes in the API Schedule 5 to be associated with the onset ofsignificant calcium silicate hydrate C-S-H(I) formation and not sodirectly with the levels of ettringite formed. In the presenceof the calcium lignosulphonate retarder formation of ettringiteis accelerated and that of calcium silicate hydrate C-S-H(I)retarded. Hence retarder response is likely to be influencedmuch more by the extent of silicate phase hydration than by theextent of aluminoferrite and aluminate phase hydration. Theviscosity changes appear to be linked more to morphologicalchanges than to direct chemical reactions increasing thequantities of products formed. The ettringite formed is moredisordered in its structure than the synthetic variety because ofthe effects of impurities contained in solid solution in thephase. Thickening time seems to be more sensitive to C-S-H(I)formation in the presence of more ettringite in retarded systems.In the API Schedule 5 testing the temperature rises to 52°C.From the phases detected during hydration, the rise intemperature to 52°C is insufficient to decompose the ettringiteformed and to allow the formation of any crystalline calciumsilicate hydrates - only the very poorly crystalline C-S-H(I) isencountered at the actual thickening time. The hydrationbehaviour of oilwell cement during Schedule 5 thickening issimilar to that encountered during the normal setting 18 ofPortland (and especially of sulphate-resisting Portland) cement,where the onset of normal setting is due primarily to theformation of significant quantities of C-S-H(I) which immobilisethe water present - ettringite plays only a secondary role inthis respect. The main difference from normal setting at ambienttemperature is the temperature effect. As a result, duringSchedule 5 hydration the various chemical reactions areaccelerated because of the higher temperatures (rising to 52°C)encountered.
d) Conclusion
Hydration of a production Clas~ G oilwell cement under both unretarded and retarded conditions by API Schedule 5 to therespective thickening times has shown some similarities withnormal setting behaviour at ambient temperature, except that theprocesses are speeded up because of the temperature rise.However, from the published work on geothermal samples 9-16,19where crystalline calcium silicate hydrates of various types andtheir derivatives are commonly encountered, it is clear that oncethe cement casing has been pumped into position, hydrothermalchanges take place with the passage of time. Such changes resultin the development of crystalline calcium silicate hydrates andthe decomposition of ettringite, whose constituents become
Chemical Aspects ofOi/well Cementing
incorporated into the silicate phases. Consequently thechemistry of early hydration of Class G oilwell cement as in APISchedule 5 is s~mply the initial process prior to the occurrenceof hydrothermal reactions, particularly as the wells becomedeeper, at later stages.
Acknowledgement
The authors wish to thank Blue Circle Industries PLC forpermission to publish this work.
TABLE 3
CHEMICAL ANALYSIS OF CLASS G CEMENT
!PI Limit
59
~
C3
S 64.7
C2s 7.0
C3A 2.1
C4AF 14.0
C4AF + 2 x C3A 18.2
K20 0.25
Na20 0.16
Na20 equivalent 0.32
MgO 0.7
5°3 1.9
Loss on Ignition 0 0 9
Insoluble Residue 0.30
!48 min - 65 max
3
24
0.75
6.0
60
References
Chemicals in the Oil Industry
1. API Specification for Materials and Testing for Well Cements.API Spec 10, First Edition, January 1982. American PetroleumInstitute, Washington D.C., 1982.
2. USSR Standard GOST 1581-78: Portland Cement for Oi1we11s.Moscow, 1978.
3. M.R. Rixom: "Chemical Admixtures for Concrete" E & F Spon Ltd.,London, 1978. p.6.
4. G.O. Suman Jr. and R.C. E11is: World Oil 1977, 185, 48.5. J.Bensted: World Cement Tech. 1981, 12, 178.6. S.N. Ghosh: "Advances in Cement Technology". Pergamon Press,
Oxford, 1982.7. H.F.W. Tay10r and D.M. Roy: 7th lnt. Cong. Chem. Cement, Paris,
1980. Principal Reports. Editions Septima, Paris p.II-2/1.8. J.P. Ska1ny and J.F. Young: lnt. Congr. Chem. Cement, Paris,
1980, Vo1.1. Principal Reports. Editions Septima, Paris,p.ll-1/3.9. A.I. Bu1atov and D.F. Novohatsky: 6th Int.Congr. Chem. Cement,
Moscow, 1974, Vol. Ill. Stroyizdat, Moscow, 1976, p.243.10. V.S. Danyushevsky and T.I. Rataychak: 6th lnt. Congr.
Chem. Cement, Moscow, 1974. Vol. Ill, pp.248-251. Stroyizdat,Moscow.1976.
11. G.L. Ka10usek and S.Y. Chaw: Soc. Petr. Eng. J. 1976, No.12, 307.12. A. Nakamura, T. Amaya, K. Kobayashi and M. Tsuji: Cement Assoc.
Japan - Rev. 32nd Gen. Meeting - Technical Session 1978, p.75.13. D.M. Roy, F.L. White, C.A. Langton and M.W. Grutzeck: AlME
lnt. Symp. Oilfield and Geotherma1 Chem. Houston, Texas, 1979,p.153.
14. C.A. Langton, E.L. White, M.W. Grutzeck and D.M. Roy: 7thlnt. Congr. Chem. Cement, Paris, 1980. Vol. Ill. Communications(cont.) Editions Septima, Paris,p.V/145.
15. K. Luke, H.F.W. Tay10r and G.L. Ka1ousek: Cement ConcreteRes. 1981, .!.!., 197.
16. E.B. Nelson, L.H. Ei1ers and G.L. Ka1ousek: Cement ConcreteRes. 1981, 11, 371.
17. J:'""Bensted and S.P. Varma: Cement Tech. 1974,2., 440.18. J. Bensted: Silicates lnd. 1980, 45, 115.19. L.D. Wake1ey, B.E. Scheetz, M.W. Grutzeck and D.M. Roy:
Cement Concrete Res. 1981, .!.!., 131.
The Role of Chemicals in Oil and Gas Production
By E. J. Vase
SHELL U.K. EXPLORATION AND PRODUCTION, 1 ALTENS FARM ROAD, ABERDEEN, U.K.
Introduction
A production platform in the North sea will have some or all of the
following, depeming whether it is producing gas as most are in the
southern North Sea, or producing crude oil as in the northern
operations area:-
A. Oil or gas producing wells,
B. Water injection wells, and/or
C. Gas injection wells,
D. Crude oil comitioning plant,
E. Gas comitioning plant,
F. Water filtration plant,
G. Gas and/or water injection facilities,
H. Effluent comitioning plant.
I. In addition there are domestic areas, plus administration
offices, communications and a helicopter landing area with
aircraft refuelling ability, maintenance workshops, stores,
sickbay etc. These installations are communities of between
200 to 400 men with all the logistical problems of life
support in a desert of water.
Shell U. K. Exploration and Production (Shell Expro for short) operates
the Auk, Brent, Cormorant, Nor th Connorant, Dunl in am Fulmar Nor th Sea
oilfields, and substantial parts of the Leman and Indefatigable
southern gas fields, on behalf of Shell, Esso and other partners.
Figure 1 shows fields some 150 kms N. E. of Shetland which are
linked to the Brent System for oil export am the Far North Liquids and
Associated Gas System (FIAG» for gas exp:>rt. Shell Expro operates
this complex networ k to serve both Shell/Esse fields and those of other
operators.
62
SuJtom
Orkney
~~~O
J
"' Mossmorran~raefoot Bay
Figure 1
Chemicals in the Oil Industry
SHELL Operatedand Associated
Oil and GasSystems
N.North Sea
c===J Oilc===J GasDD Proposed
Gas
The Role ofChemicals in Oil and Gas Production
'!he purpose of this paper is to deseribe the process plant on a typical
North Sea oil prcx1uction platform and indicate where chanicals are
often used to assist in winning oil ani gas ani their transfer to
shore. '!he mode of operation and use of chanicals outlined in this
paper is based on the Shell/Esso Brent field. '!he use of chanicals by
the many other operators will differ but we all face snnilar problems
and these differences will not be very great.
Platform Processes
Table 1 shows the design capacity of Brent Bravo production
platfoDn which is fairly typical for the Northern North Sea.
63
Table 1 BRENT B PLATFORM FACILITIES
DESIGN CAPACITY
CRUDE OIL/GAS SEPARATlrn
CRUDE OIL S'IDRAGE
EXPORT CAPACITY
GAS CCMPRESSICN
G.2\S PROCESSING
WATER INJOCTlrn
DRILLING
PCNlER GENERATICN
160,000 bid of oil320 million sef/d of gas
950,000 bls
275,000 bid
190 million scf/d
285 million sef/d
350,000 bid
38 well coniuctors
Reservoir Depth 9,500 feet
62.6 Mega watt
UTILILTIES: WATER MAKERSCHEMICAL PLMPSINSTRLMENI' AIRHEATING AND VENrlIATIONFIRE PlMPS
IN ADDITION BRENT B IS THE MAIN EXFORT STATION FOR BREm' ~S AND
GAS LlQUIOS
64 Chemicals in the Oil Industry
160,000 barrels per day will provide adequate daily feedstock for an
average sized refinery.
62.6 Mega Watt would light a small town. '!he four Brent Platforms
produce and use electrical power equivalent to the needs of a city the
size of Aberdeen.
285 million standard cubic feet is sufficient gas per day to provide
2,800 houses with gas for one year.
When crude oil is produced it contains large proportions of dissolved
gas which ha~ to be separated and treated separately to:
(a) Produce a low vapour pressure (safe for handling) crooe oil.
(b) Provide gas for energy used on the platform, if required.
(c) Provide gas for gas injection or gas sales, if required.
In most North Sea oil bearing formations the oil is in contact with
large reservoirs of water (known as formation water) and as the oil is
produced it is replaced in the oil bearing zone by this formation
water. Eventually this water is produced with the crude oil: therefore
all producing platforms are provided with the means to separate this
water fran the crude.
Figure 2 depicts a typical process train on a Brent platform.
There are usually two such trains. Crude oil from the well manifold is
separated by passing through four separators each maintained at
progressively lower pressure and temperature until crude leaving the
last separator has a low vapour pressure and can be safely stored until
exported. Oil fran the wells is a mixture of liquid hydrocarbons and
dissolved gas and nearly always in association with water. '!his water
is often an emulsion which can be difficult to break.
Chemicals used at this stage are a danulsifier, a carbonate scale
inhibitor and a sulphate scale inhibitor, all injected at the well
manifold or before the well choke. Wi th certain crooes wax deposition
can be a problem at various stages in the process calling for the use
of wax crystal modifier.
BRENT PLATFORM PROCESS
FROM WELLMANIFOLD
METHANE65%
GLY.
ETHANE17-20%
PROPANE5-10 %
35% OF GAS
Figure 2
BUTANE2-8%
TO GAS PIPEL INE(140 BARS) ORGAS INJECTIONWELLS (415 BARS)6,OOOlbs/m.2
FUEL SYSTEM
150,000bbl/D
~CRUDE
+ NGL
~~
~~
~
~Q~
~(=:;'~r;;--5'
~~;:::~
Cl~V:J
~
~~:;::~cs';:::
0'1VI
66 Chemicals in the Oil Industry
On the Brent platfonns, water will drop out in the storage cells prior
to export to the Sullom Voe Oil Terminal, but on most other platforms
water is separated in the various stages of separation at the same time
as gas stabilisation takes place. This is called three phase
sepa~ation. (See Figure 3). f.t:>st producing platfonns in the Brent
System are able to export "dead" 8-11 lbs vap:>ur pressure crude or add
natural gas liquids to the crude before export to produce a gas rich
crude with vap:>ur pressures of between 40 to 150 psi. On the Shell
platfonns this is achieved by contacting snaIl portions of "decrl" crlrle
with natural gas liquids and reinjecting this rich crude into the main
crude stream leaving the platfonn. '1b obtain these natural gas liquids
the gases from the separator train are canpressed contacted with the
crude oil sidestream, cooled and allowed to separate again into rich
crude and the more volatile gas fraction. '!he gas separated at this
stage is contacted with Glycol to ranove water and then is either
reinjected into the producing reservoir or exported to shore. Other
North sea operators control vapour pressure by pressure control of the
last stage separator. Other operators inject NGLs directly into the
exported crude oil.
Chemicals used are corrosion inhibitor continually injected before the
first cooler and batch corrosion protection of the gas export line.
Figure 4 is the flow scheme of a typical water injection system
used by Shell in their North Sea operation. Gas and water injection
into the oil bearing zone is a method of maintaining reservoir pressure
or at least minimising the reduction of pressure. In the North sea,
sea water is deaerated by vacuum and oxygen scavenger chemicals,
filtered by screens and/or diatanaceous earth filters before injection
into the reservoir. '!he quality of water required by the various
operators can range from almost untreated water to a very severe
specification dependent on the porosity of the rock into which the
water is injected. For most of the Shell operation water with 95 per
cent of all particles greater than tYJO micron diameter ranooed and an
oxygen content of five parts in one billion. is specified. On sane
platfonns injection water is filtered through deep sand bed units in
which case polyelectrolytes and ferric chloride are used to assist
filtration.
The Role ofChemicals in Oil and Gas Production
r------------ ------~--.-----
u
::fa:: ::i~
~i~!
.... :1:
~~o~
~~",Cl:
2~ ~3~~~ ..."'""a;
67
0'100
Q~
3(:;"~c;;--
s"S-~
g~~~~
~
F"LOWLlNESTO WEu..5
INJEC TION PUt.lPS
INJECTION
OVEReOAROPUMP
FIL TRATION
OIATOYACE~
EARniHOPPER
OVERBOARDDUMP
Figure 4
TRANSFER
OEAERATOR (~ANSFER) PUMPS
DEAE RATION
OXVGENSCAVENGINGPUMP & TANI(
SEA WATER INTAKE
SEA WATERPUMPS
SEAWATER
INTAKES
The Role ofChemicals in Oil and Gas Production
Table 2 shows the typical analysis of the various formation
waters, and sea water. As can be seen there is a high scaling
potential when sea water is mixed with these formation waters. '!his
can affect operation in two ways, precipitation of bar ium sulphate at
the interface causing loss of injectivity due to formation zone
blockage and to scale deposition in the production facilities when this
mixture is eventually produced along wi th crude oil. Chemicals
required for this system are scale inhibitors at both the injection
point and at the production facilities and of course oxygen scavenger
to reduce corrosion of the injection well equipment.
Dumped Production Water
Water produced with crude can be separated whilst stored in the storage
cells, but same installations separate water in the separation train.
In either case oil- contaminated water (100 to 1,000 ppn) has to be
processed to reduce any oil contamination to the level required by law
(about 40 to 50 ppm). Two systems are used, parallel plate
interceptors and gas flotation uni ts. In both these systems
polyelectrolytes can be used to improve performance.
Movement of Gas and 0 il by Pipel ine
The line used to transfer crude oil fran the Brent field to the
Shetlands is 160 kilanetres long and the gas pipeline to the St Fergus
gas plant is 450 kilanetres in length. Studies are being performed to
evaluate if corrosion is a problem in the oil line and at present it is
not yet being treated except two sections of line (Brent Alpha to Brent
Bravo and Brent Delta to Brent Charlie) which have corrosion inhibitor
continuously injected. Consideration is being made how best to treat
the very long gas line against sweet (carbon dioxide) corrosion, and we
are also prepar ing a procedure should sour (hydrogen sulphide)
corrosion manifest itself. Continuous injection of inihibitors could
be very, very expensive; therefore we are exper imenting with viscous
slugs, or gels impregnated with inhibitor. How effective such a
technique will be remains to be established.
Biocide Treatment
There has been some manifestation of sulphate reducing bacteria in
parts of these structures where water can accunulate and became
69
Table 2 REPRESENrATIVE WATER ANALYSES
-.Jo
1- ---.------------,---------1---------1---------.------, , , , ,- 1
1 1 1 1 1 1 1 1 1 1 1 1
:Field : AUK : BRENr : BRENr : FORrIES :INDEFATIGABLE: LEMAN : LEMAN : 'lliISTLE : SPA : SPA :1 I I I I I I I I I I I1 1 1 1 I 1 1 1 1 1 1 1
: Formation :RCYI'LIEGEND : MIDDLE : IiliER :PALEOCENE : RCJrLIEGEND : RCTLIEGEND: ZECHSTElli : MIDDLE : WATER : WATER :: : :JURASSIC :JURASSIC : : : : :JURASSIC: AUK : BRENr ::Well : 30/16-3 :211/29-3 :211/29-3 : 21/10-5 : 48/18-3 I 49/26-4 : 49/26-5 :211/19-1: : :I I I 1 I I I I I I I
~ : : : :: :: :-"--:---:1 1 1 1 1 1 1 1 1 1 1
:pH : 6.3 : 6.6 : 6.6 : 7.2 : 6.8 4. 7 : 4.4 : 7.0 : 7.9: 8.1:I I I 1 I I I I I I I1 1 1 1 1 1 1 1 1 I I
:Ion concns(mg/l) : : : :: :::::1 1 I 1 1 I I I I I I1 + 1 1 1 1 I I 1 1 1 I
:Na : 40,500: 9,600: 8,100: 33,000: :: 8,290: 11,000: 12,000:: : : : : : )77,940 )75,250: )35,270: : : ::K+ : 580: 170 : 180: 2, 700 :) ) :) : 240: 400: 450:I 1 I I I 1 I I I I I I1 ++ 1 I I I 1 1 1 1 1 1 I
:Ca : 5,700 I 260 : 480: 3,950: 11,822: 12,770: 57,740: 292: 495: 346:I I I I I I I I I I I1 ++ I 1 1 I 1 1 1 I 1:M3 : 900 65 55 : 500 : 4,093: 2,910: 41,290: 59 : 1,335: 13.6:I I I 1 I I I I I II + I 1 1 I 1 1 I 1 1:Ba : N.A. 39 39 : 210 : N.A.: N.A. : N.A.: 54 : - : - :I I I I I I I I I I1 ++ I 1 1 1 I 1 1 1 1
:Fe : 69 7•3 6. 0 : 170 : N.A.: N. A. : N.A.: O. 2: O. 05: O. 02 :I I 1 I I I I I I I1 _ I 1 I 1 1 1 1 1 1
:Cl : 74,000 14,400 13,472: 58,500: 146,763: 146,830: 276,900: 12,800: 20,000: 20,500:I I I I I I I I I I I1 _ 1 1 1 1 1 1 1 1 1 1
:HC03 : 150: 1,400 433 : 450 : 43 : 21: N.A.: 1,190: 95: 73:I 1 I I I I I I I I I1 _ 1 1 1 1 I 1 1 1 1 1
:003 : Nil: Nil Nil: Nil: Nil: Nil : Nil : N.A.: Nil: 17:I I I I I I I I I I I1 _ 1 1 1 1 1 1 1 1 1 1
:s04 : 650 : 33 21 : <10 : 461 : 570 : 80 : 11 : 2,760 : 2,820 :I I I I I I I I I I I1 _I 1 1 1 I 1 1 1 1_1
Q~
~;::;.$:::l~
5·So~
~~~
~V:l
~
The Role ofChemicals in Oil and Gas Production
anaerobic. However our main concern has been the possibility of these
microbes becaning active in the oil bearing rocks by being injected
wi th the injection water. Q.lr microbiologists have advised against
attempting to treat the injection water and we have accepted their
advice. Biocides are used but in small dosage for particular
applications, such as a well closed in for several weeks at a time.
The policy of whether to use biocide to protect a reservoir when
pressure maintenance is through water injection varies widely in the
North Sea fron nil use through batch treatment to possibly continuous
injection.
Policy depends on whether or not bacteria can survive and reproduce
under prevailing reservoir pressure/temperature.
The Need for Chemicals in the Future
Proouction will continue well into the next century even if no more
fields are discovered. As plant ages corrosion problems certainly are
not reduced. Seawater breakthrough will steadily increase with
sulphate scaling problems increasing in proportion. Carbonate scaling
and wax deposition will certainly continue during the lifetime of these
fields and hydrogen sulphide generation downhole is a possibility
lurking in the background. As larger quantities of water are produced
as fields age descaling chemicals consumption will increase in
proportion.
The whole area of enhanced oil recovery other than gas and water
injection is an uncharted area. Enhanced oil recovery with respect to
the North Sea is still very firmly with the E & P research laboratories
and any likely applications are a long way away.
Tb summarise finally, chemicals are required for:-
(1) Demulsification.
(2) Carbonate scale inhibition.
(3) Sulphate scale inhibition.
(4) Sweet and sour corrosion inhibition.
(5) Defoamers.
(6) Oxygen scaveng ing .
71
72
(7) Biocide treating.
(8) Wax inhibition.
(9) Wax solvents.
(10) Sulphate scale removers.
(11) Deoiling chemicals.
Chemicals in the Oil Industry
Chemical Demulsification of Produced Crude Oil Emulsions
By D. E. Graham, A. Stockwell and D. G. Thompson
BP RESEARCH CENTRE, SUNBURY-ON-THAMES, MIDDLESEX TWl6 7LN, U.K.
Abstract
During the production of crude oils, formation water (and,under conditions of water breakthrough, injection water)may also be coproduced. The high fluid temperatures,indigenous crude oil surfactants and turbulence experiencedat the wellhead chokes and valves all contribute to producea finely dispersed emulsion of water droplets-in-crudeoil. The indigenous crude oil surfactants adsorb at thewater droplet interface giving rise to an interfacial'skin' which has rheological properties capable of inducingdroplet stability.
To aid coalescence of the emulsified water droplets,demulsifier surfactants are injected into the produced crudeoil emulsion. These surfactants act to displace indigenouscrude oil surfactants, thereby reducing the interfacialwater-crude oil tension, and so causing weaknesses in theinterfacial I skin' and consequently coalescence of thewater droplets.
74 Chemicals in the Oil Industry
The surfactant activity of the demu1sifier is dependent onthe bulk phase behaviour of the chemical when dispersed inthe crude oil emulsions. This behaviour can be monitoredby determining the demu1sifier surface pressure isothermsfor adsorption at the crude oil-water interface. Further,demu1sifier adsorption is dictated by the bulk physicalproperties of the demulsifier particularly with respect tothe effect of diluents on the demulsifier efficacy. Theseproperties are described and discussed.
Direct consequencies of the bulk and interfacial physicochemicalparameters on predicting realistic field conditions fortreating p~oduced fluids can be realised when using laboratorytechniques. The importance of thermally treating the crudeoil to reproduce wellhead conditions within the oil and theconsequences upon wax behaviour and emulsion stability aredemonstrated.
Introduction
There is an increasing number of crude oil fields that arenow producing both crude oil and water. The water which iscoproduced with the crude oil can result either from theaquifer layer in the reservoir, from the injected water forsecondary or tertiary recovery stages or from both sources.It is generally believed, although not proven, that duringfluid flow up the field drillstem and riser the two fluidsare likely to remain as essentially discrete phases.However, at the wellhead chokes and valves where there issignificant turbulence, shearing and pressure drops, the twoliquid phases become mixed giving rise to a water-in-crudeoil emulsion. The indigenous surfactants of the crude oilgive rise to an interfacial skin around the dispersed waterdroplets which in turn gives rise to stable emulsions.These interfacial films have been studied l - 4 to identify
Chemical Demulsification ofProduced Crude Oil Emulsions
the specific physicochemical parameter which can best becorrelated with emulsion stability; to date, there is nosingle unique parameter that can be completely correlatedtoemu 1s ion s tab i 1i t Y4, •
There is a number of commercial and operating reasonswhy it is advantageous to remove this emulsified waterfrom the c r ude 0 i 1. It i sex pen si vet 0 t ran s p0 r tin bot htankers and pipelines; the water contains salts whichcan poison downstream refinery catalysts as well as enhancecorrosion of overhead distillation columns, pipework andpumps; and the emulsion has a higher bulk viscosity thanthe dry crude oil and this can give rise to increasedpressure gradients in pipeline transportation resulting inslower flow rates or a greater number of, or more powerful,feed pumps.
One readily used procedure for separating the water fromthe produced crude oil is by chemical addition; such chemicalsare surface active agents which act to enhance emulsioninstability and are so called demulsifiers. This paperwill discuss the surface active behaviour of a selecteddemulsifier and identify how its efficacy can be enhancedby changing its bulk physicochemical behaviour. Moreover,the enhancement is demonstrated both at the molecular levelusing interfacial adsorption isotherm behaviour, at thelaboratory level using simulated emulsions and at the pilotscale level using a dehydrating rig. In addition, since theexperiments are carried out often in an environment awayfrom the production site using crude oil that is aged, itis important that the oil be thermally treated to recapturemost of its "production" physical properties. Thi s importantconcept is demonstrated for a North Sea crude oil in terms
75
76 Chemicals in the Oil Industry
of controlling wax behaviour (ie crystal growth) within thecrude oil and consequently emulsion stability and reproducibility.
The latter is crucial when selecting demulsifiers for oilfield use.
Materials
Cru~. The crude oil used throughout this study wasobtained from one ofjthe BP operated fields in the NorthSea. The oil was allowed to stand at atmospheric pressurefor at least a day uefore being transported by road to theSunbury Research Centre. Consequently, the oil used in the
experimenfs was at least three to four days old and atatmospheric pressure but was obtained in about 10 barrelquantities so that sufficient experiments could be carriedout on the same crude oil sample batch. The barrels were
heated and thoroughly shaken befor~ taking samples forlaboratory experiments. The oil used in the model rig
experiments was recirculated continually throughout the rigruns.
Water. The water in the laboratory emulsion studies was
double distilled; simulated field formation water for theemulsions was prepared using AnalaR salts, whereverpossible.
Demulsifier. The demulsifiers used in this study werecommercially available mat2rials supplied by Service
Companies to the Oil Industry. The chemical compositions are
not completely known but on the other hand the demulsifiersare knawn to consist of more than one surface active species.The demulsifiers are designated simply as A and B throughoutthis text. The former (A) comprises a blend of ethoxylated
propoxylated adducts (mw ca 2000) together with a cationic
Chemical Demulsification ofProduced Crude Oil Emulsions
fatty acid (mw ~ 800); the latter (B) is mainly an ethoxylatedphenolic resin of molecular weight 1600. The chemicals wereselected as suitable for treating this particular NorthSea crude oil after e~aluating simulated emulsions made inthe laboratory and identifying the optimum demulsifiersfrom a range of chemicals supplied by many Chemical Companysuppl i ers.
Methods
Thermal micro~copy. An Olympus BH microscope was used inconjunction with a Mettler FP5 control unit and FP 52microfurnace. A trinocular head with eyepiece, camera andphotocell/recorder attachments allowed simultaneous visualand photographic records to be made while thermograms wererecorded. The thermograms provided the only objectivediscrimination between wax and other (insoluble) crystallinematter.
Wax crystals in crude oil were observed at a magnificationof 100X using transmitted polarised light. The crude oilsample thickness was maintained at 50 micron by use of asealed cell consisting of two perspex sheets, one 1.6 mmthick (the 'slide l
), the other 0.3 mm thick (the 'coverslip'),separated by a 50 micron thick nickel washer. The thickerperspex sheet was drilled and tapped to permit filling,cleaning and re-use of the cell.
Crude oil pretreatment. Pressure-tight stainless steelvessels (vol. ~ 700 ml) were used to reduce to a minimum any11 ight end' loss from the crude oil. These vessel s werefilled to near capacity to reduce the risk of oxidation ofthe crude oil. The oil sample was then placed in an airoven at 40°, 60° or 80°C and left for three hours prior tocontrolled cooling to ambient temperature. Two extreme coolingrates were used; rapid (10 Co min- 1 ) and slow (0.1 Co min- 1 ).
77
78 Chemicals in the Oil Industry
In the following text and plates these heating and coolingrates will be abbreviated in the following manner: 80/S
means heat the oil sample to 80°C, hold for three hoursand then cool to room temperature slowly (0.1 Co min- 1 );
40/R means heat the oil sample to 40°C, hold for threehours and then cool to room temperature rapidly(10 Co min- 1 ).
Laboratory bottle tests. These experiments were carriedout as described e1sewhere 5 with the emulsions being preparedand resolved at 40°C. In the present work, 20 ppm demu1sifierA was intected into the prepared emulsions. The demu1sifierwas used as supplied to the laboratory and consisted ofa 50% by vol. active ingredient in solvent.
Results and Discussion
Thermal behaviour of crude oils. The thermomicrograph forthe specific North Sea crude oil used in this study isgiven in Plate 1; the wax content and size distributionare typical of those observed with other North Sea crude oils.
PLATE 1: NORTH SEA CRUDE OIL AS RECEIVED
100 MICRON ~
MAGNIFICATION SIMILAR FOR PLATES 2 - 7
Chemical Demulsification ofProduced Crude Oil Emulsions
The wax crystals can be seen as the bright specks beingapproximately 10 micron in diameter. However, when thesample of oil is heated in a bomb to 80°C and then cooledthe wax morphology depends on the relative rate of cooling.For example, Plate 2 shows wax crystals in a crude oilsample which was cooled slowly and Plate 3 shows thosein a sample which was cooled rapidly.
79
PLATE 2: 80S PLATE 3: 80R
Clearly the slowly cooled sample contains a considerablygreater amount of wax in larger aggregates than the rapidlycooled sample. The same observation can be made whenheating the crude oil sample to 60°C and cooling, althoughon this occasion the difference is not as noticeable aswhen heating the sample to 8GoC (see Plates 4 and 5).
80
PLATE 4: 60S
Chemicals in the Oil Industry
PLATE 5: 60R
Again the slowly cooled sample had a greater amount of crystallinewax and also larger wax crystals/aggregates than the rapidlycooled sample. Following on with this trend, when the oilsample is heated to 40°C then there is only a marginaldifference between the quantity and size of wax crystalsfollowing both slow and rapid cooling rates (Plates 6 and 7,respectively). The fact that there is negl igible differencebetween the two cooling rates at 40°C is hardly surprisingbearing in mind (i) the original sample had been maintained
at some 22°C (room temperature) prior to heating, (ii) thetemperature at which all crystalline wax is in solution is£! 50°C (depending on the exact heating rate) and (iii) thewax thermal behaviour is greatly dependent on previous
Chemical Demulsification ofProduced Crude Oil Emulsions
thermal history (ie whether wax is in the form of largeaggregates (Plate 2) or small particulates (Plate 6)).
81
PLATE 6: 40S PLATE 7: 40R
The connotations of these observations on crude oil samplesare that the size and the number (or amount) of wax presentin crystall ine form will significantly depend on the thermalhistory of the crude oil samples and also on the pretreatmentcei 1 i ng temperatures and cool i ng rates. Thermal.hi storywill then have a consequential effect on the emulsion stability.It is generally observed that emulsion stability becomessignificantly greater when wax crystallites are present incrude oil and significantly reduced when these crystallitesare dissolved. To this end, therefore, when selectingchemical demulsifiers for treating produced crude oils it
82 Chemicals in the Oil Industry
is important to beneficiate the waxes and to return the oilsample wax content to a state approaching that perti~ent tothe production state of the oil. In the next section theeffect of oil sample thermal treatment is correlated withemulsion stability.
Effect of thermal behaviour on emulsion stability. Simulatedemulsions of the North Sea crude oil were prepared at 40°Cand resolved at 40°C using the commercial demulsifier, A.The crude oil had previously been pretreated to 80°C, 60°Cand 40°C and samples were cooled slowly and rapidly to givea variety of crystalline wax morphologies as discussed above.These oil samples were then used to prepare emulsions whichwere then resolved by chemical injection and the separatedwater level measured after 24 hours at 40°C. The comparativeemulsion stability is given in the histogram (Figure 1)
for the s pe cif i c c r ude 0 i 1 pr;~ t rea t men t s •
It is clear from Figure 1 that crude oil pretreated to 40°Cbefore emulsifying and chemically resolving is, withinexperimental error, largely unaffected by the rate of oilcooling; both rapid and slow cooling give rise to similar
emulsion resolution. However both pretreatments affordedsl ight1y more unstable oil than the II s tandard ll sample whichreceived no thermal pretreatment. The similarity betweenthe emulsion resolution histograms for 40°C thermalpretreatment tends to follow from the similarity of the waxmorphology shown in Plates 6 and 7.
Chemical Demulsification ofProduced Crude Oil Emulsions
100
80
60~
s-O)
-+->ItS
3 40-00)
-+->ItSs-ItSc-O)
20(/)
o 80R 60R 40R - 40S 60S 80S
FIGURE 1 THE INFLUENCE OF CRUDE OIL THERMAL PRETREATMENT ON THEWATER SEPARATION AFTER 24 HOURS FROM A 20% WATER-IN-NORTHSEA CRUDE OIL EMULSION
On the other hand, the ease of emulsion resolutionis significantly different for oil samples preheated to80°C prior to cooling and emulsifying. In fact, slowly
cooled oil samples were almost totally resolved by thedemulsifier A whereas the rapidly cooled samples were very
stable and were only marginally resolved by the same chemicaldemulsifier. This observation again correlated well with
the Plates 2 and 3. The slowly cooled sample gave rise tolarge wax aggregates which were too large to stabilise the
83
84 Chemicals in the Oil Industry
(approximately 10 micron diameter) droplets of the dispersedwater phase. The rapidly cooled sample gave rise to anincreased number of smaller wax crystallites which are nowcapable of stablising the emulsion. It is proposed that thisstability arises via adherence of wax particles at theoilwater interface increasing the interfacial rheology.
The resolution of emulsions with crude oil pretreated at60°C is intermediate between those samples treated at 40°Cand 80°C; see Figure 1. The correlation of emulsionstability with wax crystallite appearance, as per Plates 4and 5, is~in line with that correlation observed at 80°Conly of reduced magnitudes.
100
80
--
CtQ. 60~Q)+Jto3:
-0 40"CV+J
'"s..tU0-Q)
I---V>~ -
20
o80R 80S 80R 80S 80R
FIGURE 2 THE INFLUENCE OF CONSECUTIVE CRUDE OIL THERMAL PRETREATMENTSON THE WATER SEPARATION AFTER 24 HOURS FROM A 20% WATER
IN-NORTH SEA CRUDE OIL EMULSION
Chemical Demulsification ofProduced Crude Oil Emulsions
By way of demonstrating the repeatability of the oiltreatment on emulsion stability, Figure 2 contains repeatemulsion resolution curves using oil samples which werepreheated to 80°C before being cooled initially rapidly,then slowly, then rapidly, slowly and finally rapidly again.
At each occasion, 20% water-in-oil emulsions were preparedand resolved by chemical injection of demulsifier Aat 40°C. The repeatability was extremely good andcompares well with the similar data obtained using adifferent oil consignment shown in Figure 1.
Two important ~oints to be drawn from these data are firstlythat the progressive heating and cooling of crude oilsamples do not cause any physical or chemical change inthe oil such as loss of light ends or oxidation whichcould then in turn affect the emulsion stability ratings.Secondly, because the alternate emulsion stabilities arereproducible, the thermal behaviour of the waxes in theoil is completely reversible. This reversibility lends
credence to the view that thermally ~edting the oil to80°C will tend to revert the oil sample towards the state
that it was in at the wellhead. It is then further postulatedthat the production thermal history has been destroyed and
the oil can then be thermally manipulated to mimic anyproduction phenomena. This would further support the fact
that some confidence can be given to non-site reproducibilityof demulsifier evaluation programmes using oil which has
been pretreated to destroy the thermal history and thencooled in a manner similar to the site conditions.
Demulsifier adsorption behaviour. Most, if not all, chemical
demulsifiers are diluted in a solvent phase (often typically40-60% by volume) to reduce the surfactant viscosity and soimprove the chemical handling ability. However, it has
85
86 Chemicals in the Oil Industry
been demonstrated 5 ,6 that the interfacial behaviour of
demulsifiers can be significantly effected by the solvent phasein which they are diluted. The significant factor whicharises from the previous study6 is that the interfacial
tension adsorption isotherm shows that demulsifier B, thenonionic ethoxylated phenolic resin, can have an enhancedsurface activity when diluted in the solvent, xylene. Atthe concentration of only 0.2 ppm the demulsifier B will
have attained a maximum reduction in the oil-water interfacialtension. In other solvents such as methanol, propanol ortoluene the interfacial activity is only partially enhancedin comparison with the chemical as supplied. In the samepaper6 , light scattering data supported the proposal that
the demulsifier is readily solvated in the xylene givingalmost complete molecular solubility. However, the samechemical is more (irreversibly) aggregated in the othersolvents thereby having a reduced surface activity.
Relative n-A curves for crude oil-water interface
A relative measure of the interfacial film1s n-A curve canbe obtained by allowing the interface to establish steadyconditions of film tension and then compressing that film.Since the exact number of surface active species indigenous
to the crude oil is unknown it is not possible to give anaccurate value for A, the area per surface active molecule.Hence, it is only possible to quote A/A o , the relative
area reduction for the whole interfacial film where A isthat area existing during compression and Ao is the initialuncompressed film area. The n-A/A o can be considered arelative n-A curve. Such a curve for the North Seacrude oil-distilled water film is shown in Figure 3 alongwith similar curves for demulsifier B diluted in differentsolvents as a 1 per cent solution and then injected into thecrude oil prior to compression.
Chemical Demulsi,fication ofProduced Crude Oil Emulsions
16
87
1r/mN -1m
12
8
4
oo
, , ,'\
0.2 0.4 0.6 0.8 1.0
A/Ao
FIGURE 3 CRUDE OIL-DISTILLED WATER RELATIVE COMPRESSION CURVES INABSENCE (-----) AND PRESENCE OF DEMULSIFIER B DILUTED AS1% SOLUTION IN PROPANOL( ...•.• ) METHANOL (-----) ANDXYLENE ( - - -) AND ADDED TO THE OIL AT 0.2 ppm
The n-A curve observed for the specific North Sea crudeoil is similar to those curves obtained for a range ofother North Sea and Middle East crude oils as providedelsewhere 3 ; subtle differences do exist which can berelated to relaxation rates within the adsorbed interfacialfilm and the relative speed of compression. Addition ofdemulsifier B to the crude oil interfacial film prior tocompression generally results in a reduction of the changein n for a given compression but the reduction is clearly
88 Chemicals in the Oil Industry
dependent on the nature of the solvent in which B is diluted.
The changes observed with propanol are barely outsideexperimental reproducibility but the compression observedwith demu1sifier B in xylene is significantly reduced comparedwith the crude oil film alone.
The rheologica1 properties of crude oil-water films havebeen correlated with emulsion stability by a number ofworkers l - 4 • Shear properties have generally, but not
without exception, been well correlated to emulsion stabilityalthough recently4 attempts have been made to evaluate
dilatation~l properties. It can be deduced from the datapresented in Figure 3 that the pseudostatic dilatationalproperties of the specific crude oil film (the pseudostaticmodulus is directly proportional to the negative slope ofthe n-A/Ao curve) are much reduced when demulsifier Bis added in xylene and so it is anticipated that thiscould have significant effects on the stability of thewater-in-crude oil emulsions. From the data obtained in
Figure 3, it would be predicted that demulsifier B inxylene would destabilise the emulsions to a greater extent
than that in methanol, and in return, in propanol. Moreover,it is possible to demonstrate physically the skin developed
at the crude oil-water interface by making a hanging oildrop-in-water and then shrinking the droplet. The interfacialskin so produced remains as a wrinkled phenomenon. But,in the presence of demulsifier B this skin is difficult to
produce and indeed it is impossible when the demulsifieris added to the oil in xylene. Hence, it is perhaps worth
recalling how the demulsifer efficacy can be improved bydiluting in the xylene solvent.
Laboratory and model rig emulsion stabilities. Previous
results 6 obtained with laboratory produced water-in-NorthSea crude oil emulsions have highlighted the practicalimportance of the effect of improving surface activity of
Chemical Demulsification ofProduced Crude Oil Emulsions
demulsifier B by diluting in specific solvents. Dilutingthe nonionic ethoxylated phenolic resin chemical in xylenetends to give better solubility in the crude oil and soimprove its abil ity to enhance emul sion i nstabil ity. In
addition to this improved emulsion resolution 6 , it isalso possible to control the rate of water separation froman emulsion by judicial selection of the solvent phase asshown elsewhere 5• Consequently, the potential to controldemulsifier efficacy, by selecting the solvent in whichthe active ingredient is diluted, is open to exploitation.
In addition to~he laboratory results obtained with simulatedwater-in-crude oil emulsions, experiments have b2en carriedout on the model dehydrating rig to evaluate the emulsionresolution under conditions more closely resembling thosein production. As though to confirm those data obtained inthe laboratory, the data on the rig 7 exactly confirmed thatdemulsifier B diluted in xylene had increased efficacy overthat dissolved only in the solvent as supplied. In fact,the latter resolved 10% simulated production water-in-crudeoil emulsions to a level of only approximately 8 ~ 2% residual
water content whereas the demulsifier B diluted in xyleneas a 4% solution resolved the identical emulsion immediately
to 0.25 ~ 0.2% residual water. This important concept hassignificant advantages for offshore production.
Conclusions
There are two important findings fro~ this and other relatedstudies.
Firstly, the crude oil samples received in laboratoriesfor demulsifier evaluation should be thermally treated to
destroy the production-transport thermal history which the
89
90 Chemicals in the Oil Industry
crude oil remembers through its crystalline wax morphology.
Providing the crude oil samples are thermally treated, then
reliable and reproducible emulsion behaviour can be obtained
by which chemical demulsifier evaluations can be routinelyand reliably carried out under simulated production thermalconditions.
Secondly, the demulsifier concentrate is generally tooviscous to handle neat and so a solvent is added to improve
handling. However, a careful selection of solvent cansignificantly improve the surface activity of the demulsifier;
it is proP9sed that the correct solvent is one which allowsthe demulsifier to dissolve totally without irreversibleaggregation.
The consequences of this selection of a solvent are improvedsurface activity and emulsion resolution efficiency.
Acknowledgements
The authors wish to thank Jane Bell for preparation ofthe typescript and The British Petroleum Company plc forgiving permission to publish this paper.
References
1. J. Reisberg and T.M. Doscher, Prod. Monthly, 1956, ~,43.
2. J.E. Strassner, J. Petrol. Technol., 1968,~, 203.
3. T.J. Jones, E.l. Neustadter and K.P. Whittingham,Canadian Pet. Tech., 1978, ll, 100.
Chemical Demulsification ofProduced Crude Oil Emulsions
4. E.l. Neustadter, K.P. Whittingham and D.E. Graham, In"Surface Phenomena in Enhanced Oil Recovery", editedby Denesh O. Shah, Plenum Publishing Corp., 1981,pp 307-326.
91
5. D.E. Graham, E.l. Neustadter, A. Stockwell, K.P. Whittinghamand R.J.R. Cairns, In "Surface Active Agents", SCI publication1979, p127.
6.' D.E. Graham and A. Stockwell, European Offshore PetroleumConference~ london, 1981, p453.
7. A. Stockwell, D.E. Graham and R.J.R. Cairns, OceanologyInternational 80, 1980, Section F, 9.
Oily Wastewater Treatment in the Production of Crude Oil
By G. E. Jackson
PETROLITE LIMITED, BIRCHILL ROAD, KIRKBY INDUSTRIAL ESTATE, LIVERPOOL L33 7TD,U.K.
Increasingly more stringent environmental regulations on the
quality of water discharged to rivers and the sea offshore have
created increased interest in oil-water separation processes,
and in ways of chemically enhancing these processes.
Oily wastewater arises in a number of ways in the production
of crude oil. The major sources of wastewater include:
produced water which contains residual oil and oil derived
chemicals, after separation from the oil. The quantity of
this produced water increases as the reservoir is depleted and
water invades the formation, particularly when water injection
is used for pressure maintenance. Other sources of wastewater
include: displacement water from oil storage systems, which
may contain emulsions which accumulate at the oil-water
interface in the storage tanks; tanker ballast water;
operational discharges from rainfall run off; oily wastes
and slops from drilling operations. Before the oil-contaminated
wastewater can be discharged or re-injected for pressure
maintenance, the oil and suspended solids must be removed.
The concentration to which oil and solids in the water have
to be reduced depends on local conditions but data suggest 1
that average oil concentrations of 30-40ppm are achievable
with available technology offshore. This level can be
considerably reduced in land based operations where secondary
biological treatment can be used to reduce further the oil and
organic loading of an effluent.
Oily Wastewater Treatment in the Production ofCrude Oil 93
Contamination of water in the production of crude oil
frequently leads to intimate mixtures or emulsions of
dispersed oil, finely divided solids, dissolved organic material,
and water. These mixtures can be extremely difficult to
separate. Entrained oil may be present in the wastestream
in a variety of forms. Free oil may be present as large
d r 0 p1 e t s, Le. par tic 1 e s >1 5 0 ~m d i a met er. The sed r 0 p1 e t s are
normally easily separated by gravity. Smaller droplets
of 'dispersed' oil mayor may not coalesce and be separable
by gravity. As the oil droplets decrease further in size,
to the range of 1-5~m diameter, they become 'stabilised' or
'emulsified~ and cannot be readily separated by conventional
gravitational separation processes. Generally, emulsified
oils need a more sophisticated process, together with some
chemical treatment, in order to separate and remove the oil
contaminant. Finally, soluble oil or dissolved organic
material which is not present as discrete particles is very
difficult to remove without chemical treatment and may increase
the stability of the emulsified oil in some cases.
Emulsion Formation and Stability
Co-production of oil, gas, and water in the presence of
surfactants leads to the formation of two types of emulsion:
water in oil or 'regular' emulsions, and oil in water or
'reverse' emulsions.
In a reverse emulsion, the oil is broken up into very small
particles or droplets which are dispersed in water, the external
phase. This can happen in production systems by shearing the
fluids in a pump, in a choke, in a production separator etc.
Dispersing the oil in this way leads to a tremendous increase
in the interfacial energy of 'the system.
If the two immiscible liquids concerned were pure, the
emulsion produced would be extremely unstable thermodynamically
relative to the two bulk phases separated by a minimum area
of interface. This is why two immiscible liquids when pure
do not form emulsions, and an emulsifying agent has to be present.
94 Chemicals in the Oil Industry
At the interface between the oil particles and water there
is always an unequal distribution of charges between the two
phases. This causes one side of the interface to acquire a
net charge of a particular sign giving rise to a potential
across the interface which is known as the 'electrical double
layer'.
The emulsifying agents or surfactants act by absorbing
at the interface as an oriented interfacial film, hence
stabilising the dispersed particles whether it be a liquid/
liquid or liquid/solid dispersion.
These emulsifying agents act by:
a) redDcing ~ow,the interfacial tension between the
oil and water:
So, for a fixed amount of mixing energy W ergs given to the
system
W = ('tow) (Aow)
any reduction in 'tow will lead to a corresponding increase
in Aow, the interfacial area. This increase in Aow is achieved
These barriers inhibit
by creating a large number of smaller particles. La an
emulsion
b) decreasing the rate of coalescence of the dispersed
particles by forming a mechanical, steric; and/or
electrical barriers around them.
close approach of the particles.
The resistance of the dispersed oil particles to coalescence
is a measure of the 'stability' of the emulsion, and is
determined by:
i) the physical nature of the interfacial surfactant
film.
ii) the presence of a charge on the dispersed phase
droplets or particles, which constitutes an electrical
barrier to the close approach of the particles.
ill) the viscosity of the continuous phase, water.
iv) the oil particle size distribution.
Oily Wastewater Treatment inthe Production ofCrude Oil
Emulsifying agents found in oil-water reverse emulsions tend
to be anionic and non-ionic surfactants, e~. sodium and potassium
soaps, sodium naphthenates, cresylates and sodium and potassium
sulphides. These are often only water soluble at neutral or
alkaline pH, and in such cases pH adjustment may be used to
reduce emulsion stability and improve oil removal efficiencies.
Apart from surfactants which may derive from the crude
oil itself, very finely dispersed solid particles may also act
to stabilise o/w emulsions. These can originate from a
number of sources such a silts, clays, fine particles of
limestone or sands from the formation, any insoluble inorganic
mate r i a 1 e.g. i r 0 n sui phi d e, s c ale 0 r cor r 0 s ion pro d u c t s wh i c h
may precipitate from the aqueous phase.
A further source of potential o/w emulsifying agents
are the other chemicals being used in the production system
and includes: regular demulsifiers, scale and corrosion
in h i bit 0 r s, s c a v en g er s, b i 0 cid e s, pro d u c t s fro m a cid i sin g
operations, chemicals used for tertiary recovery programmes.
The ability of these chemicals to create a reverse emulsion
varies widely and may not pose a problem at normal usage
levels. However, overtreatment, batch treatments, or squeeze
treatment programmes can lead to severe problems when
excesses of the chemicals are present in the wastewater stream.
In most cases it is necessary to use a reverse demulsifier
to destabilise the dispersed oil droplets, increase their
size and hence increase the efficiency of the physical
separation processes used to de-oil the water.
Oil Removal Methods
The optimum process or combinatian of processes for a
particular oily wastewater depends on a number of factors t
Le. oil droplet size distribution, oil concentration, gravity
of oil, level of suspended solids, presence of surfactants etc.
The optimum process will produce the required effluent water
quality at the lowest capital operating and maintenance cost.
A brief description of these individual unit processes
follows.
95
96 Chemicals in the Oil Industry
Gravity Separation
Primary treatment or equalisation of oily wastes is generally
by gravitation. This is the most efficient and economical
way to remove large quantities of free oil, and is usually
achieved by equalisation tanks fitted with oil skimming
facilities. Although gravity separation is effective in
The performance of a
removing free and some dispersed oil it will not remove
soluble oils and most emulsions.
gravity separator is governed by:
a) The Stokes Rising Velocity of the individual droplets
of free oil.
This is a tunction of temperature and density difference
between oil and water.
b) The hydraulic loading of the unit.
The API Separator is designed to remove oil droplets of
150~m diameter or larger. 2
Tne parallel plate separator has also been used for
primary de-oiling] This is basically a large number of
shallow separators stacked on top of each other operating
in parallel. As the wastewater flows between the plates the
oil floats to the under-surface of the plates, coalesces,
and finally rises to the top of the tank where it is skimmed.
The plates establish laminar flow through the plate pack and
drastically reduce the distance that oil droplets must rise
in order to be skimmed. Plate separators are generally
designed for removal of 60~m diameter oil droplets.
The performance of gravity separators may be enhanced
by promoting agglomeration and/or coalescence of oil droplets,
which increases the Stokes rising velocity of the oil droplets.
This may be achieved by pH adjustment and/or the use of
reverse demulsifiers.
A very important factor in the design and operation of
gravity separation systems is the efficient removal of any
suspended solids which settle out and form an oil-wet sludge.
Air flotation
The two main types of flotation process used for de-oiling
water differ in the way in which the gas (usually air) is
Oily Wastewater Treatment in the Production ofCrude Oil 97
introduced to the system. Both rely on the interaction of
bubbles with the dispersed oil droplets in order to increase
their rising velocity.4
Induced Air Flotation I.A.F.
In I.A.F. air or gas is drawn into the liquid by an eductor
rotor and is sheared into bubbles (10 2 -10 3 micron diameter).
The main oil removal mechanism is via oil droplet/air bubble
interaction. This process may be considerably enhanced by
the use of an appropriate organic polyelectrolyte flotation
reagent. Inorganic coagulants are generally unsuitable for
this process due to the violent stirring action of the rotors
which tends _to redisperse the rather fragile flocs formed
when using salts.
Dissolved Air Flotation D.A.F.
In D.A.F., the whole of the wastewater stream, or part of it,
is saturated with a gas,usually air under pressure. The air
in excess of atmosphenc saturation is precipitated by pressure
release in a flotation chamber. Bubbles generated in this
manner are much smaller than for I.A.F. 30-150 ~m.
Once again, the air bubble/oil droplet interaction is
very important in determining the efficiency of the process,
and this may be increased dramatically by the addition of an
appropriate organic polyelectrolyte flotation aid. This
acts to destabilise emulsified oil, and improve bubble/droplet
interaction. When organic polyelectrolytes are used alone,
the floated-skimmed oil may be recycled to the primary
treatment unit. If inorganic salts are used as coagulants,
large volumes of oily sludge tend to be generated. This
seriously reduces the ability to ,recover the skimmed oil, and
can create a disposa~ problem.
The size and weight of D.A.F. units preclude their use
in offshore applications.
Filtration Systems
Filtration Systems have been applied to the separation of free
and emulsified oil from wastewater streams 5. Filter media
of sand, anthracite, plastics, graphite, etc., have all been
used with varying success.
98 Chemicals in the Oil Industry
Granular media filtration is more appropriate for solids
removal from wastewater, though its use in de-oiling is
claimed to be efficient. 6
Oil removal is proposed to be by separation of the oil
and ·solids in the upper layers of the filter bed followed
by enhanced coalescence of the solids-free oil droplets.
The coalesced oil tends to remain floating in the upper part
of the bed until the filter is back-washed. Addition of
polyelectrolytes has been shown to improve the performance
of this process significantly.
A number of other processes have been used with varying
success for~de-oiling wastewater and include: ultrafiltration,
coalescers and centrifugation. However, these are not applicable
for handling large volumes of water.
Chemical Enhancement of Oil-Water Separation Processes
Chemicals are frequently used to enhance the physical separation
processes described above. Since the most common type of
emulsifying surfactant found in reverse emulsions are anionic
and non-ionic it is not surprising that cationic polyelectrolytes,
or blends of these with inorganic salts, are found to be
extremely effective in destabilising emulsions and improving
process efllciency.
The mechanism of action of these chemicals is proposed
to be: adsorption at the interface followed by charge
neutralisation and/or interparticle bridging. This destabilises
the colloidal particles and allows their agglomeration or
flocculation and subsequent separation from the bulk phase.
Inorganic Coagulants
Metal salts which are used as coagulants include zinc,
aluminium, and iron salts. In water these hydrolyse to form
insoluble hydroxides. These precipitated hydroxides provide
the charges needed to neutralise the charge on the colloidal
particles, and form flocs which enmesh the particles.
These metal salts are particularly sensitive to changes in
pH and alkalinity. The flocs which they form tend to be easily
re-dispersed, and tend to generate large volumes of sludge
which may cause a disposal problem.
Oily Wastewater Treatment in the Production ofCrude Oil
Organic Polyelectrolytes
The use of metal salts has declined over recent years with
99
the advent of water-soluble organic polymers. These are long-
chain macromolecules made by linking together synthetic
monomers, some of which carry electrical charge or contain
groups which can be ionised.
The important characteristics which govern the effectiveness
of these polyelectrolytes are:
i . the mol e cuI a r we i g h t J Le. c ha i n 1 en g t h
i i . ch a r get y pe, Le. non - ion i c, ani 0 n i c, 0 rea t ion i c
i i i. c h a r g e den sit YJ i.e. ch a r g e per un i t we i g h t 0 f poly mer
The m09t widely used non-ionic polymers are polyamides
which vary in molecular weight from 10 6 _ 30x10 6 .
e.g.
polyacrylamide
Anionic polymers carry a negative charge, an example being
the co-polymer
acrylamide
x
acrylate salt
The functional group providing the negative charge centre is
the carboxylate anion which at normal pH ranges is the
predominant form. The ratio (x/y) will determine the charge
density on the polymer chain.
There is a large variety of cationic polyelectrolytes
available commercially, ago Polyamines, polyquaternaries,
polydiallyldimethylammonium chloride, co-polymers of
acrylamide, and dimethyl aminomethyl methacrylate etc.
An example of a cationic polymer is the condensation
product of an amine with epichlorhydrin.
100
e-g.
Chemicals in the Oil Industry
H H
-7-(CH1 )n- N-rtCH1)n-.l.-
H N-'CH 'NH H N-(CHJ- NH ____2 \ ~n n
The charge on the polymer chain is carried on the nitrogen atoms
which mayor may not be protonated depending on the pH,
amine
R,+"N - Hl.
RI
amine salt
These polyamines may be further reacted to form quaternary
ammonium ~alts which are permanently charged,i~. in a
quaternised polymer the charge density is independent of pH.
e.g.
R1
'+R2- N - R3 ClIR
4
These polymers are available in a number of physical forms,
the low to medium molecular weight usually as solutions, but
as the molecular weight is increased the viscosity of the
polymer solution increases and for these it is normal to
use an emulsion or dispersion polymer. Solid polymers are
available commercially but not widely used in the oil-field.
Effect of Charge Density on Polymer Performance
In an effort better to understand the mechanism of emulsion
destabilisation, a study was made of the effect of charge
density on the performance of polyelectrolytes in a number
of wastewater treatment processes.
The polymers used were a series of polyquaternary
ammonium compounds (C23,C35,C55 and C76 ) quaternised to
varying degrees in order to vary the charge density on the
polymers. The charge density or mole % quaternised was 23,
35, 55, and 76 mole % respectively and the molecular weight
was essentially constant at rV10 6 •
Zeta Potential Studies
The Zeta potential of colloidal silica was measured using a
Oily Wastewater Treatment in the Production a/Crude Oil 101
zeta20
Potent al
100mgl- 1 dispersion of 1 .11J.m particles in deionised water
buffered at pH 8 with ammonium chloride. Measurements were
made as a function of polyelectrolyte dose for each of the
four polymers.60
- 60
A-40
C7~ CS8 /& EJ--
;JJ ~- &. G
oI-~//~'----,'/-----'--,--,../-...-..-.-....,----"-.. (iJr J! 0.2/' 0.3 0,4
-20 <if/ 0 Dose polymer ppm --+
-40 ·11 ~ 0/~
t
mv
Figure
The results are shown in Figure 1. The dose of polymer required
to neutralise the charge on the particles decreased as the
charge on the polymer increased,up to 50%. At 50%, further
increase in the charge density does not produce any further
appreciable decrease in the dose of polymer required for
charge neutralisation.
Adsorption Studies
Size-graded silica sand, 70-80 mesh D.S. sieve, was thoroughly
washed, filtered, dried and its specific surface area measured
using the BET method.
Equilibrium adsorption isotherms were measured for C23
and C76
on silica sand after contacting the polymer solutions
for 24 hours. Equilibrium polymer concentrations were determined
using DV adsorption spectrophotometry at 270 nm.
The equilibrium adsorption density of the low charge
density polymer, C23
, was much greater than for C76
, and was
found to increase as the ionic strength of the polymer solution
102 Chemicals in the Oil Industry
increased. Using the adsorption density, the specific surface
area of the sand, and the molecular weight of the polymer,
the effective surface area of the sand covered per polymer
molecule was calculated. At low ionic strength this gave
1 . 6 x1 06 2 5 2A for C76
and 4.5x10 A for C23 .
Induced Air Flotation Studies
A laboratory scale induced air flotation unit was used to
study the effect of polymer structure on IAF de-oiling of
a synthetic emulsion of oil in water. The unit consists of
a 3 litre bowl in which there is immersed a variable speed
rotor. The vacuum created by the impellers of the rotor pulls
air down a standpipe, where it is sheared through a diffuser
into small bubbles which float to the surface. Blank runs
were carried on the emulsion without polymers.
I
CV
30
70
50
80
90
40
20
10
1
Oil
ppm
Residual60
and
Grease
10 20 30 40
Dose polymer ppm
Oily Wastewater Treatment in the Production ofCrude Oil
The flocculated oil which floated to the surface was
skimmed for 3 minutes. The oil and grease level in the
underflow was measured by Freon extraction and I.R. absorbance
103
measurement at 3.4~m. Runs were made with the oily water
treated with C23
, C33
and Ci6
at various doses. The oil
removal efficiency was measured at each dose and the results
are shown in Figure 2.
The most highly charged polymer C76
gave the lowest
residual oil level at the lowest dose, 7-8ppm. C33
optimised at 15ppm and the lowest charge density polymer
needed 25ppm to optimise its performance. The form of the
performance curves also varied as the charge density decreased.
The curve f6r C76
was very deep and the performance curves
became shallower as the charge density reduced to 23 mole%.
Sedimentation Studies
The conventional stirred jar tests for sedimentation of solids
was carried out on turbid river water. One litre samples were
dosed with polymers, rapid mixed for 30 seconds, slow mixed for
1 minute and allowed to settle for 30 minutes. The supernatant
was then sampled and the turbidity measured using a Hach
Turbidimeter; results are shown in Figure 3.
60
r 50 C33
Turbidity
NTU
40
C,23
30
20
S 10 lS
Dose ppm -----.
20 2S
104 Chemicals in the Oil Industry
The results closely parallel the Zeta Potential measurements.
As the charge density increased the minimum of the performance
curve moved to lower dose of polymer: C23
~20ppm, C33
N15ppm
with C58
and C76
giving almost the same performance with a
minimum of ~ 1 Oppm. As the charge densi ty increased, the
treatment range decreased.
Filtration Studies
A pilot scale upflow filter containing silica sand was used
to filter turbid river water at a flow rate of 7.0gpm/ft 2•
The differential pressure across the filter and the residual
turbidity in the effluent were monitored. At the end of each
run the sand media was thoroughly back washed and cleaned
by air scouring and flushing twice. Polymers were i~ected
as 1% solutions immediately upstream of the filters.
Data for C76
and C23 are shown in Figures 4 and 5.
Px10psi
TurbidityNTU
f
100
80
60
40
20
-1/16.0mgl
/ 10.6mgl-1
EJ/ ..J
~
10.6mgl-1
2 3 4 sTime hours -..
Oily Wastewater Treatment in the Production ofCrude Oil 105
The criteria used to evaluate filter performance were:
a) Rapid reduction of effluent turbidity to 1NTU, and
maintenance of this quality for the length of the filter
cycle.
b) The differen tial pressure across the bed, /::;. P, should
not increase rapidly i~. maximise filter cycle time.
Without chemical addition the turbidity removal was
maximum 10-20%. Addition of 10ppm of C76
gave good performance
for about 2 hours at which point 'breakthrough' occurred.
Increasing the dose to 16ppm gave good quality water for almost
six hours at which time the ~P limit of 6psig was reached and
the run terminated.
The other polymers were all tested under the same conditions
and at the same dose of 16mgl- 1 .
-147mgl
100
16mgl-1
Px10psi
TurbidityNTU
16mgl- 1
••
••• •
••• 0
• 0 ~~/,O~ ~O 0
~ooo-
•
40
20
80
60
t
1 2 345 6 7 8
Time hours -----.
106 Chemicals in the Oil Industry
Dosing C23
at 16ppm, Figure 5, never achieved the desired
effluent quality, and the rate of head loss development was
very slow. Increasing the dose to 47mgl- 1 to give an
equivalent cationic charge dose gave adequate performance
for almost two hours. At this point breakthrough occurred
and the effluent quality deteriorated rapidly. The rate of
head loss development increased rapidly on increasing the
polymer dose to 47mgl- 1 .
Treatment with C33
at 16~pm only gave good performance
for 2~ hours. Normalising the dose on a charge density basis
gave good performance in terms of solids removal but gave
a much faster rate of head loss development.
Dosing at 16ppm gave almost equivalent performance to
that of C76
with a slightly reduced cycle time. Increasing
the dose of C58
to normalise the charge dose improved the solids
removal but once again increased the rate that ~p increased, and
hence decreased the cycle time.
Discussion
Equilibrium adsorption densities and calculated values of the
relative surfaces of polymers C23 and C76
on silica sand
correlate well with the rates of the doses required to
neutralise the surface charge on colloidal particles. Zeta
pot e n t i a 1 d a t a in d i cat e t hat a 1 i mi tin g v a 1 u e ex i s t s, ab 0 v e
which increasing the charge density on the polymer further
does not produce a proportionate ability to neutralise particle
charge.
If the mechanism of action of the polymer in the applications
examined is primarily adsorption followed by a charge
neutralisation, then the data indicate that the more highly
charged the polymer, the lower the dose required to optimise
the polymer performance. Also, the greater would be the
tendency of the polymer to 'overtreat' since if the polymer
had higher than this limiting value of charge density, the
'excess' charge per polymer chain will tend to re-stabilise
the dispersed particles if more than the optimum dose is
applied.
Oily Wastewater Treatment in the Production ofCrude Oil
In all the applications studied it was found that, the
higher the charge density,the more effective the polymer is.
Further,for flocculation and induced air flotation the
highest charge density polymer tends to have a much narrower
treatment range,L~ a greater tendency to 'overtreat'.
In the case of filtration where the removal mechanism
for particles is proposed to be a two-step process, transport
of the particle to the media surface followed by attachment
via the polymer, the results indicate that the attachment
step required a minimum critical charge density on the polymer
before the deposited solids can withstand the high hydraulic
shear within the filter-bed.
Summary
The processes described above for treating oily wastewater can
all be enhanced by the addition of an appropriate chemical.
Selection of a chemical treatment programme and optimisation
of the process can be achieved by use of laboratory tests
followed by full scale plant trials. These should be closely
supervised and monitored.
The data presented on polyelectrolytes illustrates the
importance of charge density as one parameter which determines
their efficiency in various water treatment processes.
References
1. D.O.E. Pollution Paper No. 6, H.M.S.O., 1976.
2. Manual on Disposal of Refinery Wastes, Volume on
Liquid Wastes, Chapter 5, American Petroleum
Institute, Washington DC, 1975.
3. G.J. Iggleden, Chemistry and Industry
November 1978, 826.
4. R.J. Churchill and K.J. Tacchi, Water 1977,
AIChE Symposium Series 178, ~, 1978, 290.
5. G.E. Jackson, Crit. Rev. in Environmental Control,
1980, 2-.Q., 339, and 1 980 ~, 1.
6. R.A. Boze, C.C. Tyrie, R.K. Hummel, SPE Publication
7813, presented Production Operations Symposium
of SPE, Oklahoma City, February 1979.
107
The Use of Ethylene-Vinyl Acetate Copolymers as FlowImprovers and Wax Deposition Inhibitors in Waxy CrudeOil
By G. W. Gilby
IMPERIAL CHEMICAL INDUSTRIES PLC, WELWYN GARDEN CITY, HERTFORDSHIRE, U.K.
Introduction
The majority of crude oils, if not all, contain a proportion of petroleumwaxes. The concentration, structure and molecular weight ranges of thesewaxes vary considerably from one crude oil source to another, and, sincetheir boiling points also differ certain waxes occur, and indeedconcentrate, in different distillate fractions. The tendency of thewaxes to precipitate and crystallise as the oil cools during production,transportation, storage or even subsequent use gives rise to a varietyof problems such as poor flow or in extreme cases gelation,sedimentation, deposition on pipe and storage vessel walls, filterblockages etc. These problems arewegl known within the industry andhave been widely reported elsewhere 1- •
Control of Paraffin Wax Related Problems
Complete elimination of problems related to crystallisation of paraffinsduring crude oil production by the obvious method of heating pipelines,storage vessels etc is clearly not often economically viable. Howevera variety of other techniques for the control of such problems do existso that at least they become manageable and the wax, and therefore theproblem, is transferred to downstream operations and/or products wherethey may perhaps be more conveniently handled. Examples of thesealternati2e techniques have been listed more comprehensivelyelsewhere ,7 but include:-
(a) Dilution with low wax content crude stock or light distillates.
(b) Controlled thermal conditioning to take advantage of the naturalpour point depressing effect of resins etc which may be present inthe oil.
(c) Pigging of pipelines. This largely re-disperses deposits onpipeline walls although some d~posit may be carried through the pipeahead of the pig.
(d) The addition of solutions of oil-soluble surfactants such aspolyolesters or amine ethoxylates. These possibly act partly asdispersants for the wax crystals keeping them in suspension andpartly by modifying the surface characteristics of, for example, thepipe wall as a result of which the wax crystals show less tendencyto adhere.
The Use ofEthylene- Vinyl Acetate Copolymers
(e) The use of wax crystal modifiers. A variety of different additives,usually polymeric, have been shown to modify the wax crystal sizeand regularity which results in a reduced tendency to interlock andform a gel and hence lowers the pour point of the oil, ie they actas pour point depressants. Materials which act in this way includepolyalkyl acrylates and methacrylates, low molecular weightpolyethylene waxes, certain aromatic-paraffin wax condensationproducts and ethylene-vinyl acetate copolymers.
The preferred technique, or indeed combination of techniques, fortreating any crude oil will depend on a great many factors and it isbeyond the scope of this paper to discuss these. Suffice it to saytherefore that economics are paramount and these can be dramaticallyinfluenced by such factors as location, climatic conditions, topography,availability of materials and energy and also the efficiency of theresponse of the particular crude oil to the various available techniquesor chemical treatments. This paper is concerned with the use ofethylene-vinyl ac~tate (EVA) copolymers as wax crystal modifiers and, inparticular, the s'tructural and other factors which can influence theselection of the preferred EVA copolymer for any particular oil.
Petroleum Waxes and Mechanism of Crystal Modification
Types of Wax. The waxes occurring in crude oils are very complexmixtures of normal paraffins, branched or isoparaffins and cylcoparaffinsor naphthenes. These are simply illustrated in Figure 1. Although oflittle practical relevance to the oil production situation whereprecipitation and crystallisation is complex, it helps in the generalunderstanding if the basic characteristics of the two main categories ofwax extracted from crude oils are compared. These are listed in Table 1and Figure 2 shows crystallisation exotherms measured by differentialscanning calorimetry (DSC) on some typical commercially available refinedparaffin and microcrystalline waxes. The individual base lines of thesecurves, in this and all other similar figures showing DSC exotherms inthis paper, have, been staggered to minimise confusion of one curve withanother. Similar crystallisation exotherms on waxy crude oil sampleswhere, at the commencement of the test, the waxes are in solution showthat crystallisation is delayed to a lower temperature and thetemperature range over which crystallisation occurs is very much broader.This is of course to be expected. In practice the crystallisationprocess is considerably influenced by many factors including shear andthermal history and although observation of these exotherms provides someinformation it is of limited practical use.
Wax Crystal Structure. In some circumstances close packed hexagonal ortriclinic lattices can be found but by far the most common paraffin waxcrystal lattice is orthorhombic, each chain having the fully extendedzigzag configuration. The ideal crystalline form is as thin rhombicplates although long needles also form during crystallisation from crudeoil. Microcrystalline waxes also form thin plate-like crystals although,as their name implies, their size is much smaller due to the sterichindrance of the side branches and cyclic groups restricting crystalgrowth. These smaller crystals show much less tendency to interlock andform a three dimensional network compared with the normal paraffins andthe problems associated with wax in crude oil production andtransportation are more usually, but not necessarily always, associatedwith the larger crystal formations resulting from normal paraffins.
109
110
Figure
Table 1
Chemicals in the Oil Industry
CHJ CHJ CHJ CHI C~ CHJ CHz CHJ CtIz CH~
\/\/\/\/\/\/\/\/\/C~ C~ C~ C~ C~ C~ C~ C~ c~
NORMAL PARAFFIN
c~ c~ c~ c~ c~ c~ ,~ c~ c~
/\/\/\/\/\/\/\/\/\c~ c~ c~ c~ c~ c~ c~ c~ ~ c~
\CHz
ISOPARAFFIN /
CHJ
CYCLOPARAFFIN
Typical formulae of petroleum waxes
Typical Composition and Properties of Commercially Available Paraffin andMicrocrystalline Waxes.
Paraffin Waxes MicrocrystallineWaxes
Normal paraffins (%) 80-95 0-15Branched paraffins (%) 2-15 15-30Cycloparaffins (%) 2-8 65-75
Melting point range (OC) 50-65 60-90Average molecular weight 350-430 500-800
rangeTypical carbon number range 18-36 30-60Crystallinity range (%) 80-90 50-65
The Use ofEthylene- Vinyl Acetate Copolymers 111
t
PARAFFIN WAX(M.PNTapprox.6S·C)
PARAFFIN WAX(M.PNT approx. SO·C)
MICROCRYSTALLINE WAX(M.PNT approx. 5S·C)
MICROCRYSTALLINE WAX(M.PNT approx. 8S-C)
dHdt
Scale [- 2 m cal sec1
Coating
80 60 40 20Temperature (OCl
o -20
Figure 2 Crystallisation exotherms of different refined petroleum waxes
112 Chemicals in the Oil Industry
Mechanism of Crystal Modification. An important common feature of thewax crystal modifiers mentioned above is that they all include withintheir structure crystallisable polymethylene segments identical with thebasic paraffin wax chains. This is illustrated in Figure 3 for ethylenevinyl acetate copolymers. These polymethylene se~ents can crystallisewithin the polymer network itself to give crystalline regions orcrystallites, as they ~re sometimes known, and it has been shown, atleast for polyethylene and ethylene-vinyl acetate copolymers, that thelattice form is also orthorhombic, ie identical with that most common inparaffin waxes. This common crystal structure between polymer and waxclearly plays an important role in the mechanism by which the growth ofthe paraffin wax crystal is modified. Although not studied by the authorit can reasonably be assumed that the other wax crystal modifiersmentioned above which contain polymethylene segments also exhibit thesame orthorhombic crystal form.
, II CH, CHz CH, CH, C:iz CHz C~
il\/ \1\/ \/\1\/1\,CHz CHz CH, CH, CH, CHz CH, II II I
C~ C~ C~ C~ C~ C~ C~ C~ c~ C~ C~ c~ c~
/ \ / \ 1 ) / \ / '-I \./ \ / \ / \ / ~ / \ / \ / \CH CKz iCH, CH, CHz CHz CH, CH, CHz I CH, CH, CH
/ I I /o' I
C~ C~ C~ C~ C~ C~ C~ C~ 0
\ /\/\/\/\/\/\/\/~ \C=1 : CH, c~ CH, CH, CH, CH, C~ I C:0
/ J I /C~ I C~
I I
AMORPHOUS: CRYSTALLINE REGIONS : AMORPHOUSREGION , J REGION
Figure 3 Close packing of the po1yethy1ene parts of the chain enablingcrystallisation and the disruptive effect of vinyl acetate groups
The exact way in which crystal modifiers operate is not absolutely clearbut it is a~most certainly a combination of different mechanismsinvolving both nucleation and either co-crystallisation or absorption.In order to achieve any effect the additive must be in solution in thecrude oil at a temperature at which at least some proportion andpreferably the major part of the offending waxes are also in solution.As the oil cools the waxes and the additives crystallise out within thesame temperature range. Nucleation of crystals by crystallisablepolymethylene segments of the polymer is believed to lead, to theformation of a large number of wax crystals. The growth of thesecrystals is then subsequently arrested by the incorporation into thelattice of further polymethylene segments of the additive whose bulkysubstituent groups prevent further incorporation of molecules of theparaffin. It also seems likely that the polymethy1ene segments of theadditive actually build onto the wax crystal as a result of nucleation bythe wax crystal itself. In order to achieve the maximum affect on waxcrystal growth it is desirable that molecules of the modifying additivecontinue to precipitate from the crude oil throughout the whole periodduring which the wax is also precipitating. To achieve this it issometimes useful to use blends of additives having slightly different
The Use ofEthylene- Vinyl Acetate Copolymers
solubility characteristics. Melt crystallisation exotherms of the activeingredients of two commercially available crude oil flow improvers ofdifferent chemical types are shown in Figure 4 - that based on ethylenevinyl acetate copolYmer confirming the use of the blending technique.
113
POLY METHACRYLATE
EVA COPOLYMER BLEND
dHtdt
[ -1Scale L1m cal sec
Cooling
Ba 60 40 20. 0Temperature ee)
-20
Figure 4 Commercial pour point depressants- crystallisation exotherrns
114 Chemicals in the Oil Industry
Structure and Properties of Ethylene-Vinyl Acetate Copolymers
General. The range of properties available from ethylene-vinyl acetatecopolymers is exceptionally wide and this has led to large scale usagein many different industries. In the treatment of crude oil therelevance of crystallisation and solution characteristics has alreadybeen mentioned and discussion of structure/property relationships herewill be largely restricted to those having an influence on theseproperties. It also follows that products which are either noncrystalline or largely insoluble in oils are of doubtful interest andwill limit the range of EVA copolymers suitable for crude oil treatment.The main structural features of EVA copolymers which have an influence ontheir properties are:-
comonomer ratio (or, as more usually expressed, vinyl acetate content)average molecular weightshort chain branchinglong chain b;ranchingmolecular weight distributiondistribution of vinyl acetate groups
A more detailed discussion of the influence of each of these on generalproperties may be found e1sewhere 10 • For crude oil treatment only thefirst four of these need be considered since it is these that have themain influence on their crystallisation and solution characteristics.The fifth, molecular weight distribution has, for practical purposes,almost no effect on either of these properties. Although the sixth,distribution of vinyl acetate groups, would be expected to have someeffect, in fact, the polymerisation of ethylene with vinyl acetateproceeds in such a completely random manner that it is not easy toexercise control over this aspect of their structure. This means thatstatistically, EVA copolymers of the same vinyl acetate content have more
or less the same distribution of vinyl-acetate groups within theirstructure. Hence this may also be ignored for the purposes of thispaper.
Comonomer Ratio or Vinyl Acetate Content. This is one of the two mostimportant factors which control all the properties of ethylene-vinylacetate copolymers, the other being average molecular weight which is,of course, discussed below. As vinyl acetate content increases, threeimportant trends can be identified. Firstly degree of crystallinity isreduced, secondly polarity of the polymer increases and thirdly, at veryhigh levels of vinyl acetate, chain stiffness is increased by sterichindrance. However, as far as crude oil treatment is concerned, it isthe first of these that is of most importance. The relationship betweencrystallinity and vinyl acetate content of EVA copolymers is shown inFigure 5. Crystallisation exotherms measured by differential scanningca10rimetry on EVA copolymers having different vinyl acetate contents areshown in Figure 6. It is interesting to note that the peaks of theseexotherms span the range for petroleum waxes. From the foregoingdiscussions on wax control it follows that this ability to controlpolymer crystallinity, and indirectly the temperature range over whichcrystallisation occurs, by altering vinyl acetate content is ofconsiderable significance. It is of equal importance that this reductionin crystallinity is, not surprisingly, accompanied by a correspondingincrease in solubility due to the increased amorphous content of the
The Use ofEthylene- Vinyl Acetate Copolymers 115
o 10 20 30 40 50
VINYL ACETATE CONTENT~)
Figure Relationship between vinyl acetate content and degree ofcrystallinity for EVA copolymers
copolymer. This is illustrated in Table 2 by comparing the pour point of5% solutions of various EVA copolymers in toluene. The reasons forchoosing this method of comparing solubility will become clear later inthis paper.
Table 2
Pour Point of Solutions of 5% of Different EVA Copolymers in Toluene.
EVA Copolymer Characteristics
Vinyl Acetate MFI Hydrocarbon Branches perContent 1000 Carbon Atoms
(% by weight)
Pour Point(OC)
24 20 7 733 25 6 2
28 6 6 928 400 9 2
28 400 9 228 400 19 -5
116
dHldt
18%VA
12.S%VA
[
-1Scale - 1 m cat sec
Cooling
80 60 40 20 0 -20Temperature °C
Chemicals in the Oil Industry
Figure 6 Effect of VA content on crystallisation exotherms of EVAcopolymers
EVA copolymers containing less than about 15% of vinyl acetate by weighttend to be comparatively insoluble unless their molecular weight is alsovery low and these latter products are comparatively costly. For thisreason EVA copolymers containing from about 18-40% vinyl acetate are ofmost interest in crude oil treatment and in fact products containing from25-40% VA are the most commonly used.
The Use ofEthylene- Vinyl Acetate Copolymers
Average Molecular Weight. As with vinyl acetate content, averagemolecular weight has a very considerable influence on many of theproperties of EVA copolymers. However, degree of crystallinity is anexception to this, there being no significant difference between EVAcopolymers of widely differing molecular weight provided vinyl acetatecontent and other structural features such as chain branching areidentical. Molecular weight does however, as would be expected, have asignificant influence on solubility characteristics: the higher themolecular weight, the poorer its solubility in oils and other organicsolvents. This is also illustrated by means of solution pour point inTable 2. Products having number average molecular weights in the range10,000 to 30,000 appear to be of most interest in crude oil.
Figures for molecular weight are in fact rarely quoted for polymericmaterials and for EVA copolymers it is standard international practiceto follow the melt flow rate or melt flow index (MFI) procedure ofclassification using International Standards Organisation Test MethodISO R292. This is a ram extrusion viscosity measurement carried outunder standardised conditions which gives a value which is inverselyrelated to molecular weight. This method of describing the molecularweight of EVA copolymers will be adopted in this paper. Table 3 showsthe approximate relationship between MFI and number average molecularweight.
Table 3
Relationship Between MFI and Approximate Number Average Molecular Weightof EVA Copolymers.
MFI Approximate NumberAverage Molecular Weight (Mn)
2 32,00020 24,000
200 19,000400 13,000
Short and Long Chain Branching. The influence of hydrocarbon chainbranches on the properties of EVA copolymers is, as might be expected bycomparison with isoparaffin and cyc10paraffin waxes, largely associatedwith their disruption of the crystallisation process. The mainhydrocarbon branches in EVA copolymers are alkyl and the disruptionincreases with number of carbon atoms up to about six. Chains longerthan this can themselves become part of the crystalline network and arethose defined as long chain branches. Although these long chain branchesdo have an influence on some properties of EVA copolymers other thancrystallisation, these effects are in fact irrelevant to the presentsubject. In addition short chain branches generally outnumber long chainbranches by some 20-25 to 1 and hence, for the purposes of this paper, itis not necessary to distinguish between long and short chain branches.
117
118 Chemicals in the Oil Industry
The most common side chains found in EVA copolymers are methyl, resultingfrom the frequent use of propylene as chain transfer agent, and butyl,produced by intramolecular chain transfer. Other chain lengths such asethyl are also found. A useful quantitative comparison of the influenceof chain branch length or other substituent group on crystallinity hasbeen given by Salyer and Kenyonll . This compares the disruptiveeffect of these various branches in terms of the number of main chaincarbon atoms on each side of the branch point over which crystallisationis prevented. For methyl branches this is 3, for butyl 4 and for acetoxygroups resulting from the copolYmerised vinyl acetate it is also 4. Itcan readily be seen from this that the influence of including anadditional side branch is far greater than increasing the length of anexisting branch and hence for the purposes of this paper it is sufficientto consider only number of branches and not to distinguish theirindividual lengths. The influence of chain branching on crystallinity isillustrated in Figure 7 in which crystallisation exotherms of two EVAcopolYmers, having identical vinyl acetate contents and molecular weights(MFIs), but differing in total number of side chains are compared. Thearea of each exotherm approximates to the amount of crystallised polymer.This difference in degree of crystallinity is of course also reflectedby a difference in solubility characteristics and this is again shown interms of effect on pour point of 5% solutions in toluene in Table 2.
dHtdt
19 Chain Branches
9 Chain Branches
Scale [= 1 m cal. sec'
VA Content 28%
MFI 400
80 60 40 20 0Temoerature (OC)
-20
Figure Effect of hydrocarbon chain branching on crystallisationexotherms of EVA copolymers
The Use ofEthylene- Vinyl Acetate Copolymers
Simple Laboratory Tests for Initial Screening of EVA Copolymers as WaxControl Additives
No single laboratory test is capable of determining the best wax controladditive for a particular crude oil. Indeed, because of many complexinteractions, different crude oil compositions and different oil fieldproduction conditions, laboratory tests can only be used for initialscreening. Final selection of the most cost effective additive mustdepend on the results of pilot plant experiments and actual field trials.Nevertheless such laboratory tests do provide a useful pre-selectionguide such that additives unlikely to give useful effects may beeliminated and only those shQWi~ginitial promise are evaluated at themuch more costly pilot"or production stages.
Pour Point. This is an internationally known test method which, as itsname implies, relates to the temperature at which the oil is justpourahle. Several different pour point values can be quoted for anyoneoil sample, eg mifiimum pour point, maximum pour point, etc. Thesedifferences result from different heat treatment or pre-conditioning ofthe oil sample and other procedural differences such as cooling rate andtemperature of addition of any additive. Ouite clearly such differencescan dramatically influence the crystallisation behaviour of the waxes andadditives and as a consequence widely differing pour point figures canbe obtained on the same oil sample.
The basic procedures for pour point determination are described ininternational specifications and need not be detailed here. The resultsquoted in this paper have been determined in accordance with theseprocedures except that the oil samples have been conditioned at, andadditive doping has taken place at, a temperature approximating to thatof the crude oil at the well head. By using this procedure an indicationwhether or not the additive is effective over the temperature rangeencountered in production is obtained. Indeed actual experience hasconfirmed the value of this procedure in initial screening programmesusing EVA copolymers.
Viscosity and Yield Stress. The viscosity of the crude oil during itspassage through a pipeline for example is clearly important. Inparticular, throughput rates and energy consumption, and thereforeproduction costs, are obviously directly related to it. Laboratorydynamic viscosity measurements give valuable information on this.However, in many situations, arguably it is the yield stress of the oilin the event of solidification (or gelation) which is of mostimportance, since it is this which governs the ability to restart flowafter a production stoppage. For the purposes of. this paper emphasis hastherefore been placed on this aspect.
There are several techniques available for determining yield stress usingrotational viscometers or miniature pipelines but these tend to sufferfrom certain disadvantages. In particular, the equipment is usuallycomparatively expensive. There is also a risk of obtaining falsereadings due to unseen contraction of the oil away from a criticalsurface and further the time required to obtain statistically soundresults can be very lengthy.
119
120 Chemicals in the Oil Industry
A very simple test which overcomes these limitations involves the useof glass tubes say 100-200 mm long by 10 mm internal diameter. In thistest several samples, usually not less than 10, of each crude oil areconditioned, cooled and sheared as appropriate above the pour point. Theglass tubes, sealed with a cork at one end, are then filled to a lengthof approximately 100 mm with the crude oil. Cooling and conditioning isthen continued, obviously without shear, as required. Typically this mayinvolve cooling from about 35°C to 4°C over a period of several hoursfollowed by storage for 72 hours at this temperature before conductingthe test. The yield stress is simply measured by applying air pressureto one end of the tube and recording on a manometer the pressure at whichthe gelled slug of oil starts to flow. By testing a large number ofsamples it is possible to eliminate obviously erroneous results. Ouiteclearly this test is far removed from actual operational conditions butnevertheless it has again proved of value in the initial screening of EVAcopolymers as oil flow improvers.
Wax Deposition Tests. No ~t§ndard wax deposition test exists althoughseveral have been reported ' • The equipment used in the wgrk reportedin this paper is similar to that used by Mendell and Jessen but hasbeen somewhat modified particularly with respect to control andinstrumentation. Figure 8 shows a schematic diagram of this apparatus.With this equipment the oil product may be circulated through thedeposition cell under variable, but closely controlled, conditions oftime, temperature, flow rate and shear rate and the deposit on the cellwall collected and weighed. The percentage reduction in deposit comparedwith untreated samples of oil can be calculated using the followingrelationship:
Stirrer
ThermostaticallyControlled Bath
OilFlow-'
OilReservoir
PeristalticPump
Deposition cell
Cooling Jacket
Coolant Flow
+- Drain Cock
Chiller/HeatExchangeUnit
Figure 8 Schematic diagram of wax deposition test equipment
The Use ofEthylene- Vinyl Acetate Copolymers
W - W% Reduction = __u t x 100
Wu
where Wu is the weight of deposit from the untreated crude oil
and Wt is the weight of deposit from the treated crude oil
Results of Laboratory Screening Tests on a Variety ofCrude Oil Samples
Results of a number of pour point, yield stress and deposition testsusing different crude oils are presented in Tables 4 and 5. Study ofthese, and many other results not presented here, together with someknowledge of experience in the field, has led to the followingconclusions:
Simple laboratory tests of the type described in this paper are veryuseful for initial screening of EVA copolymers for use as crude oilflow improvers or wax deposition inhibitors.
Different crude oils react differently to different EVA copolymers andit is often necessary to provide a special formulation for aparticular crude oil.
3 EVA copolymers having low levels of hydrocarbon chain branching areusually more effective than EVA copolymers of similar vinyl acetatecontent and average molecular weight (MFI) but containing higherlevels of hydrocarbon branches.
Field Experience
Published information on the use of EVA copolymers in crude oilproduction is sparse. This is perhaps one result of the patentsituation briefly mentioned below. EVA copolymers are nevertheless inuse in various parts of the world for both flow improvement and theinhibition of wax deposition. It is therefore considered to be ofinterest to provide some information on one situation where an EVAcopolymer has been in use successfully, without problems for severalyears.
The oilfield in question is located in Eastern Europe and the crude oilhas a pour point of l8-20°C. This oil is required to be pumped througha subterranean pipeline 70 kilometres in length. Winter soiltemperatures are 4°c and the operator specifies a maximum pour point ofO°C during winter to give a reasonable margin of safety. Laboratory pourpoint tests showed that the addition of 100 ppm of EVA copolymercontaining 28% of vinyl acetate and having an MFI of 400 readily met thisrequirement. In this case copolymers with a high level of chainbranching were selected since the copolymer solution, in a mixed aromaticsolvent, is pumped through a small diameter pipe 2.5 kilometres in lengthand it therefore also needs to exhibit a low pour point. This solutionis added to the crude oil in a mixing tank which collects the output fromseveral wells. In practice the dosage rate of the active ingredient isvaried depending on the climatic conditions and is typically 20 ppmduring the summer and 100 ppm in winter. Throughout several yearsoperation no flow problems have been encountered either during rer.ularproduction or on re-starting after stoppages.
121
122 Chemicals in the 0 it Industry
Table 4 Effect of Different EVA Copolymers on the Pour Point ofVarious Crude Oils
1 J1 EVA Copolymer Characteristics 11 1 Addition1 1 Rate of1 VA Content MFI Hydrocarbon 1 EVA to1 % branches per 1 oil (ppm)1 1000 carbon 11 atoms 11 1I 1I Untreated Crude Oil 1I 1I 24 20 7 I 1001 ,- 24 20 11 1 1001 11 24 400 10 1 1001 24 400 16 1 1001 24 400 24 1 1001 I1 1I 28 400 9 1 1001 28 400 19 1 1001 11 11 Untreated Crude Oil 11 11 24 20 7 1 25I 28 400 9 1 251 28 5 6 1 251 1I 33 25 4.5 1 251 33 45 8.5 1 251 11 11 Untreated Crude Oil 11 I1 28 400 9 I 251 28 400 19 1 25I 1I 24 400 10 1 251 24 400 16 1 251 1I I1 Untreated Crude Oil II II 18 2 6 I 200I 18 2 •5 8 1 2001 II 28 400 9 I 2001 I
111 Pour Point1 (OC)1I11I
30
814
121820
920
8
1-18
below -25
-23-13
-1
-26-16
-22-10
21
1122
25
Table 5 Effect of Different EVA Copolymers on Pour Point, Yield Stress and Wax Deposition ~of Various Crude Oils. ~
s:~
EVA Copolymer Characteristics I I I I I~g,
EVA I Pour Point I Yield Stress I Reduction I ;:::s-.Copolymer I (OC) I (N/m2) I in I ~
~VA Content I MP! I Hydrocarbon I Addition I I I Deposition I ;::
% 1 I branches per I Rate I I I (%) I 71000 carbon I (ppm) I I I I :s
atoms I 1 I I I;::~~~~
Untreated Crude Oil I - I 30 I 250 I - I E;-I I I I I ~
24 I 20 I 7 1 100 I 8 1 35 1 40 I (J.g
28 1 5 I 6 1 100 1 11 I 30 I 55 I \:)
~~
28 I 400 I 9 I 100 I 9 I 25 I 50 I ~"""'I:
28 I 400 I 19 I 100 I 20 I 55 I 25 ~
28 I 400 1 21 I 100 I 21 I 70 1 20I I I I I I
33 I 25 I 5 I 100 I 15 I 45 1 -I I I I I I
40 I 50 I 6 I 100 I 26 I 85 I 35I 11 1
Untreated Crude Oil 1 - I 8 I -I 1 1 1
28 I 400 1 9 I 100 1 Below -25 I - I 80I 1 I I
1 IUntreated Crude Oil I - 1 -1
I I I 128 I 5 1 6 I 100 1 Below -25 1 - I 75
I 1 I I I28 I 400 I 9 I 100 I Below -25 1 - 1 85
Nw
124
Future Development
Chemicals in the Oil Industry
The use of EVA copolymers in crude oil is currently covered by patentsin many, but far from all, countries and this may have restricted theirexploitation in some circumstances. However, the earliest patents inthis field were filed many years ago and will expire within the next fewyears in most countries. When considered within the time scale of oildiscovery to actual production this unexpired period is not long. It isexpected that this will stimulate efforts to develop the use of EVAcopolYmers in the field on a much wider scale. Indeed an increasingawareness of the future potential for EVA copolymers can already bedetected, not only when used alone but also in conjunction with otheradditives, where their combined use can give improved performance. All inall an exciting prospect for a fascinating area of modern oil industrytechnology.
Acknowledg_ement
The author gratefully acknowledges the helpful comments and informationprovided by several colleagues and the permission of ICI (Petrochemicalsand Plastics Division) to publish this paper.
References
C A Bilderback and L A McDougall, J Pet Tech 1969, ~, 1151.
2 A Uhde and G Kopp, J Inst Pet, 1971, 1I, 63.
3 R C Price, J Inst Pet, 1971, ~, 106.
4 M Brod, B C Deane and F Rossi, J Inst Pet, 1971, 1I, 110.
5 J L Mendell and F W Jessen, J Can Pet Tech, 1972, 11(2), 60.
6 P B Smith and R M J Ramsden, Proc Eur Offshore Pet Conf, London 1978,283.
W Smith, Oil Gas J, 1979, 12, Ill.
8 P A Bern, V Withers and R J R Cairns, Proc Eur Offshore Pet Conf,London 1980, 571.
9 C W Bunn, Trans Farad Soc, 1939, ~, 482.
10 G W Gilby, Developments in Rubber Technology -3, Applied SciencePublishers, London, 1982, Chapter 4, p.101.
11 I 0 Salyer and A S Kenyon, J Poly Sci, 1971, ~, 3083.
Water Scaling Problems in the Oil Production Industry
By K. S. Johnson
OILFIELD CHEMICAL SERVICES, 430 CLIFTON ROAD, ABERDEEN AB2 2EJ, U.K.
Types of scali'ng compounds found in oilfield production systemsare discussed with particular reference to physical environmenteffects on scaling probability.
General calculation methods for predicting scaling tendency arementioned together with the static scale precipitation tests and therelatively new dynamic capillary tube pressure drop increase orblocking test.
Generic chemical types that are used as scale inhibitors are listedand reviewed and the mechanism by which they act is touched on.
Areas of oilfield systems where scaling may create operational problemsand application usage of scale inhibitors to prevent scaling in thesesystems are discussed.
Water is utilised in oilfield systems in water injection (secondaryrecovery) to maintain reservoir pressure and to create a drivingforce towards the production wells.
It is also produced along with crude oil as part of the IItotalproduced fluids". Initially it is present as formation water;later, where secondary recovery ;s practised, water associated withcru de oi 1 wi 11 be a mi xture of forma tion wa ter and returned i njecti onwater. Where practicable and certainly in all offshore oilfieldinstallations where water injection is carried out, the water usedwill be seawater.
The chemistry of many of the waters encountered in oilfield operationsis such that low solubility compounds are present and under certainconditions may precipitate out and form scale build up.
126 Chemicals in the Oil Industry
The chemical composition of seawater varies in different parts ofthe world. As an example, are given in TABLE 1 typical majorcomponents chemical analysis of North Sea and Arabian Gulf seawaters.
It may be seen that seawater contains tons that in combinationcould give rise to compounds known ~o have low so~ubility.
In the case of North Sea seawater this would be 1tmi'ted to CalciumCarbonate (by the initial decomposition of bicarbonate). Otherionic combinations (e.g. calcium sulphate, barium sulphate andstrontium sulphate) of low solubility are nevertheless nQt insufficient concentration to give rise to precipitation and hencepossible scaling.
TABLE 1---------
!y~!~~~_~~~Q~_~Q~~Q~~~I~_~~~tj!~~h_~~~~Y~!~_E.QB-~Q~I~_~~~
~~g_~8~~!~~_§~kE_~~I~8§
North Sea ~r~,~·!~,!2_ §~l f---_.~ ... ---
Sodium (Na) 11000 13700Potassium (K) 460Calcium (Ca) 476 576Magnesium (Mg) 1440 1670Barium (Ba) 0.1 NItStrontium (Sr) 7 NILIron (Fe) 0.05 NIL
Chloride (Cl) 19900 24500Sul phate (504) 2725 3400Carbonate (C03) NIL NILBicarbonate ( HC03) 145 159Hydroxyl (OH) 1~IL NILTotal Dissolved Salts 35000 44000pH 7.8 7.8
All data as mg/l except pH.
Water Scaling Problems in the Oil Production Industry
It should be noted however that the fact that a chemical compoundis precipitated from solution under a particular prevailing set ofconditions does not automatically imply that it will form a scale~
i.e. it will deposit as a hard solid on the walls of pipework,heat exchanger surfaces, valves and vessels etc. However, inmany cases where precipitation does take place, scaling occurs andin consideration of water systems in oilfield operations it isalways prudent to consider scaling possibility serious·ly sincenot to do so could be very costly, both in the replacement ofscaled up equipment or in the downtime involved in carrying out adescaling operation.
Produced waters may be totally formation water (i.e. water that ispresent within the rock formation), or may be a combination offormation water and seawater which has been injected into theformation via an injection well.
The poi nt in a well's 1i fe where injected seawater is fi'r'st foundwith produced formation water is called "seawater breakthrough".The time from start up of seawater injection to when water analysisindicates that seawater has made it through the formation to aproduction well will depend primarily on the reservoir geology and
. the rate of water injection; the time period can range from amatter of months to several years.
Formation waters vary very considerably in chemical compositioneven over limited areas. As an example, four produced wateranalyses from areas of the North Sea are given in TABLE 2. It isconsidered for each example that seawater breakthrough has not yetoccurred.
It may be seen that considerable variation in individual ionicspecies concentrations and total dissolved solids can occur.Examples 2 and 3 are analyses of produced waters from wells inthe same field, in fact wells on the same production platform.
It can be readily seen that ionic combination may suggest thepossibility of calcium carbonate scaling. Although barium andstrontium are present there is no sulphate (except for water (4)which has 11 mg/l) and hence 110 possibility of barium or strontiumsulphate precipitation.
The picture may change markedly when seawater breakthrough occurs.Seawater contains the order of 2725 mg/l of sulphate ion. Hencewith only a small percentage seawater breakthrough there is thepossibility of particularly barium sulphate precipitation. Ingeneral where a water has both barium and strontium content,despite the fact that strontium is considerably more soluble thanbarium, if there is sufficient sulphate ion present and scalingoccurs then analysis of the scale will reveal principally bariumsulphate but some strontium. Strontium co-precipitates withbarium sulphate even at sub-solubility levels.
127
128
TABLE 2----------
Chemicals in the Oil Industry
Sodium (Na)Potassium (K)
Calcium (Ca)Magnesium (Mg)
Barium (BatStronti urn (Sr)I ron (Fe)
Chloride (Cl)Su1 pha te (S04)Carbona te (C0
3)
Bicarbonate (HC03)
Hydroxyl (OH)
Approx TotalDissolved Sales
pH
NOTE:
17280
580
2890
3105
195
19
31950
NILNIL312NIL
53541
6.74*
2
9330
198
460
56
4240
0.1
14320NILNIL980
NIL
25926
7.76*
3
8370
200240
52
43
46
0.1
13000
NILNIL
1100
NIL
23051
8.2*
4
29370
372
2808504
252
574
52360
11
NIL496
NIL
86747
1. pH values at atmospheric pressure.2. All data as mg/l except pH.3. Waters 2 and 3 are from individual wells on the same productton
platform.
An example of seawater breakthrough may be seen in TABLE 3 wherethe effect on formation water 4 (TABLE 2) from increasing percentageseawater composition is calculated. It can be seen that atapproximately 6% seawat~r composition, the amount of sulphatesupplied in the seawater will be sufficient to satisfy thestiochiometry of the reaction to produce barium sulphate. It canalso be seen that there is a mixed waters (formation + seawater)ratio above which sulphate content is always in excess. Withincreasing seawater breakthrough the actual quantity of barium andstrontium per unit of produced water volume decreases and hence thepotential rate of scale build up will also decrease.
Water Scaling Problems in the Oil Production Industry
TABU: 3---------
129
Formation Water/Seawater Percentage Mixes mg/1Analytical 100% 100%
Parameters I.-ormation Sea-Water 95/5 90/10 85/15 80/20 75/25 water
Barium 252 239 227 214 202 189 NIL
Strontium 574 546 517 489 461 432 7
Sulphate 11 147 282 418 544 689 2725
StoichiometricRatio Ba: S04(theoreti ca1=
1:0.7) 1:0.04 1:0.61 1: 1.24 1: 1.95 1:2.7 1:3.64 -
Excess S04 2-after reacti onwith Barium (i.e.available for Sr) NIL NIL 123 268 403 537 -
StoichiometricRatio Sr:S04(theoreti ca1 =
1: 1.09) - - 1:0.24 1:0.55 1:0.87 1: 1.24 -
-NOTES:
1. There is sufficient sulphate ion for complete barium precipitation at 6%seawater breakthrough.
2. There is sufficient sulphate ion to satisfy the stoichiometry of barium andstrontium at approx. 20% seawater breakthrough.
3. The ionic strength of the formation water is 1.56. Hence solubilities ofboth barium and strontium will be higher than theoretical for a giventempera ture.
130 Chemicals in the Oil Industry
Mixed waters will also change the probability of calcium carbonatedeposition. TABLE 4 shows the effect of seawater breakthrough onformation water (1) in TABLE 2.
The Langalier Scaling Index (see later for details) ha~ been calculatedfor the pure waters and various combinations of their mixtures; thetemperature at which the index becomes positive (i.e. scaling may bepredicted) is also calculated.
GRAPH 1 shows these calculated data diagramatica11y.
It can be seen that at the temperature considered (850C), which isthe bottom hole temperature (BHT) for the well in question, that bothindividual waters would be predicted "scaling". The combination waters,in every case, have a higher scaling index indicating relativeprobability and severity of scaling. The worst case is when a 50/50waters mix exists.
I~~k~ 1~EE~~I_QE_~~~~~I~~_~~~~~I~8Q~§~_Q~_~_EQ~~I!Q~_~~I~~:~~h~!~~_~~~~Q~~I~_Q~~Q~!I!Q~
Analytical SEAWATER/FORMATION \~ATER MIXTURES mg/lParameterRe 1ated to 1OO~~ 100%Scaling ormation 75/25 60/40 50/50 40/60 25/75 Sea-Tendency Water \'.Jater
pH 6.74 7.02 7.19 7.3 7.41 7.58 7.86
Sodium 17280 15960 15168 14640 14112 13320 12000
Calcium 2890 2282 1918 1675 1432 1067 460
Magnesium 310 582 746 855 964 1127 1400
Barium 5 3.78 3.04 2.55 2.08 1.32 0.1
Strontium 195 148 120 100.7 81.8 53.6 6.4
Chloride 31950 28882 27042 25815 24588 22748 19680
Carbonate NIL NIL NIL NIL NIL NIL NIL
Bi carbonate 312 269 243 226 209 183 140
Sulphate NIL 662 1060 1325 1590 1987 2650
Scaling Index by !Stiff Davis Extrof Langaliermethod +1.65 +1.80 +1.83 +2.13 +1.88 +1.86 +1.68
Temp above300 C 230 C 23° C 230 C 200 Cwhich SI +VE 200 C 280 C
Water Scaling Problems in the Oil Production Industry 131
~ 10I,-----1---'·-----.----- --- --_._-.,.------ ---+-- .. ~- ~
II
I
I
!+-----+----+----+---+-----t------;.--.,...-O+-----+--
I ~ I i: ~: 1 II ' cfil (;\3'- 'I o:~ I i
~. -_.:- -~._~ -.-- ~_.. ---1-- -------I J--· -,- ",fi 5 ~J I I II S:! \' I ! I I
I ''ll 9 2.lI \ I I' i' I "'I "
~-----l-}----- -'-.~ '\ t-··_' ·'r--~-t--:---l-·/!--+--'---·---'---4'-·'--
l---.~-l--::--: 1-~--1~1 .1;/I', Jji 2~ I "i \}-l-/j
\ i ,! I I.~---+----i------+----+-'----t----+------1o-~--!---
I 1,0 ~c."> ~ 411' 50 ,p -'P ..~ ~c
ill !
132 Chemicals in the Oil Industry
From the scaling index calculated at 850C is also determined thetemperature at wh~ch the waters first become scaling. The minimumtemperature is 28 C, that of seawater alone. It may be deducedtherefore that 3n a downhole situation where the temperature rgngewill be from 85 C (bottom hole temperature) reducing to say 60 Cas the surface separation equipment scaling could be expectedthroughout the system.
It is also in~eresting to note that,since seawater has a positiveindex from 28 C,for seawater used in water injection systemsthere is the possibility of carbonate scale ~mere water is used,for heat exchange/cooling purposes, prior to injection into theformation.
Knowledge of simple solution chemistry has been assumed but factorsthat influence solubility of scaling salts may not be widely knownand therefore are briefly reviewed.
Key factors that may influence scaling probability in oilfield systemsare:
tempera turepressurepH valuetotal ionic strength of the solution containing the scaling ions.
TABLE 5 lists the common scaling species and the physical conditionsthat influence scale formation.
As mentioned earlier, since few waters contain carbonate ion thepotential for scaling comes from the initial decomposition ofbicarbonate by the reaction.
Ca(HC0 3)2~ CaC03 + CO 2i +H20.The solubility of calcium carbonate in pure water is 53.0 mg/l (250 C)
In the presence of carbon dioxide the pH is lowered and the solubilityof calcium carbonate increases. Conversely if the carbon dioxideconcentration is reduced (e~. in a reducing pressure situation as ;na produced water passing through a well choke valve or a separatorvessel, or by injection seawater being deoxygenated by a vacuumstripping tower) then the solubility of calcium carbonate decreases.
The effect of C02 partial pressure on the solUbility of calciumcarbonate for a range of temperatures is shown in GRAPH 2.
Water Scaling Problems in the Oil Production Industry
TABLE 5---------
~~~Q~_~~~~!~§_~~~~!~~_!~_Q!~E!~~g_~Y~I~~~_~!I~_!~Eh~~~~!~§
E~Y~!~~~_E~~IQ~~
133
Calcium Carbonate
Calcium Sulphat€as gypsum, hemi hydrate,anhydrite
Barium Sulphate
Strontium Sulphate
GRAPH 2---------
Partial pressure CO2,Temperature.Total Dissolved Solids.
Temperature.Total Dissolved Solids.Pressure.
Temperature.Total Dissolved Solids.Pressure.
Tempera tu re.Total Dissolved Solids.
EFFECT OF COz PARTIAL P(~ESSURE ON THESOLUBILITY Of CALCIUM CA.ROONATF.
120
100 -
00-
(,0c~
PHESSURE(BAR) 40-
20
--~i----y----.,.------.-,-...---,-.~1000 I~OO 2000 2~OO 3000 3500
SOLUBILITY OF CoCO~
(mo ILlTHE)
134 Chemicals in the Oil Industry
An example of the effect of pressure change deposition is shownin PLATE 1. The photograph shows scale deposition in a wellflow line. In this case there was at least an indication thatscale deposition could occur but none had been found downhole.The high pressure drop accross the Christmas tree valve systemswas sufficient to "seed out" crystals of scaling species and theimmediate downstream flow line rapidly scaled up.
Temperature also has a marked effect on the solubility of calciumcarbonate. Contrary to conventional solubility behaviour. thesolubility of calcium carbonate decreases with increased temperature.GRAPH 3 illustrates this effect at a fixed partial pressure of C02in pu re wa ter .
Total disso1veu salts of the water containing the calcium carbonateis also an important factor. Up to a TDS of approx 200,000 mgilthe higher the level of dissolved salts (excluding of course Ca 2+or C03-2- /HC03-) the greater the solubility of calcium carbonate.Above this TDS level no further enhanced solubility is observed.
PLATE 1 Photograph of Scale Deposition in Crude Flow Ltne
Calcium sulphate (gypsum) scale may be found in some oilfield waters.The reaction is simply
Ca2+ + S042- ~ CaS04
Solubility in distilled water is given as 2080 mg/l (250 C). Theactual calcium sulphate molecular structure is dependent on temperature;up to 400 C it is Ca S04 2H20, solubility increasing with increasedtemperature. From 400 C to 1100C water of crystallisation is drivenoff to form the hemihydrate and anhydrous salt.
Water Scaling Problems in the Oil Production Industry
-----··----·-lSOLUBILITY OF CaC03 AT I BAR
COl PARTIAL PRESSURE IN PURE WATER
1250
135
1000
750
SO~~~~1TY(m~/I )
500
250
O~--"I--,--r-i-'-~---r----.--~_--.20 40 C:O 80 100
TEMPERATURE. QC
Over this range, solubility decreases with increased temperature. Itis therefore important to be aware of the operational temperature rangeand whether the water is undergoing an upward or downward temperaturechange.
The type of scale formed is generally hard and difficult to removeonce laid down. Simple inhibited acid treatment may be used forcalcium carbonate but passivation occurs when calcium sulphate removalis attempted using mineral acids alone. It is generally necessary topre-treat with a "converter" (ammonium carbonate - to produce calciumcarbonate) before acid treatment.
Carbon dioxide partial pressure is not a factor in the precipitationof calcium sulphate. The only real effect of a high C02 environmentis to hold calcium carbonate in solution thus leaving more calcium ionsfree to combine as calcium sulphate.
Presence of dissolved solids TDS (other than Ca2+ and 5042- ions),increases calcium sulphate solubility as with calcium carbonate upto a TDS of approximately 150,000 mg/1. Above this dissolved saltsva lue the solubi 1i ty of cal cium sul phate decreases.
GRAPH 4 shows the solubility of calcium sulphate at a range of salt(NaCl) solution concentrations. The graph holds for temperaturesbetween 0 - 900C.
Increased pressure is found to increase solubility. There arehowever at present no complete data on this effect. At very highpres su res the effect is reversed and a decr'ease in sol ubi 1i ty occu rs.
136 Chemicals in the Oil Industry
SOLUBILITY OF GYPSUM IN Noel BRINESFROM ooe -90°C
8000
LEGENDTEMP ·C
o 0·55
p 106 25• 35
50• 70
• 90
o~----..----r- i I •
50 100 ,~o 200 250
NoCI CONCENTRATION(om/l)
300
'-- -1
Barium sulphate is one of the most insoluble compounds formed inoilfield water systems. The reaction to form barium sulphate ;ssimply
Solubility in distilled water is quoted as 2.3 mg/l (250C).
Solubility increases with temperature in the pure water and also inbrine solutions. For example the solubility of barium sulphate isquoted at 2.3 mg/l at 250C and 3.9 mg/l at 950 C. For barium sulphatein 5~ brine solution the figures are 20 mg/l and 42 mg/l respectivelyfor the two temperatures considered.
The converse is equally true; hence for waters at well bottom containingbarium and sulphate ions in solution as the temperature and pressuredecrease up the tUbing string and through the surface separation system,precipitation of barium sulphate may occur.
The effect of temperature and ionic strength on the solubility ofbarium sulphate is shown in GRAPH 5.
Pressure also increases solubility of barium sulphate; however, asyet there are no pUblished data.
1·0
Water Scaling Problems in the Oil Production Industry
,..-.------------_._--_._---_.._----SOLUBILITY OF BaS04 IN Noel SOLUTIONS
OOS04SOLUBILITY
(moll)
o L-...----or-----_.,-.-------r.----~i-2·0 3·0 4·0
IONIC STRENGTH
l137
It can be seen that for say a mixed water containing barium and sulphateions that scaling may occur if the separate ionic concentrations areabove the values as defined by the key physical conditions. Henceif barium is known to be present in the formation water and seawaterbreakthrough has taken place then the probability of scale depositionsomewhere in the system should not be ignored. Failure to findbarium in the analysis of a produced water sample taken at the surfacefacility in a water known to contain some barium must suggest thatprecipitation has already taken place and the scale has already beendeposited downhole.
Strontium may under conditions~of high sulphate level precipitateas strontium sulphate. The actual quoted solubility of SrS04 is150 mg/l in pure water solution, up to an ionic strength ofapproximately 1.3; the solubility increases to 750 mg/l afterwhich there is no appreciable increase. This effect is shown inGRAPH 6.
Generally strontium sulphate scale is not found alone but incombination with barium sulphate. Strontium sulphate is known toco-precipitate with barium sulphate even under sub-solubilityconditions.
There is some increase in strontium sulphate solubility withtemperature rise although not as pronounced as with barium.Pressure would seem to have no effect.
138 Chenlicals in the Oil Industry
-------------------------_._---_._---SOLUBILITY OF SrSO" IN No Cl SOLUTIONS t~T 25°C
500
SrSO" 400SOLUBILITY
(mQ/I) 300
200
100
------,------·-,------·T·--- , -r05 10 15 2-0 2-5
IONIC STRENGTHL- . . ... .• _ .._._.__._-
g~~~!'!!1i!}~~iQ!}_Qf_~rQ~~~i!l~~_Qf_§~~l~_EQr'E~~iQ~_~~_~~l~~!~~iQ!}_
~~!bQ~~
The standard calculation method applied is the Stiff, Davismodification of the original work carried out by Langalier. l ,2The method extends the "Langalier Saturation Index" to apply tohigh dissolved salt waters (oilfield 5rines).
The stability Index (SI) is determined, whereSI pH - pHspH actual pH of waterpHs the predicted pH value the water would attain when
saturated with calcium carbonate at a given temperature.
pHs K+ pCa + p Alkand hence SI = pH - (K+ pCa + pAlk)where K is an empirical constant used to compensate for thedissolved salts content and temperature. Dissolved saltscontent is expressed as ionic strength.
Water Scaling Problems in the Oil Production Industry
pCa = log
Mols Ca++/litre
pAl k log
Equivalents total alkalinity/litre
The details of the calculation procedure a~e not given here but arepresented fully in the literature.3,4
A positive SI value indicates that scaling is likely i.e. pH>pHs:water is supersaturated with respect to calcium carbonate.
At SI = 0 the water is on its saturation point with respect tocalcium carbonate.
A negative SI value indicates that scaling is unlikely t.e. pH(pHs:water is not saturated with respect to calcium carbonate.
It must be appreciated that the method is not absolute. A calculatedlow order positive index water (say up to + 0.5) may not under someconditions deposit carbonate scale; however the posibi.lity should notbe overlooked. For waters of higher positive SI value it would beunwise to assume no scaling will occur and to take some form ofscale control measure.
The possibility of calcium sulphate scaling from waters is calculatedusing the Stillman, McDonald, and Stiff Method. 5
The solubility of calcium sUlphate is effectively independentof pH value. The method compares the theoreti'cal solubiltty ofcalcium sulphate in the solution concerned at a giventemperature with the actual amounts of calcium and sulphate tonspresent.
The calculated solubility of CaS04 in meq/litre liS"
S = 1000[(X2+4K)O.5_X]
where K is the solubility product constant (from ionic strengthand temperature)X is excess corrmon ion diffet'ence (i .e. difference in Ca 2+ and S042ion concentration) in moles/litre.
If S is found to be less than the actual amount of CaS04 presentthe. scaling is likely. Conversely for a ca'lculated value of Sgreater than the actual for Ca504, scaling would not be predicted.
The method is fully detailed with calculation graphs etc in therecommended reference books.
139
140 Chemicals in the Oil Industry
The solubility of barium sulphate in water is v~ry low. Watersthat contain barium and sulphate ions should be treated withconcern. Dissolved salts content and temperature will affectthe solubility.
GRAPH 5 gives a basis for determination whether a calculatedbarium sulphate content will remain in solution at the temperatureconsidered or will precipitate.
A graph of strontium sulphate solubility is given in GRI\PH 6.Calculated strontium sulphate contents in waters under constderationthat are above the solubility curve would indicate that stronttumsulphate d~position is likely. It should however be rememberedthat strontium has a tendency to co-precipitate with barium sulphateeven at contents well within its normal solubility.
Er~~!i~~!_h~~2r~~2!:~_~~~b2~_2f_~~~!i~9_!~~~~~~t_E!:~~i~!!Q~_~~9
~~~!~_!~~i~i~2r_~~~!~~~12~
There are two basic methods in general use by oil and chemical servicecompanies.
Static Scale Precipitation method and the dynamic "Tube Blocking ll
technique.
The static precipitation method was developed by BP Research~ Sunbury;the dynamic test method was originated by Shell Petroleum but has beenmodified and improved by others.
The method is essentially a beaker technique whereby a formation water(either real or synthesized) is mixed with seawater in a number ofvolume ratios, generally from 90:10 to 10:90 formation water toseawater. The pH values of waters to be mixed are adjusted to6.0 prior to mixing. The mixed waters are held at a temperature of 700efor a fixed time neriod (usually 16 hours) after which each is separatelyfiltered through a 0.45 micron Millipore filter. The concentrations ofcalcium, barium and strontium remaining in solution are then determined.
Tests are carried out on "blanks" (not containing scale inhibitor)and then, if the intention is to identify the best inhibitor chemical, ona number of potential candidate chemicals at a range of concentrations.
A plot of inhibitors efficiencies at a given dose level for the rangeof water ratios considered will indicate the ranking of the chemicalsstudied. By considering a range of dose levels the best performingchemical and its optimum application level may be determined.
Water Scaling Problems in the Oil Production Industry
The method is applicable to scale inhibitor performance evaluationfor calcium carbonate, calcium sulphate, barium sulphate and strontiumsulphate scaling either singly or in combination by preparation of suitablesynthetic water mixtures.
Variously modified testing units have been made to the initial conceptby workers in the field of oilfield water scaling problems.
The basic principle, however, is essentially the same. The methoddepends on the rate at which the pressure drop increases through astandard length of capillary tubing. The tubing bore diameter isnormally of the order 1.Omm; length is dependent on individualpreference but should be no less than 1 metre. Generally stainlesssteel tubing wound into a coil is used; care must be taken to ensurethe tubing configuration is the same for each comparative test sincechange in bend radius will significantly alter the results.
The apparatus is shown diagrammatically in FIG 1 set up for calciumcarbonate scaling work.
It consists of a water storage reservoir for the water under test anda second reservoir containing either a solution of the scale inhibitorto be evaluated or the second water with or without added scale inhibitor.
Flow from the two reservoirs ;s accurately ratioed to give the requiredvalues by two variable speed peristaltic pumps.
The two flows are mixed in the magnetically stirred mixing unit fromwhere the mixed waters (or water minus scaling ion + water with scalingion and scale inhibitor) are transferred to the test coil. The coilis inrnersed in a constant temperature bath at the test temperature.Flow from the coil is to waste or may be collected in an automaticsampler for ions analysis. The pressure change across the system(really the change across the capillary tube since the volume of therest of the system is a constant) is measured by a pressure transducer,the signal from which is amplified and displayed on a moving chartrecorder.
The tinit described is a low pressure system generally operatingup to 15 psi. Other more sophisticated units have been designedto work at typical reservoir pressures.
Typical results obtained from the low pressure unit are shown inGRAPH 7.
GRAPH 7 shows (lhs) the rate of pressure increase for the scalingsolutions alone; (rhs) the effect of partially scaling the capillarytube and then applying scale inhibitor. It can be seen that at4ppm the inhibitor was effective (i.e. no increase in 6P occurred);at 3ppm there was insufficient inhibitor present to stop scaling.
It can be seen that the unit can differentiate to the extent of lppmchange in inhibitor dose level. The test procedure is rapid (cf theStatic Test) and is found in practice to be highly reproducible.
Work is in hand to modify the apparatus for barium and strontiumsulphate scaling \>/oy'k. As yet however no firm data are available.
141
STI«'l.E.R..,J::..N
WATER. FEEl)PUMP
L, I ,~,. C.01\_i
\,1'\
~F:NSwc...e:tt
w(-\~T£
Diagramnatic Representation of Dynamic Tube BlocktngApparatus - set up for Calcium Carbonate work.
Q~
~~.
~c;;--S·S.~
~~;:::~~~
~
..2..n:b fttt-02.1l ER..
All. XQu:,..r=tu.
..UNI'A/b
\JRTER.~
.. -rE,.t\'. c.oN~RoL.
DATA
• __ IAHP.
~c.ALE
INHH~rrOI<
PUNP
FIG. 1
WfllER~T~A(4E
Lw A-rE.f'.. lA.~i)ER.-r"'E.ST)
Water Scaling Problems in the Oil Production Industry
i lkR; I 3HRi
! '~ I;. i ;i I I I i I
.•. _._.~ L_ .....L_ ...J..._.1... __ .•
Control of scale formation in oilfield water is generally achievedby the addition of scale inhibition chemicals.
There are two main mechanisms by which scale inhibitors act.1. Crystal distortion.2. Threshold effect.
Crystal distorters act by becoming incorporated into the crystals asthey are formed. This has the effect of distorting the normallyregular crystals, thus reducing significantly adhesion betweenindividual particles or any solid surface with which they come intocontact.
Threshold effect chemicals act in sub-stoichiometric concentrationsto adsorb into the forming crystal nuclei preventing further crystalgrowth and hence deposition as scale.
Threshold effect chemicals, used at well below the stoichiometricconcentrations of the potential scaling species they are intended tocontrol) are most suitable for oilfield water applications.
Dose level of an effect scale inhibitor is normally in the range of1 - lOppm. Chemical must be added before the point of initialscale formation. Chemicals of this type only work effectively fromsolution.
Three basic chemical types have been shown to have the requiredscale inhibition properties. These are:-
Organic polymers: - generally of the polyacrylamide or polyacrylatetype.
143
144 Chemicals in the Oil Industry
Chemicals of this type may be used in high temperature conditions(up to 2000 C) for the control of calcium carbonate, calciumsulphate, barium sulphate and strontium sulphate scale.
They would probably be the leading type of product for welldownhole "squeeze" applications if it \'Iere not for the problemsof monitoring the returning inhibitor {see later). They havebeen shown to be very effective in scale control in productionsystems separators and oily water clean up units when added atthe well-head manifold; scale deposition is often induced bypressure drop through the separator train.
A new range of phosphino-substituted polycarboxylic acid inhibitorshas recently been developed where the active ingredient is aphosphorus-containing polycarboxylic acid. The addition of thephosphorus enables the product to be monitored at low concentrations.The type of chemical may well find application in downhole squeezetreatments ~ince it combines the high temperature stability of apolycarboxylate with a means of analytical measurement in separatedproduced water.
It is primarily designed to inhibit barium and strontium sulphatescale formation but also displays some effect against calcium carbonate.
Organic phosphonates are generally effective on carbonate and sulphatescales. They have reasonable thermal stability and may be usedat temperatures up to about l750 C without efficiency losses due todecomposition. They have therefore been the most widely used chemicaltype for production well squeeze treatments since they have a readilyanalysed functional group. The phosphonate is generally reduced tophosphate which may be readily determined by colorimetric means.
Phosphate esters are generally effective against carbonate and sulphatescale formation. They are more commonly used in low temperature conditionssince they have lower thermal stability.
They may be used for protection against scaling in water injection systemswhere the temperature of the injection water is unlikely to be very high/even where water is pre-utilised for heat exchanger duties, and inproduction separator and oily water systems.
Their use in squeeze applications would be limited to low bottom holetemperature wells. They have the advantage, where they can be used,of ease of analysis at low levels via the phosphate grouping.
~~g~lr~~~~!_~~9_~ee!!~~!!2Q_2!_~~~1~_!~~!~!!Qr~
As discussed above, water scaling problems occur in the followingoilfield systems.1. Water injection.2. Downhole/in production tubing.
3. In production process train (separators, oily water clean up systems).
Water Scaling Problems in the Oil Production Industry
For water injection systems it is convenient to add the chemicalinto the water flow line by means of a metering pump. Chemicalis generally added as early as possible into the injection watersystem and certainly ahead' of heat exchanger/oil cooling units.A general flow diagram of a water injection system is shown inFIG 2, indicating preferred addition point for scale-inhibitivechemical. Little maintenance is required in carrying out scaleinhibitor addition. The chemical is supplied in liqUid formand the dose level is determined with respect to the as suppliedchemical. It is only required therefore to ensure that thedosing pump output is at all times correctly ratioed with theseawater injection throughput to maintain an effective scaleinhibition treatment.
Scaling problems from produced waters - formation or mixedformation + returning injected seawater - may occur at the wellbottom (i.e. at the perforation levels) or as the produced fluidsprogress up the production tubing.
Scaling species may be seeded out by pressure~ temperature orvelocity changes in the production well system.
Generally wells are not completed such that a chemical dosingline (macaroni string) extends from the surface facility to thebottom of the well and hence chemical cannot be added continuouslyto the produced fluids to inhibit scaling.
The only practical method therefore of getting scale inhibitor intothe fluids is by the technique known as "squeezing". This consistsof reverse flowing a production well by applying excess pressure fromthe surface facility and adding to the reverse flow scale inhibitorsolution.
In practice~ the procedure is generally carried out as follows:-
Surfactant "Spearhead" injection - a dilute solution of a stJrfactantin water is injected into the production well to overcome any emulsionblock that may occur. Sufficient is added such that it is pushedoutward from the perforated zones of the well bore into the formationitself, the main purpose being to water-wet the formation and allowadsorption of scale inhibitor solution added subsequently.
Scale Inhibitor injection - the scale inhibitor to be used is injectedinto the rroduction well at low concentration in water (generally 1 3% of as supplied chemical). The quantity required is a matter ofconjecture~ most service companies having their own ideas of theamount needed to give an effective duration squeeze.
Overflush Injection - to ensure the ~cale inhibitor is pushedaway from the well-bore and into the formation such that it maybe adsorbed an overflush of water (or possibly di€sel or evenproduced gas) is used. The extent that the scale i'nhibitor
145
146
lI\
... ~"2 :J....- .....- .. ~~
Chemicals in the Oil Industry
~.,..-------1..~
1.1 0
\">.n1 :f
'4.l\.9. ,
LIWI1-1V>I>-1V>I
IZI01~I
1-1UIWI'"":)1ZI~I
I0:=1WI1-1«I3:1
I-11c::(1UI~I
0-1>-11-1
Il.L-101
:i:0:=1C,.!JI«I~I
01I
3101-11Lt.. I
IIII
01NI
II
.1C,.!JI~I
lJ...1
Water Scaling Problems in the Oil Production Industry
is pushed in terms of radius from the well-bore is againsubjective; in general though it should be in the range of8 - 15 ft radial displacement into the formation.
Generally the well is shut for some 24 hours after completionof the squeeze chemicals application; it is then slowly broughtback to full production. Adsorbed scale inhibitor is desorbedfrom the formation into passing fluids. Initially aesorptionis high leading to an excess of scale inhibitor present overactual requirement. Gradually the amount of chemical presentin the produced fluids falls to a level at which it is no longergiving full inhibition protection. At this point, it is necessaryto re-squeeze the well. An effective squeeze treatment should lastsome 3 - 4 months.
The explanation of adsorptionjdesorption given above is an oversimplification; there are many papers written on this subjectwhich look closely at the possible squeeze mechanism. 7, 8
It is important to be able to determine quantitatively down to theperformance threshold level of the scale inhibitor in order todetermine when it is necessary to carry out a further squeezetreatment. Hence the chemical used must have a parameter orfunctional group capable of being accurately determined. It ishere when the phosphonate and phosphino polyacrylate inhi'bitorsscore over the straight polyacrylate. Being essentially a hydro-carbon species it is difficult to differentiate between thepolyacrylate and residual oil in the separated water.
In many caseS serious scaling does not occur down-hole but i~
seeded out in the separation and oily water clean up systems.A typical system is shown diagrarrmatically in FIG j . If itcan be shown that downhole scaling is not a current problem andproviding regular checks are made to ensure that no change towardsdown-hole scaling is occurring (by study of water anaylsis results),it is convenient to add the scale inhibitor at the topside facility.The chemical should be added as neat downstream of the Christmastree valve system as possible for each individual well to be treated.The production volume/water cut of the well or wells to be treatedshould be determined on a regular basis and the dose level of chemicaladjusted accordingly to ensure effective treatment.
Dependent on the scaling tendency and the potential amount of scaleit may be necessary in some instances to add chemical at two points,at the wellheads and again upstream of the oily water separation units.
With treatment for scale inhibition under any conditions, itmust be stressed that it is important that the application ofthe chemical is not taken for granted. Routine checks on ashift basis should be made to ensure the chemical is in factbeing added at the correct level. Then assuming an effectivechemical was selected, few scale related problems should beexperienced.
147
148 Chemlcals in the Oil Industry
-~.J.'4'~d'lS od'"•.J-~,...,~~
- - - -~y>q--e::================
cA~+-- .t to I..,
~ ~~ I.,i~ ,
L-.J.-s -- - - -... ~0 Cl(
..J ,.. -.
D
~IWIt-I(/')1
>-1(/')1
I2:101...... 1t-Ie:t:10::1e:t:10-1Wl(/')1.........12:101...... 1t-IUI::::>101010::10-1
IWI01::::>10::1UI
I-lle:t:1UI...... 10-1>-1t-I
Iu...101
~:0::1Cl'1c:(1...... 101
I3101-llu...1
IIII
0 1MI
II
-ICl'1...... 1u...1
Water Scaling Problems in the Oil Production Industry
References----------
1. Langa1i er WF. JAl,WA Vo1. 28 (1936) .
2. Stiff H.A. and Davis L.E. "A Method for Producting theTendency of Oilfield Waters to Deposit Calcium Carbonate".Trans AIME 1952 195.
3. "Oilfield Water Systems" (Second Edition) Dr. C. C. PattonCampbell Petroleum Series 1977.
4. "Water Technology in the Modern Oil Industry" - McKenzie D.Hydrotech Ltd. 1981.
5. Skil1man H.L., McDonald J.P. Jr., and Stiff H.A.American Petroleum Institute Meeting, Division of ProductionPaper 906-14-1 March 1969.
6. Hughes C.1. and Whittingham K.P. B.P. Research CentreEuropean Petroleum Conference, London. Oct. 1982.
7. Vetter O.J. "Adsorption-Desorption - Is it the basis ofChemical Squeeze Technique?" Trans AIME - 1971 SPE Paper 3544.
8. Tinsley J.M., Lesater R.M., Knox J.A. AIME 1967. SPE Paper1771.
149
The Chemistry of Corrosion Inhibitors Used in OilProduction
By J. A. Kelley
TRETOLITE DIVISION, PETROLITE CORPORATION, ST. LOUIS, MISSOURI 63119, U.S.A.
INTRODUCTION
Corrosion inhibitors are r-outinely used in oil production at rates varying from a few
parts per million (mg/I) to thousands of parts per million. Many of the commercial
corrosion inhibitors are unique mixtures that may contain surfactants, film enhancers,
demulsifiers, or an oxygen scavenger in addition to the inhibitor moiety. The purpose of
this paper is to provide a brief discussion of the chemistry of t!le inhibitor moieties and
provide a few illustrative examples of formulation considerations. This paper does not
attempt to describe all of the commerically available formulations, but rather the broad
chemistries within which they fall.
The majority of corrosion inhibitors used in petroleum production are nitrogenous in
nature and can be classified in a method similar to Bregmanfs1 as follows:
1) Amides/lmidazolines
2) Salts of nitrogenous molecules with carboxylic acids
3) Nitrogen Quaternaries
4) Polyoxyalkylated amines, amides, and imidazolines
5) Nitrogen heterocyclics
There are other, non-nitrogenous inhibitors that contain phosphorus, sulfur, or oxygen
atoms but they are used less frequently.
AMIDES/lMIDAZOLINES
Many of the common oil and water soluble corrosion inhibitors contain amides
and/or imidazolines which are produced by condensing a carboxylic acid with a primary
amine. The carboxylic group is often derived from low cost natural sources such as crude
or refined tall oil.2 The typical fatty acid derived from tall oil is composed primarly of
C18 linear saturated and unsaturated chains with minor amounts of C16 linear chains and
some rosin acids.3,4 Naphthenic acid mixtures derived from petroleum are also used.5
The Chemistry ofCorrosion Inhibitors Used in Oil Production 151
The amine frequently used in the reaction is a polyamine having the structure H2N(
R-NH)x H where R is an alkylene group containing 2 to 6 carbon atoms and x is a
small whole number greater than 1. A frequently used polyamine is diethylene
triamine (R=CH2CH2 and x=2). Mixtures of higher homologs (x=4 etc.) can also be used.2
An example of a common imidazoline is :
where R is derived from the previously mentioned tall oil fatty acids. A water soluble or
water dispersible inhibitor blend is often made from such an imidazoline by adding a low
molecular weight organic acid and a mixture of solvents and perhaps a surfactant.6,7
SALTS OF NITROGENOUS MOLECULES WITH CARBOXYLIC ACIDS
There are numerous references that discuss salts formed by the neutralization of the
basic nitrogen by tall oil fatty acids, polymerized fatty acids, naphthenic acids, or simpleorganic acids. 8,9,10,11,12,13,14 A recent example utilizes a high molecular weight
polymerized carboxylic acid neutralized with a tallow amine.lS The use of polymerized
fatty acids in inhibitor formulations is estimated to be in the millioM of pounds per
year.16 In general, any unreacted basic amine or the imidazoline itself can be fully or
partially neutralized with wide variety of acids.
QUATERNARY NITROGEN
The term quaternary nitrogen applies to compounds in which all of the hydrogens of
the ammonium ion have been replaced by linkages to carbon. These are often referred to
as cationics as shown:
+R'I
R~N -R X-
1",R
152 Chemicals in the Oil Industry
The quaternary nitrogen compounds are excellent cationic surfactants and may
possess biocidal, demulsifying, or corrosion inhibiting properties.l7,18 In the fatty
amine quaternaries, at least one of the R groups consists of a long alkyl chain and
may have more than one cationic nitrogen atom.l9 Other nitrogen containing
compounds that are quaternized include imidazolines,20 polymerized amines,21,22
and pyridines.8
POLYOXYALKYLATED AMINES, AMIDES, AND IMIDAZOLINES
Any reactive site can be oxyalkylated to modify solubility or dispersibility of
the inhibitor intermediates. Examples include an ethoxylated rosin amine,
polyamines 'with epichlorohydrin,21 beta amine ethoxylates,23 and ethoxylated
imidazolines and amines.24
NITROGEN HETEROCYCLICS
There are numerous examples of heterocyclic nitrogen compounds in the
patent literature. Typical are alkyl piperazine and alkyl pyridine hydrochlorides,25
and alkylated polymerized pyridine.26
INlDBITOR CONTAINING PHOSPHORUS, SULFUR, AND/OR OXYGEN
There are a variety of inhibitors that contain phosphorus, sulfur, or oxygen
atoms in the molecule. Their use is often limited to narrow areas. Examples
include dialkyl disulfide oils,27 phosphate esters of cyclic amidines,28 quinoline
phosphonates,29 pyrophosphates,30 and amino phosphonic acids.31
INHIBITOR FORMULATION
Many of the successful corrosion inhibitors are carefully formulated mixtures
that may contain one or more inhibitor moieties from the classifications mentioned
earlier. In addition to the inhibitor, a surfactant, demulsifier, scale inhibitor,
biocide, or oxygen scavenger may also be incorporated.
A low cost water soluble inhibitor can be made using the imidazoline depicted
earlier by simply adding acetic acid and a suitable solvent. In an oilfield water system
where solid deposition such as iron sulfide is a problem, a suitable amount of a nonionic or
cationic surfactant has to be added to reduce the tendency for solids to deposit on metal
surfaces. A buildUp of iron sulfide often leads to a pitting type of corrosion under the
deposits. If the oilfield water contains low levels of oxygen, a small amount of a suitable
The Chemistry ofCorrosion Inhibitors Used in Oil Production 153
sulfite or hydrazine oxygen scavenger might be included in the fc,rmulation. It is also
important to reduce solids deposition in waters that contain low levels of oxygen to
prevent a severe pitting type of corrosion. Likewise, if a mineral scale problem exists in
the system, a suitable scale inhibitor that is compatible with the corrosion inhibitor has to
be added.
A laboratory test called the C02 sparge test is often used to screen water
soluble/water dispersible inhibitors. The results correlate well with field experience. The
test is based on the linear polarization principle. There are numerous multichannel
instruments that allows ten or more inhibitors to be evaluated in a twenty-four hour
period. The test can be run as a sweet or sour system, in straight brine or a
brine/hydrocarbon ,mixture, and up to a temperature of 1500 F. See Appendix 1 for more
details.
An effective oil soluble inhibitor can also be made from the same imidazoline by
simply replacing the acetic acid with a high molecular weight acid and using an aromatic
based solvent. To aid in uniform distribution of the inhibitor and ease of application, a
suitable nonionic or cationic surfactant is often added to make the oil soluble inhibitor
somewhat dispersible in the water. Secondly, a small amount of surfactant usua.lly
increases the effectiveness of the inhibitor. The table below illustrates the effect of the
addition of a surfactant and polymerized fatty acid to an amine based inhibitor. The
corrosion data was obtained from a dynamic corrosion test commonly known as a wheel
test, the details of which are given in Appendix 2.
Table 1 31
Inhibitor
Amide
Amide + Polymerized acid
Amide + Polymerized acid + surfactant
96 Protection at 60 ppm inhibitor
18
62
96
To minimize or avoid creating stable emulsions, a small amount of demulsifier may also
be added.
There are additional problems to consider when formulating an inhibitor for gas
wells. Care must be taken to devise a formulation that provides a uniform dispersion of
the inhibitor on the tubular goods for the selected application method. The inhibitor must
also possess good thermal and chemical stability in well fluids under production
conditions. Two of the inhibitor removal processes that exist in gas wells are washing by
154 Chemicals in the Oil Industry
produced fluids and evaporation. Thus, the inhibitor moiety and any additives should have
a very low vapor pressure under production conditions and be as insoluble as possible in
well fluids, depending on the treatment method. 33
Inhibitors for use in gas wells are usually evaluated under higher pressures and
temperatures than are obtainable in the wheel test. Special test cells are often used to
simulate the acid gas partial pressure in these wells (u~ to 200 psi Pco2 or PH2S).
Alternately, high pressure autoclaves capable of accomodating field fluids under the
conditions encountered in deep gas wells are often used. A typical autoclave test may run
for several weeks.
Most oil companies use a variety of laboratory tests to qualify inhibitors for field
use. These tests determine the need to add or delete components to achieve the desired
properties for a given application. Emulsion tendencies, solubility, partitioning
coefficient, and effectiveness in a variety of corrosion tests are among the qUalification
tests.,34,35,36
Considering all of the blend components and their possible combination, including
hundreds of surfactants and other additives, it is easy to understand the great number of
commercially available corrosion inhibitors.
APPENDIX 1: C02 Sparge Test
The test relies on the linear polarization technique and utilizes the three electrode
system. One of the electrodes is called the reference electrode; the second the test
electrode; and the third the auxiliary electrode. The corrosion rate value (mpy) obtained
with the meter is the corrosion rate of the test electrode.
About 800 mls of a laboratory brine or a brine/hydrocarbon mixture in a 1000 ml
beaker is sparged with C02 (or H2S) for one hour with stirring to saturate the brine with
C02 (or H2S) and remove oxygen. The electrodes are degreased in acetone and immersed
in 15% hydrochloric acid for ten seconds and removed. They are then allowed to
precorrode for two hours while C02 is continuously sparged into the solution. Neat
inhibitor is injected under the surface of the brine and the corrosion rate is continuously
monitored. An uninhibited blank is always included. The test is allowed to run for 24
hours after which the final inhibited and uninhibited corrosion rates are measured and the
corrosion protection calculated from:
The Chemistry ofCorrosion Inhibitors Used in Oil Production 155
% Protection = (Final blank MPY - Inhibited MPY) 100Final Blanks MPY
CORROSIONMETER [
CURRENT SOURCE
t
~CO 2
-OIL
-BRINE
STANDARDIONNa +Mg ++Ca ++Cl SO -4
BRINEMg/L
20,0002,000
40032,500
590
156
Appendix 2: Wheel Test
Chemicals in the Oil Industry
The wheel test is a dynamic corrosion test for evaluation of corL"osion inhibitors.
There are basically two versions of the test, both of which rely on determining the weight
loss of a steel coupon to calculate the corrosion rate. The first version (constant contact)
simulates treatment by continuous chemical application. The second (film peristency)
test corresponds to the conditions experienced during slug or batch type application of
chemicals. The procedure involves placing preweighed coupons into test cells with either
hydrocarbon (e.g. kerosene) and synthetic brine or actual produced fluids that have been
saturated with carbon dioxide, hydrogen sulfide or a combination of both. The chemical is
introduced into the cells at actual use concentration which may be in the fifty to one
hundred parts per million level for the constant contact version or thousands of parts per
million for the film persistency version. The coupons are added to the cells (care being
taken to exclude oxygen) and the cells loaded on a wheel that rotates inside a heated
cabinet. In the film persistency version the coupons are removed after a short period of
time (e.g. one hour), placed in fresh uninhibited fluids, and the test continued.
The total test period varies but is usually from twenty-four to seventy-two hours.
At the end of the specified time the coupons are removed, cleaned, and reweighed and a
percent protection for each inhibitor calculated as below:
96 Protection (uninhibited coupon loss - inhibited coupon loss) 100uninhibited coupon loss
REFERENCES
1. J.I. Bregman, "Corrosion Inhibitor", Macmillan Company, New York, 1963, p.197.
2. G.D. Chappell and J.R. Stanford, Corrosion Inhibitor Used in Brines ContainingOxygen, U.S. 4,010,111, Mar. 1, 1977.
3. J. Drew and M. Propst, ''Tall Oil", Pulp Chemical Association, New York, 1981,p.98.
4. L. Zachary, H. Bajak, and S. Eveline, "Tall Oil and Its Uses" Pulp ChemicalAsociation, New York, 1965, pp. 25-26.
5. C.L. Howle, Corrosion Inhibition with Oil Soluble Diamides, U.S. 3,997,469,Dec. 14, 1976.
The Chemistry ofCorrosion Inhibitors Used in Oil Production
6. K.H. Nimerick, Inhibitor to Corrosive Attack and Method of Use, U.S.3,692,675, Sept. 19, 1972.
7. M. Safar et al., A Mixed Corrosion Inhibitor, GB 2,064,985 A, June 24, 1981.
8. M.D. Coffey, Corrosion Inhibitor for Aqueous Brines, G.B. 2,027,686 A, Feb.27, 1980.
9. S.E. Jolly, Corrosion Inhibitors, U.S. 3,661,981, May 9, 1972.
10. L.W. Jones, Water Dispersible Corrosion Inhibitor, U.S. 2,839,465, June 17,1958.
11. J. Maddox Jr., Carboxylic Acid Salts of 1-Aminoalkyl-2-PolymerizedCarboxylic Fatty Acid Imidazolines, U.S. 3,758,493, Sept. 11, 1973.
12. G.D. Chappell and J.R. Stanford, Corrosion Inhibitor Used in Brines ContainingOxygen, Canadian 1,019,554, Sept. 25, 1977.
157
13. J. Maddox, Jr. and W. Schoen, Composition and Process for InhibitingCorrosion in Oil Wells, Canadian 856,824, Nov. 24, 1970.
14. Improvements in or Relating to the Prevention of Corrosion, U.K. 809,001,Feb. 18, 1959.
15. J.R. Stanford and G.D. Chappell, High Temperature Corrosion Inhibitor forGas and Oil Wells, U.S. 3,959,158, May 25, 1976.
16. E.C. Leonard, Polymerization-Dimer Acid, J. Am. Oil Chemists' Soc., 1979,~ 782A.
17. P.M. Quinlan, Sulfur-containing Bis-Quaternaries, U.S. 4,057,390, Nov. 8, 1977
18. T.J. Bellos, Method of Protecting Metal Surfaces Against Abrasive Wear inSubmersible Pumps, U.S. 3,661,784, May 9, 1972.
19. E.H. Pryde, "Fatty Acids", American Oil Chemists' Society, Champaign,Illinois, 1979.
20. T. Kataoka, Chigasaki-Shi, and A. Takada, Method of Inhibiting the AcidCorrosion of Metals, U.S. 3,736,098, May 29. 1973.
21. D. Redmore and T. Welge, Method of Inhibiting the Corrosion of Metals in anAcidic Environment Using Quaternary Ammonium Salts of Polyepihalohydrin,U.S. 3,885,913, May 27, 1975.
22. T.J. Bellos, Method of Protecting Metal Surfaces Against Abrasive Wear inPumps with Polyquaternaries, U.S. 3,751,364, Aug. 7, 1973.
23. J.L. Walker and T.E. Cornelius, Filming Amine Emulsions, U.S. 3,931,043, Jan.6, 1976.
24. W.B. Hughes, Composition for and Method of Inhibiting Corrosion of Metals,U.S. 2,940,927, June 14, 1960.
25. P. Merchant, Jr., C.O. Ohaji and F.L. Powell, Water Soluble WaterfloodCorrosion Inhibitor, U.S. 3,989,460, Nov. 2, 1976.
158 Chemicals in the Oil Industry
26. P.M. Quinlan, Quaternized Derivatives of Polymerized Pyridines andQuinolines, U.S. 4,297,484, Oct. 27, 198!.
27. S.P. Sharp, Inhibiting Corrosion in High Temperature, High Pressure Gas Wells,WO 80/02700, Dec. 11, 1980.
28. D. Redmore, Corrosion Inhibitors Employing Phosphate Esters of CyclicAmidines, U.S. 3,711,403, Jan. 16, 1973.
29. D. Redmore, Use as Corrosion Inhibitors: Quiaoline and IsoquolinePhosphonates, U.S. 3,888,627, June 10, 1975.
30. D. Redmore, B.T. Outlaw, and R.L. Martin, Pyrophosphates, U.S. 4,075,291,Feb. 21, 1978.
31. L•• Jones, Oil-Soluble Phosphonic Acid Composition, U.S. 3,770,815, Nov. 6,1973.
32. J. Stanford, Inhibition of Corrosion of Metals, U.S. 3,412,024, Nov. 19, 1958.
33. R.R. Annand, 28th Annual Southwestern Petroleum Short Course, April 1981,Texas Tech. Unv., Lubbock, Texas, pp. 8,9,
34. A.C. Nestle, Materials Performance, Jan. 1968, Vol. 7, No. 1, p. 3l.
35. L. Gatlin, Materials Performance, May 1978, Vol. 17, No. 5, p. 9.
36. NACE Publication ID 182, Material Performance, Dec. 1982, Vol. 21 No. 12,p.9.
Quaternary Ammonium Compounds: Evaluation andApplication in the Control of Sulphate- reducing Bacteria
By E. BessemsAKZO CHEMIE, DUREN, WEST GERMANY
A. F. ClemmitAKZO CHEMIE U.K. LTD., HOLLINGWORTH ROAD, LITTLEBOROUGH,GREATER MANCHESTER OL15 OBA, U.K.
1 . Introduction
The objective of biocide addition to oilfield systems is
to eliminate/control the growth of sulphate reducing
bacteria (SRB). The SRB, in anaerobic coditions, generate
hydrogen sulphide by reduction of sulphate ions thus:
The hydrogen sulphide produced is toxic and corrosive
reacting with iron:
Fe +
The prevention of H2 S formation is therefore necessary for
the safe and efficient operation of an oil producing
installation.
2. Chemical Types
If firstly we look at chemicals which are considered to have
general biocidal activity they fall into a number of
categories:
i) Chlorine and Chlorine Release Chemicals
e.g. chlorine
sodium hypochlorite
chloramines
chlorinated guanidines
chlorinated tripotassium phosphate
(Iodophors)
160
( ii)
Chemicals in the Oil Industry
Advantages
Cheap, wide spectrum, short kill time.
Disadvantages
oxidation of system
potentially corrosive
reaction with organic material
Phenolics
e. g. dichloroxylenol, benzyl cresol
( iii)
( iv)
Advftntages
long time of activity.
Disadvantages
Too toxic and environmentally unacceptable.
Organometallics
Mainly compounds of copper, tin and mercury.
Advantages
Excellent biocidal activity.
Disadvantages
Toxic, environmentally unacceptable.
Oxidants
e. g. Hydrogen peroxide
Advantages
Ease of handling, cheap.
Disadvantages
Their strong oxidising potential precludes their
use in many systems.
v) Aldehydes
e.g. Formaldehyde
Glutaraldehyde
Quaternary Ammonium Compounds in the Control ofSulphate- reducing Bacteria 161
Advantages
Cheap, long time of activity.
Disadvantages
Toxic
Can have handling problems.
( vi) Quaternary Ammonium Compounds
e.g. trimethylalkylammonium chloride
Advantages
Cheap, long time of activity.
Disadvantages
Require careful selection for sea water compatibility.
Readily absorb on surfaces (can also be an advantage).
Foaming.
Typical MIC values against gram + and gram - bacteria of the
various biocide types are given
3. Mechanism of Operation
Table 1.
For oilfield operations, the biocide types normally encountered
are:
i) Chlorine
ii) Aldehydes
(iii) Quaternary Ammonium Compounds
Relatively little work has been done on how biocides work
but outlined below are possible mechanisms of operation:
i) Chlorine
Whilst there are a number of theories to explain the
antimicrobial action the most acceptable ones are those
based on the investigations of Green et al (1946)1
and Knox ~ (1948)2. The chlorine is believed to
penetrate the cell wall where it contacts the enzyme
system oxidising SH groups on the enzymes and blocking
the life cycle of the cell.
162
TABLE 1
Chemicals in the Oil Industry
MIC ppm
Biocide g + g - fungi
-Quaternaries
alkyltrimethylammonium
chloride
alkyldimethylbenzylammonium
chloride
heteraoaromaticammonium
chloride
-Formaline
formaldehyde
formaldehyde release compounds
-Phenolic compounds
phenolics
alkylphenolics
chlorinephenolics
diphenyl derivatives
5 200 25 -100
2 50 1-50
80 150 1500-3000
30 30 30-1000
50 50 1000
1000 1000 300-1000
200 3000 5000
4 200 25-150
100 500 500
-N containing compounds
biguanidines
chlorhexine
triazine
thiocynates
-Halogen compounds
chlorine
chlorine release compounds
iodophors
20
3-25
5-60
100
1-5
100-250
10-25
10-15
300
1000
10-100
4-35
100
20 -300
Quaternary Ammonium Compounds in the Control ofSulphate-reducing Bacteria 163
( ii)
( iii)
Aldehydes
These are believed to operate again by penetration
of the cell walls and reaction with the free amino
groups of proteins.3
Quaternary Ammonium Compounds
Very little is known about the mode of operation of
quaternaries. A possible mechanism can be attributed
to the cationic nature of the chemicals causing
disruptign of the cell wall by reaction with the
phospholipids of the cells. At high concentrations
the QAC penetrates the cell and reacts with both
protein and nucleic acids.
4. Chemical Aspects of Biocides
In this section we shall cover the chemistry of amines and
quaternary ammonium compounds examined as biocides. Various
types of "amines" are illustrated below:
Amines
Primary
Ethoxylated Amines
Secondary Tertiary
R1 R3'-N/
IR2
Quaternary Ammonium Compounds
Cl
164 Chemicals in the Oil Industry
Cl
Ethoxylated Quaternaries
Amine Salts
Cl
R'COO
The alkyl groups (R) attached to the nitrogen can of course
vary but we shall be mainly concerned with those of carbon
chain lengths CS-C1S.
The biocidal activity of a range of the above products against
SRB has been determined and the effects of the various
molecular modifications, e.g. quaternisation, ethoxylation
and carbon chain length of constituent groups can be seen.
Before discussing these structural effects, the techniques
used to assess the biocidal activity of the chemicals will be
explained.
5. Test Methods
The concentration of biocide needed to prevent growth of
SRB is called the bacteriostatic activity and is expressed
as the Minimum Inhibiting Concentration (MIC). This
concentration will prevent further growth of SRB but will not
kill them.
The MIC value is measured by the dilution technique, where
the SRB isolates are incubated anaerobically for two days and
Quaternary Ammonium Compounds in the Control ofSulphate-reducing Bacteria 165
the growth of the SRB suspension is determined by photometric
analysis. This SRB suspension is then injected into a series
of serum bottles containing seawater, medium and different
quantities of biocide. The lowest level of biocide preventing
SRB growth gives the MIC.
Bact~ricidal Activity
This is the concentration needed to kill the SRB and is a
higher concentration than the bacteriostatic activity. The
bactericidal activity is expressed in terms of concentration
and killing time. It is measured by the Suspension Test.
Care must be taken in the interpretation of bactericidal
activity taking account of influencing factors such as
number of colonies, temperature and storage conditions.
6. Structural Effects on Bacteriostatic Activity.
Recent results on the range of amines and quaternary
ammonium compounds are given in Table 2.
From the table it is apparent that only the quaternary
ammonium compounds as a group show any real bacteriostatic
activity to SRB though some amine salts also show promise.
It can be seen that amines and ethoxylated amines show little
activity and the effect of ethoxylation of a quaternary
ammonium compound reduces the activity.
Within the group of quaternaries some effects of chain
length and distribution can be seen. (Table 3 gives chain
length distributions considered). Quaternaries based on
tallow (mainly C16
, C18
chains) were unsuitable due to water
insolubility. A chain length of 10 carbon atoms i.e.
decyltrimethylammonium chloride is largely ineffective
against SRB but increasing chain length to C12
or using
two C10
chains on the molecule reduces the MIC from 800 to
100. The use of coco derived quaternary, which is mainly
C12
/C14
chain length though it contains C8
-C18
chains, gives
166
TABLE 2
Chemicals in the Oil Industry
MIC in ppm
Product SRB 1 SRB 2
Quaternaries
Trimethyltallowammonium chloride
Trimethyldecylammonium chloride
Dimethyld~decylammoniumchloride
Trimethyldodecylammonium chloride
Trimethylcocoammonium chloride
Dimethyldicocoammonium chloride
Dimethylcocobenzylammonium chloride*
(Middle cut)
Dimethyltetradecylbenzylammonium chloride*
Amines
N,N-dimethyldodecylamine
N,N-dimethyltetradecylamine
N,N-dimethylcocoamine
Ethoxylated Amines
bis (2-hydroxyethyl) cocoa~ine
polyoxyethylene (5) cocoamine
Ethoxylated Quaternaries
Methylbis (2hydroxyethyl) cocoammonium
chloride
Methylpolyoxylene(15)cocoammonium chloride
Amine Salts
Cocoamine acetate
N,N-dimethylcocoamine acetate
N-coco-1,3-diaminopropane diacetate
I N S 0 L U B L E
800 800
100-200 100-200
100-200 100-200
50 50-100
3200 3200
400 100-200
200 50-100
400 400
3200 800-1600
3200 3200
3200 3200
3200 3200
3200 3200
800 200-800
3200 3200
3200 400-800
400-800 200-800
50 50-100
TABLE 3 Chain Length Distributions
C8C
1D C 12 C14 C 16 C18 C 18=
Trimethylcocoammonium chloride 5 6 53 19 9 2 6
Trimethyldodecylammonium chloride - 1 98 1 - - -
Dimethyltetradecylbenzylammonium chloride - - 3 94 3 - -
Trimethylcocoammonium chloride (Middle Cut) - 1 67 28 4 - -
(Q:;::~
~~;:::::~
~~
~~a;:::::Eo~
g~a:;::;:::::
~5So~
g;:::::
~~~~~~
~~
~~
5Oq
~~
~~
~o
0"1-......J
168 Chemicals in the Oil Industry
some further improvement over the C12
based quaternary
indicating a beneficial effect of a mixed C 12 /C 14 chain
length. The benzyl quaternary ammonium compounds have
similar activity to their methyl equivalents. Chain length
effects can again be seen comparing the performance of the
*three chemicals in Table 2. Here the derivative based on
a pure C14
chain length has relatively poor performance
compared with a coco derivative (mainly C12 /C 14 ). By
removing the lower and higher components to give almost
entirely C12
/C14
chain lengths a further performance
improvement results.
It was also apparent from the work that a specific chemical
had different performance against SRB from different sources
(Table 4).
TABLE 4
SRB--
Product Source 1 Source 2 Source 3 Source 4
DMCB 50 100 200 100
DMMCB 50 50 200 50
DM14B 400 400 200 25
TMC 100 200 200 100
This illustrates the importance of biocide selection for
specific SRB.
Synergistic Effects
Some work on the effect of combining an aldehyde with a
quaternary was also studied. Results are given in Table 5.
Quaternary Ammonium Compounds in the Control ofSulphate-reducing Bacteria 169
TABLE 5
MIC
SRB 1 SRB 2
Quaternary -Aldehyde +Aldehyde -Aldehyde +Aldehyde
TMC 50 50 50-100 100
TM12 100-200 50 100-200 50
DMCB 400 100 100-200 50
DMMCB 200-400 50 50-100 50
Footnote: DMCB
DMMCB
TMC
TM12
DM14B
Dimethylcocobenzylammonium chloride
Dimethylcocobenzylammonium chloride
(middle cut)
Trimethylcocoammonium chloride
Trimethyldodecylammonium chloride
Dimethyltetradecylbenzylammonium
chloride
Factors other than MIC must of course be taken into account
when assessing a chemical or chemical mixture:
Sea water compatibility.
Compatibility with other chemical used.
Effects of pH and temperatures.
Partition coefficient between oil and water.
Corrosivity.
Toxicity and environmental hazards.
Monitoring
The regular monitoring of field conditions and biocide
performance is necessary for their proper applications.
170 Chemicals in the Oil Industry
A simple method consists of using serum bottles filled with
medium and sealed with a rubber septum. A sample of water
suspected of containing SRB is injected into the bottle.
If the medium turns black then SRB are present and can be
further investigated by the techniques previously discussed.
REFERENCES
1. D. E. Green and P. K. Stumpf J. Am. Water Works Assoc.,
38, ~Ol (1946)
2. W. E. Knox, P. K. Stumpf, D. E. Green and V. H. Auerbach,
J. Bacteriology, 55, 451, (1948).
3. H. S. Rosenkranz, Bull. Environ. Contam. Toxicol., ~,
242 (1972).
The Role of the Service Company in Offshore Operations
By G. E. Payne
CONOCO (U.K.) LIMITED, RUBISLAW HOUSE, ANDERSON DRIVE, ABERDEEN AB2 4AZ, U.K.
Introduction
Chemical service companies have been involved with the U.K. Offshore
oil industry since the first well was drilled. Drilling muds are
sophisticated blends of chemicals supplied by service companies.
When oil is found and production starts another whole range of
chemicals may be required as outlined in other papers. Some of
the service companies specialise in mud chemicals and some in
production and treating chemicals. A few companies can supply products
for both the drilling and production phases. Yet another group
tend to deal more with maintenance products.
Some cynics might say that all a service company does is to buy
bulk chemicals from the manufacturer and blend them with other materials
which may be only water or cheap solvent and then sell them at a
handsome profit. Whilst this has undoubtedly happened at different
times in different places the offshore oil industry generally requires
such a diverse range of chemicals that this approach is not generally
possible.
The service company must supply chemicals which effectively solve the
problems being encountered. If the existing products are not wholly
suitable new ones need to be developed. Having chosen the chemical
it must then be supplied in a form suitable for shipping to the offshore
installation and for its safe use there. If required chemical service
company personnel must also visit the rig or platform to help ensure
that the chemical does the job that it is supposed to do.
Selection of Chemicals
In selecting a chemical an operator is making two choices, that~of
the chemical itself and also the company supplying it. When one
considers that over thirty companies are active in the area the choice
of chemical can be a difficult task. The selection may be carried
out in various ways and each operator may take a different approach.
172 Chemicals in the Oil Industry
The nature of the chemical will often aid its selection. As already
mentioned certain chemical types are only supplied by a proportion
of the service companies and very few companies are in a position to
offer a chemical for every need. Of the companies that can offer
a particular type of chemical an operator may only consider those
with local representation and stocks. If a chemical is needed
urgently even those companies with local stock points may not be
able to supply the particular chemical required due to temporary
shortage or other reasons. Of the chemicals which are available
previous usage or knowledge gleaned from other operators may give
an idea of relative effectiveness. So the selection process may
proceed by ~ series of eliminations.
For a problem which is likely to be long standing many operators
will initially use a readily available chemical which may only be
partially effective whilst carrying out tests and trials to find
a more suitable product. OPerators with extensive laboratory and
test facilities may require samples to be submitted from as many
sources as possible to find the most cost effective chemical. Where
the test facilities are limited or if the nature of the laboratory
work involved in evaluating chemicals is time consuming or expensive
a degree of selection may be made and only a few products evaluated.
A few service companies may be asked to submit only one product each.
A service company in this case has to try to assess the problem and
make the best choice of the chemicals it has available.
In some cases an operator may only carry out plant trials. In this
instance generally only a few products will be tested. These may
be from different companies or perhaps only fro@ one company.
Supply Arrangement
Having chosen a chemical it must then be delivered to the place where
it will be used. The operators arrange shipment from the supply
base warehouse or quayside to the offshore installation. The service
company must deliver the material to the supply base in a form most
suited for the particular installation.
The Role ofthe Service Company in Offshore Operations
For small usage volume products the usual form of supply is the
45 imperial gallon drum for li.quid materials. Other smaller sized
containers may also be appropriate. Solid products used in the
preparation of drilling muds and fluids are usually supplied in
50 kg bags.
Because the volumes o~ fluid being treated are often very large
even modest chemical treatment rates at the part per million level
may mean substantial quantities of chemical are being consumed.
The unit quantities quuted above for liquids at least are too small
in this instance. Many liquid chemicals are now supplied offshore
in intermediate bulk containers which range from about 100 to 500
gallons in size .,-
If a chemical is CLassified as being a Dangerous Good its packaging
for carriage on a ship is governed by the Merchant Shipping (Dangerous
Goods) Regulations 1981. For some chemicals this means an IMCO
Type 1 tank for the size of load mentioned above. Such tanks must
withstand without damage a rigorous test programme after which
they will be certified as conforming to the type 0 The requirements
of these tanks is such that they will cost approx. £3,000 - £5,000
depending on the actual size and design.
An average round trip for any tank travelling regularly to an offshore
installation is about three weeks. If one tank full of chemical
is used every week a minimum of three tanks will be required to supply
one installation with one chemical. A service company will therefore
have a considerable capital investment tied up in the form of tanks.
Bulk tanks of any type must also be regularly maintained, inspected
and tested. This operating cost associated with the tank together
with the initial capital cost will generally be recouped by loading
the price of the chemical. Thus a service company that has been
active for a number of years and which has written off much of its
tank costs will have an advantage over a company setting up and having
to purchase or lease tanks afresh.
173
174 Chemicals in the Oil Industry
Some operators"have decided to supply tanks to the chemical service
companies for shipment of chemicals to their installations. The
operator then has a better means of comparing one service company's
prices with another. An operator may supply tanks which it has
purchased especially for this purpose. Another alternative now
available is for the operator to contract out the supply and handling
of tanks to a specialist service company providing this facility.
Platform or rig storage is generally limited. Prompt delivery to
keep the offshore stores topped up is often essential to maintain
drilling or production operations. Service companies with stocks
close to the offshore supply bases have an advantage over those
delivering 'from more distant stock points. This is expecially true
when supplies are required unexpectedly due to a spillage or other
temporary shortage offshore. It goes without saying that companies
who literally miss the boat will tend not to be looked at favourably.
Giving Service Offshore
Some operators restrict the access of service company representatives
to their offshore installations. Other operators expect the service
company to provide personnel to assist with the administering of the
chemicals to the system. In the latter case representatives may
spend a considerable time offshore especially when trials are being
carried out. This service is generally given to the operator free
of charge. However nothing is free and these costs are taken into
account in the pricing of the chemical.
Even when the service company personnel do not visit the offshore
installation they will generally be expected to give advice pertinent
to the use of their company's products. The type of injection equipment
required including material of construction requirements and the point
of injection into the system illustrate the type of information
required. The level of treatment to be applied to the system will also
need to be given if this has not already been determined.
The Role ofthe Service Company in Offshore Operations
A particular point to be e10phasised by the chemical supplier is the
safety aspects associated with individual chemicals. All chemicals
should be supplied with adequate information to allow safe usage.
Product notes and/or material safety data sheets must be available
giving relevant precautions to be taken in handling and using different
chemicals. Point of usp. hazard warning cards should also be supplied
for those chemicals of a hazardous natuLS.
Monitoring of Effectiven~~
In selecting a chemical laboratory tests may have been carried out.
Alternatively a chemical known to work at other locations may have
been chosen. However until a chemical h,.... .3 been used in a plant
trial and the system ~~-itored the effectiveness cannot be fully
predicted. Service company representatives are often present at
plant trials and in some cases will supervise the trial. Personnel
involved must therefore be practical and capable of troubleshooting
and improvising.
Effectiveness may be monitored in various ways depending on the nature
of the chemical. Corrosion inhibitors can be monitored relatively
easily using well known techniques. Demulsifiers may also be shown
to be effective quite easily. An important part of effectiveness
monitoring is to ensure that using a chemical to solve one problem
does not create other problems in the system being treated or other
ancillary systems. It is no good getting good corrosion inhibition
with a product that may cause problems like foaming or emulsion
formation. If more than one chemical is used in a system it is
important that the chemicals are compatible with each other and will
not cause gunk at the treating levels of concentration. If the
chemicals are injected at the same point or close to each other
the products must be compatible at full strength as well. These
are points that the service company should check prior to any chemical
being used.
In drilling operations the properties of the mud need to be adjusted
according to the depth at which drilling is proceeding. This adjustment
requiIesconstant monitoring throughout the drilling operation and this
175
176 Chemicals in the Oil Industry
is carried out by a mud engineer supplied by the service company.
Similarly in cementing operations the cement engineer supplied by the
service company will monitor the mixing of chemicals into the cement
so that the right properties are achieved.
Monitoring effectiveness may be possible in a relatively short period.
However if the period becomes extended it is essential that proper
records of the levels of chemical treatment used are kept over the
period. The service company representative may visit the installation
and check injection rates from time to time and also take other
interim measurements. He should also check that the amounts "used"
on the platform correlate with that supplied by his company.
As part of effectiveness operators are looking for ease of handling
of chemicals. Materials which flow easily in a warm laboratory may
be more difficult to coax out of a drum or tank having been exposed
to wintry conditions on the deck of a supply boat to get offshore
and then kept exposed on the cellar deck of the platform once there.
Also chemicals which require diluting before being injected are not
generally liked unless proper mixing tanks are installed on the
platform.
Once the effectiveness and ease of handling of a chemical have been
demonstrated and the rate of usage established an operator can then
determine the cost effectiveness of a particular product. At the
end of the day it is the cost effectiveness rather than the parts
per million used which is important.
Safety
The safety aspects of using chemicals anywhere cannot be over
emphasised. Earlier it was stated that a service company must
be able to supply chemicals safely and help ensure their safe use
offshore.
The legislation governing Dangerous Goods has already been mentioned.
This was enacted to protect warehousemen, dockers and supply boat
The Role ofthe Service Company in Offshore Operations
deck crews from injury due to substandard packaging. Legislation
is usually only taken to mean the minimum standard required and
anything over and above this is to be welcomed.
Many goods may not be classified as dangerous but may still require
special handling in the case of spillage. Some chemicals which are
not dangerous by themselv~s may be potentially hazardous when mixed
with other materials. Such information must be supplied preferably
on the container itself.
Personnel on the offshore ~nstallation must be made aware of any
hazard associated with a particular chemical or combination of
chemicals. Protective clothing must be provided if appropriate.
All pertinent information is covered in the form of a Material Safety
Data Sheet which shoula De supplied by the service company.
Environmental ASPects
Any chemical used offshore will sooner or later find its way into
the sea. This may be deliberate or accidental. Whilst those chemicals
which are deliberately added to overboard discharges must be scrutinised
closest the consequences of accidental discharges of all chemicals
should be known.
In 1979 the Department of Energy introduced a notification scheme
for chemicals used offshore. Service companies were invited on a
voluntary basis'to submit information to the Department of Energy
to enable a category of useage to be allocated to each chemical.
The categories range from 1 to 5 for the different levels of usage
for which notification is requested. category 0 requires no
notification.
The list published by the Department of Energy indicates that
information on only a fraction of the chemicals presently being
offered to the operators has been submitted thus allowing a category
to be allocated. Clearly if the voluntary scheme becomes mandatory
some service companies may be disadvantaged.
177
178 Chemicals in the Oil Industry
Environmental aspects should be taken into account by operators
when selecting chemicals for certain uses. If the chemical is
ultimately going to be discharged as in the case of a pipeline
preservation chemical a license to discharge may be required.
~oxicity data may have to be submitted to the Ministry of Agriculture,
Fisheries and Food (MAFF) or the Department of Agriculture and Fisheries
for Scotland (OAFS) and the Department of Energy to allow the license
to be issued and the discharge to take place. A service company
would be required to supply such information.
Conclusion
This paper has given an outline of the type of service expected by
the operators from the supply companies. Some operators place more
emphasis than others on the different aspects of the service required.
In some cases the chemicals supplied and the prices charged by different
companies are much of a muchness. To aid the selection in these
cases the operator may look for the best service. If a supplier does
decide to become a service company it must be prepared to offer the
service required as well as the chemicals.
The Market for Chemicals in the Oil Industry
By R. C. Parker
SHELL INTERNATIONALE PETROLEUM MAATSCHAPPIJ, DEN HAAG, THE NETHERLANDS
SYNOPSIS
Speciality chemicals are used extensively by the petroleum industry and inparticular for oil and gas field exploration, drilling and production.Drilling activity fluctuates, but recently around 100,000 wells have beendrilled each year. World crude production (outside the Eastern Blockcountries) now runs at around 40 million barrels per day (bId) and theassociated water production is estimated at 16 million bId. The world gasproduction averages 3000 billion cubic ft per day.
Hundreds of chemicals are used in significant quantities to enable wells tobe drilled and to treat and recover the large streams of oil, water and gas.Current sales of chemicals related to drilling and associated activities areestimated at around £3300 million per year, for production related use £300million per year and for enhanced recovery techniques around £150 million peryear. Significantly of the total estimated expenditure of £3750 million peryear, approximately 80% is accounted for in the United States. Based onpresent oil production, the chemical cost associated with producing onebarrel of oil is approximately 25 pence. Market growth rate will depend to amajor extent on world demand for hydrocarbons; however a value of at least10% per annum may be foreseen.
Whilst these statistics indicate an impressive chemical market, evaluationshould be tempered with a degree of caution. The chemical spectrum associatedwith oil and gas exploration and production is highly diversified andspecialised and application invariably necessitates dedicated service back-upand operational expertise. As such it is a highly competitive and wellestablished business and great care should be exercised if considering marketparticipation, especially since the success, or otherwise, of participationmay often depend on the now very unpredictable value of a barrel of oil atany particular moment in time.
A review of the market for chemicals in oil and gas development will bepresented with particular emphasis on types and quantities of chemicals,reasons for application and future trends.
N.B. Cost trends on a world wide basis are difficult to establish.Reference to pertinent literature and trade journals has been augmentedby personal communication and trend extrapolation. As such, the economicfigures quoted in this paper are meant to portray order-of-magnitudeexpenditures and should not be interpreted as absolute values.
180
I. INTRODUCTION
1. GENERAL
Chemicals in the Oil Industry
Oil and gas development follows a logical and sequential course of events. Inits broadest terms, an exploration well will be drilled in an unknown area toprove (or otherwise) the presence of hydrocarbons. Should the wellsuccessfully encounter hydrocarbons, so-called appraisal wells will bedrilled in the immediate vicinity to gain more knowledge of the extent of theaccumulation and the approximate quantity of hydrocarbon present. Thereafter,should the size of the discovered field prove attractive for development inthe prevailing economic climate, development wells will be drilled accordingto an optimised subsurface pattern to efficiently produce and drain thereservoir. Production facilities will be installed close to the developmentwells to process the oil and/or gas and water streams which will be producedfrom the reservoir. The oil and/or gas will then be evacuated from the fieldby the most appropriate method e.g. pipeline or tanker.
In all these activities, from the drilling of the exploration well toevacuation of the product, significant quantities of chemicals are used. Insome extreme cases, development of a particular oil or gas field could not beeconomically undertaken without the use of specialised treatment chemicals.This section (I) will introduce the principal areas of chemical applicationand the following sections will describe in more detail types and quantitiesof chemicals, used in the principal areas.
2. SPECIFIC AREAS OF CHEMICAL APPLICATION
The use of chemicals in oil and gas development can be more specificallyindicated by itemising the numerous activities.
2.1 Drilling, Cementing, Completing and Stimulating Wells
Drilling a well requires the use of a drilling fluid, also known as a "mud".Significant quantities of commodity and speciality chemicals are used informulating drilling fluid systems.
Once a borehole has been drilled, steel pipe known as casing must be cementedin the hole to prevent borehole collapse and allow drilling to continue todeeper geological horizons. Correct cementing formulations are critical tothe integrity of the well and necessitate the use of chemical additives.
If a well has encountered hydrocarbons, the hydrocarbon bearing interval willusually be cased off with steel pipe. Clear completion fluids (e.g. brines)will then be used in the well to minimise production impairment to thereservoir rock. The casing will be perforated in selected intervalscorresponding to the productive zones. In many cases, the wells will notproduce to their maximum efficiency either because the rock in the immediatewell bore was damaged by the drilling fluid, or the actual properties of therock matrix itself are inferior (e.g. low porosity or permeability). In thesecircumstances the well will be stimulated by a selective treatment designedto improve the productivity. A wide range of chemicals from inorganic acidsto highly developed polymers are used in stimulation activities.
The Market for Chemicals in the Oil Industry
2.2. Producing Hydrocarbons
181
In a typical oilfield development, a combined stream of oil, associated gasand water must be separated and processed to give acceptable products eitherfor sale (i.e. oil and gas) or disposal/reinjection (water). Separation ofoil and gas usually takes place initially, which now and again may requirethe use of chemical defoamers. Thereafter the crude oil stream oftencontaining emulsified water must be treated with suitable demulsifiers toreduce the water content of the crude to sales specification. The separatedwater may then require treatment with de-oiling chemicals to render itacceptable for either disposal or subsurface reinjection. Depending on thecharacteristics of the crude oil it may then require further chemicaltreatment with wax depressants, fluidity improvers, friction reducers etc. toallow economic transportation. Depending upon the characteristics of theproduced water, and its eventual mode of disposal, it may require furtherchemical treatment with biocides, corrosion inhibitors, scale inhibitors,polyelectrolytes etc.
In a typical gas field development, chemical requirements for corrosioninhibition and hydrate reduction are often called for.
2.3. Additional Oil Recovery
Primary production of oil, which usually relies upon the natural drivingforces in the reservoir to produce the oil to surface, seldom recovers anappreciable quantity of the total oil present in the subsurface strata. In atypical sandstone reservoir, primary recoveries of 30-50% may be obtained,whilst in limestone reservoirs, recoveries can often vary from 5% to 25%. Inorder to maximise recovery of oil, alternative production methods arerequired to augment the primary process.
Typical secondary recovery processes are water injection and gas injection.So called enhanced recovery processes aim to recover oil left behind or notproducible by the natural drive mechanisms or secondary recovery methods. Theenhanced recovery processes may be arbitrarily split into thermal methods andmiscible/chemical methods. Thermal methods encompass hot water injection,steam injection and in situ combustion. Miscible methods involve theinjection of enriched hydrocarbon gases, or carbon dioxide or nitrogen.Chemical processes involve the injection of polymers and/or surfactants orcaustic. In all these additional recovery processes, significant quantitiesof speciality chemicals are used, especially in chemical/surfactant flooding.
1. ACTIVITY SCENE
Approximately 100,000 wells are drilled annually worldwide (excluding Chinaand Eastern Block Countries) of which about 80% are drilled in the UnitedStates. In Western Europe, some 400 wells are expected to be drilled in 1982and of these, around 200 will be drilled in the United Kingdom. Just overhalf the UK wells are expected to be development wells, whilst the remainderfall in the exploration/appraisal category. Drilling for oil and gas inWestern Europe nowadays predominantly takes place in remote offshore areas,
182 Chemicals in the Oil Industry
for example the North Sea. The operating cost of an offshore drilling rig canamount to £60,000 per day (£40 per minute). The cost of a well itself in suchan area can range from £2 million to £20 million, depending upon the severityand complexity of the operating and drilling conditions. The cost ofchemicals utilised in drilling and completion operations can typically varybetween 5% and 15% of the total well cost.
2. DRILLING CHEMICALS
2.1 Functions of a Drilling Fluid
The majority of chemicals used in the drilling and completion of a well areutilised in preparation and maintenance of a suitable drilling fluid or"mud". In the conventional rotary drilling process, mud is pumped downthrough the drillpipe string, out through the bottom of the drilling bit andcirculated back to the surface. The mud circulation system is the heart ofthe drilling process and it would be impossible to drill a well without asuitable drilling fluid. The principal functions of the drilling fluid are asfollows:
i) Transportation of drilled rock cuttings out of the borehole
ii) Maintenance of the stability of the borehole
iii) Prevention of the ingress of oil, gas or water into the borehole duringthe drilling process
iv) Provision of lubrication and cooling to the drilling bit.
2.2 Design and Choice of a Drilling Fluid
Drilling fluids are prepared from a variety of commodity and specialitychemicals. The choice of drilling fluid is principally dependent upon thecharacteristics of the foreseen geological strata which will be penetrated.Since, in any well, differing geological conditions are encountered, theresultant choice of drilling fluid will be a flexible compromise to cope withthe anticipated problems. Hence, each drilling fluid is prepared specificallyfor the well being drilled and calls upon the talents of research chemists,practical chemists and engineers to devise the most appropriate formulation.An improperly designed drilling fluid can, in extreme circumstances, resultin the complete loss of a well, with all the financial and operationalramifications which result. The components of drilling fluids are usuallypurchased in 50 pound sacks or drums and mixed at the drilling site. Some arebulk delivered.
2.3 Classification of a Drilling Fluid
The classification of a drilling fluid is primarily dictated by thecharacteristics of its base liquid. The major classification is as follows:
i) Water based (e.g. fresh water, seawater, brine, mixed salts)
ii) Oil based (e.g. diesel oil, "non-toxic" oil, invert oil emulsion)
iii) Others (e.g. air, gas, mist or foam systems)
In terms of usage worldwide, approximately 99.5% of wells are drilled withwater based mud systems, 0.4% with oil base mud systems and 0.1% with othersystems. Water based muds are generally cheaper and more environmentally
The Market for Chemicals in the Oil Industry 183
acceptable than the other alternatives. However, such statistics can bemisleading when applied to a specific area. For instance in the UK sector ofthe North Sea it is estimated that the distribution is around 60% for waterbased systems and 40% for oil based systems. The particularly difficultdevelopment drilling conditions in this part of the North Sea have dictatedthe requirement for a more refined and expensive solution (i.e. oil basemuds).
2.4 Chemicals used in Water Based Drilling Fluids
As indicated previously, drilling fluids are prepared from a variety ofcommodity and speciality chemicals. Examples of a few of the typical types ofchemicals are as follows:
i) ~~!~~!!~~_~~~~!~
Materials with high specific gravity utilised to provide the required densityof the drilling flGid. Barytes (BaS0
4), iron oxides (haematite, ilmenite),
calcium carbonate. Barytes is the most commonly used weighting agent.
ii) ~!~~~~!i!~E~
Materials used mainly to build fluid viscosity. Bentonite clay is the mostcommonly used product, together with lesser amounts of other clays e.g.attapulgite. Polymers are also now being increasingly used e.g. partiallyhydrolysed polyacrylamides, cellulose ethers, copolymers of vinyl acetate andmaleic anhydride.
iii) ~!~£~E~~~£~
Materials which disperse solid particles in the drilling fluid. Examples areferrochrome lignosulphonates, chrome-free lignosulphonates, sodiumpolyacrylates, phosphates.
iv) ~!~!~_!~~~_~~~!£!~~~
Materials which prevent the loss of fluid from the mud to permeable andporous rock formations. Examples are carboxymethyl cellulose, xanthan gum,guar gum, polyacrylates, pre-gelatinised starch and lignite.
v) ~~~~~~!~Z_~~~~!~~!~
Appreciable quantities of lime and sodium hydroxide are used for pHadjustment. Also other chemicals are used to provide correct ionic balance inthe fluid e.g. sodium chloride, potassium chloride, lime and calciumchloride.
vi) 2£~~E_~£~~!~!!~Z_~~~~!~~!~
To a limited extent, biocides, corrosion inhibitors, surfactants anddefoamers. Since these chemicals are used more extensively inproduction-related problems they will be described in more detail in a latersection.
2.5 Quantities and Costs of Chemicals used in Water Based Drilling Fluids
The mud cost for an average well in the United States is of the order of£15,000 whilst for a deep well (> 15,000 ft) it can accumulate to £300,000.Approximately 1.5% of the 80,000 wells drilled in the U.S. can be classifiedas deep. The total world market value of chemicals used for water based,drilling chemicals is estimated at around £2500 million per year and anapproximate breakdown would be as follows:
184 Chemicals in the Oil Industry
Category of chemical MT x 103 (£ x 106) (%)
Weighting agents 10,000 775 31
Viscosifiers 4,500 425 17
Dispersants 350 375 15
Fluid loss additives 70 375 15
Commodity chemicals 450 175 7
Speciality/others 150 375 15
MT = Metric tons
The mud cost of an average well drilled with water based drilling fluids inWestern Euro~e is estimated at around £100,000. The total market value of thedrilling chemicals used in Western Europe is therefore estimated atapproximately at £24 million, broken down as follows:
Category of chemical (£ x 106 ) (%)
Weighting agents 5.2 22
Viscosifiers 2.3 10
Dispersants 3.6 15
Fluid loss additives 6.2 25
Commodity chemicals 1.5 6
Speciality/other 5.2 22
2.6 Chemicals used in Oil-Based Drilling Fluids
Oil based drilling fluids are used for special drilling applications. Theyconsist of either 100% base oil (e.g. diesel or a "non-toxic" oil) or invertemulsions with water contents up to 30% to 40%. In common with water baseddrilling fluids, weighting agents (e.g. barytes) and commodity chemicals(e.g. sodium chloride, calcium chloride, lime) are used in the preparation ofthese systems. Examples of other types of chemicals utilised in the make-upare as follows:
i) ~E!~~E~_~~~!~!~!~E~
Materials required to emulsify water into the base oil to provide a stableinvert oil emulsion mud. Typical chemicals are polymerised/oxidised tall oilsoaps; animal fatty acids plus alkanol amides; oleyl amide + oleic acid +dimerised oleic acid; magnesium soaps of fatty acids + tall oil resin + fattyamides; fatty imidazoline derivatives.
The Market/or Chemicals in the Oil Industry 185
ii) ~~!!!~~_~~~~!~L~~~~~~~E~_~~~!~!~!~E~
Materials designed to preferentially oil-wet solids introduced in the mud andprovide additional stability to the system. Examples are amide derivitives oftall oil; long chain fatty amides; oleyl amide lignosulphonate; fattydiamine; imidazolines and ethoxylated alkyl phenols.
iii) Y!~~~~!~!~E~
Materials required to impart viscosity to the system. The main product usedis an organophilic bentonite.
iv) ~!~!~_!~~~_~~~!!!~~~
Materials which prevent the loss of the continuous phase of the mud (i.e.oil) to permeable and porous rock formations. Examples are oxidised asphalt;organophillic lignite or mixtures of polyphenols.
v) Q!~~E_~~~~!~!!!~_~~~~!~~!~
To a limited extent, thinners are used e.g. petroleum sulphonates ornaphthenic acids.
2.7 Cost of Chemicals used in Oil Based Drilling Fluids
As indicated in section 2.3 the use of oil base drilling muds in the UnitedStates is very limited. In relation to world activity, a significantproportion of oil base mud application takes place in Western Europe. The mudcost for an average well using an invert oil emulsion (20% water) is of theorder of £150,000, of which some 30% of the cost may be attributed to thediesel oil. Hence chemical additive cost per well would be about £110,000,and the total market value of these drilling chemicals in Western Europe maybe estimated at around £18 million, broken down as follows:
Category of Chemical (£ x 106) (%)
Weighting agents 5.4 30
Primary emulsifier 4.5 25
Secondary emulsifier 0.9 5
Viscosifier 1.8 10
Fluid loss additive 2.7 15
Speciality/other 1.8 10
Commodity chemicals 0.9 5
186
3. CEMENTING CHEMICALS
3.1 Functions of Oil Well Cement
Chemicals in the Oil Industry
During the drilling of a well, it is necessary to place steel pipe known ascasing into the drilled hole. The casing is cemented in position, i.e. astrong cement sheath is placed in the annulus between the outside of thecasing and the borehole itself. The principal functions of the cementedcasing are:
i) Prevention of borehole collapse
ii) Allow drilling to continue to deeper geological horizons
iii) Isolate productive hydrocarbon ZOi ~s from non-productive ones.
The cement commonly used is Portland cement with various additives. Theadditives modify the properties of the cement to allow acceptable rheology,setting timea and to match the formation characteristics of the individualwell.
3.2 Chemical Additives for Cementing
The principal additives used in cementing are as follows:
i) ~~!~~!!~~_~~~~!~
These products are usually required when high pressure conditions areencountered. They are similar additives as those used for drilling fluidsi.e. barytes, iron oxides.
ii) ~~~!_£!E£~!~!!~~_~~!~E!~~~
Products which prevent the loss of cement slurry to the formation when lowpressure conditions are encountered. Examples are gilsonite and mica.
iii) ~££~!~E~!~E~
Products which will accelerate the setting time of the cement in order tospeed up operations. Examples are sodium chloride (up to 5% by weight),calcium chloride and sodium silicate.
iv) ~~!~E~~E~
Products which will extend the normal cement setting time to render theslurry pumpable over an extended period. This feature is often required whenplacing cement slurries in deep hot wells. Examples are ligninretarders-calcium lignosulphonate and calcium sodium lignosulphonate;carboxymethyl hydroxyethyl cellulose (CMHEC) and saturated salt water.
v) ~!~!~_!~~~_~~~!!!~~~
Products to control the loss of water from the slurry to the formation.Examples are carboxymethyl cellulose (CMC), polyacrylamides and silica flour.
vi) ~!~E~E~~~!~L~E!£!!~~_E~~~£~E~
Products designed to improve the rheology of the slurry. Examples arelignosulphonates, lignins, sodium chloride, aryl alkyl sulphonates.
The Market for Chemicals in the Oil Industry 187
vii) Q!~~E_~~~!!!~~~
Other chemicals such as bentonite, pozzolan (volcanic ash) and latex are usedin varying amounts for specific applications.
3.3 Cost of Chemical Additives for Cementing
The chemical additive market for cementing is appreciably less than that fordrilling fluids. The total world market value of chemicals associated withcementing operations is estimated at around £300 million. An approximatebreakdown would be as follows:
Category of chemical (£ x 106 ) (%)
,- Weighting agents/other additives 90 30
Lost circulationmaterials 23 8
Accelerators 44 15
Retarders 46 15
Fluid loss additives 76 25
Dispersants 21 7
In the UK sector of the North Sea an average cost for cementing additiveswould be around £12,000 per well. Hence the approximate total market value ofthese chemicals in this area is £2~ million, i.e. about 1% of the worldmarket.
4. COMPLETION/STIMULATION CHEMICALS
Completion of a well often involves the use of clean non-damaging (to thereservoir rock) fluids. The principal fluids used are brines e.g. sodium orcalcium chloride, calcium bromide and in extreme case zinc bromide. In somecases, the rock may have been damaged by the drilling process and/or is ofpoor quality such that a less than optimum productivity is obtained. In suchcircumstances, the well may be stimulated to improve the productivity. Thetwo principal methods of stimulation are acidising and hydraulic fracturing.In certain specific instances, stimulation can also be achieved by injectionof solvents, surfactants, enzymes, gas-generating compounds or polymers.
4. 1 Acidising
In carbonate rock formations (e.g. limestone, dolomite), hydrochloric acid(15% or 30% strength) is usually injected to clean the rock around theimmediate well-bore and establish communication to natural fissures andfractures. Occasionally, other acids are used e.g. formic or acetic. Acombination of hydrofluoric and hydrochloric acids is usually used tostimulate sandstone formations.
188
4.2 Hydraulic Fracturing
Chemicals in the Oil Industry
In order to improve productivity from low permeability rocks, a highlyviscous fluid often containing a proppant (e.g. sand or glass beads) isforced into the well. The viscous fluid fractures the rock, the proppantenters the induced fracture and then keeps it open to improve the flow fromthe rock matrix.
4.3 Chemical Additives
In acidising techniques, additives such as corrosion inhibitors, surfactants,che1ating agents and polymers are used. In hydraulic fracturing, significantquantities of polymers are used to engineer an optimum rheo10gica1 and stablefracturing fluid. The principal additives can be categorised as follows:
i) Viscosifiers. The most widely used viscosifiers are based onhydroxypropy1 guar gum and some cellulose derivitives. Their main taskis to reduce pressure losses due to friction whilst pumping, providecarrying capacity for the large volumes of proppant, and to create andpromote wider fractures.
ii) Surfactants, e.g. sulphonates, non-ionics and quaternary ammoniumcompounds. The chemicals are required to prevent the formation ofemulsions or precipitates between the treatment fluid and the formationfluid.
iii) Fluid loss additives e.g. guar gums, hydroxyethy1 cellulose po1yamines.These chemicals prevent loss of fluid to the formation and assist infracture propagation.
iv) Clay stabilisers, e.g. potassium chloride (ca. 2% by weight) hydroxyalumina, zirconium oxychloride. These chemicals are used to eitherprevent or minimise clay hydration in water-sensitive rock formations.
4.4. Cost of Completion/Stimulation Chemicals
Typically, the majority of expenditure for completion and stimulationchemicals takes place in the United States. An estimated breakdown of costfor 1982 for chemicals is as follows:
Acidising Chemicals
Acids
Corrosion Inhibitors
Clay Stabilisers
Friction Reducers
Others
Sub Total
190
6
5
5
5
211
The Market/or Chemicals in the Oil Industry
Fracturing chemicals
Viscosifiers 165
Fluid Loss Additives 20
Surfactants 20
Others 20
Sub Total 225
Grand Total 436
In the UK sector of the North Sea, the total market value of these chemicalsis estimated to be about £14 million, i.e. about 3% of the US market.Acidising is useg extensively in the carbonate reservoirs of the Middle Eastand that may be expected to contribute a further approximate £50 millionresulting in a world market of around £500 million. Market growth, dependenton future activity can be expected to be of the order 10-14%.
5. FUTURE TRENDS
5.1 Drilling Fluids
189
Drilling activity is moving towards more hostile environments. The search foroil and gas is becoming more difficult and new and deeper geological horizonsmust be explored. Consequently, new chemicals must be developed to performunder extremes of temperature, pressure and environment e.g. 400°-500°F;25,000 psi and appreciable quantities of H2S and CO
2(10-50%). Increased
emphasis will be directed towards polymers. The industry trend towardslow-solids fluids requires polymers that do not undergo shear degradation,have good salt tolerance and filtration control and are stable attemperatures up to 300°F. No single polymer displays all these properties andblends are currently used. Further work is required on polyacrylamides andpolyacrylates to improve their temperature stability and effective use atlower dosage rates. A final and most important trend is towards the use ofenvironmentally acceptable chemicals. Increased environmental awareness andlegislation is having a significant impact on drilling operations anddisposal of chemicals.
5.2 Cementing
In line with the future trends for drilling fluids, cementing chemicaladditives will also need to be developed to withstand extremes of temperatureand pressure. A continual problem facing the industry is the prevention ofgas migration through cement columns. As a result many wells areinefficiently cemented and require costly repair work. Extensive researchwork is presently being directed towards this problem.
190
5.3 Completion/Stimulation Chemicals
Chemicals in the Oil Industry
Development in completion fluids will be towards a better understanding ofthe physical and chemical properties of mixed brine systems under varyingtemperatures and pressure. Corrosion inhibition techniques for such systemswill also require further development.
In hydraulic fracturing the trend will be towards new, improved and moreversatile polymers. Both emulsions and foams are increasing in popularity asfracturing fluids, and extensive work can be anticipated in this direction.
Ill. PRODUCTION CHEMICALS--------------------
1. ACTIVITY SCENE
The world demand for speciality chemicals for the treatment of oil, gas andassociated water is obviously highly dependent upon volumes to be treated.World crude oil production (outside the Communist Block) now runs at about40 million barrels per day (b/d) and the associated water production isestimated at 16 million bId. The world gas production averages 3,000 billioncubic feet per day. Some of the chemical problems which occur duringhydrocarbon production and processing are associated with crude oildehydration, foaming, paraffin wax deposition, fluidity and restartability ofwaxy crudes, friction reduction of crude flow in pipelines, corrosion,scales, de-oiling of water, bacterial activity, deposition of gas hydratesand sulphur. The list is by no means exhausted and serves only to illustratethe multitude of chemical problems which can be encountered and which areoften specific and unique to a particular situation and usually require anequally specific and unique solution to the problem.
2. PRODUCTION OPERATIONS
In order better to understand the specific need for chemicals, it isnecessary to overview the actual hydrocarbon production process. After thedrilling of wells in an oil or gas field has been completed, productionoperations commence. Production operations are responsible for the handlingof all produced and injected fluids, from the wellhead to the point ofdisposal. In a typical offshore production platform development, thefollowing major processing activities would take place:
i) Wellheads and flowlines
Produced fluids are collected from individual producing wells and gatheredinto a common manifold system. Typical chemicals used in this activity arecorrosion inhibitors, scale inhibitors, wax inhibitors, hydrate inhibitors.
ii) Q~!L~~~L~~~~E_~~e~E~~~£~
The produced fluids are separated into their three major constituents undercontrolled conditions of temperature and pressure. Not all wells producewater during the early phase of production, but invariably do during thelatter stages. Principal process chemicals used are defoamers anddemulsifiers, fresh water washing (to remove salt).
The Marketfor Chemicals in the Oil Industry 191
iii) 2!!_~~~~~~~!~~
Crude oil is normally pumped from the separation facility either to a tankeror pipeline for evacuation. Typical chemicals used in this process, dependingupon the characteristics of the oil, are wax inhibitors, corrosioninhibitors, and friction reducers.
iv) ~~~_E!~~~~~!~~_~~~_E!~~~~~!~~
Gas which is either produced (natural) or separated from oil (associated) isnormally processed to recover the heavier components, e.g. propanes, butanesetc., which are often recombined with the oil stream. The gas is then usuallydried prior to being compressed for transmission to shore. Typical chemicalsused are glycols (for drying), hydrate reducers and corrosion inhibitors.
v) ~!~~~~~~_~~~~!
The water whieh is separated from the oil or gas is subject to a degree ofchemical treatment depending upon its final mode of disposal - usuallysubsurface re-injection or surface disposal. Typical chemicals used arecorrosion and scale inhibitors, biocides, de-oiling chemicals andpo1ye1ectro1ytes.
3. PRODUCTION CHEMICAL PROCESSES
3.1 Dehydration of Crude Oils
i) !~!~~~!~~_~f_~!!f!~!~_~~~!~!~~~
When oil is initially produced from a well, it usually contains associatedgas but only minor amounts of water (less than 0.5%). With time, anddepending on the production characteristics of the reservoir, the "water-cut"will increase and it is not uncommon for greater than 50% of the produced •fluids to be water within a period of five years. Under such conditions, thewater is generally emulsified in the oil and it is most important that theoil and water are efficiently separated from one another.
Three conditions are necessary for the formation of a stable emulsion (astable emulsion is defined as an emulsion that will not break down in anacceptable retention time without some form of treating) :
The liquids must be immiscible
There must be sufficient agitation to disperse one liquid as droplets inthe other
There must be an emulsifying agent present. Without this emulsifyingagent emulsions would be highly unstable.
In forming a normal emulsion (water-in-oi1) there are two forces that arecontinually in direct opposition. The surface tension of the water permitsthe droplets to form larger droplets which when sufficiently large will yieldto the force of gravity and settle out (Stokes Law).In opposition, the film of emulsifying agents provides a barrier betweendrops and tends to prevent the joining of the water droplets.
192 Chemicals in the Oil Industry
ii) ~~~E~~!~E!~!!~~_~~~_~!~~!!!!I_~~_~!!_~!~!~_~~~!~!~~~
~b.e st..a'o-\..\:\..t..~ Cl~ a1:\. ~~~\.S\.()1:\. ,-a~ \)cc. aii'C.c::..'t.'C.~ ~1 ~a\.\1 \.a~\.~.Yt~, 0.\\ \)\ ~\\\.t.\\
can be classified into a chemical or physical category or both. The naturalmaterials (emulsifying agents) which stabilise crude oil emulsions are eithersurface active agents or finely divided solids, which have a tendency toabsorb at the oil water interface, lower the surface tension and increaseemulsion stability. Typical surfactants present within crude oil areasphaltenes, aromatic and naphthenic compounds of varying degrees ofcomplexity. Finely divided solids also present within the crude oil streamsuch as clays, silica, carbon black, insoluble asphaltenes and variousinsoluble inorganics such as iron oxide, iron sulphide and barium sulphateall aid emulsion stability. A further point on emulsion stability is that fornormal oilfield emulsions, interfacial tension decreases with increasingemulsifying agent concentration. Crude oil contains dissolved compounds whosedegree of ionisation depends on the pH of the water phase. When crude oil isin contact with acid solutions, the nitrogen compounds are ionised, absorbedat the oil-wa~er interface and lower the interfacial tension. At intermediatepH values, the asphaltenes, resins, and organic acids and bases onlymoderately affect the interfacial tension. To minimise emulsion formation,the crude oil should not contact either high or low pH water because theinterfacial tension between the oil and water droplets is low at either endof the pH scale.
Other factors influencing the stability of oilfield emulsions are thetemperature/viscosity, particle size distribution of water droplets, densitydifference between crude oil and water, water content and age of theemulsion.
iii) ~E~~~_~!!_~~~l~E~!!~~_i~~~!~!~~_~~~!~~!!!~~!!~~2
For effective dehydration, the following sequential steps are required:
destabilisation of the emulsion
coalescence of the destabilised water droplets
separation of the water from the oil phase
Presently, the most popular method of breaking an emulsion is by theapplication of chemicals (demulsifiers).
Chemicals appear to be the most significant factor in treating oil emulsionsand are used to neutralise the emulsifying agents.Demulsifiers are surface active agents which should easily migrate though theoil phase to the interface and change its character from oleophilic tohydrophilic. The basic theory is that an emulsifying agent should be addedwhich would normally produce an oil in water (reverse) emulsion. Byattempting to reverse phases, the intermediate condition of a destabilisedwater drop is obtained. The activity of demulsifiers is related to twogeneral functions - speed of migration to the interface and performance atthat site.
Depending upon the chemical character of the compound stabilising theemulsion, the pH of the solution, temperature etc. a demulsifier can be ananionic, cationic or non-ionic agent.
Anionic demulsifiers are typically oils and alcohols, organic amine-fattyacid soaps and sulphonated aliphatic and aromatic compounds.
The Market/or Chemicals in the Oil Industry
Cationic demulsifiers are typically quaternary ammonium salts, whilst themajority of non-ionic agents are esters.
All these compounds have in common that they consist of a non-polarhydrocarbon chain which is attached to the oil phase and a polar-hydrophilicpart which seeks the water phase. Demulsifiers are usually supplied as a25-50% solution of active material in alcoholic or aromatic solvents.
193
With so many variables in the system, a demulsifier is often a chemical orformulation of chemicals unique to the particular emulsion requiringtreatment. Laboratory tests are required to select from a large number ofchemicals available the most effective one(s) for a certain emulsion. Forreliable conclusions it is required that representative emulsion samples beused and that the test temperature be adjusted to that expected to prevail inthe field. Consequently the most reliable results are those obtained fromtesting on site.
Final conclusions on the best demulsifier for a certain emulsion can only bedrawn from a comparison of several promising chemicals in a field test. Suchfield trials are usually conducted under supervision of the chemical supplieron a no-cure, no-pay basis. The ultimate objective is to find a chemicalwhich, at acceptable cost, effectively separates oil and water at the lowestpossible temperature, yielding dry oil, clean water and a minimum ofinterfacial sludge.
In view of the constantly expanding development of new and improved chemicalsit is essential to review from time to time the particular approach to ademulsification problem and attempt to achieve a more cost-effectivesolution. As an example, a specific crude oil stream in South East Asia hadpersistently caused dehydration problems ever since production commenced.Considerable effort was spent on attempting to solve the problem during theearly 1970's, and it was ultimately found that with the state of the art atthat time, the crude could only be effectively dehydrated using aciddemulsifiers albeit at high chemical dosage rates (500-600 ppm). This methodof dehydration continued until the late 1970's, when a concerted campaign wasagain started to try to improve the situation. After appreciable work,utilising Service Company assistance, it was found that the crude could beeffectively dehydrated with a non-acid demulsifier, at chemical dosage ratesan order of magnitude less. As a result of this optimisation, an annualsaving on dehydration chemicals of around £2~ million was realised.Typically, in a production area and depending upon the severity of thetreatment, chemical costs for demulsification can vary between £5 and £30 per1000 bbl water processed.
In field operations, demulsifier is injected as close to the wells aspossible - sometimes even into the wells. In offshore operations, wherepossible, chemical destabilisation takes place on the production platforms,coalescence in the trunk lines and settling/water separation in onshorefacilities.
Traditionally, the Oil Companies have not become involved in the developmentof demulsifiers; this was usually left to the Service Companies.However, to a certain extent this approach is changing and now some of themajor international Oil Companies are diversifying their interests into thisbusiness. Furthermore, in the face of increased operating costs, OilCompanies are concentrating their attention on optimising the applicationaspects of chemical demulsification in creating favourable conditions forchemical destabilisation, coalescence, settling and liquid phase separation.
194 Chemicals in the Oil Industry
During 1981, the cost of demulsifiers in North Sea applications was estimatedat around £3 million (in the United States some £60 million).
3.2 Defoaming of crude oils
Foaming of crude oil is a persistent industry problem causing poor wellproductivity performance, inefficient oil/gas separation and measurementdifficulties. The mechanism of defoaming is to deactivate the surface activecompounds in the crude oil and alter the surface tension of the oil filmssurrounding the gas bubbles. This weakens the surface film and releases theentrapped gas.
Many defoamers are commercially available (e.g. phosphate esters, metallicsoaps of fatty acids). However, the category most ideally suited for crudeoil application are the organic silicone compounds. The dimethyl siliconefluids appear the best performers under a wide range of conditions. Theyexhibit exceptiional stability and resistance to oxidation and heat. Compoundswith viscosities (at 75°F) between 500 and 15,000 cp seem most effective.Laboratory screening followed by field testing is usually required tooptimise exact type and concentration. Dosage requirements are usually verylow. In a recent field example, a silicon dosage rate of less than 1 ppmeliminated foam carry over and improved throughput capacity of a productionunit from 93,000 bid oil to 114,000 bid. The successful treatment not onlyresulted in future reduced equipment savings but also an accelerated oilincome of around £350,000 per day for a chemical treatment cost of no morethan £1 per day!
Silicones have appeared compatible with most other chemicals added to thecrude and their effect on downstream processes is minimal.
3.3 Wax Deposition Inhibitors for Crude Oil
Paraffin wax deposition is prevalent in the oil industry. Depending on thecharacteristics of the particular crude oil and producing temperatureconditions, wax can deposit at any part in the producing system from well topipeline.
As crude oil containing parraffin wax cools, the wax molecules begin toprecipitate and build up a crystalline matrix. The wax crystal is bothhydrophobic and oleophobic and in practical terms this means that the crystaldoes not go with either the water or the oil phase. Thus it preferentiallyprecipitates from solution, adhering to exposed surfaces, for instance pipewalls.
Prevention of wax deposition is achieved by deposition inhibitors, which areeither dispersants or crystal modifiers. Dispersants are developed tocoat small paraffin wax particles chemically and change their ability toadhere to each other or to pipe surfaces. In the small particle state, waxwill stay suspended in the crude oil for trouble-free movement. Thedispersant is chemically structured so that it has a large, dense head on oneend and a low density tail on the other. The head has an attraction for thewax particle and the low density tail may be either water or oil soluble,depending on the phase into which the paraffin wax is to be dispersed. Inmost cases it is easier and more desirable to disperse wax in the oil phase.
The Market jar Chemicals in the Oil Industry 195
Crystal modifiers co-crystallise with paraffin crystals and prevent thecrystals from attaching to each other and forming a network of largecrystals. The compound will also help to reduce the adhesiveness of the wax,preventing it from sticking to a pipe surface. Wax crystal modifiers aregenerally linear polymeric molecules with branched side chains.
Dispersants and crystal modifiers are usually injected continuously; whenusing the latter compounds, the application temperature is critical andshould be higher than the cloud-points, i.e. the temperature below whichcrystallisation begins.
There is limited experience with dispersant type wax inhibitors, whichappeared ineffective in the few cases applied. The crystal modifiers are verysuccessful and these compounds have been used where economically justifiable.The most effective compound used so far has been a copolymer ofalkylacrylate.
In a West African oil field, where wax deposition in down-hole tubing andflowlines necessitated frequent scraping and pigging, application of thiscopolymer dramatically reduced clean-out frequencies. This was achieved atadditive concentrations of 100-200 ppm, injected down-hole with the lift gas.
In another case, in an European oilfield, it appeared possible completely toeliminate wax deposition in a 10 mile 4 inch trunk line at an injection rateof 200 ppm.
Similar experience has been reported from some Canadian oil fields.
Nett savings reported have been modest, of the order of one penny per barrelof crude treated. The reason is that - compared with other additives comparatively high concentrations of chemical have to be applied;furthermore, conventional mechanical treatments are in general not verycostly. Most benefit .~ derived from the fact that the chemical treatment contrary to mechanical treatment - renders continuous production possible;therefore, in many cases the major pay-out for chemical treatment is in factderived from the elimination of deferred production of crude oil.
Screening of wax deposition inhibitors can be carried out in the laboratorywith special test equipment, including a miniature pipeline. Usually fieldtrials are carried out to confirm the results of laboratory investigations.
3.4 Fluidity and Restartability Improvers for Crude Oils
The use of these compounds is to improve the pumpability of waxy crude oilswhich are subjected to low temperatures. Their principal application is toreduce the viscosities and gels under such conditions.
When waxy crude oil is cooled off paraffin wax crystallises; this causes achange in the structure of the crude resulting in viscosity increases andsubsequent increased pumping and flowline pressures. Fluidity improvement isneeded.
These oils also exhibit a yield value. When the crude sits still at acritical temperature, it sets up. When pressure is applied, a greater amountof energy is needed to start the fluid flowing than is necessary to maintaina constant pumping rate. Restartability improvement is needed in this case.
196 Chemicals in the Oil Industry
Crystal modifiers are used as fluidity and restartability improvingadditives. These additives are chemically similar to the compounds used toprevent wax deposition.
The use of fluidity additives permits waxy crudes to be produced and pumpedover long distances without applying diluents or heat, while the use ofrestartability additives permits line shutdown and static cooling of waxycrude. Depending on the type of crude, additive concentrations of 100 to 200ppm are usually sufficient to achieve the required results.
The effectiveness of candidate compounds is normally evaluated both in thelaboratory and the field. Laboratory tests are carried out in a pipe lineloop test rig.
Fluidity and restartability improving additives find growing application,specially now more crude oil is being produced offshore in both temperate andarctic zones.
In one case waxy crude pumped through a 170 mile pipeline can be kept fluidat temperatures ranging between 50 and 60°F by doping with 150 ppm of acopolymer of alkylacrylate.
Restartability presented no problems at temperatures as low as 40°F.Laboratory tests had shown that the pour-point of this crude could be reducedfrom 70 to 20°F by doping w!ih 150 ppm of this additive. The viscosity duringpumping (shear rate 200 sec ) could be reduced from 110 to 25 cP at 60°F.
3.5 Pumpability Improvement (Drag Reduction) for Crude Oils
Drag reduction is the increase in pumpability of a fluid caused by theaddition of small amounts of chemical to the fluid. Drag reduction occursonly in turbulent flow.
The only extensive practical use of drag reducers has been with aqueoussystems. In the oil industry these compounds have been used in hydraulicfracturing treatments. Water soluble polymers such as guar gum or highmolecular weight carboxymethyl cellulose have been effective in reducinghorsepower requirements and/or increasing injection rates during treatments.
The state of the art of drag reduction in oil pipelines is just beyond theexperimental stage because it was difficult to find suitable materials ableto reduce drag in aliphatic hydrocarbons.
Long chain polymers of high (one to ten million) molecular weight, such assynthetic rubber compounds, have been found effective drag reducers for crudeoil. An almost unsurmountable problem appeared to be the shear degradabilityof these compounds; the effect of high-shear conditions encountered incentrifugal pumps causes a degradation of the long-chain polymers wherebyless effective, short-chain compounds are formed. A solution was found byadding these chemicals in solid form. This allows the chemical to dissolveslowly, producing drag reduction as it moves through the line. At the sametime, useful polymer in the form of undissolved solids passes undegradedthrough the pump stations and continues to dissolve down-stream of the pump.
Chemical additions of the order of 50 ppm are required to achieve a frictionreduction of some 10%. There is some decrease in drag reduction withincreasing pipe diameter.
The Market/or Chemicals in the Oil Industry
3.6 Deoiling of Produced Water
Deoiling of produced water is usually carried out with the help of equipmentoperating on the principles of gravity (skim tank, API separator, CorrugatedPlate Interceptor or Tilted Corrugated Plate Interceptor) or gas flotation.In some cases, where very low oil contents are required (e.g. forre-injection, the generation of steam), the gas flotation stage is followedby either filtration or a combined treatment of flocculation and filtration.
For gravity separation, conventional de-oiling chemicals are used, whichfunctionally and physico-chemically resemble the demulsifying compounds usedin crude oil dehydration. Their purpose is to destabilise oil-in-wateremulsions; this is achieved by eliminating the predominantly hydrophiliccompounds present in the oil-water interface.
197
De-oiling chemicals are therefore surface-active agents which alter thecharacteristics of the interface. They should easily migrate through thewater phase to the interface and concentrate there, changing the character ofthe interface from hydrophilic to oleophilic. To achieve this the non-polarhydrocarbon part of the compound, which orients itself in the oil phase,should dominate the polar-hydrophilic part, which seeks the water phase. Themajority of the chemicals that can be used for de-oiling are represented bythree categories:
i) Alkyl quaternary ammonium compounds.
ii) Alkyl benzyl quaternary ammonium compounds.
iii) Pyridinium compounds.
Finding the most suitable de-oiling compounds for a given oil-contaminatedwater is a matter of trial and error and resembles the finding of ademulsifier for crude oil emulsions. Again Service Companies play animportant part in the selection process.
Chemical is injected as far upstream of the gravity separation equipment asoperationally possible, in order to give sufficient opportunity forcoalescence of the destabilised oil droplets in the line system.
For oil removal by gas flotation often other chemicals, so called flocculants,are used. Their task is to increase the size of the oil droplets byflocculation. Mostly organic flocculants are used for gas flotation; they arepolyelectrolytes, which have cationic, anionic or non-ionic functionalgroups. Inorganic flocculants have been found unsuitable, because they makethe floc heavy and are detrimental when returned with the oily froth to theoil treating system.
If oil has to be removed from water by flocculation followed by filtration,then inorganic flocculants such as alum, ferrous sulphate, ferric chlorideand copper sulphate can be used, often in combination with a small amount oforganic flocculant. The separated oily floc is usually disposed of by burningin special inclnerators.
Deoiling compounds of various types are used in international operations.Upstream of gravity separation equipment surfactants in concentrations of10-20 ppm have been used. Depending on the degree of coalescence the oil-inwater emulsions are subjected to, oil removal efficiencies of 80 to 95percent have been achieved. For mechanically induced gas flotation unitsflocculant concentrations of up to 10 ppm are usually adequate to achieve
198 Chemicals in the Oil Industry
over 90% removal of suspended oil. In one production area a mini emulsion(droplet size one micron average) containing up to 1000 ppm suspended oil istreated with inorganic flocculant and almost 100% oil removal is achieved inthe floc separation and filtration equipment.
3.7 Gas Hydrate Reduction
Gas hydrates are solid compounds formed by the reaction of gas with water.They resemble snow in appearance and form as crystals. When formed in welltubulars, pipelines and gathering systems gas hydrates cause partial orcomplete blocking, reducing or stopping gas flow ("Line freezing").
Chemical compositions are:
Methane Hydrate CH4
• 7 H20
Ethane Hydrat~ C2H6 • S H20
Propane Hydrate C3
HS
• IS H20
Also CO2
and H2S form hydrates.
The temperature at which hydrates form increases with pressure and gasdensity. For instance, methane hydrate can be formed at 40°F and 500 psi.When the pressure is increased to 2000 psi, the temperature critical for theformation of hydrate increases to 60°F.
Hydrates are most conveniently controlled by preventing their formation.The three accepted methods are:
· Dehydration
· Chemical additives
• Heating
Free water is necessary for the formation of hydrates. If the water dew pointof the gas is lower than its temperature, no hydrates are formed.
The chemical additives used depress the hydrate temperature of gas. Althoughammonia, sodium chloride or calcium chloride have been used, one of the morewidely used chemicals for this purpose is methyl alcohol. It is moreeffective than ethyl or isopropyl alcohol, and is also the least expensive.Alcohol is not readily reclaimed from an aqueous solution, so its use isrestricted to applications where it is expendable. The amount of alcoholrequired for any specific condition is usually calculated. A general practiceis to inject alcohol into a flowline near the well head. This eliminates theneed for a header and permits the total production to be transported to acentral facility where the free liquids can be removed and the gas processed.Gas produced offshore is treated with alcohol before transportation bypipeline to an onshore facility.
Glycol has also been used and has the advantage that it can be recovered froman aqueous solution by boiling off the water. The regenerated glycol is thenreturned to the injection point. Ethylene glycol is the preferred glycol.
The Market/or Chemicals in the Oil Industry
4. OTHER PRODUCTION SPECIALITY CHEMICALS
199
Typical production speciality chemicals, over and above those outlined in theforegoing sections are corrosion inhibitors, scale inhibitors and biocides.
4.1 Corrosion Inhibitors
These are chemicals which protect metals, exposed to an agressiveenvironment, against corrosion in wells and surface facilities.
Oil Environment
The type of corrosion which can take place in oil wells, pipelines andfacilities is usually sweet (C0
2) or sour (H2S); oxygen corrosion seldom
occurs. No corrosion takes place when dry oil is produced or handled; asionic reactions between CO
2or H
2S are the cause of metal corrosion, the
presence of water in the system ~s essential for these reactions.
The corrosion inhibitors used for this application are usually the surfaceactive - adsorptive type, the so called film formers. Almost 90 percent ofthe inhibitors in successful use today are either based on the long chainaliphatic diamines or on long carbon chain imidazolines. Variousmodifications have been made of these structures to change the physicalproperties of the material. For example, ethylene oxide is commonly reactedwith these compounds in various molecular percentages to give polyoxyethylenederivatives that have varying degrees of brine dispersibility. Manycarboxylic acids are used to make salts of these amines or imidazolines.
Corrosion inhibitors can be applied continuously or by batching. If acontinuous down-hole treatment is required, the chemical can be injecteddirectly into the annulus of the well with the help of a marcaroni pipe orin gas lift wells - with the lift gas. Before continuous treatment a singlebatch of inhibitor is circulated to lay down an initial protecting film. Thefrequency of batch treatments depends on the severity of the corrosionproblem and the fluid velocity in the production conducts. Batch treatmentsby squeezing into the formation are often successfully applied.
Selection of a corrosion inhibitor takes place in the laboratory; arepresentative mixture of the crude oil concerned with the relevant formationwater and gas phase is brought into dynamic contact with steel coupons, withand without inhibitor under simulated well condition ("wheel" test or"rotating bottle test"). Successful candidates are selected for fieldevaluation.
The performance of corrosion inhibitors in the field is closely monitored.Coupon tests and iron counts are still being used for this purpose. Corrosionrate measurements using polarisation resistance techniques can be used aswell, but periodic changes of electrodes are needed due to fouling.
Water Environment
In produced water systems corrosion can be caused by dissolved oxygen, carbondioxide, hydrogen sulphide or bacteria. Dissolved salts, the pH, thetemperature and the water velocity in the system strongly affect the rate ofcorrosion. Depending on the final destination of the produced water, adecision should be made whether measures have to be taken to preventcorrosion or not. If so, several methods can be applied, including removal ofthe corrosive gases, using corrosion resistant material or applying corrosioninhibitors. A combination of one or more methods is also practised.
200 Chemicals in the Oil Industry
When oxygen is the cause of corrosion in a given system then, in most cases,oxygen will be removed or corrosion resistant materials will be used. This isbecause there are hardly any suitable compounds available. The classicpassivating inhibitors such as chromates or nitrites, or inorganic barrierformers such as zinc salt phosphate combinations or the silicates, are ruledout for once-through systems because very high concentrations are requiredparticularly in the presence of a significant chloride content. Combinationsof amino methylene phosphate and zinc salts have been successfully used incirculating water systems and proved more effective than the inorganicphosphate-zinc salt combination. Recently an organic sulphophosphate wasintroduced which shows promising results as an oxygen corrosion inhibitor.
When HZS and/or COZ cause corrosioq in a given system, barrier forming or"filming" inhibitors will be used. Because oil is usually absent or onlypresent in low concentrations, these inhibitors should be water soluble, i.e.the balance between the hydrophobic hydrocarbon chain and the polar portionof the inhibitor molecule should be changed in favour of the latter. However,as the inhibitor film stability is determined by the interplay of a number offactors involving both the hydrophobic and hydrophylic portions of themolecule, a delicate balance has to be attained because changes in themolecule that promote water solubility tend to decrease film stability. Thisconflict between solubility and film stability has been one of the basicobstacles to be overcome in formulating an effective water soluble inhibitor.
However, a wide variety of inhibitor formulations is available for corrosioncontrol in water systems. Most of these are produced from only a few types ofstarting materials. Fatty acids or rosin acids, some form of basic nitrogenprecursor and ethylene oxide are the active ingredients sources.
After transformation into the final product, the resulting ingredients areusually dissolved in an alcohol-water solution. Actual inhibitor contentranges from ZO to as much as 65-70%, depending on the solubility of thecompound. Often, more than one type of inhibitor molecule will be used.
The available commercial inhibitors may be grouped as follows:
Primary monoamines (as salts, ethoxylates or unmodified form)
Polysubstituted monoamines (both secondary and tertiary forms)
Diamines/polyamines/imidazolines (either unmodified or as derivatives)
Quaternary ammonium compounds (after as trimethylalkyl)
Concentrations ranging between 5-Z5 ppm are required, depending on watertemperature, pH, salinity and flow velocity. The chemical is usually injectedcontinuously at strategic locations into pipe-line, pump suction, etc. Theeffectiveness of the inhibitor is evaluated by monitoring the corrosion rate;rates of 10-Z0 mpy are considered acceptable from the metal-loss point ofview.
Gas Environment---------------Corrosion in gas production wells and surface system is usually caused byCOZ' HZS or a combination of these two acid gases. Protection of off-theshelf carbon steel is needed when the partial pressure of CO2 in the systemexceeds 7 psi and that of H S exceeds 0.05 psi*). In the latEer case stresscorrosion cracking occurs. tn all cases the presence of condensated water isrequired to have any corrosion at all.
*) Partial pressure of H2S in a system containing 0.01 mol % HZS (100 ppm or6.7 grains per 100 SCF) at a total pressure of 1000 psi equals 0.1 psi.
The Marketfor Chemicals in the Oil Industry
The corrosion inhibitors used resemble those applied in oil wells; they arefilm-forming and adsorb onto metal surfaces. They create a hydrophobic layerthat prevents the corrosive gases from contacting the metal surfaceintimately enough to allow chemical reactions to proceed.
Corrosion inhibitors can be introduced into the well by c~ntinuous down-holeinjection via the annulus, by conventional batch treatment or bybatch-squeezing. The inhibitor is usually dissolved in diesel oil, keroseneor - if available - gas condensate; 5-10% solutions are applied.
Subsurface CO corrosion occurs in a major European gas field.This results trom 0.9% CO
2(20 psi partial pressure) in the gas, together
with water vapour, which condenses in the tubulars causing formation ofcorrosive carbonic aid. Originally corrosion was controlled by batchtreatments. However, when well production rates were increased (increasinggas velocities in the tubing from 40 to 65 ft/sec.), protection by batchtreatment appeared inadequate.
Continuous treatment was started by injecting 60-70 GPD of 8% inhibitorsolution into the wells via the annulus and an injection valve at 8500 ft.Some 285 wells now on production are continuously treated. Corrosion ratesaverage 1.4 mpy, which means an average tubing life of 11 years.
201
A high-pressure (20,000 psi), high-temperature (380°F) sour gas field in theUSA produces a mixture of 27-45% H
2S, 3-9% CO
2and 45-65% methane from 19,700
22,200 feet deep horizons. Production averages 15 million cu ft per well.
The gas is water-saturated at bottom hole conditions and produces nohydrocarbon condensate. This composition, coupled with the high pressure andhigh temperature, constitutes a very corrosive environment. A successfulcorrosion prevention system was developed which was continuous chemicalinhibition. A key feature of the well completion design is the absence of adown-hole packer between the production casing and tubing to provide forcirculating fluids (API grade C-75 and P-I05 steel are used for the welltubulars for the upper and lower parts respectively).
The inhibition fluid has to meet the following requirements:
Must prevent corrosion
Have proper phase behaviour
Be of predictable and uniform quality
Be manageable
Be able to be dehydrated
Have a low vapour pressure
Be non-scaling
The greatest problem was to find an inhibition system which maintained aliquid phase in the entire tubing string. This problem was empirically solvedby duplicating bottom hole conditions in surface test facilities with variouscarrier oils until one was found which yielded sufficient liquid phase atacceptable ratios of circulated carrier oil to gas.
To keep the inhibition system manageable, the viscosity had to be low enoughto be pumped in cold weather.
202 Chemicals in the Oil Industry
The ability to separate water from the inhibitor system is important. Thiswater is picked up from the water-saturated sour gas system at a rate of6-8 barrels per million cu ft gas produced. A low vapour pressure of thesystem is an economic necessity, because carrier oil and inhibitors are bothexpensive. It is an obvious prerequisite that the inhibitor system isnon-scaling or non-fouling; it reduces well production and inhibitorcirculation and necessitates expensive work-overs.
The most suitable inhibitor system appeared to be 50-50 mixture of twospecially refined oils containing 1% of inhibitor (an imidazole with anolefin chain). The results of the application of this technology have beenvery successful since its introduction in 1974. Tubing inspection revealed nointernal corrosion. Some minor pitting (20-40 mils) was observed after 3-4years of service.
4.2 Scale Inhibitors
These chemicals prevent or m1n1m1se the deposition of scale from water as aresult of an instability condition induced by a change of temperature orpressure. Also mixing with an incompatible water causes instability and scaledeposition. Scales of calcium carbonate, calcium sulphate and barium sulphatehave been encountered both down-hole (in formation, perforations, casing,tubing) and at the surface (flowlines, oil/gas separators, transfer pumps).
The action of most scale inhibitors is basically one of adsorption on themicrocystalline nuclei to inhibit growth to full-fledged scale crystals; asmall amount of chemical can tie up a large amount of scale-forming material.These inhibitors are usually phosphorus compounds in several forms. Someinorganic polyphospates, such as sodium hexametaphosphate, characterised bya P - 0- P link, are very effective in the low to medium temperature ranges(up to about 150°F) against deposition of calcium carbonate and calciumsulphate. At higher temperatures these compounds are ineffective. Theprotection against calcium carbonate scale is excellent (2-5 ppm inhibitorneeded), against calcium sulphateJfair (10-20 ppm), and against bariumsulphate, poor (> 50 ppm).
Organic phospate esters, characterised by a R- 0- P link, are generallymore stable than the inorganic phosphates, especially at elevatedtemperatures (up to 250°F). However, they are not compatible with highcalcium waters and in some formation squeezes they can produce emulsionblocks. The protection against carbonate and sulphate scale is fairly goodwith required additions ranging from 10-20 ppm.
Organic phosphonates J characterised by a R - C - P link, have a high heatstability (350°C), excellent solubility in high-calcium waters and do notseem to cause emulsion blocks on squeezing. Protection against carbonate andsulphate scale is very good with required additions ranging from 5 ppm (forCaC0
3) to 20 ppm (for BaS0
4).
Organic amino-phosphates are intended not only to provide scale control butalso corrosion control. The phosphate-ester portion of the molecule is thesame as in the organic phosphate ester. In addition, there is a nitrogenhydrogen link in the molecule which enables it to serve the dual function.
Some organic polymers are also active as scale inhibitors; it is believedtheir activity is also based on an adsorption mechanism which preventscrystal growth. This type of inhibitor is comparatively new on the market andlittle practical experience is available.
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Some scale inhibitors function by a chelating mechanism wherein one moleculeof sequestrant reacts with one atom of calcium or barium to form a solublecomplex. In this way calcium or barium ions are unable to combine withcarbonate or sulphate ions and precipitate. An example of a chelating agentis EDTA (ethylenediaminetetraacetic acid). This compound is rarely usedbecause comparatively large quantities are required and it is expensive.
203
Most scale inhibitors are already effective at the threshold concentration of2 ppm. However, in practice concentrations of 5-20 ppm are maintained. Foroperational reasons, the liquid form is preferred for field use; this impliesthat the originally solid polyphosphates have to be dissolved before use.
The selection of scale inhibitors is carried out on basis of laboratoryevaluation tests followed by field trials. On basis of the temperatureprevailing in the system to be protected, a first selection is made beforethe laboratory tests. A simple apparatus is available to screen scaleinhibitors. Scaling solutions, containing inhibitor, are pumped at constantrate through a long capillary tube and the pressure measured. If scaledeposition occurs; this pressure shows an increase. The compound that canprevent a pressure increase at the lowest concentration is selected forfield trials.
Down-hole, scale inhibitors can be applied by batch-squeezing, continuousinjection via the annulus or using slowly dissolving compounds.
Batch-squeezing has been successfully applied by the industry in several oilfields. In one field severe production losses occurred due to deposition ofcarbonate scale in valves, well tubing, production sleeves and even in theproducing formation. Liquid scale inhibitors provided a method of preventingscale deposition using the squeeze technique. This technique has been appliedin more than hundred wells, squeezing being combined with acid clean-outtreatments to remove scale that had previously been deposited.Amino-methylene phosphonate is used in 40 barrel batches, consisting of freshwater containing 3% active material. After squeezing into the formation, theinhibitor is displaced with diesel oil to five feet distance from theborehole. Although scale deposition is effectively prevented, in some of thetreatments a decrease in production rate was observed. It is believed this iscaused by the formation of emulsion blocks during squeezing.
Retreatment is done when phosphonate residuals drop below 10 ppm. Squeezetreatment cycles of three to fourteen months have been obtained.
4.3 Biocides
The problems caused by micro-organisms can be numerous and varied in effectand impact. Micro-organisms that can cause significant problems in producedwater are slime producing bacteria (blockage of filters), iron bacteria(blockage of filters, corrosion), yeasts and filamentous fungi and sulphatereducing bacteria (SRB). These latter anaerobic micro-organisms cause themost serious material problems which plague production operations. Their mainfeature is that they can reduce inorganic sulphur compounds to sulphide. Thetypical overall equation for the metabolism of SRB is:
The problems caused by SRB are therefore associated with the generation ofH2S and CO 2 and the removal of hydrogen from an aqueous system.
204 Chemicals in the Oil Industry
A biocide can either be bactericidal or bateriostatic, largely depending onconcentration. Which of these two properties are required in a particularlocation will depend on circumstances. Thus if a large bacterial populationneeds to be reduced or eliminated, a bactercidal action will be required.
Although there are many service companies who provide a multiplicity ofbiocide formulations, there are relatively few biocides in common use. Theseare quaternary ammonium compounds, amines, chlorinated phenols, chlorine,aldehydes and thiocyanates. Formulations may contain more than one of thesecompounds. In most situations this list is reduced for various reasons. Thus,incompatibility with other chemicals, partition into oil, insolubility inwater, environmental considerations and insufficient biological activity canall permit the sensible use of only an extremely limited selection.
Most micro-biological activity can be suppressed by the cheapest bactericideavailable, chlorine. The disinfecting effect is mainly due to the formationof oxygen in "statu nascendi" which kill bacteria by oxidation. There is alsoevidence that the chlorine kills bacteria by precipitating their proteins aschlorinated p'rotein compounds. Chlorine can be inj ected as gas from pressurebottles or as hypochlorite. Hypochlorite can originate from common bleachingpowder or from on-site electrolytical generators. Injection is usuallycontinuous; the required concentrations depend on the BOD of the water residual chlorine concentrations of up to one ppm are normally maintained.
SRB are often insensitive to chlorine and more potent biocides such asquaternary ammonium compounds, aldehydes or a mixture of these compounds arerequired. Shock treatments are given; weekly or twice weekly 3-6 hour, 50-100ppm slugs of biocide are added. Every 2-3 months the biocide is changed toeliminate the possibility of the SRB becoming immune to treatment.
Screening of biocides takes place in the laboratory using cultures of SRBisolated from the water concerned in accordance with API recommended practiceNo. 38. Often a modified method is used, whereby a medium prepared from thesubject water is applied.
Monitoring of SRB in a system is crucial; SRB counts are established usingmethod API RP 38 or, where possible, measurement of adenosine triphosphate(A.T.P. photometry). The latter method has the advantage of rapidity, butsuffers from the disadvantage on non-selectivity.
5. COSTS OF PRODUCTION SPECIALITY CHEMICALS
On a world market scale, the following breakdown of production specialitychemical expenditure is estimated:
Demulsifiers 135Corrosion Inhibitors 85Surfactants 15Biocides 10Scale Inhibitors 35Wax Inhibitors 10Others 10
300
Approximately £7 million is expected to be spent in the United Kingdom.
The Market for Chemicals in the Oil Industry
6. FUTURE TRENDS
205
Some typical examples of new product needs for production specialitychemicals are as follows:
i) Development of non-toxic non-polluting chemicals for corrosion andbiocidal inhibition, especially for offshore.
ii) Development of biocides which will be effective throughout the reservoirand will not adhere to the rock, or degrade under extremes oftemperature and pressure.
iii) Improved de-oiling compounds to process water from thermally affectedcrude.
iv) Non-emulsifying corrosion inhibitors which are stable at high pressureand temperature.
v) Improved corrosion and scale inhibitors for high temperature andpressure application in both oil and gas wells.
Ill. OIL RECOVERY CHEMICALS----------------------
1. ACTIVITY SCENE
Primary recovery of oil and gas generally relies on the natural drive energy(usually pressure) within the reservoir. Typical recoveries (as a percentageof original oil in place) vary, among other parameters, on the nature of thecrude oil. For example, heavy and viscous crudes may yield only 1-5% whilstlight crudes can yield from 10-40%. Secondary recovery processes such aswater injection and gas injection are often utilised to recover additionaloil. Enhanced oil recovery is the description applied by the oil industry tonon-conventional techniques for getting more oil out of subsurface reservoirsthan is possible by primary or secondary recovery processes. The oil notproducible, or left behind, by these conventional recovery methods may be tooviscous or too difficult to displace. It may also be trapped by capillaryforces in the flooded parts of the reservoir, or by-passed by the injectedwater or gas. In general, the aim of enhanced oil recovery techniques is torecover more oil by improving the displacement efficiency. Enhanced oilrecovery techniques are conveniently subdivided into various categories, i.e.miscible, chemical and thermal processes.
Small amounts of speciality production chemicals are utilised in primary andsecondary recovery processes. However, the significant potential forchemical utilisation is within the enhancr2 oil recovery techniques. Of theworld cr?2e oil reserves of some 5.5 x 10 barrels, only around1.5 x 10 barrels (27%) is eSf~mated to be recoverable by conventionalmethods. The remaining 4 x 10 barrels may be seen as a target for enhancedrecovery.
2. SECONDARY RECOVERY METHODS
2.1 Water/Gas Injection
Over the years it has been established that maintaining reservoir pressurecan yield more oil than can be obtained by primary recovery alone. By suchtechniques, the reservoirs natural energy and displacing mechani~m, which areresponsible for primary recover~ are supplemented by the injection of wateror gas.
206 Chemicals in the Oil Industry
In the case of water injection, over 90% of the North Sea fields have ontheir platforms a seawater injection facility, capable of producingsufficient treated water to replace the extracted oil and gas volumetrically.Typical chemicals used in water treatment are biocides (sodium hypochlorite,glutaraldehydes etc.), scale inhibitors, corrosion inhibitors and oxygenscavengers (sodium bisulphite, ammonium bisulphite) most of these chemicalshave already been mentioned in the foregoing sections.
Little or no chemical treatment is required for gas injection, since the gasis usually dried and compressed prior to re-injection.
3. ENHANCED OIL RECOVERY METHODS
3.1 General
Although each_EaR method (chemical, miscible or thermal) has its own range ofapplication, 'these methods are to a large extent complementary and thustogether cover a wide range of reservoir conditions.
In spite of the considerable effort spent on research and field testingduring the last 30 years, enhanced oil recovery techniques are, on the whole,still very much in a stage of development.
Most successful so far have been thermal recovery methods, particularly thoseemploying steam. For many years steam drive and steam soak have been appliedon a large scale in e.g. Venezuela, the USA and the Netherlands. Obvioustargets for the application of thermal recovery are the large heavy oilaccumulations in Venezuela.
The prospects for "miscible" recovery (including e.g. non-miscible nitrogeninjection) techniques are promising. Large-scale miscible gas injectionprojects are underway in various parts of the world.
Although the mechanism of chemical flooding is now much better understoodthan ten years ago, these processes are still in the testing stage.Nevertheless, for a large fraction of the light oil in place world-wide,chemical flooding is considered to be the only method for increasing theultimate recovery above what can be produced by conventional methods.Consequently, its long term potential should not be overlooked.
It is important to realise that EaR methods always have to be tailored verycarefully to the specific conditions of the reservoir where they are to beapplied. This also means that extensive field testing is a prerequisite forlarge-scale application.
The long-term future for enhanced oil recovery is promising, but it is notexpected to contribute significantly on a world scale before the end of thecentury. Even that will require a considerable further technical andfinancial effort.
3.2 Thermal Processes
The purpose of these methods is primarily to reduce the oil viscosity andthereby improve the sweep efficiency for heavy oil (specific gravity 0.95 to1.01 at 60°F).
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Steam DriveBecause-of tts relatively low density and viscosity, steam tends to by-passthe oil along the top of the reservoir. This negative effect is, however,more than compensated by several positive aspects:
i) its large heat content
ii) the relatively high pressure gradient in the steam zone due to thehigh velocity of the condensing steam
iii) effective heating of the underlying oil by water of condensation
iv) low residual oil saturation in the steam zone due to (partial)vaporisation
As a result, steam drive has been a very effective recovery method forheavy-oil reservoirs, and has found wide application during the last fewdecades.
207
Steam SoakThis process,-also referred to as "cyclic steam injection", "steamstimulation" or "huff and puff", was developed in the late 1950s for theheavy-oil fields on the Bolivar Coast in Venezuela. Steam soak isessentially a stimulation method which will activate natural drive mechanisms(rock compaction, solution gas drive, gravity segregation) which are dormantunder "cold" conditions. It is also applied in combination with steam drive.
The success of the steam soak method is due to a combination of factors:
i) the strong reduction in oil viscosity between, say 50 and 100°C
ii) the effective redistribution of heat around the well bore due tothe fact that steam overruns the oil and thus forms a thin steamzone on top of the oil
iii) storage of a large fraction of the heat injected in the rock, whichacts as an effective heat exchanger slowing down shrinkage of thehot zone around the well bore during the production phase.
As a result, high oil/steam ratios can be obtained.
!!o!. ~a!.e.!:.i.nie~ti.0E.Although less effective, both as a heat carrier and as a displacement fluid,hot water may find application in reservoirs where pressures are too high forsteam injection. At very high temperatures (around 350°C) hot water may actas a solvent for oil and thus bring about a reduction of the residual oilsaturation.
In-situ combustionTwo pri~cipal-techniq~es have been tested, both in the laboratory and in thefield - forward and reversed combustion. In forward combustion, thecombustion front moves in the same direction as the injected air, whereas inthe reversed combustion process, it moves in the opposite direction. Forwardcombustion is now generally preferred to reversed combustion.
The attraction of the ISC process is that heat is generated in situ,utilising the heavy ends of the crude that would otherwise b~behind.
208 Chemicals in the Oil Industry
On the other hand, of course, energy is needed for compression of the air tobe injected. There are no heat losses in injection wells. Furthermore, byinjecting water together with the air, the process can, in principle, beturned into an in situ steam generation process.
Unfortunately, it is difficult to control this process under reservoirconditions. In the case of "dry" combustion (air injection only) the problemis how to control movement and temperature of the combustion front. In thecase of "wet" combustion water and air tend to follow different paths as aresult of gravity. High temperatures and the presence of corrosive fluidslead to frequent well failures.
In spite of all this, there are still a number of - reportedly successful in situ combustion projects in operation. It seems unlikely, however, thatthis number will grow substantially until the operational problems describedabove have been solved.
f.h~m..!:c~~ ~t..!:l..!:s~d_i~.!..h~r~al.E.r~c~s~e~In steam projects, water treatment chemicals (inhibitors, softeners, oxygenscavengers) are used extensively to render the source water suitable forboiler feed water for steam generation. On the processing side, steamaffected crude is notoriously difficult to dehydrate and requires specialistexpertise and chemicals for both demulsification and de-oiling of the producedwater. Furthermore, thermally affected crude often generates significantquantities of H2 S and CO 2 which require appropriate inhibition chemicals.
3.3 Miscible Drive Methods
The principle of a miscible or near-miscible drive process is to eliminate orstrongly reduce the interfacial tension between the displacing and thedisplaced fluid, with the purpose of mobilising the oil trapped by capillaryforces after water or gas drive.
Two types of miscibility can be distinguished; direct miscibility in whichthe fluids mix in all proportions, and developed miscibility where the fluidsare not directly miscible, but develop miscibility as a result of componentexchange between two fluids.
Processes of this kind, based on the injection into the oil reservoir of asuitable solvent or gas, have been studied since the early 1920s, and intheory they can recover all the hydrocarbons left behind by conventionalrecovery methods. But, since the miscible drive fluid is often more mobileand less dense, it tends to by-pass the oil by over-running it or fingeringthrough it, thus leading to low displacement efficiency.
The main miscible-drive fluids are: hydrocarbon solvents, (enriched orhigh-pressure) hydrocarbon gas, carbon-dioxide and nitrogen. Theapplicability of these fluids depends largely on reservoir pressure,availability and cost.
Hydrocarbon solventsAny s;l;e~t-miscibl~ ;ith oil (for example, LPG, kerosine or gasoline) can beinjected into a reservoir. But, since the cost of such refined products ishigh, the miscible fluid is not injected continuously but in the form of aslug - typically 10 to 20 per cent of the reservoir pore volume - followed bya gas or water drive. This technique is effective at low pressure andtemperatures. Nevertheless, the cost of these solvents will usually beprohibitive.
The Market/or Chemicals in the Oil Industry 209
!!.Y.Q.r~c~rE..0~.&a~A lean gas is miscible with the crude at high reservoir pressures. In thecase of developed miscibility, the injected gas contacts the oil, and theintermediate hydrocarbon components evaporate from the oil into the gas. Atthe displacing front a rich gas mixture develops, and this may becomemiscible with the oil. By, adding intermediate components (C3-CS) miscibilityis achieved at lower pressures. Because of its high value natural gasinjection is usually justified only as a combined EOR/gas conservationproject.
Carbon dioxideThe minim~m-miscibilitypressure for CO 2 varies, depending on temperature andpurity. In addition to miscibility CO 2 injection has several otherfavourable effects, such as swelling and viscosity reduction of the oil andreduction of the gas-oil interfacial tension. It also dissolves to asignificant extent in the water and lowers the pH, which may effectwettability.
CO 2 can be injected as a slug typically at pressures of 1200-2500 psi anddisplaced by hydrocarbon gas or nitrogen. Alternatively, CO 2 can be appliedunder conditions where viscous forces are predominant, which involve eithercontinuous injection, or CO 2 alternated with water.Apart from technical problems (corrosive effect on lines, tubulars) the mainlimitation of this method is the availability of CO 2 • Large-scaleapplication of this process is foreseen in the USA, where natural carbondioxide reservoirs have been found within a reasonable distance of targetprojects.
CO 2 injection, in particular for well stimulation, has also been consideredfor deep heavy oil reservoirs, where the pressure is too high for steaminjection and injectivity too low for hot water injection. It seemsdoubtful, however, whether the CO 2 will dissolve fast enough in the oil.
NitrogenIncreas~d-i~terest in the use of nitrogen developed when it became cheaper tomanufacture and inject this inert gas than a hydrocarbon gas. At first,waste gases such as stack gas, flue gas and exhaust gas were considered andfield tested. But the problem with these is that they contain waste productssuch as nitrogen oxides and sulphur oxides which give rise to corrosion andpollution problems. Later, attention turned to producing nitrogencryogenically.
Although nitrogen is not miscible with the reservoir oil at low pressures, itcan develop miscibility at sufficiently high pressures. Its application isnot, however, limited to miscible recovery pressures; in view of itsunlimited supply it can be used to replace non-miscible hydrocarbon gasinjection in secondary recovery projects, or as a drive fluid for moreexpensive miscible slugs.
Chemicals utilised in miscible processesThere-are-f~w-miscibl~proj~cts-pre;e~tly-i~operation and chemicalrequirements are low, predominantly corrosion inhibition chemicals.
3.4 Chemical Processes
Chemicals can be added to change the physico-chemical properties of thedisplacing fluid and those of the oil. The primary objective is to reducecapillary forces, to increase the viscosity of the displacing fluid or toplug off thief zones and so improve recovery efficiency.
210 Chemicals in the Oil Industry
Chemical recovery methods employ polymers, surfactants or caustic soda. Anew technique that has shown promise is the use of foam as a mobilityreducing agent in steam and miscible drive projects. This is very much inthe experimental stage.
Polymer floodingA polymer-dlsso1ved-in the injection water will reduce water mobility andprevent bypassing of the oil. The principal water soluble polymers arepolyacrylamides and polysaccharides. Polyacrylamides can be very effectivewhere the salinity of the reservoir brine is below, say, 1 per cent (comparedwith 3.5 per cent in sea water). They are prone to shear degradation in lesspermeable reservoirs. Polysaccharides are less sensitive to sheardegradation and salinity and can therefore be used in most reservoirs withmoderately saline reservoir waters. However, polysaccarides need protectionagainst biological degradation and a biocide therefore has to be injectedwith them. Their long-term stability at reservoir temperatures is underappraisal.
The increased viscosity of the displacing fluid resulting from the additionof polymer leads to more efficient displacement of the oil but reduces thefluid's injectivity. Depending on oil viscosity, a polymer flood projectcould double the recovery obtainable with a conventional water drive. Withthe high cost of polymers and reduced injectivity, however, there is a limitto the maximum concentration that can be used. For all practical purposesthe application of this technique is restricted to reservoirs containing oilwith viscosities in the range 10 to 100 cP at temperatures below 80°C.
Surfactant floodingThis process,-llke ;iscfble drive, aims at producing the residual oil leftbehind by water drive by reducing the oil-water interfacial tension. Thesurfactant solution is followed up by a polymer slug (for stability) and,finally, by water.
Factors that influence the formation of oil-in-water or water-in-oilemulsions are the composition of the oil, reservoir temperature, reservoirbrine salinity and the type of concentration of surfactant.
At present, systems containing specifically tailored surfactants can bedesigned for application in sandstone reservoirs at temperatures up to 80°C.Oil viscosity preferably should be low, as well as salinity « 10% TDS).Excessive clay, because of its cation exchange capacity, can be harmful tothe surfactant slug.
The overall recovery efficiency of a surfactant flood could be of the orderof 30 to 60 per cent of the oil left behind by conventional recovery methods.The main problem in surfactant flooding is still to maintain the integrity ofthe surfactant slug while displacing it through the reservoir. Even then,there will always be a considerable time lag between injection of the firstchemicals and the arrival of the oil bank at the production wells. Thisobviously leads to long pay-out times.
Caustic floodingCaustfc-floodfng(dflute solutions of sodium hydroxide or sodiumorthosilicate) is based on the principle that the organic acids naturallypresent (e.g. naphthenic) in some oils can react with the alkali in a causticsolution. This reaction leads to the in situ formation of surfactants andemulsification at the oil/water interface. The result is a decrease ininterfacial tension between the oil and the water, comparable to that broughtabout by surfactant flooding.
The Market/or Chemicals in the Oil Industry 211
A pre-condition for in situ emulsification is the presence of sufficientpetroleum or organic acids in the oil. This is almost exclusively the casewith medium and heavy oils.
The caustic solution reacts not only with the oil but also with the reservoirrock and brine. ConsequentlYt it is rapidly depleted t and it is this effectthat complicates the design and control of caustic flooding projects. Morelaboratory and field testing will have to be done before this method t whichis promising in principle t can be implemented on a large scale.
R.l~g.B.iE.g_oif_tE.i~f_z~n~s
The target of miscible and surfactant drives is the residual oil in thewater-swept part of (primarily) light oil reservoirs. In addition t a largevolume of oil is left behind in the non-swept part of the reservoir.Recovery rif this oil would require in-depth plugging of the swept zones orareas without t however t damaging the remaining, oil-saturated parts.Obviously, this is one of the most delicate problems to be solved in recoveryprocess research. ,No satisfactory solution has been offered as yet t but inview of the large possible rewards a continued research effort in this areaseems fully justified.
Chemicals utilised in chemical processesAs indicated pr;vio~sly-:-typical ~h;U1Tc-;(; ;sed for polymer flooding arepartly hydrolysed polyacrylamides t biopolymers t and hydroxyethyl celluloses.Effective polymers ~re required which offer high viscosifying power at lowconcentrations. In practic€t the latter are usually in the order of 600 ppmbut can range from 100-2000 ppm depending on field conditionR t polymer typeetc. These concentrations refer to initial flooding s~dges. In prolongedflooding t the polymer concentration is gradually dropped to cut costs. Thepolxmer, should be highly water soluble and of high molecular weight(lOD- IO ) in order to provide for large swollen and hydrated coils insolution and high viscosifying power. In addition t the polymer cha~ns m~y hecharged and possibly branched or partly cross-linked for l1a~imum coilstiffness and extension by electrostatic repulsion and sterfc hinderingeffects. Polymer retention shou16 be low. Anionic pGlyrners tend to showbetter t lower retention than non-ionic polymers. Both types are superior tocationic polymers t which are highly retained in most reservoirs. In thereservoir, during flooding, the polymer may be exposed to conditions of hightemperature (up to 110°C) and high salinity (Na+ > 2 M, Mg 2+ 'V 0.11'1, Ca 2 +ions and others) for periods of up to 10 years. Such severe conditions maycause viscosity reduction t precipitation and/or chemical breakdown of thepolymer. So far all polymers tested have stability shortcomings. Durin~l
flood injection t the polymer is exposed to high shear rates (» 1000 sec )which may also cause molecular breakdo~ln. Natural polymers show lowresistance against biodegradation and hence the use of biocides orstabilizers has to be considered. In the case of micellar polymer flooding(surfactant followed by polymer)t the polymer used in the drive water must becompatible with the components in the preceding surfactant slug. Neitherphase separation defects (floccing t gelling t precipitation etc.) nor chemicalreactions (cross-linking etc.) should occur at the interface of the twoflooding compositions. Typical surfactants which are used in micellarflooding are based on hydrocarbon sulphonates (for example petroleum orsynthetic sulphonates) which are added in concentrations of up to about 5% wto the drive water.
212 Chemicals in the Oil Industry
4. Economic Aspects and Long Term Prospects
The predominant future chemical requirements will be based on EOR techniques.The time from laboratory test to first oil response in a field pilot dependson the scope of the pilot, but may be as much as ten years. The reason forthis is not only that EOR processes are complicated, but also that they haveto be tailored carefully to the specific conditions of the target reservoir.Against this background the number of active EOR Projects world-wide israther impressive: nearly 400 in 1981, of which some 250 in the USA.Together, these projects produce nearly 900,000 bid, about equally dividedbetween the USA and the rest of the world. Since 1973 there has been asteady increase in activity. Although the EOR production potential is minoron a world-wide scale, it has become a significant factor for some countries,certainly in terms of technical effort and expertise required.
Steam plays a predominant role, with more than two-thirds of the projects andof the total EOR production. Most of the activity is in the USA, Venezuelaand the Netherlands. Steam injection is likely to continue its relativelyrapid expansion, in view of the very large scope for further application inthe various heavy oil provinces of the world.
The other EOR methods together show a very slow growth in activity, without,however, a corresponding increase in oil production. These processes stillsuffer from technical problems and/or high costs. There are, however, anumber of large-scale gas injection projects in operation and others plannedin the North Sea, Middle East, Africa, the USA and Canada. There are alsoencouraging signs for carbon dioxIde and polymer injection, which have bothseen a relatively rapid growth in recent years.
Nitrogen injection is a newcomer, but shows promise for one or more largeNorth Sea reservoirs.
It is important to keep in mind that polymer injection and thermal methodsfind application only in reservoirs containing medium viscosity and heavycrudes. A large volume of oil is left behind in light oil reservoirs, eitherby-passed by water or gas or trapped by capillary forces. It will benecessary to rely primarily on miscible and chemical drive methods forrecovering this oil. Hence, it must be expected that in the long term,depending of course on the development of crude prices, these methods willbegin to play a more important role.
The scope for EOR world-wide is large: perhaps an additional 400 billionbarrels recoverable from conventional reservoirs and an additional300 billion barrels from "tar-sands". However, even under the mostfavourable crude price scenario, the build-up of enhanced oil recoverypotential will be severely constrained by long lead times and by the heavytechnical and financial effort required.
As far as chemical flooding is concerned, the economics of surfactant andpolymer flooding are affected to a great extent by the amounts and costs ofapplied chemicals and by the timing and volume of additional oil produced.
The size and concentration of the surfactant slug depends on the expectedloss of surfactant in the formation due to absorption on rock and theinteraction with reservoir fluids. Thus the amount of surfactant needed isprimarily determined by relevant formation properties, irrespective of theamount of residual oil present. The concentration of the polymer slug is
The Market/or Chemicals in the Oi/Industry
determined by the increase in viscosity dictated by the oil viscosity and bythe degree of retention in the formation.
The amount of additional oil producible is determined by the amount of oilleft behind by conventional production methods and by the expected recoveryefficiency of the surfactant or polymer flood.
213
In the following table the chemical requirements per barrel oil additionallyproduced used for the surfactant and polymer flood are presented. Thesefigures serve as bases for cost estimates and the estimated futurerequirements of polymers and surfactants.
Type Injection Fluid Chemical RequirementChemical Concentration
(ppm) (lbs/bbl)
Polymer flooding
Polymers 500 - 1,500 1.5 - 3.0
Surfactant flooding
Surfactant 40,000 - 60,000 12 - 24Polymers 500 - 1,500
Table 1: Chemical requirements per barrel additional oil produced.
As an example of unit costs for chemical flooding, with a world oil price ofUS $35/barrel, the total cost per barrel of oil produced by a surfactantflood could be US $15-35, while the cost of a barrel produced by a polymerflood could be US $15-25.
To put these cost figures in perspective, they are compared with those ofalternative energy sources in Table 2.
Type Production cost (US $)per barrel oil equivalent
Coal 3 - 15Conventional oil 1 - 15Liquid Gas 10 - 23Liquid from heavy oil/tar 15 - 25Liquids from shales 15 - 35Liquids from coal 30 -+40Biomass for fuel 30+Solar hot water 50
Table 2: Cost per barrel oil equivalent for alternative energy.
214 Chemicals in the Oil Industry
It is estimated that the total cost of chemical expenditure on EOR techniquespresently runs at about £150 million per year. The majority of thisexpenditure is on surfactants and polymers in an approximate ratioone-third/two-thirds.
On the long term the potential of chemical flooding cannot be neglected. Forsome 30% of the medium and light oil found so far, chemical flooding isconsidered to be the only possibility to increase the ultimate recovery,above what can be obtained by conventional proven processes (i.e. water orgas injection). Hence, it appears reasonable to assume that by the year2000 chemical flooding will claim its appropriate share of the total EORproduction.
As a result, future world-wide surfactant and polymer requirements forchemical flooding during the early next century could reach some 5 millionton per year of surfactants and 1 million ton per year polymers, representinga total chemical business for those two types of chemicals alone of some£10 billion per year (£ 1982).
5. Future Trends
From the performance point of view, there is an evident demand for novel andimproved polymers, which can be tailored to meet specific field conditions.So far no polymer has been obtained which possesses all the propertiesrequired (see Table 3). Biopolymers appear to be highly effectiveviscosifiers, with low salt and shear sensitivity and generally favourablefilterability. The present polymer types, however, are relativelytemperature sensitive, not very storage stable and rather costly. Hydrolysedpolyacrylamides have excellent water solubility and good storage stabilityand low temperature sensitivity. They are, however, shear and salt-sensitiveand some exhibit filterability defects. Their viscosifying power underreservoir conditions is probably restricted.
Service companies are presently looking into the possibility of using on-sitepolymerisation techniques with the objective to reduce transportation costsand allow complete tailoring of the polymer to the reservoir.
In the longer term, certain oil companies are looking at microbes to generatepolymers in situ.
v. CONCLUSIONS
The world market for chemicals in the oil industry is presently estimated ataround £3750 million. Market growth rate will depend to a major extent on theworld demand for hydrocarbons; however a value of at least 10% per annum maybe foreseen. Significant potential lies in the development of new polymericchemicals which are multi-functional, cost effective and stable at extremesof temperature and pressure. There will be an increasing trend towardsexpansion of chemical recovery methods for oil but economic techniques arenot expected to be fully developed until the next decade.
A final point of emphasis is that the world market for chemicals in oil andgas exploration and production is highly diversified, specialised andapplication invariably necessitates dedicated service back-up and operationalexpertise. As such, it is a highly competitive and well established businessand great care should be exercised if considering market participation,especially since the success or otherwise of participation may often dependon the now very unpredictable value of a barrel of oil at any particularmoment in time.
The Market for Chemicals in the Oil Industry
TABLE 3
COMPARATIVE PROPERTIES OF POLYMERSAND THE IR AQUEOUS SOLUTIONS EVALUATED FOR EOR
215
Properties
Mode of action
Concentrationrequired forsay a viscosity • 20 CPat 10 5- 1
23 °c in freshwater'-(rel. units)
Ease of dissolution
Fil terability(Le. viscosity reductionupon filteringover 0.45-1.2 lJmfilter)
Pseudo plasticity
Salt sensitivity (Le.viscosityreduction uponaddition ofNa2+, Ca2+,
Mg2+)
Temperaturesensi tivity(i.e. viscosityreduction uponincreasing temp.)
Mechanical(shear)stability
Storagestability ofpolymersolution
Polymer priceindication($/kg)
Polyacrylamide(anionic)
-Permeability agent-Viscosifier
100
Both hydration andgel dispers ionproceed rapidly.'ro avoid mechanicaldegradation lowshear mixing shouldbe applied.
Sharp viscositydecrease. Moleculestend to associateand are fi 1 teredoff. Shear degradation does also
high
high
low
low
Good. No viscosityreductions/gelformation after
o6 months at 23 C
2.50-400*
Xanthan gums
Viscosifier
110
High shear mixing required todisperse (disintegrate) gel.
Restricted viscosity reduction,provided dissolution containsno gel.
medium
restricted
medium
high
No viscosity reduction, but gelformation owingto biodegradationFiltering ofsolution prior tostorage, aidsstability
5.00-6.50
Hydroxyethylcellulose
Viscosifier
>250
Hydration takesa long time. Ge 1can be dispersedat low shear.
Distinct visositydecrease. Polymeris retained onfilter. probablybecause of highconcentrationsrequired to reachpractical viscocitylevels
low
low
high
high
Poor storage stability owing to severebiodegradation. Useof biocides (H2C-0)required
2.70-3.30
* Speciality products, developed for EOR.
216 Chemicals in the Oil Industry
VI. GENERAL BIBLIOGRAPHY
I. "Composition and Properties of Oil Well Drilling Fluids"G.R. Gray, H.C.H. Darley, W.F. RogersGulf publishing Company, Third Edition, Fifth Printing,September 1979
2. "Drilling and Drilling Fluids"G.V. Chilingarian, P. VorabutrEl sevier, I 981
3. "Cementing" SPE/AIME MonographD.K. Smith, 1976
4. "Hydraulic Fracturing" SPE/AINE MonographHowards, Fast 1970
5. "Acidizing Fundamentals" SPE/AIME MonographB. Williams, J.L. Gidley, R.S. Schechter, 1979
6. "~~ater Problems in Oil Production"L.C. Case, 2nd Edition, PPC Books, Tulsa Oklahoma, 1977
7. "Oilfield Water Systems"C.C. Patton, Campbell Petroleum Series, 1977
8. "Water Formed Scale Deposits"J.C. Cowan, D.J. Weintritt, Gulf Publishing Company, Houston,Texas 1976
9. "H2S Corrosion in Oil and Gas Production - A Compilation ofClassic Papers"R.N. Tuttle, R.D. Kane, NACE, Houston, Texas 1981
10. "Corrosion Inhibitors"C.C. Nathan, NACE, Houston, Texas 1974
11. "Corrosion Control Handbook"Energy Communications Inc. Dallas, Texas, 1975
12. "Introduction to Oil Recovery Techniques"Shell Technology Series, 1/1981
13. "Enhanced Oil Recovery by Thermal Methods"Shell Technology Series, 1/1982
14. "Enhanced Oil Recovery by Miscible and Chemical Methods"Shell Technology Series, 2/1982
IS. "State of the Art of Enhanced oil Recovery"H.J. de Haan, H.M.L. v. Breen, Second European Symposium on EnhancedOil Recovery, Paris, November 1982
The Market for Chemicals in the Oil Industry
16. "Scraping the Barrel, the Worldwide Potential for Enhanced OilRecovery"R. Dafter, 1980, Financial Times Business Information Ltd, London
17. "\Alinning More Oil, Increasing Importance for Enhanced Oil Recovery"R. Dafter, 1981, Financial Times Business Information Ltd, London
18. Oil and Gas Journal
19. World Oil
20. The Petroleum Engineer
21. Chemical Week
22. Chemical and Engineering News
23. Abstracts Oilfield Chemicals
24. UK Department of Energy Brown Book
25. Journal of the Society of Petroleum Engineers
217