Ebook Chemistry in the oil industry VII Part 2

(BQ) Part 2 book Chemistry in the oil industry VII has contents: The challenges facing chemical management, optimising oilfield oxygen scavengers, a chemical packer for annular isolation in horizontal wells; the development of advanced kinetic hydrate inhibitors,...and other contents.

USING ELECTROCHEMICAL PRE-TREATMENTS FOR THE PROTECTION OF METAL SURFACES FROM THE FORMATION AND GROWTH OF CALCIUM CARBONATE SCALE A P Morizot,' S Labille,2A Neville' and G M Graham2 'Corrosion and Surface Engineering Research Group, Department of Chemical and Mechanical Engineering 'Oil field Scale Research Group, Department of Petroleum Engineering, Heriot-Watt University, Edinburgh ABSTRACT This study examines the potential of adsorption of scale inhibitor and indeed other cations such as magnesium and calcium, promoted by electrochemical pre-treatment, to effectively protect metallic surfaces from the adhesion and growth of calcium carbonate scale Tests have been conducted which examine the surface of stainless steel rotating disk electrodes (RDE) under ambient conditions The involvement of divalent cations such as Mg2+in the inhibition of scale is clearly demonstrated Visualisation of the amount of scale deposition, with and without electrochemical pre-treatment, has been conducted using scanning electron microscopy (SEM) In summary, this paper describes the beneficial effects of using an electrochemical pretreatment to inhibit scale deposition on metal surfaces and assess the catiodinhibitor interactions and their effect on inhibitor efficiency INTRODUCTION The nucleation and growth of scale (i.e insoluble mineral salts) on surfaces is one of the main aspects of crystal formation which causes operational problems in industrial plant and facilities Formation of scale in the pores of rock can cause plugging of wells and deposition on production equipment (e.g pipework) can lead to increased turbulence in flow systems and can eventually block flow lines Notwithstanding this fact, the main effort in scale research has been to develop an understanding of scale formation (precipitation) in the bulk solution and several models have been developed to assess the scaling tendency of particular waters based on thermodynamic data [e.g 11 Information from these models is often used in well-management programmes to control scale formation and indicate inhibitor dosing rates The methodology commonly adopted for assessing the efficiency of inhibitor chemicals is based on NACE standard TM0197 [2] in which the scale-forming ion concentration is measured (by Inductively Coupled Plasma (ICP) for instance) when two brines are mixed and scaling occurs The effectiveness of inhibition is evaluated by comparing the ion concentration in presence and in absence of inhibitor after bulk precipitation has occurred This method has been used to rank the efficiency of inhibitors in a wide range of environments [e.g 31 However, there are 132 Chemistry in the Oil Industry VZZ several limitations of this method in relation to the inability to assess the effectiveness of inhibitor treatments in preventing deposition of scale on surfaces Hasson et al [4]also expressed their opinion that that although the large bank of work carried out on bulk precipitation is valuable there is a real need to understand the kinetics of scale formation at a solid surface and this requires alternative test procedures In recent work it has been shown that surface deposition can be monitored using an electrochemical method to assess the rate of oxygen reduction reaction at the electrode This has been used by the current authors to compare the efficiency of inhibitors in preventing precipitation in the bulk solution and deposition at metal surfaces [5,6] Other techniques which have been used and show promise for monitoring surface deposition include in-situ microscopy [ ] , the quartz crystal microbalance [8] and electrochemical impedance spectroscopy [9] In studies of surface deposition and scale inhibition it is important to consider the inhibitor action at the metal surface Many of the polymeric scale inhibitors have also been shown to reduce corrosion rates [lo] Their efficiency with regard to corrosion has often been attributed to their ability to adsorb on metal surfaces and their action is therefore one where active corrosion sites are blocked [ 13 In relation to scale control one of the likely mechanisms stated for control of growth is adsorption onto growth sites [ 121 In previous communications [13, 141 the formation of an inhibitor film on metal surfaces has been reported and it has been demonstrated that conditions at the surface (e.g cation concentration and species, inhibitor concentration, applied electrode potential) can all affect the level of film coverage In this paper the efficiency of several pre-treatment conditions, in which the Mg2+,Ca2+ and inhibitor combinations are varied, in reducing deposition of CaC03 on metal surfaces is assessed EXPERIMENTAL TECHNIQUES Stainless steel rotating disk electrodes (RDE), as shown schematically in Fig la, were used as the surface onto which deposition occurred In this study the two main experimental phases were: 1) pre-treatment of the RDE surface and ) scale deposition tests to assess the efficiency of the pre-treatment 2.1 Pre-treatment The RDE was rotated, in a solution of 5g/l NaCl containing inhibitor at pH=lO, at 600 rpm with a potential of -1V/SCE (Saturated Calomel Electrode) applied for minutes using the three-electrode cell as shown in Fig lb The electrode was then rinsed with distilled water prior to scale deposition tests The environmental conditions used in the pretreatment (inhibitor, Ca2+ and Mg2+ concentration) are given in Table The inhibitor used in this study was Polyphosphino Carboxylic Acid (PPCA), with mean molecular weight of 3,600 g/mol The molecular structure of PPCA is shown in Fig 2.2 Scale deposition Two synthetic brines were used in this study They were prepared in such a way that when mixed in a 50%:50% ratio the resulting solution reproduced the composition of a 100% formation water typical of the Banff field situated in Block 29/2a of the UK sector of the New Technology 133 (4 rn b f -, 15 mm 70 mm Figure (a) RDE sample and (b) electrode cell set up for pre-treatment of RDE surfaces Table Parameters for the pre-treatment of RDE samples prior to scaling tests Inhibitor PPCA OH Phosphino polycarboxylic acid - PPCA Figure Molecular structure of the PPCA inhibitor species used in the study Chemistry in the Oil Industry VII 134 Table Compositions of the brines used in this study Na' Ca2+ Mg2+ K+ Ba2' Sr2+ sod2- Concentration (ppm) I Brine - SW Brine I - FW 25,210 25,210 5,200 690 1,170 270 0 0 0 North Sea The brines were filtered (0.45 pm) prior to use, in order to remove impurities, which might provide some nucleation sites The brine compositions are given in Table The pH of brine (Brine containing C032-) was adjusted to 9, in order to accelerate the scaling procedure The electrodes were immersed in the brine mixture at room temperature using the experimental set up in Fig with a rotation of 600rpm The tests were two hour duration Rotating Electrode of brine and Figure Experimental set-up for scale deposition on RDE samples Following deposition tests using the RDE a thorough examination of the extent of scale formation on the surface was conducted using the SEM New Technology 135 RESULTS Without electrochemical pre-treatment extensive deposition occurred on the stainless steel electrode from the supersaturated formation water in the one hour immersion period as shown in Fig 4a The crystals were of a cubic form and from Fig 4b the size is typically 10-2Opm (maximum length dimension) In Figs 5-8 the SEM images corresponding to the four different pretreatment conditions are shown The (a) figure represents a lower magnification view from which the general scaling extent can be seen and (b) shows a higher magnification view to enable the crystal characteristics to be seen Some interesting observations can be made from these as reported in the next paragraphs Firstly it is clear that in comparison to the untreated reference sample there is a significant reduction in scale deposition when pre-treatment has been carried out in the presence of Mg2' ions The beneficial effect of pretreatment is greatest when both inhibitor and Mg2+ions are present (compare Figs and 8) Although visibly less scale is produced when Mg2+ions are present during the pretreatment there is no obvious change in the crystal size or morphology Where the pre-treatment was performed in a solution containing Ca2' ions and no inhibitor there was little visible reduction in the amount of scale deposited as can be seen comparing Figs 4a and 7a Addition of inhibitor during the pretreatment reduces the scale deposition compared with the reference sam le but the pretreatment is less effective than when carried out in the presence of M$ ions There is no change in the crystal morphology - both cases produce cubic crystals of similar size Figure Scale deposition of CaCOj from the 50:50 brine mix on a metal RDE sample without pre-treatment DISCUSSION From previous studies reported in the literature it has been confirmed that polymeric inhibitors can effectively adsorb on metal surfaces to form a film which is effective in reducing corrosion rates [lo] In previous work by the authors [13,14] the extent of film formation by PAA and PPCA inhibitors has been studied using an electrochemical technique and the film formation kinetics have been shown to be dependent on Ca and Mg ion content, inhibitor concentration, hydrodynamic regime and applied electrode potential 136 Chemistry in the Oil Industry VZI Figure Scale deposition with electrochemical pre-treatment in a solution containing 250ppm PPCA and 500ppm MgClz Figure Scale deposition with electrochemical pre-treatment in a solution containing 250ppm PPCA and 500ppm CaClz Figure Scale deposition with electrochemical pre-treatment in a solution containing no inhibitor and 5OOppm CaCl2 In the current study it has been shown that the film formed during electrochemical pretreatment can be effective in reducing the extent of CaCO3 deposition from a supersaturated solution An adsorbed film can be formed without electrochemical pretreatment and in a study by Mueller et al [15] the reduction of crystal (CaC03) formation rate on stainless steel when pretreated by immersion in a solution containing New Technology 137 polyaspartate was reported They also observed a reduction in average crystal size which was not the case in the present study Figure Scale deposition with electrochemical pre-treatment in a solution containing no inhibitor and 500ppm MgClz Figure Qualitative summary of inhibitive effects of pre-treatment in presence of inhibitor and absence and presence of Ca2' and Mg2+ions Figure is a schematic summary of the efficiency of each of the pretreatments applied in this study In the presence of inhibitor, addition of Ca2' and Mg2+ ions during pretreatment enabled better inhibition to be achieved This indicates that the Ca2' ions and more effectively Mg2+ions promote the ability of the inhibitor to bind with the surface and develop an efficient inhibitor film to retard deposition Two binding mechanisms are proposed The first involves an electrostatic cation bridge between the dissociated acrylate functional groups on the PPCA and adsorbed divalent cations Adsorption of divalent cations leads to a more positive surface charge through which the negatively charged dissociated acid units to bind [ 16, 171 Alternatively, in the presence of magnesium cations, a magnesium hydroxide film can form at the electrode surface This may lead to strong hydrogen bonding mechanisms between the carboxylate acid groups and hydroxyl groups in an analogous manner to that described for adsorption at the silica surface [ 181 The mechanism involved in the electrochemical adsorption of PPCA at the electrode surface is currently under examination Interestingly pretreatment in a solution containing Mg2+without inhibitor produced a significant inhibitive effect It has been widely reported in the literature that the presence of Mg in solution can affect the formation of CaC03 and in particular it can promote formation of aragonite rather than calcite [ 191 In the current study there is an obvious inhibition of calcite formation on pretreatment in the presence of Mg ions In cathodic protection it is known that the initial layer of calcareous deposit which forms is typically Mg-rich [ 141 and so in the absence of inhibitor it is feasible that a precursor Mg-rich layer 138 Chemistry in the Oil Zndustry VII has formed during the pretreatment This Mg-rich layer forms rapidly and has been detected by X P S [14] although the nature of it is still not fully clear However this layer has a significant inhibiting effect on CaCO3 deposition possibly through blocking initiation sites at the metal surface through formation of a thin Mg-containing layer CONCLUSIONS Electrochemical pre-treatment of metal RDE coupons can lead to effective surface inhibition of CaC03 The presence of Mg2+ions during the pretreatment enables a significant reduction in scale to be obtained and this is most effective when PPCA is present The pretreatment of surfaces to enhance film formation and hence reduce scale deposition may have practical implications for oilfield scale control References Yuan M D and Todd A.C., Prediction of sulphate scaling tendency in oilfield operations, SPE- Production Engineering Journal, Feb., 63-72 (199 1) NACE Standard TM 0197-97, Laboratory Screening Test to Determine the Ability of Scale Inhibitors to prevent the Precipitation of barium Suphate and/or Strontium Sulfate from Solution (for Oil and Gas Production Systems), Item no 21228, NACE International, 1997, Graham, G.M., Boak, L.S and Sorbie K.S.: "The Influence of Formation Calcium on the Effectiveness of Generically Different Barium Sulphate Oilfield Scale Inhibitors" SPE 37273 presented at the SPE Oilfield Chemistry Sym., held in Houston, 18-21 Feb 1997 Accepted for publication SPE Production & Facilities, in press Hasson D et al., Influence of the flow system on the inhibitory action of CaC03 scale prevention additives, Desalination, 108, 67-79 (1996) Neville A et al., Electrochemical assessment of calcium carbonate deposition using a rotating disk electrode (RDE), Journal of Applied Electrochemistry, 29 (4), 455-462 ( 1999) Morizot A P et al., Studies of the deposition of CaC03 on a stainless steel surface by a novel electrochemical technique, Journal of Crystal Growth, 1981199, 738-743 ( 1999) Davis R V et al., The use of modem methods in the development of calcium carbonate inhibitors for cooling water systems, Mineral Scale Formation and Inhibition, edited by Zahid Amjad, Plenum Press, New-York, 33-46 (1995) Noik C et al., Development of electrochemical quartz study microbalance to control carbonate scale deposit, CORROSION/99, paper NO1 14, NACE, Houston (1999) Gabrielli et al., Study of calcium carbonate scales by electrochemical impedance spectroscopy,Electrochimica Acta, 42(8), 1207-1218 (1997) 10 Fivizzani K P et al, Manganese stabilisation by polymers for cooling water systems, CORROSION/89, Paper No 433 (Houston, TX : NACE) 1989 11 Chen Y et al, EIS studies of a corrosion inhibitor behaviour under multiphase flow conditions, Corrosion Science, 42 (2000) pp979-990 12 Verraest D L et al., Carboxymethyl Inulin : A new inhibitor for calcium carbonate precipitation, JAOCS, Vol 73, No 1, 1996, pp55-62 New Technology 139 13 Morizot A P and Neville A., A study of inhibitor film formation using an electrochemical technique, CORROSION/2000, Paper No183, Orlando, March 2000 14 Morizot A.P., Electrochemically based technique study of mineral scale formation and inhibition, PhD thesis, Heriot-Watt University, November 1999 15 Mueller E et al, Peptide interactions with steel surfaces : inhibition of corrosion and calcium carbonate precipitation, Corrosion, Vol 49, No 10, 1993, pp829-835 16 Sorbie, K S et al, The effect of pH, calcium and temperature on the adsorption of inhibitor onto consolidated and crushed sandstone, , SPE 68th Annual Technical Conference, Houston, 1993, Paper No SPE 26605 17 El Attar, Y et al, Influence of calcium and phosphate ions on the adsorption of partially hydrolysed polyacrylamides on Ti02 and CaC03, Progr Colloid Polyrn Sci,82, 1990, 43-5 18 Iller, R K., The chemistry of silica, J Wiley and Sons, New York, Chapter 6, 1979 19 Jaouhari R et al, Influence of water composition and substrate on electrochemical scaling, Journal of Electrochemical Society, 147 (6), June 2000, pp2 151-2161 280 Chemistry in the Oil Industry V l l depressurization test was used for the live oil sample The tests were performed at varying inhibitor concentration RESULTS AND DISCUSSION 3.1 Stability Analysis 3.1.1 Analysis of Dead Oil Table 1, shows the SARA data for the crude oil The saturate content approximately equals that of aromatics The asphaltene content is only slightly lower than that of the resins - the peptizers This is the first indication of potential instability Table SARA Data for Crude Oil Pseudocomponent Weight Percent Saturates 39.3 Aromatics 38.1 Resins 13.6 Asphaltenes 9.0 Table shows the stability data for the crude oil It is apparent from the data that the oil is unstable The oil has a CII of 0.92 and an asphaltene-resin ratio of 0.7 This asphaltene-resin ratio is well above the threshold value of instability of 0.35 The Oliensis Spot Test Number is indicating a very unstable oil Figure 1, shows a plot of the normalised-intensityof the NIR laser as a function of the APDT number The APDT number is defined as the ratio of heptane titrated in ml, divided by the initial mass of oil (16.5 grams) A very unstable oil usually has an APDT value between and A stable oil generally has an APDT number of or higher at inflexion Between and 2, the oil is considered moderately unstable The crude oil under consideration has an APDT number of 1.25, which puts it under the moderately unstable category From the four stability tests conducted, it was concluded that the oil is unstable and could cause potential asphaltene deposition problems Table Stability Data for Crude Oil Stability Criteria Value Range of Instability Colloidal Instability Index 0.92 >0.9 Asphaltene-Resin Ratio 0.7 >0.35 APDT Number 1.25 2.5 B 1.60 C 1.45 No Inhibitor 1.25 3.3 Asphaltene Inhibitor Selection with Live Oil Inhibitor A, the most effective chemical selected from the heptane precipitation and APDT tests, was tested on the high pressure cell at varying concentrations to determine the rate at which the inhibitor will be injected into the wellbore Figure shows a typical trace for the live oil tests There was no drastic shift in the onset point The depressurization parameters were similar to those for the crude without inhibitor Table shows the deposition data The amount of asphaltene coming out of solution decreased as the inhibitor was added to the crude The quantity of asphaltenes depositing decreased dramatically with the addition of inhibitor A However, an increase in the concentration of inhibitor above 500 ppm did not yield substantial increases in deposit reduction Above 500 ppm, the deposition inhibition tapers off at around 62% The most cost-effective injection rate was determined as 500 ppm Based on the live oil data, inhibitor A was recommended to be injected, at 500 ppm, downhole into the well This treating rate was fbrther optimized in the field to 300 PPm Chemistry in the Oil Industry VII 284 Live Oil Deposition Data for Asphaltene Inhibitor A Table (sl Inhibitor (ppm) I TS (AD+AP) I Deposition Inhibited (%) 0.148 0.138 0.286 500 0.056 0.105 0.161 62.1 1000 0.055 0.099 0.154 62.7 2000 0.041 0.084 0.124 72.5 - 3SOE-08 Onset Pressure 4700psia 3.00E-08 2.503-08 i c 1.50E-08 - 1.00E-08 - Saturation Pressure 4000psia 5.00E-09 - 0.00Ei-00 2000 4000 6000 8000 10000 12000 14000 Pressure @sin) Figure Live Oil Deposition Tests for Crude treated with 500ppm of an Asphaltene Inhibitor A MONITORING OF INHIBITOR PERFORMANCE Inhibitor A was injected continuously at the rate of 300 ppm at a depth of 14,743’ The production stabilized at 1950 BOPD, 81 BWPD and 1572 MCFD for several months and then began to decrease steadily The well was shut in and a slickline tool with a gauge ring was sent down the well The tool went as far as the injection point without encountering any constrictions or obstructions Below the injection point a narrowing of the tubing diameter, believed to be a result of asphaltene deposition, was detected and the gauge ring was pulled out to avoid sticking it in the well Large amounts of asphaltenes were circulated out of the well during cleaning of the portion of the well below the injection point 285 Flow Assurance The absence of asphaltene deposits above the injection point was testimony to the fact that chemical A successfully inhibited the asphaltene deposition and that laboratory methods could be used to pick an asphaltene inhibitor that works successfully in the field CONCLUSION Laboratory methods consisting of both dead and live oil tests were used to pick an asphaltene inhibitor for a Latin American operator The inhibitor was optimized in the field to a lower injection rate and continuously injected into the wellbore The effectiveness of the inhibitor was determined through monitoring of production volumes, and the well diameter The asphaltene inhibitor successfully inhibited asphaltene deposit formation in the tubing at all points above the inhibitor injection point Below the injection point asphaltene deposits were encountered The results obtained from this work show the effectiveness of the three-prong strategy and the fact that an asphaltene inhibitor selected from laboratory tests can perform successfully in the field Nomenclature A D AP - APDT BOPD BWPD CII MCFD NIR PVT SDS Tblank Tsarnple TS - - - Mass of asphaltene deposited Mass of asphaltene precipitated Asphaltene precipitation detection test Barrels of oil per day Barrels of water per day Colloidal instability index Thousand cubic feet of gas per day Near infra-red Pressure-Volume-Temperature Solids detection system Transmittance of blank sample Transmittance of treated sample Total Mass of asphaltenes out of solution Acknowledgements Our sincere thanks go to the management of Baker Petrolite for permission to publish this paper and to Dr Klaus Weispfennig for helpful discussions References C.E Haskett and M Tartera, A Practical Solution to the Problem of Asphaltene Deposits - Hassi Messaoud Field, Algeria, J Pet Tech., 1965,4, 387-391 R Thawer, D.C.A Nicholl and G Dick, Asphaltene Deposition in Production Facilities, SPE Production Engineering, 1990,475-480 G.A Lambourn and M.Dunieu, Fouling in Crude Oil Preheat Trans, in Heat Exchangers Theory and Practice, Taborek, Hewitt and Afghan (eds.), Hemisphere Publishing Co N.Y , (1983) 286 Chemistry in the Oil Industry VII S Asomaning and A.P Watkinson, Petroleum Stability and Heteroatom Species Efects on Fouling of Heat Exchangers by Asphaltenes, Heat Transfer Eng., 2000, 21, 10-16 G.L Oliensis, Proc Assoc Asphalt Paving Technol., 1935, 6, 88 in Kirk-Othmer Encyclopaedia of Chemical Technology 3'd edn., 1992, 3, M Howe-Grant (ed.) Baker Petrolite Level Quality Manual, Revision 0, October 1999 Methods for Analysis and Testing, 40fhAnnual Edition, Institute of Petroleum, London, 1981, 1, 143 S Asomaning and C Gallagher, High Pressure Asphaltene Deposition Technique for Evaluating the Deposition Tendency of Live Oil and Evaluating Inhibitor Performance, Preprints, The Second International Conference On Petroleum and Gas Phase Behavior and Fouling, Copenhagen, Denmark, August 26-3 1,2000 W K Stephenson, Producing Asphaltenic Crude Oils: Problems and Solutions, Petroleum Engineer, 1990, 24-31 Subject Index Acartia Tonsa (Crustacean), 12,23,61 Acidising, 68 acetic acid, 73 enzyme based, 67 in situ generation of acid, 70 retarded, 69 Acid Stimulation, 239 Adsorbability (Koc), 15 Alkoxylation, 61 Alkylphenol Ethoxylates, 44,45,61 Alkylphenol, 45,51,56,59-62 Ammonium Bisulphite, 163, 174 Annular Gel Packer, 202 Annular Isolation, 202 Antibodies, 123 Antifoam, 45 ASMO, Asomaning, S., 277 Asphaltenes, 56,58, 144,254,255,277 flocculation, 255,257 Asphaltene inhibitors/dispersants, 255,257, 260,277 test methods, 256, 257, 260, 277, 278,279 field testing, 256 squeeze treatment, 262 case history, 285 Ballard, D.A., 189 Best Available Techniques (BAT), 4, 6, Best Environmental Practice (BEP), 4,6, Best Practicable Environmental Option (BPEO), 36,38 Bioaccumulation, 5,6, 8, 12, 15,24,27, 31, 33-35,44,48,50-52 Bioaccumulation Potential (Log Pow), 12, 15, 21,23, 31,44-48,50, 52,54, 61 Biocide, 29 Bioconcentration Factor (BCF), 6, 12,44, 46-48,50-54 Biodegradability, 3, 8, 12, Biodegradation, 12, 15, 18,23,24, 26,28,33, 35, 36,4345,48,49,61 Biological Diversity (Biodiversity), Biomagnification, 24,26,27,29,44,48, 50, 51, 54, Biotransformation, 48, Blue Mussels, 23, 52 BODIS, 23 Bourne, H.M., 123 Brady, M.E., 107 Cairns, R.J.R., 213 Capillary Electrophoresis, 52 CEFAS, 24,28, 14, 16, 33 Cellular, 49,50 Cementing, 21,25, 33 Chalmers, A., 163 Chan, K.S., 202 Charlton, K.A., 123 CHARM, 3, 8, 11, 13, 14, 18,21,22,24-26, 28,3 1-39,4143 CHARM User Guide, 25 Chemical Compatibility, 270 Chemical Hazard Assessment and Rsk Management, see CHARM Chemical Management, 123, 143 Chemical Packer, 202 Christmas Trees, 181 Collins, I.R., 223 Coalescence, 58,59 Competent Authority, 8-12, 34 Completion, 1, 25 Completions sand control, 107 gravel packing, 107, 11 Conductivity, 83 Contracting Parties, 3, 5,6, 13 Contracting Relationships, 147 Corophium Volutator, 12, 23,27,61 Corrosion, 30, 57 Corrosion Inhibitor(s), 20, 30, 238, 248 Corrosion Ratesrnonitoring, 174, 177 Crude Oil, , Cuttings, 8,33 Daniel, S., 107 Database, 24,26,27,30,60 Deepwater, 144 Degradable Bridging Polysaccharide, 194, 198 Demulsification, 56, 58, 61 Demulsifier, 30,56, 59,60,62 Denmark, 21,26,29,33 Department of Trade and Industry (DTI), 27, 28,60 Desulphated Seawater, 225 Diesel Oil, 288 Dilution Factors, 13 Discharge, 3-6,8-11, 13-16,2 1-23,25-28, 31-37,41,44-46,48,58-62 Dispersion, 46,49,56 Dissolved Oxygen Measurement, 170 Dithiocarbamate, 149 flocculation with, 157 properties, 156 structure, 156 synthesis, 155 Dixon, R., 180 Drilling, 10,21,23,25,33 Drilling Clean-up Treatments, 191 Drilling Fluid(s), 8, 27, 189 Drilling Mud, see also Muds electrically conductive, 83 oil based, 83 water based, 115 EEMS Database, 60 Electrical Treating, Electrochemistry, 131 rotating disc electrode, 132 Emmons, D., 223 Emulsifying Agent, 56,57 Emulsion(s), 56, 57, 150 Endocrine Disruption, 6,56,6 1,62 Environment, 3,4,6,7, 10, 18,23-25, 32, 37, 61,62 Environmental assessment, 4, 28,46 bioaccumulation, 228 biodegradation,228 CEFAS, 228 CHARM, 184 compartment, 41,42,47,49 concern, 11 damage, 37,56,61 data, 21,22,24,25,29-33,35 dithiocarbamates 158 effects, 23-25,40,41, 50 evaluation, 32,33,39 exposure, 41,49 goals, 4, hazard quotient, 228 HOCNF, 184,228 hydraulic production control fluidstesting, 185, 186 impact, 8, 10, 16,21,27,31, 39,41, 60,62 issues, 44 legislation, 59, 62 OCNS, 228 OPSPARCOM, 183,228 Chemistry in the Oil Industry VII PARCOM, 183 PEC/NEC ratio, 228 performance, 7, 15, 19,25,29, profile, 24,27, 56,61 properties, 25 protection, 37 regulation, 57, 58 risk, 32, 33,44,46 testing, 22, 26, 29 toxicity, 228 Enzymes, 67 Esterase, 70 Urease, 78 EOSCA, 21, 31, 32, 33,35, 36, 38,44,54, 56,61,62 Ethoxylates, 44,45,47,50, 56,59,61 EU, 4,9, 14, 15,60 European Oilfield Specialty Chemicals Association see EOSCA Expert Judgement, 11, 18,24,36,43 Fate, 45,4749, 51,61 Feasey, N.D., 223 Field Deployment, 270 Filter Cake Integrity, 195 Fish, 49-5 Fletcher, P., 107 Flocculants, 149, 157 Flocculation, 58,59 Flow Assurance, 223 Formaldehyde, 56,5942 Formation Damage, 68,74, 114 removal, 68, 115 France, 28 Franklin, R., 96 Fu, B., 264 Gas Demand (Growth), 143 Gas Hydrates, 144,240,264 Gel Packer Chemistry, 203 George, E., 107 Germany, 28 Gills, 49, 50 Glycols, 264 subsea production control fluids, 183 Graham, G.M., 131 Guidelines, 9,22,23,28,46 Harmonised Mandatory Control System, see HMCS Harmonised Offshore Chemical Notification Format, see HOCNF Harris, R.E., 67 Hart, P.R., 149 Subject Index Hazard Quotient (HQ), 13, 14,22, 25,29, 31, 35, 36,40,62 Hazardous Substance, 4-9, 11, 16,24,31 Health, 9, 10,26,32,35, 56,60,62 Heath, S.M., 123 Heavy Metals, 8, 11 Henriquez, L.R., 3, High Performance Liquid Chromatography (HPLC) Method, 23 HMCS, 3,4, 8,9, 13, 14, 16,21-23, 26-33, 3638,60,61 HOCNF, 3, 8, 9, 11, 12, 15,22,24,26-29, 31, 33, 34, 38,4346, Hoey, M., 96 Horizontal Wells, 202, 209 HPLC, 46,47,52 HS&E atmospheric emissions, 145 water discharges, 145 Hydrates, 144 Hydrate Inhibitors, 264 thermodynamic inhibitors, 264 lunetic hydrate inhibitors, 265,266, 269,270 anti-agglomerants, 265 autoclave and rocking cell tests, 265, 266 polymer chemistry, 267 Hydraulic Production Control Fluids, 180 functions, 182 glycols, 183 oils, 183 performance demands, 182 properties, 182 specifications, 182 Hydrophilicl Hydrophobic, 45,46,50,5 135 Imidazolines, 30,45,47 Intelligent Wells, 144 Invertebrates, 49, 50 Ireland, 28 ISO, 15, 16, 19,23 Jacques, P., 56 Jordan, M.M., 223 Koc, 15 KPD Centre, 27 Labille, S., 131 LAS, 48-5 LCso.6, 12, 13, 17, 23, 24,41, 43, 61 Levey, S.J.M., 83 Logging, 84 289 Log Pow,6, 18,43,48,50,52,61 Low Dosage Hydrate Inhibitors, 264 Lungwitz, B., 107, 202 MacDonald, H., 163 Mammalian, 6,40, 60 Management Decision, 9, 10, 15, 18,43,60 Martin, I., 56 Material Compatibility, 270 McKay, I.D., 67 McMahon, A.J., 163 McWilliams, P., 44 MEEKC (MicroEmulsion ElectroKinetic Chromatography), 52,54 Membrane, 49,50 Memorandum Of Understanding (MOU), 32, 35,38 MetabolicNetabolism, 45,46,48,49,5 1,52 Methanol, 264 Mobility Ratio, 14 Morizot, A.P., 131 Morris, L., 107 Muds, 23,25 Mytilus Edulis, 52 NEC-No Effect Concentration, 33,34,35,38 Netherlands, 3, 16,20,21,26,27, 29 Neville, A., 131 Newbigging, C., 56 North Sea, 3,26, 27,56,61,62 Norway, 1,26,27,29 Novatech, 27 Octanol-Water Partition, 45,47,48, 52 OECD, 18,23,33,46,47,52,53 Oestrogenic, 61,62 Offshore Chemical Regulations, 27 Offshore Chemicals, 3,4, 8-10, 14-16,21, 24,26,28,31, 33,34,45,60 Offshore Industry Committee (OIC), 4, 15, 16 Oil Production Increase, 13,218,219 Oils subsea production control fluids, 183 Oil Demand (Growth), 14 Organic Phase Drilling Fluids (OPF), Organisms, 5,22,48-5 Organohalogen Compounds, 11 Oschmann, H.-J., 254 Oslo Convention, OSPAR Oslo and Paris Commission, 4-8, 12-16, 21,23, 24,28-30, 33, 37,38, 4345 290 Convention, 3-5, 7, 11, 17 Decision 2000/2, 3, 8, 13, 16,21 Decision 2000/3,8,33 Recommendation 2001/1, Recommendation 2000/4, 10,24 Recommendation 2000/5, 9,22 Strategy, - 8, 18,24,43 Oxygen Depletion, Oxygen Scavengers, 163 ammonium bisulphite, 163 ammonium bisulphite, reaction with oxygen & chlorine, 174 corrosion rates/monitoring, 174, 177 dissolved oxygen measurement, 170 laboratory testing, 164, 168 offshore application, 169, 171 sodium bisulphite, 163 Paraffin, 255 Paraffin Waxes, 56 Paris Convention, , PARCOM-Paris Commission, 3,23, 32-34, 38 Payne, G., 21,44 PEC, 8,10,13-15,25,33-36,38 - 42,60,61 Performance Standard, Permeability, 13 Permission, 9-11, 18,24,34,43, 60 Persistenflersistence, 5, 6, 12,21, 27 Phage Display Technology, 124 PLONOR (Pose Little Or NO Risk), 9, 11, 16, 18, 20,23,24,43 PNEC, 8,10,13-15,25,35,36,38,4042, 60,61 Pollution, 3-5,7,27, 32 Polymers/Polymeric, 12, 15,24,29, 30 configuration, 153 water clarification, 151, 152 Porter, A.J., 123 Pre-Screening, 9, 10, 13-16, 18,21,22,24, 27, 32, 34,37, 39,43,60,61 Precautionary Principle, 6, 18, 37,43 Predicted Environmental Concentration, see PEC Predicted No Effect Concentration, see PNEC Premachandran, R., 96 Preparation or Mixture, 8-15, 18,23,25,2729, 31,34-36,43,46,50,60 Production Chemical, 10,25,46,47 Protocol, 3, 12, 14,23,29 QSAR (Quantitative Structure-Activity Relationship), 44,47, 53, 54 Chemistry in the Oil Industry VII Quaternary Amines/Ammonium Compounds, 30,45 Ranking, 9, 13-16, 18,20,24,25,29,30, 34, 43 Recombinant Yeast, 61, 62 Reference Platform, 13 Refusal of Permission, 10, 18,43,60 Reservoir Drilling Fluids, 189 Resin(s), 56, 59-62,255 Reversible Invert Emulsion Drilling Fluid, 192 Rheology dynamic, 99 viscoelasticity, 96, 108 Ring Tests, Risk Analysis, 32, 33, 39,40 Risk Assessment, 6,25,26,28,31, 35,37, 40,44-46,49 Risk Quotient (RQ), 25,26 Rolovic, R., 202 Rowntree, R., 180 Safety, 9, 10,26,35, 56,62 Sandstone Reservoirs, 13 Sawdon, C.A., 189 Scale, 131, 144,223 calcium carbonate, 223 barium sulphate, 224 case history, 244 composition and relative solubility, 224 management, 229,249 milling, 233 monitoring, 239,249 prediction, 226 scaling index, 226,230 Scale Dissolvers, 238 Scale Inhibitor, 25,29, 125,225 deposition, 135 detection, 123 efficiency measurement, 131 emulsified, 238 enzyme precipitated, 76 minimum inhibitor concentration (MIC), 23 oil soluble, 238 PPCA, 132 solid inhibitors, 234 squeeze treatments, 230,247 Scale Protection, 131 Scophthalamus Maximus (Fish), 12,23 Seawater, 3, 11 Seawater Composition, 167 Subject Index 29 Sediment, 4042,46,48,49,57 Sediment Reworker, 12,23 Semi Permeable Membrane Devices (SPMD), 52-54 SFT, State Pollution Control Authority, 27 Sidetracks, 233 Sjuraether, K., 223 Skeletonema Costatum (Algae), 12,23,61 SMART (Specific, Measurable, Achievable, Realistic and Time Limited), , 17 Sodium Bisulphite, 163 Sodium Lauryl Sulphate (SLS), 50 Spain, 28 Standard InstallationsPlatforms, 25, 29 State Supervision of Mines, 3, 27 Still, I., 31 Strachan, G., 123 Subsea, 144 hydraulic production control fluids, 180 functions, 182 performance demands, 182 properties, 182 specifications, 182 Substance, 4-16,22-27, 31, 33-36, 39,43, 44,46,47,52,60 Substitution, 6, 8-10, 16, 18,20, 24, 34,43, 60 Supply Chain Management, 145 Surface Active, 44-48, 52 Surfactant(s), 15,25,44-53,61,96, 108, 150, 152 Amphoteric, 44,45,48 Anionic, 44,45,47-50 Cationic, 44,45,47-50 Nonionic, 44,45,48,50, 51 Surrogate, 44,47,51-53 Synthetic Fluids, 23, 33 Tehrani, M.A., 83 Thatcher, M., 21 Toxic/ Toxicity, 3, 5,6, 8,9, 11-13, 15, 18, 21,23,26,27-30,33, 35, 36,40,41, 43,62 Taint, 9, Taxonomic, 49,6 Yen, A., 277 UK, 21,26-29,32,37,60,62 UKOOA, 228 Uncertainty Analysis, 25 Wang, F., 202 Ward, D., 202 Wardell, T., 56 Waste Management, 7, 8, Waste Stream, 41 Water chemical treatment of injection water, 178 clarification, 149, 151 oilfield, 57 on-line analysis, 145 produced, 8,46,57,62 separation, 149 shut off, 76 surfactants, 150, 152 Wax, 144 Waxes, 56,58 Webster, S., 143 Well borehole imaging, 84 stimulation, 68 Well Operations, Wells (Oil), 57 West, S., 143 Wet Wells, 213 Workover, 25 Xmas Trees, 181 ... Chemistry in the Oil Industry VII 134 Table Compositions of the brines used in this study Na' Ca2+ Mg2+ K+ Ba2' Sr2+ sod2- Concentration (ppm) I Brine - SW Brine I - FW 25 ,21 0 25 ,21 0 5 ,20 0 690 1,170 27 0... the use of these compounds 150 Chemistry in the Oil Industry VII 1 .2 Physical Chemistry of Water Clarification 1 .2. I Types of Emulsion Petroleum emulsions can be either water -in- oil or oil -in- water... whilst still accessing new technology? TECHNOLOGY CHALLENGES Some of the key technological challenges facing the oil industry are: 144 Chemistry in the Oil Industry VII Deep water In the 1980s BP's