WATER TREATMENT HANDBOOK.pdf

Water Treatment Handbook i

Contents

CHAPTER 1: INTRODUCTION ............................ 1-1BACKGROUND ................................................................... 1-3

Existing Systems Designed for Old Waterfloods......... 1-3A New System To Be Installed for a New Waterflood

or EOR Project ......................................................... 1-4OILFIELD WATER REQUIRING TREATMENT ................... 1-4

Water Sources ................................................................. 1-4Characteristics of Waters That Affect Their

Handling and Treatment .......................................... 1-5Produced Waters: ........................................................ 1-5Source Well Waters: .................................................... 1-6Open Waters: ............................................................... 1-6

WATER TREATMENT OBJECTIVES .................................. 1-7POSSIBLE TREATMENTS REQUIRED TO ACHIEVE

OBJECTIVES ................................................................ 1-8Treatment Objective Injection ................................... 1-9

Filtration ....................................................................... 1-9Removal of Free Oil from Water ............................... 1-10Effective Corrosion, Scale, and

Biological Control ............................................... 1-11Separate Treatment of Waters .................................. 1-11EOR Treatment Considerations in Addition to

Those Listed Above ........................................... 1-12Treatment Objective Surface Disposal ................... 1-12Additional Water Treatment Objectives ...................... 1-13

Corrosion, Scale, and Biological Control ................ 1-13Recovery of Free Oil in Water and Lost Revenue ... 1-14Special Treatment for EOR Requirements .............. 1-14Nonroutine Treatments of Special

Oilfield Waters ..................................................... 1-15OILFIELD TREATMENT METHODS AND EQUIPMENT .. 1-15GLOSSARY ....................................................................... 1-19

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CHAPTER 2: ANALYTICAL ANDTEST METHODS .............................................. 2-1

WATER ANALYSIS.............................................................. 2-3Reasons for Water Analysis ........................................... 2-3Constituents Determined and Properties Measured ... 2-4Significance of Components or Properties .................. 2-5

Cations ......................................................................... 2-5Sodium, Na+ .............................................................. 2-5Potassium, K+ ........................................................... 2-5Calcium, Ca2+ ........................................................... 2-5Magnesium, Mg2+..................................................... 2-7Barium, Ba2+............................................................. 2-7Strontium, Sr2+ ......................................................... 2-7Iron, Fe ...................................................................... 2-7Hardness ................................................................... 2-8

Anions .......................................................................... 2-8Chloride, Cl- .............................................................. 2-8Salinity, Chlorinity, and Chlorisity ........................... 2-9Salinity ....................................................................... 2-9Chlorinity ................................................................... 2-9Chlorisity ................................................................. 2-10Organic Acids ...................................................... 2-10Alkalinity.................................................................. 2-11

Dissolved Gases ........................................................ 2-11Oxygen, O2 .............................................................. 2-11Carbon Dioxide, CO2 .............................................. 2-12Hydrogen Sulfide, H2S ........................................... 2-12

Neutral Components ................................................. 2-12Silica ........................................................................ 2-12Bacterial Content .................................................... 2-12Oil-in-Water Content ............................................... 2-13Total Residue .......................................................... 2-13Suspended Solids................................................... 2-13Total Dissolved Solids ............................................ 2-14

Properties ................................................................... 2-15pH............................................................................. 2-15Temperature ............................................................ 2-15Turbidity .................................................................. 2-15Color ........................................................................ 2-16Density .................................................................... 2-16Conductivity ............................................................ 2-16

Sampling ........................................................................ 2-16Sample and System Identification ........................... 2-17Sampling Procedures ................................................ 2-17Field Measurements .................................................. 2-19Preserved Samples.................................................... 2-20Unpreserved Sample ................................................. 2-21Oil-in-Water Content .................................................. 2-21

Analytical Methods ....................................................... 2-22Chemical Properties .................................................. 2-22

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Physical Properties ................................................... 2-29Standard Analytical Methods ................................... 2-29

Analytical Report .......................................................... 2-30Sample Identification ................................................ 2-31Methods of Presentation of Components ............... 2-31Units of Measurement ............................................... 2-34

Concentration Units Based UponPhysical Properties .......................................... 2-37

Concentration Units Based OnChemical Properties......................................... 2-38

Units Used for Properties ...................................... 2-41Hypothetical Salt Combinations .............................. 2-45Solubility Calculations .............................................. 2-46Composition Diagrams ............................................. 2-47

Quality Control .............................................................. 2-47Anion/Cation Balance ............................................... 2-47Calculated vs. Measured TDS................................... 2-48Calculated vs. Measured Specific Gravity ............... 2-49Methods Using Electrolytic Conductivity ................ 2-50Regions of pH and Carbonate Species.................... 2-53Solubility Calculations .............................................. 2-54Replicates, Standards, and Spiked Samples .......... 2-54

OIL-IN-WATER ANALYSIS................................................ 2-54Free Oil vs. Dissolved Oil ............................................. 2-55

Dissolved Oil .............................................................. 2-55Free Oil ....................................................................... 2-57

Sampling ........................................................................ 2-58Analytical Procedures .................................................. 2-59

EPA Method 413.1. Oil and Grease. Total,Recoverable (Gravimetric, Separator FunnelExtraction) ........................................................... 2-60

EPA Method 413.2. Oil and Grease. TotalRecoverable (Spectrophotometric, Infrared) .... 2-60

EPA Method 418.1 Petroleum Hydrocarbons. TotalRecoverable (Spectrophotometric, Infrared) 2-61

API Recommended Practice for Analysis ofOilfield Waters, API RP 45 .................................. 2-62

Quality Control .............................................................. 2-62SUSPENDED SOLIDS ...................................................... 2-64

Sampling and Analytical Procedures .......................... 2-64National Association of Corrosion Engineers

Standard Test Method TM 0173-84 .................... 2-65X-Ray Diffraction Analysis ........................................ 2-66X-Ray Fluorescence Analysis ................................... 2-66Scanning Electron Microscopy ................................ 2-67Other Procedures ...................................................... 2-67

Quality Control .............................................................. 2-67REFERENCES................................................................... 2-69GLOSSARY ....................................................................... 2-71

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CHAPTER 3: OIL/WATER SEPARATION ............ 3-1PREFACE ............................................................................ 3-3WATER QUALITY REQUIREMENTS .................................. 3-3

Injection Requirements .................................................. 3-3Disposal Requirements .................................................. 3-5Discharge Requirements................................................ 3-6EOR Requirements ......................................................... 3-6

OILY WATER TREATING EQUIPMENT .............................. 3-8General ............................................................................ 3-8

DEHYDRATION SEPARATORS ........................................ 3-10SETTLING SKIM TANKS .................................................. 3-11COALESCERS .................................................................. 3-12

Loose-Media Coalescers .............................................. 3-12Fixed-Media Coalescers ............................................... 3-13

PLATE PACKS (INCLUDING SP-PACK ANDVERTICAL TUBE COALESCER) ............................... 3-15

FLOTATION ....................................................................... 3-16Dissolved Gas Flotation ............................................... 3-17Induced or Dispersed Gas Flotation ........................... 3-18

Mechanical IGF Units ................................................ 3-19IGF Selection ................................................................. 3-20Eductor IGF Units ......................................................... 3-20

Dissolved Gas Flotation Units vs. IGFs .................. 3-21Factors Influencing Flotation Cell Performance ..... 3-21

Gas Concentration ................................................. 3-22Salinity of Produced Water .................................... 3-22Inlet Oil Concentration ........................................... 3-23Temperature ............................................................ 3-23Flotation Aids and Surface Chemistry .................. 3-24

HYDROCYCLONES .......................................................... 3-24Design and Principle of Operation .............................. 3-25

Static Hydrocyclones ................................................ 3-25Dynamic Hydrocyclones ........................................... 3-26

Factors Influencing Performance .......................... 3-26Typical Performance ..................................................... 3-28

Static Hydrocyclones ................................................ 3-28Dynamic Hydrocyclones ........................................... 3-29

Applications to Date ..................................................... 3-29Hydrocyclone Selection ............................................... 3-30

FILTERS ............................................................................ 3-31Downflow Sand/Multimedia Filters ............................. 3-31Nutshell Filters .............................................................. 3-31

THE INTEGRATED TREATMENT SYSTEMS APPROACHTO COST-EFFECTIVE WATER TREATMENT ........... 3-32

PROCESS/EQUIPMENT SELECTION .............................. 3-35MONITORING AND MEASUREMENT .............................. 3-37

General .......................................................................... 3-37On-Line Methods .......................................................... 3-37

Infrared Light Scattering ........................................... 3-37Infrared Light Absorption ......................................... 3-38

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Direct Absorption ................................................... 3-38Solvent Extraction/Infrared Absorption ................... 3-39Ultraviolet Absorption ............................................... 3-39

Laboratory Methods ..................................................... 3-40REFERENCES................................................................... 3-41GLOSSARY ....................................................................... 3-43APPENDIX ......................................................................... 3-45

CHAPTER 4: FILTRATION ................................... 4-1CHAPTER 5: SCALING AND

WATER FORMED SOLIDS .............................. 5-1INTRODUCTION ................................................................. 5-3SCALES AND THEIR PREDICTION ................................... 5-3

Common Scales .............................................................. 5-4Calcium Carbonate ...................................................... 5-4Calcium Sulfate............................................................ 5-4Barium Sulfate ............................................................. 5-7Strontium Sulfate......................................................... 5-8Iron Compounds .......................................................... 5-8

Predicting Scale Formation ........................................... 5-9Solubility Calculations ................................................ 5-9Saturation Index .......................................................... 5-9Calcium Carbonate Scaling Calculation .................. 5-10Calculations of Sulfate Scaling Tendencies ............ 5-11Computer Programs for Scaling Tendency

Calculations ......................................................... 5-11SCALE PREVENTION....................................................... 5-12

Avoid Mixing Incompatible Waters .............................. 5-12Adjusting Brine Chemistry .......................................... 5-13

Water Dilution ............................................................ 5-13pH Control .................................................................. 5-13Removal of Scale-Forming Gases............................ 5-13Removal of Scale-Forming Ions ............................... 5-13Addition of Chelators ................................................ 5-14

Environmental Controls ............................................... 5-14SCALE INHIBITORS ......................................................... 5-14

Principle of Use............................................................. 5-14Types of Scale Inhibitors.............................................. 5-15Selection of Scale Inhibitors for Further Evaluation . 5-17Scale Inhibitor Evaluation Laboratory Performance

Tests ........................................................................ 5-18Scale Inhibitor Testing Field Performance

Monitoring ............................................................... 5-19Application of Scale Inhibitors .................................... 5-20

Batch Treatments ...................................................... 5-20Continuous Recirculation ......................................... 5-21Scale Inhibitor Squeeze Product Selection ........ 5-22Squeeze Treatment Design ....................................... 5-24

SCALE REMOVAL ............................................................ 5-28Scale Identification ....................................................... 5-28

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Chemical Removal ........................................................ 5-29General Comments .................................................... 5-29Calcium Carbonate .................................................... 5-30Calcium Sulfate.......................................................... 5-31Barium Sulfate ........................................................... 5-32Iron Compounds ........................................................ 5-33

Mechanical Removal..................................................... 5-34Scale Removal From Surface Lines ......................... 5-34Downhole Cleanout ................................................... 5-34

REFERENCES................................................................... 5-37GLOSSARY ....................................................................... 5-43APPENDIX ......................................................................... 5-47

CHAPTER 6: CORROSION EFFECTS ................ 6-1INTRODUCTION ................................................................. 6-3CORROSION AFFECTS WATER QUALITY ....................... 6-3GENERAL CORROSION .................................................... 6-4LOCALIZED CORROSION ................................................. 6-5

Pitting............................................................................... 6-5Crevice Corrosion ........................................................... 6-6Galvanic Corrosion ......................................................... 6-6

CORROSION RATE ............................................................ 6-7Effect of Dissolved Gases .............................................. 6-7Effect of Dissolved Solids .............................................. 6-9Effect of Oil and Grease ................................................. 6-9Effect of Flow and Suspended Solids ......................... 6-10Effect of Water Treating Chemicals ............................. 6-10Effect of pH.................................................................... 6-11Effect of Temperature ................................................... 6-11Effect of Deposits ......................................................... 6-12

MONITORING .................................................................... 6-12Inspection ...................................................................... 6-13Coupons and Spools .................................................... 6-13Iron Counts.................................................................... 6-14Electrical Resistance .................................................... 6-14Linear Polarization........................................................ 6-15Galvanic Probes ............................................................ 6-15Hydrogen Monitors ....................................................... 6-16Ultrasonic Surveys ....................................................... 6-16

CORROSION PREVENTION............................................. 6-16Inhibitors ....................................................................... 6-18Alloys ............................................................................. 6-18Plastics and FRPs ........................................................ 6-21Cathodic Protection ...................................................... 6-21Removal of Dissolved Gases ....................................... 6-22Coatings ........................................................................ 6-24Linings ........................................................................... 6-24Pigging and Scraping ................................................... 6-25

GENERAL REFERENCES ................................................ 6-27NACE Publications ....................................................... 6-27Books ............................................................................. 6-27

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APPENDIX AINDEX TO CHEVRONCORROSION PROTECTION MANUAL ..................... 6-29

APPENDIX BINDEX TO CHEVRON COATINGS MANUAL............. 6-31

APPENDIX CINDEX TO CHEVRON PIPELINE MANUAL ............... 6-33

CHAPTER 7: MICROBIOLOGICAL PROBLEMSIN PRODUCTION OPERATIONS ..................... 7-1

INTRODUCTION ................................................................. 7-3MICROBIOLOGICAL ACTIVITY CAUSES PROBLEMS .... 7-3

Plugging and Fouling ..................................................... 7-4Microbial Reservoir Souring .......................................... 7-4Microbiologically Influenced Corrosion ....................... 7-5Environmental Concerns ............................................... 7-6Chemical Consumption .................................................. 7-7Water Chemistry ............................................................. 7-7Formation Damage ......................................................... 7-8

MICROBIOLOGICAL ENERGETICS .................................. 7-8MICROORGANISMS INVOLVED IN MICROBIAL

PROBLEMS ................................................................ 7-11Sulfate-Reducing Bacteria SRB .............................. 7-11Slime-Forming Bacteria ............................................... 7-16Acid Producing Bacteria APB ................................. 7-17Iron Bacteria .................................................................. 7-17Sulfur-Oxidizing Bacteria ............................................. 7-18Planktonic vs. Sessile Bacteria ................................... 7-18

Planktonic Bacteria ................................................... 7-18Sessile Bacteria ......................................................... 7-19

Bacteria Classified According to Habitat.................... 7-19DETECTION OF BACTERIA ............................................. 7-20

Sampling Methods for Bacteria ................................... 7-21Planktonic Bacteria ................................................... 7-22Sessile Bacteria and Biofilms................................... 7-22

Test Procedures for Bacterial Types ........................... 7-23Culturing Methods ..................................................... 7-23

Broth Bottles ........................................................... 7-25Solid Culture Media ................................................ 7-26Pour-Plate Method .................................................. 7-27Spread-Plate Method .............................................. 7-27Melt Agar Tube Method .......................................... 7-27

Direct Methods ........................................................... 7-28ATP Assay ............................................................... 7-28Epifluorescence/Cell Surface Antibody Methods. 7-29APS Reductase Antibodies Method ...................... 7-29Phospholipid Signature ......................................... 7-30Radio-Respirometry ............................................... 7-30Chemical Analysis .................................................. 7-31Hydrogenase Enzyme Detection ........................... 7-32

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Sulfur Isotope Differentiation Method ..................... 7-32Comparison of Field Kits for SRB ............................ 7-33

CONTROL OF BACTERIAL ACTIVITY ............................ 7-34Bacterial Control by Mechanical Design .................... 7-35Bacterial Control by Physical Cleaning ...................... 7-35Bacterial Control by Chemical Cleaning..................... 7-36Bacterial Control by Ultraviolet Radiation .................. 7-38Bacterial Control by Biocides ...................................... 7-38

Types of Biocides ...................................................... 7-38Biocide Selection .......................................................... 7-41

Time-Kill Procedure for Biocide Effectiveness .... 7-44Estimation of Biocide Batch Frequency ............... 7-46Factors Affecting Biocide Effectiveness ............... 7-47

Sessile Samples for Biocide Testing ....................... 7-49Laboratory Recirculation Loops............................ 7-50Field Side-Stream Test Loops ................................ 7-50Field In-Line Probes ............................................... 7-52

Biocide Treatment Procedures ................................. 7-53Biocide Toxicity ......................................................... 7-53

MONITORING METHODS FOR MICROBIAL ACTIVITY .. 7-55REFERENCES................................................................... 7-57GLOSSARY ....................................................................... 7-59

CHAPTER 8: CHEMICAL INJECTION................. 8-1INTRODUCTION ................................................................. 8-3NATURAL COMPONENTS OF OILFIELD WATERS.......... 8-4TYPES AND FUNCTIONS OF OILFIELD CHEMICALS ..... 8-5

General ............................................................................ 8-5Scale Inhibitors ............................................................... 8-6Corrosion Inhibitors ....................................................... 8-6Biocides ........................................................................... 8-7Emulsion Breakers ......................................................... 8-7Reverse Breakers............................................................ 8-8Coagulants and Flocculants .......................................... 8-8Antifoamers ..................................................................... 8-9Surfactants ...................................................................... 8-9Paraffin Treating ............................................................. 8-9Oxygen Scavengers ...................................................... 8-10Sulfide Scavengers ....................................................... 8-10Hydrate Inhibitors ......................................................... 8-11Gas Dehydration Chemicals ........................................ 8-11Well Stimulation Chemicals ......................................... 8-11

Acids ........................................................................... 8-11Fracturing Fluids ....................................................... 8-12Additives .................................................................... 8-12

Workover Fluids ............................................................ 8-13Weighted Brines ........................................................ 8-13Corrosion Inhibitors (see list above) ....................... 8-13Biocides (see list above) ........................................... 8-13Oxygen Scavengers (see list above) ....................... 8-13Viscosifiers ................................................................ 8-13

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IONIC CHARACTER OF OILFIELD INJECTEDCHEMICALS ............................................................... 8-14

CHEMICAL INTERACTIONS ............................................ 8-14Cation/Anion Interactions Resulting in

Scale Formation ..................................................... 8-15Surfactant Interactions ................................................. 8-18

Demulsifier/Reverse Demulsifier Interactions ........ 8-19Description of Demulsifier Chemistry ................... 8-19Treatment Problems and Interactions ................... 8-20

Demulsifiers ......................................................... 8-20Reverse Demulsifiers .......................................... 8-21

Other Surfactant Interactions ................................... 8-23Biocide Reactions ......................................................... 8-24Strong Acid Reactions ................................................. 8-24

SOME DOS AND DONTS WITH RESPECT TOCHEMICAL INTERACTIONS ...................................... 8-25

GLOSSARY ....................................................................... 8-27

CHAPTER 9: WATER/FORMATIONROCK INTERACTIONS ................................... 9-1

INTRODUCTION ................................................................. 9-3Mechanisms of Formation Permeability Damage ........ 9-3

Formation Clay Deflocculation and Migration .......... 9-3Formation Clay Structural Expansion ....................... 9-4

Mica Alteration ................................................................ 9-5Differential Dissolution .................................................. 9-6Dissolution and Reprecipitation .................................... 9-7Precipitation .................................................................... 9-8Identifying Potential Formation Permeability

Damage ..................................................................... 9-8Water and Rock Analyses .............................................. 9-9Proper Salts and Concentrations ................................ 9-10

PREVENTING FORMATION DAMAGE IN THE FIELD .... 9-13REFERENCES................................................................... 9-15GLOSSARY ....................................................................... 9-17APPENDIX ......................................................................... 9-19

CHAPTER 10: HANDLING SEPARATEDWASTES ........................................................ 10-1

INTRODUCTION ............................................................... 10-3ORIGIN OF WASTE STREAMS ........................................ 10-3FACTORS IN HANDLING SEPARATED WASTE

STREAMS ................................................................... 10-9Minimizing Arbitrary Recycling ................................... 10-9Incorporating Point-Source Treating Into the

System Design...................................................... 10-10Concentration of Separated Wastes ......................... 10-11

DISPOSAL OF THE SEPARATED WASTES .................. 10-14Waste Disposal and the Environment ....................... 10-15

Environmental Regulations and Regulators ......... 10-16Federal ...................................................................... 10-16

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State (California) ...................................................... 10-17Local ......................................................................... 10-17Federal ...................................................................... 10-17State (California) ...................................................... 10-17Classification and Relative Disposal of Wastes ... 10-18

REFERENCE ................................................................... 10-22GLOSSARY ..................................................................... 10-23APPENDIX ....................................................................... 10-25

INDEX ...................................................................................... I-1

Chapter 1: Introduction 1-1

C H A P T E R

1

Introduction

1-2 Water Treatment Handbook


Water treating presents

special challenges

because oilfield waters

change continually in

volume and chemical and

physical properties.

BACKGROUNDHandling and treating of water in an oil field are impor-tant factors for successful, economical operation of thefield. These factors become especially important as fieldsmature and the produced water cuts increase to levelswhere the volume of water treated, reinjected, or dis-posed of can be 10 to 50 times the volume of oil pro-duced. Even in new, low-water-cut fields, at least asmuch water as oil produced may have to be treated andinjected to maintain reservoir pressure and to controlvoidage. Enhanced oil recovery (EOR) projects requiregood-quality water for injection for three reasons:

1. To raise and maintain reservoir pressure.

2. To act as the carrier for the chemicals designed to freeoil from pore spaces and/or improve the sweepefficiency.

3. To be converted to steam and transfer heat needed tolower viscosity and mobilize heavy crudes.

Water treating systems present some special challenges.The greatest challenge relates to the fact that oilfieldwaters change continually in terms of volume and chemi-cal and physical properties. Also, because of its reactivity(corrosivity, scaling tendency, microbiological activity,etc.), water causes the treating system itself to changewith time.

The following discussion illustrates some problemsinvolving water treating systems.

Existing Systems Designed for OldWaterfloodsThe system probably was designed and installed longbefore the current operating staff became involved.These persons are not familiar with the details and objec-tives of the system. The water has changed and thesystem has gone through multiple modifications. Thesystem may not be able to handle the present waterneeds. A decision on making further modifications ordesigning a new system must be made. Whether thesystem is modified or rebuilt, it will probably have tohandle increasing volumes of water. Should the new


Three categories of water

sources are from oil or gas

production, source wells,

and open sources.

design be similar to the existing system? Or should itincorporate new technology? The problems with thepresent system must be diagnosed so that they are notincorporated into the new design or modifications. Thepossibility of a future EOR application may need to beconsidered. Input from geologists and from design andconstruction, gas and chemical, reservoir, and productionengineers is needed for many of these decisions.

A New System To Be Installed for a NewWaterflood or EOR Project A decision must be made about using a design that theoperating people are familiar with or trying new technol-ogy. Again, input from geologists and from design andconstruction, gas and chemical, reservoir, and productionengineers is needed to prevent repeating past errors; toconsider capital, operating, and other costs; to anticipatefuture requirements; to incorporate reservoir factors; andto consider environmental concerns.

OILFIELD WATER REQUIRING TREATMENTWater SourcesThe waters handled in producing operations vary fromfield to field and during the life of any particular field.Water sources can be grouped into three general cate-gories: oil or gas production, source wells, and opensources. Depending on the life of a waterflood, producedwater is made up of a combination of natural formationwaters and injected water, which itself may be a mixtureof produced water, source well water, and waters fromseveral open sources. Consequently, the proportions ofthese waters change during the life of the field. Likewise,salinity and other properties of the produced waterchange. Water from source wells is generally producedfrom aquifer formations separate from the reservoirbeing flooded.

Open water sources include oceans and bays, rivers,canals, and lakes, as well as rain runoff collected ononshore fields and deck runoff from offshore platforms.Other sources of open water are waste waters generatedby oilfield operations like filter backwash, induced gas


Potential problems from

handling produced waters

include their corrosivity,

variable composition,

tendency to carry or form

solids, and oil content.

flotation skimmings, pit water, and tank bottoms. Thesewaters, although only a small fraction of the total waterused in a field operation, are particularly detrimental towater handling and treatment because of their chemistry.Water chemistry is complicated by any chemicals added,oxygen dissolution, and by-products of scale, corrosion,etc. They also usually contain high concentrations ofsuspended solids, oil, and/or sludge.

Oilfield waters are complex mixtures that change withtime and location. They require specific handling andtreatment according to their intended use.

Characteristics of Waters That Affect TheirHandling and TreatmentThe following lists give important characteristics ofwaters from the three sources discussed above that mustbe considered in their handling and treatment, whetherfor injection or for disposal.

Produced Waters:1. Generally are corrosive as a result of elevated tem-

perature and high salinity.

2. Usually contain dissolved gases (oxygen, carbondioxide, and/or hydrogen sulfide), which increasecorrosiveness.

3. Will vary in terms of physical and chemical propertieswith time, location, and field operations (wells shutin, brought on line, being worked over, stimulated,etc.).

4. Typically contain dissolved iron, which causes thewater to be chemically unstable, leading to scale and/or precipitate formation and interaction with otherwaters or chemical additives.

5. Contain suspended solids, including clays and otherformation fines, iron sulfides, paraffins, and asphal-tenes that are coated with oil, which causes them toagglomerate.

6. Contain various amounts of free oil and dissolvedorganic compounds.


7. Are or readily become microbiologically active owingto the presence of dissolved organics, reducible oxy-gen sources, and other conditions required for bio-logical growth.

8. Contain sufficient levels of dissolved solid to becomesources of scaling solids caused by commingledwaters or changes in temperature, pressure, or flowrate or direction.

Source Well Waters:1. Tend to be less corrosive because they contain little or

no dissolved oxygen.

2. May contain dissolved carbon dioxide or hydrogensulfide.

3. Have salinities and temperatures that cover wideranges.

4. Generally have a low suspended solids content (withproper source well completion).

5. Tend not to be microbiologically active.

6. May have scaling tendencies generally caused bycommingling of incompatible waters, affected bytemperature, pressure, or flow changes.

Open Waters:1. Are very corrosive because of high levels of dissolved

oxygen.

2. Can contain anywhere from low to very highconcentrations of suspended solids that may be or-ganic or inorganic and can vary seasonally and/orwith the oilfield operation that is the water source.

3. May have variable chemistry, depending on the watersource.

4. Often are microbiologically active and potentialsources of bacterial contamination in surface facilities,wellbores, and waterflooded formations.

5. May contain significant nutrients and reducible oxy-gen to facilitate bacterial growth.


Two general objectives

for treating water in an oil

field are to prepare the

water for injection or

disposal.

6. Are generally the source of sulfate ion to form sulfatescales when commingled with waters containingbarium, strontium, or calcium ions.

WATER TREATMENT OBJECTIVESThere usually are two general objectives for treatingwater in an oil field. The first is to prepare the water forinjection. This could be in a conventional waterflood, asa requirement in an EOR project, or for subsurface dis-posal. In all three cases, filtration may be required tominimize wellbore plugging caused by suspended solidsin the injected water. In addition, treatment may beneeded to reduce free oil, to remove oxygen or otherdissolved gases to control corrosion, to change the pH orwater chemistry to allow chemicals to be added for EORpurposes, or to reduce the water hardness to prepare thewater as steam generator feed. Subsurface injection fordisposal may be required because of the imposition of azero discharge environmental regulation.

The second general objective is to prepare an oilfieldwater for surface disposal by discharge to an ocean, ariver, a canal, or a municipal sewer system. As dischargeregulations and questions of liability become increasinglystrict, surface discharge will become less common (al-most the exception).

There are several additional objectives for treating oil-field waters. Actually, these objectives are not indepen-dent of the general objectives.

1. To control the detrimental effects of corrosion, scaleformation, and biological activity on piping, tanks,other surface equipment and facilities, and downholewell equipment.

2. To recover oil and revenue lost because of ineffectiveoil/water separation.

3. To provide the treatment required to use a water forEOR.

4. To meet the nonroutine treatment requirements forhandling special oilfield waters (added to theinjected water or disposed of separately). Thesespecial waters include:


Everything done to the

water upstream affects

everything that happens

downstream. A total

system approach must be

taken.

Tank bottoms, sand dumps, induced gas flotationskimmings, filter backwash, and pit waters.

Spent water-softener regeneration brine.

Glycol/water mixtures from gas dehydration.

Desalter waste water.

Water from pipe scraping (pigging) operations.

Backflow water from wells following stimulationtreatments.

Field or platform rain runoff.

Platform deck wash water.

These special waters are best treated as small-volumepoint sources before being allowed to commingletogether or with the main injection water. When com-mingled, their associated high solids and chemical load-ings have an extreme negative impact on water quality.When handled separately, the special chemical treatmentand solids removal requirements of these waters are metmore effectively to minimize this negative impact. Inaddition, flow rates, chemistries, and solids loadings ofthese waters fluctuate greatly. Handling them separately(with special tanks, chemical additions, etc.) tends tolevel out the fluctuations before they affect the combinedwaters.

POSSIBLE TREATMENTS REQUIRED TOACHIEVE OBJECTIVESA variety of processes are available for treating oilfieldwaters to achieve the objectives described above. Thewater treating system may be as basic as adding chemi-cals to change the water chemistry. At the other extreme,the system could require the combination of chemicaladditions, tanks to provide required residence time,water softening, phase separation (filtration, oil removal),process regeneration (filter backwash, softener regener-ation), and additional cleanup steps to treat wastestreams (filter backwash, tank or flotation skimmings,spent regeneration brine, pit water) for disposal. Every-


Economical justification

for filtration must

consider its costs versus

the benefits of increased

injector life and improved

waterflood sweep

efficiency.

thing done to the water upstream affects everything thathappens downstream. A total system approach must betaken.

A total system approach considers the interactions of theseparate parts of the system and their effect on the wholesystem. For example, a surfactant chemical added to thebackwash to improve filter-bed cleanup could be anemulsion stabilizer. If the backwash water is returned tothe system upstream of the oil/water separation equip-ment, the efficiency of that equipment will be lost. Ormaximizing water removal from crude by adding chemi-cals may increase the oil content in the water to a levelthat fouls the filter media and destroys filter efficiency.

Treatment Objective InjectionFiltration1. Economical water injection requires that lives of the

injection wells to be maximized. Economical justifica-tion of filtration must consider more than the capitaland costs of the filters. Filtration costs must be com-pared with costs for drilling new wells, working overor redrilling plugged wells, or stimulating partiallyplugged wells. An effective stimulation treatmentdoes more than just increase injectivity one time only.The number of times an injector can be stimulatedsuccessfully must also be considered. This includesthe detrimental effects of acids on well equipment andthe effect of the treatment on injection profile. Thereis also the question of whether permits may be se-cured from regulatory agencies to drill new wells.Regulations are becoming more restrictive for dis-posal wells. A proper decision to install filters musthave input from reservoir, production, gas and chemi-cal, and design and construction engineers, as well asfrom environmental coordinators.

2. The need to maintain profile control (sweep) byremoving the suspended solids that plug tight zonesis another factor to include in considering filtration.


3. As a general rule, a clean water handling system(with minimum suspended solids) is required tomaintain good water quality for injection throughoutthe life of a waterflood.

Solids that drop out in pipes, tanks, process equip-ment, injection lines, and tubing hinder corrosionand scale inhibitor and biocide effectiveness.Thus, they reduce water quality (further accumu-lation of scale, corrosion, and biological reactionproducts).

Accumulation of solids in lines also causes waterquality to decline as water flows through thesystem and solids are dislodged owing to pressuresurges, flow-rate variations, or water chemistrychanges.

Poor water quality, caused by ineffective watertreatment in the early life of a waterflood withresulting accumulations of solids in the injectionlines and tanks, leaves the system so dirty thatsubsequent installation of filters and other watertreating equipment often cannot overcome thedeleterious effect that the dirty system has onwater quality. At that point, it is usually too late,unless special steps are taken to clean up theinjection water lines and/or to install filters at thewellheads.

Similarly, a water handling system should be keptclean in anticipation of later EOR projects wherewater- quality requirements may be even morestringent. These earlier solids accumulations tendto slough off when they come into contact withsurface-active chemicals (surfactants), carbondioxide, miscellars, low-salinity water, and hightemperatures associated with EOR.

Removal of Free Oil from Water1. Free oil in water often is associated with sludge and

agglomerated solids (iron sulfides, other scales, for-mation fines, paraffins, and asphaltenes) that pluginjection wells.


Waters of different

qualities should be

treated separately as a

point source.

2. Free oil interferes with scale and corrosion inhibitorsand biocides, resulting in poor water quality.

3. Oil and sludge damage the efficiency of filtering.

4. Oil and sludge around an injector wellbore reducerelative permeability to water.

Effective Corrosion, Scale, and BiologicalControl1. The by-products of poor control of corrosion, scale,

and biological activity reduce water quality (bothchemistry and suspended solids) and cause injectorplugging by solids and interactions between thewater and the formation rock.

Separate Treatment of Waters1. The following are general rules for treating different

oilfield waters:

Waters of different qualities (in terms of bothchemistry and suspended solids) should not bemixed before treatment (or before potential inter-actions are identified). The quality of the resultingcombined water will be no better than that of theworst water in the mixture.

Treat each water separately as a point source ofsuspended solids, corrosion, scale, and bacteria.

If following the above steps is impossible and thewaters are mixed before treatment, sufficientresidence time must be provided (1) to allow themixed water to come to chemical equilibrium forall interactions to occur and (2) to stabilize thewater to maximize particulate formation beforefiltration.

Once treated by chemical or mechanical processes,waters must not be allowed to come into contactwith air (oxygen). Contact with oxygen causesadditional particulates (iron compounds particu-larly) to form. This is especially a problem withproduced water. Benefits of corrosion control andfiltration are nullified if contact with oxygenoccurs downstream from the filters (from


unblanketed tanks, influx of oxygenated water,leaking pump seals, use of air to scour filter me-dia, etc.).

EOR Treatment Considerations in Addition toThose Listed Above 1. Added chemicals or changes made in water chemistry

to meet an EOR objective may interfere or interactwith chemicals added for other purposes. The resultis a loss of water quality at a time when an improve-ment in water quality is needed for a successful EORproject. Such interferences include but are not limitedto:

Surfactants counteracting (e.g., a wetting agentstripping off a filming corrosion inhibitor).

Polymers and surfactants interacting.

Biocides (aldehyde type) reacting with a polymer.

Scale and corrosion inhibitors and biocides becom-ing ineffective at low-pH (CO2 injection) condi-tions.

Note that other state and federal regulations must bemet, in addition to considerations for treating a water forinjection. In fact, the regulations themselves may be themotivation for injection.

Treatment Objective Surface DisposalSurface disposal is controlled by the conditions specifiedin a discharge permit obtained from a state or federalregulatory agency. The permit sets the environmentaldischarge standards and/or limits including but notlimited by:

1. The oil and grease content (defined by the methodspecified for measuring the concentration of hydro-carbons/organics in the water).

2. The toxicity (in turn defined by the toxic effect ofthe water on the mortality of one or more biologicalspecies based on a test method acceptable to the stateor federal agency and specified in the dischargepermit).


It is important to control

corrosion, scale, and

bacteria growth both to

protect equipment and

maintain good water

quality.

3. A list of effluent components with maximum allow-able concentrations (absolute or relative to ambient).

Effluent components include (in addition to oiland grease content and toxicity) suspended solids,oxygen demand, sulfides, chlorine, pH, ammonia,radioactivity, metals, and organics.

4. Temperature.

5. Volume of water discharged.

Meeting these standards may require additional oilremoval and other equipment besides that needed forinjection. In some cases, special processes, such as acti-vated carbon adsorption, have been required to removeorganics (e.g., phenols). Drinking water standards,groundwater protection, and air pollution controls arebecoming more important in state and federal surfacedischarge permitting processes.

Additional Water Treatment ObjectivesCorrosion, Scale, and Biological Control1. An effective water treating program to control prob-

lems caused by corrosion, scale, and bacteria must bebased on two equally important perspectives. Boththe equipment and the water must be considered.First, all the field equipment including systempiping, pumps, tanks, process equipment (separators,filters, deaerators, flotation units, filters, etc.), well-heads, and tubing need to be protected from thedeleterious effects of all three problems. Second, theinterrelated effects of corrosion, scale, and bacteria onthe quality of water flowing through the system mustbe considered. For example, a corrosion rate that isacceptable in terms of equipment life may beunacceptable in terms of its effect on water quality.Dissolved iron released by corrosion reactions comesout of solution to form particulates and scale when itcomes into contact with air or H2S. Suspended solidscontent also is increased by scale formation andbiological activity.


The value of the crude oil

recovered can more than

pay for the recovery

equipment, plus improve

the water quality.

2. The chemicals added to the water to control corro-sion, scale, or biological activity may not be compat-ible. Included are surfactants of all types, polymers,reducing agents, and oxidizing agents. The combina-tion of chemicals used and the points where they areadded must be evaluated carefully.

Recovery of Free Oil in Water and LostRevenue1. The value of crude oil is an important factor in the

economics of recovering additional free oil fromproduced water. The increased revenue from the oil iscompared with the costs of installing additional oil/water separation equipment or improving existingseparation equipment through design or chemicalchanges. Even the choice of a filter design can beaffected by the filter s ability to recover oil and toremove suspended solids.

2. Some equipment or operation changes to improve oilseparation include the use of coalescers, improvedtank design to increase residence time for better oil/water separation, increased gas flotation capacity, achange in coalescing or coagulation chemical type orpoint of addition, and use of other types of separa-tors.

Special Treatment for EOR Requirements1. To add special EOR chemicals to the injection water or

to use the water for steam generation, softening,reducing the alkalinity, or raising the pH of the watermay be necessary.

2. Softening the water may require the oil and sus-pended solids content of the water to be reducedfurther to prevent fouling of the softener resin bedand solids deposition on steam generator tubes.

3. The added EOR chemicals may affect water chemistryand pH so much that the corrosion and scale inhibi-tors must be changed to be effective at the new condi-tions. Similarly, the biocide (particularly an oxidizingtype) will no longer be usable in the presence of


polymers added for EOR. Also, polymers will in-crease the biological activity of the system, requiringre-evaluation of biocides.

4. Finally, added surfactants and pH changes for EORwill dislodge scales and other deposits from pipesand vessels. Secondary filtration or filter modifica-tions will be needed.

Nonroutine Treatments of Special OilfieldWaters1. As stated earlier, these special waters (tank bot-

toms, flotation skimmings, pit waters, spent softenerregeneration brine, etc.) are best treated as small-volume point sources. As such, the treatment ofeach water must be tailored to its specific chemicaland physical properties and destination (handledseparately or mixed with other waters for injection oropen discharge). Consequently, a complete spectrumof mechanical and chemical treatment procedures canbe involved.

OILFIELD TREATMENT METHODS ANDEQUIPMENTThe following outlines mechanical and chemical methodsand equipment used to treat oilfield waters to achieve theobjectives discussed above. The length of the list illus-trates the large number of options available. Details aregiven in succeeding chapters.

1. Mechanical (Physical) Methods With or WithoutChemicals and Heat Added

A. Oil/Water Separation

1. Free-water knock-out vessels2. Two- and three-phase separators3. Skimmer tanks and vessels4. Pits5. Coalescers6. Combinations of coalescers and skimmers


7. Precipitators8. Flotation units

a. Dissolved gasb. Dispersed gas

9. Disposal piles (on platforms)10. Hydrocyclones liquid/liquid

a. Staticb. Dynamic

B. Filtration (suspended solids)

1. Sand filtersa. Upflowb. Downflowc. Duoflowd. High and low ratee. Single and multimediaf. Coalescingg. Horizontal and vertical

2. Precoat filters (diatomaceous earth)3. Cartridge filters

a. Disposable cartridgeb. Backwashable

4. Fluidized bed, regeneration-type filtersa. Walnut-shell mediab. Pecan-shell media

5. Hydrocyclones solid/liquid6. Flotation units (see Item A-1-h)7. Dry cake filters

a. Precoat and body feed on wire-wrap screen1. Diatomaceous earth

2. Pearlite

3. Walnut and pecan shells

b. Rotary drum filters

c. Plate-and-frame filters

C. De-aeration (oxygen removal)


1. Gas stripping

a. Nitrogen

b. Fuel gas

c. Flue gas

d. With or without packing or plates

2. Vacuum

D. Gas Stripping to Remove H2S

2. Chemical Methods (Involve Changes in Water Chem-istry)

A. Surfactant Addition

1. Emulsion breakers for oil/water separation

2. Filter cleaners in backwash water

3. Relative permeability modifiers to improvewater injectivity

4. De-aerator antifoamers and defoamers

5. Some biocides

6. Corrosion inhibitors

7. Scale inhibitors

8. Oil-coalescing surfactants

B. Oxygen Scavenging

1. Various sulfides ( )SO , HSO , SO2 32 32 C. Biocide Addition

1. Oxidizers

a. Chlorine

b. Chlorine dioxide

2. Aldehydes

3. Quaternary amines

4. Mixed aldehyde/amines

D. Corrosion-Inhibitor Addition

1. Filming amines

2. Water dispersible or soluble


E. Scale-Inhibitor Addition

1. Phosphates

2. Phosphonates

3. Mixtures

F. Changing pH

1. Decrease

a. Adding SO2 to control scale

b. CO2 flooding (EOR)

c. Reducing alkalinity

d. Decreasing solubility of dissolved organiccompounds

2. Increase

a. Neutralizing weak acid softener spentregenerant

b. Removing of H2S or CO2 from water

c. Neutralizing water for discharge

d. Caustic flooding (EOR)

G. Controlling Cation Concentration

1. Softening

a. Exchange divalent ions for monovalent ions

b. Lime soda

2. Direct addition of salts

a. Increase potassium concentration

b. Increase salinity

3. Mixing waters of different salinities

H. Adsorption of Dissolved Organics on ActivatedCharcoal

I. Addition of Polymers

1. Filteraids

2. Coagulants

3. Polymer flood (EOR)


GLOSSARYincompatible waters waters when mixed form solid

precipitates.

total system approach considering effects in the entiretreatment system.

Chapter 2: Analytical and Test Methods 2-1

C H A P T E R

2

Analytical and Test Methods


WATER ANALYSIS

Reasons for Water AnalysisChevron produces roughly 10 times as much water ascrude oil. This water causes many problems in produc-ing operations and in treating for use or disposal. Water-related problems include:

Bacterial activity.

Corrosion.

Emulsions.

Formation damage.

Environmental restrictions.

Equipment fouling.

Formation plugging.

Scale and precipitate formation.

Incompatibility.

In water sampling and analysis, we determine the typeand amount of dissolved and suspended material in thewater and the physical, chemical and microbiologicalproperties of the water. Water analysis is a first step in adiagnostic procedure (1) to ascertain the possibility ofproblems, (2) to determine the existence of problems,(3) to test possible physical and chemical remedial treat-ments, and (4) to measure the effectiveness of thesetreatments.

Water is a major component of all EOR projects. In caus-tic and steamfloods, we must know the types andamounts of hardness and alkalinity and the total salinityto determine the type and extent of softening required tominimize the formation of plugging precipitates andfouling scale deposits in steam generators. Knowledge ofhardness, alkalinity, and total salinity is necessary topredict the effectiveness and compatibility of chemicalfloods with surfactants or foams. With CO2 floods,knowing the changing chemistry of CO2-acidified injec-tion water (as it moves through and reacts with theproducing formation) helps us identify formation rock

Critical components:

dissolved solids,

suspended solids,

physical, chemical, and

microbiological

properties.


dissolution reactions and potential corrosion and scalingproblems in producing wells and surface treating equip-ment.

The composition of produced water can sometimesindicate the source sand or formation for the producedfluids. When compared with the compositions of injec-tion and connate waters, produced-water compositioncan indicate the time and extent of injection-water break-through.

Composition changes across a facility for production,separation, treating, and injection can pinpoint locationsand types of problems. Chemical analysis can helpdiagnose the problems and determine the effectiveness oftreatment schemes. Dissolved oxygen measurements canindicate the need for and effectiveness of mechanical andchemical de-aeration. Monitoring oil-in-water content orthe types and amounts of suspended solids mirrors theperformance of the chemical treatment or process equip-ment. It also confirms whether environmental dischargerequirements are met.

Because of the importance of oil-in-water concentrationand suspended solids in fouling equipment and plugginginjection or disposal wells, the sampling for and analysisof these two items are treated separately in this chapter.Bacteria and bacterial fouling problems are discussedChapter 7.

Constituents Determined and PropertiesMeasuredThis chapter focuses on those major components andproperties of water that are important in recognizing andtreating of water-related problems in producing opera-tions. Characterizing waters for trace elements, as in anextensive geochemical analysis, is not covered. Simplerprocedures and techniques are used; major componentsare determined; fewer properties are measured; and theemphasis is on rapid, reproducible, relatively accurateprocedures and methods for sampling and analysis.

Table 1 lists the components determined and propertiesmeasured for the purposes of problem solving. Not allcomponents are determined nor all properties measured


in each analysis. Emphasis is on those componentspertinent to the system or problem under study. Thosefactors of importance for each type of situation are dis-cussed next.

Significance of Components or Properties

Cations

Sodium, Na+ Is the principal monovalent cation in most waters.

All commonly occurring sodium compounds aresoluble, although sodium chloride may precipitatefrom highly concentrated, nearly saturated brines.

Should be determined analytically, not calculated bydifference, as was common in many older analyses.

Is the primary cation contributor to total dissolvedsolids (TDS) and ionic strength.

Used in cation/anion balance as a quality-controlcheck.

Potassium, K+

Is usually present at lower concentrations than so-dium.

High levels may indicate sample contamination fromdrilling or completion fluids.

All commonly occurring potassium compounds aresoluble.

May be combined with and reported as equivalentamount of sodium ions.

Calcium, Ca2+ Usually is the principal divalent cation.

Contributes to and may be reported as water hard-ness.

Combines with sulfate or carbonate ions to formsuspended solids or adherent scale deposits.

Cations are positively

charged ions that moved

towards the cathode in an

electrolysis cell.

Sodium ions are the

major cations in normal

produced or connate

waters.

Calcium and magnesium

are the principal

hardness ions in

produced waters.


Table 1 Primary Components and Properties of OilField Waters

Cations Sodium, Na+

Potassium, K+

Calcium, Ca2+

Magnesium, Mg2+

Barium, Ba2+

Strontium, Sr2+

Iron, Fe2+

Hardness, as CaCO3

Anions Chloride, Cl-

Salinity, Chlorinity, andChlorosity

Carbonate, CO andBicarbonate, HCOSulfate, SO

32-

3

42

Organic Acids, as AcetateAlkalinity, as CaCO3

Dissolved Gases Oxygen, O2Carbon Dioxide, CO2Hydrogen Sulfide, H2S

NeutralComponents

SilicaBacterial ContentOil-in-WaterTotal ResidueTotal Dissolved SolidsSuspended Solids

AmountTypeParticle Size Analysis

Properties pH (field and lab)TemperatureTurbidityColorDensity (or Specific Gravity)Conductivity (or Resistivity)


Magnesium, Mg2+ Frequently is present in smaller amounts than calcium

except in seawater or connate waters derived fromseawater.

Contributes to and may be reported as water hard-ness.

May form insoluble magnesium hydroxide at highpH.

Readily forms ion pairs with sulfate ions, therebydecreasing the activity of free sulfate ions and increas-ing the apparent solubility of sulfate scales and pre-cipitates.

Barium, Ba2+ Is frequently found in produced waters but at a lower

concentration than calcium or magnesium.

Combines with sulfate ions to form extremely in-soluble barium sulfate deposits that are difficult toremove.

May indicate the presence of other radioactive alka-line earth cations (e.g., radium).

Strontium, Sr2+ Usually is associated with but at lower concentrations

than barium.

Forms insoluble strontium sulfate or mixedstrontium/barium sulfate precipitates.

Iron, Fe Usually is determined and reported as soluble iron

and total iron (soluble + insoluble).

May occur naturally in some waters and formationsbut frequently indicates corrosion of producing andtreating equipment.

Is present initially in the reduced form, Fe2+ or Fe(II),in produced water.

Reduced iron, Fe2+ or Fe(II), is more soluble thanoxidized iron, Fe3+ or Fe(III).

NORM (naturally

occurring radioactive

material) is usually

radioactive divalent

cations included in

sulfate scales.

Soluble iron may be an

indication of corrosion.


Reduced iron oxidizes easily by contact with air orother oxidants.

Iron counts are useful in detecting and monitoringcorrosion only in sulfide-free waters.

Red water suspended iron oxide and hydrox-ides, usually found in oxidizing environments.

Black water suspended iron sulfides, usuallyfound in reducing environments with measurablesulfide levels.

Iron sulfides and oxides cause severe formationplugging and may be difficult to remove by acidizing.

Iron sulfides are readily oxidized upon exposure toair or an oxidizing environment.

Hardness Originally named for and determined by reaction

with soap solution to form scum or bathtub ring.

Reported as parts per million (ppm) or milligrams perliter (mg/L) as calcium carbonate.

Composed primarily of calcium and magnesium ionsbut includes any other di- and trivalent cations.

Indicates relative carbonate scale formation potential.

Frequently precipitated in boilers, steam generators,and highly alkaline waters.

May be determined directly by titrimetric chemicalanalysis or calculated by conversion of di- and tri-valent cation concentrations to chemically equivalentamounts of calcium carbonate (CaCO3).

Anions

Chloride, Cl- Major anion in many waters.

High concentrations increase water corrosivity.

Stable anion, useful for identifying and tracing waterflow.

Calcium and magnesium

are the principal hardness

ions and form an

insoluble scum with

soaps.

Anions are negatively

charged ions that move

towards the anode in an

electrolysis cell.


Salinity, Chlorinity, and Chlorisity Terms frequently used to describe the amount of

dissolved solids, in terms of Cl- or Cl- equivalents, inseawater or waters derived from seawater by dilutionor concentration.

Should not be used for waters with anion composi-tion ratios differing from those of seawater, e.g.,waters with high ratios.

Salinity Total solids after all carbonate and bicarbonate have

been converted to oxide, all bromide and iodide havebeen replaced by the equivalent amount of chloride,and all organic matter has been oxidized.

Usually reported as grams per kilogram (g/kg) ofsolution or parts per thousand (ppt, )

Calculated from chlorinity only for seawater andseawater-like waters by the following empiricalrelationship:1

salinity, = 0.03 + 1.805 x (chlorinity, ).

Calculated from measured chlorisity by using Table210:IV of Ref. 2 (1980) (Pages 109-20).

Experimentally determined by measuringtemperature-corrected specific gravity with a hy-drometer and converting to salinity by means ofdensity/salinity tables [Table 210:II, Ref. 2 (1980),Pages 105-06].

Chlorinity Now defined in parts per thousand (ppt, ) as the

number of grams of silver necessary to precipitatethe Cl- and Br- in 328.5233 g of seawater.3

Usually determined by titration with silver nitrate.

Can be calculated from ionic concentrations by

Cl()= 0.9996 (Cl 0.4437 Br 0.2794 I )- + +

Salinity, chlorinity, and

chlorisity are used only

for waters similar in

composition to seawater.


Chlorisity Obtained by multiplying chlorinity by the density of

water at 20C.

Similar to chlorinity except chlorisity is a weight-per-volume concentration term.

Carbonate and Bicarbonate, CO32- andHCO3

Major component (along with organic acids) of alka-linity.

Forms scale deposits with calcium ions.

Relative proportions of CO HCO CO32

3 2

are pH-

dependent.

Decomposes at high temperatures to yield carbondioxide in the vapor (steam) phase and hydroxideions in the liquid phase.

Carbonates are sometimes referred to as phenolphtha-lein alkalinity; bicarbonates as methyl orange alkalin-ity.

Sulfate, SO42

Forms insoluble deposits with calcium, barium,strontium, and other alkaline earth cations.

Electron acceptor (oxidizing agent) in the biogenic orthermal production of hydrogen sulfide.

Barium sulfate (barite) is a common component ofdrilling muds and may appear as a contaminant inproduced water.

Organic Acids Major component (along with carbonates and bicar-

bonates) of alkalinity in some produced waters.

Generally are low-molecular-weight (C2 to C4) ali-phatic acids or naphthenic acids (saturated acids withfive- and six-membered rings of carbon atoms).

Alkalinity is a measure of

the capacity of a water to

react with acids.

Bicarbonate and

carbonate are the major

components of alkalinity

in many produced waters.

Organic acids can be a

carbon and energy source

for bacterial activity.


Low-molecular-weight aliphatic acids are readilysoluble in moderately basic waters.

Acetic acid (or acetate ions) is the most commonlyoccurring organic acid in produced water and may bepresent in concentrations as high as thousands ofmilligrams per liter.

Naphthenic acids have low water solubilities, espe-cially at pH less than 4 to 5.

May have been formed by bacterial action or bythermal decomposition of more complex organicmaterial in crude oil or crude oil precursors.

Carbon and energy sources used by many bacteria,including sulfate-reducing bacteria (SRB).

Alkalinity Measure of ability to combine with or consume hy-

drogen ions from an acid.

Made up primarily of carbonate, bicarbonate,and organic acid anions, with minor contributionsfrom other acid anions (e.g., bisulfide, borate, phos-phate) and weak bases (e.g., ammonia).

Is a major factor in fixing the pH and buffer capacityof the water.

Is usually determined by titration with standard acidand then broken down into component parts by otheranalytical and calculation methods.

Dissolved Gases

Oxygen, O2 Can cause severe corrosion if present in even low

levels.

Recommended levels 20 parts per billion (ppb) tominimize corrosion.

Oxidizes soluble iron to precipitate iron oxides.

Can oxidize dissolved sulfides to form colloidalsulfur.

Promotes growth of aerobic, slime-forming bacteria.

Dissolved oxygen is a

major contributor to the

corrosivity of oilfield

waters.


Carbon Dioxide, CO2 Acid gas that decreases pH of water.

High concentrations increase corrosion rates.

Influences formation and dissolution of carbonatescales.

Hydrogen Sulfide, H2S Is highly toxic.

Acid gas that decreases pH at high concentrations.

Increases water corrosivity.

Reacts with oxygen or other oxidizing agents to formhighly corrosive solution.

Causes mechanical failure of steel components.

May indicate active sulfide-producing bacterial (SPB)population.

Reacts with soluble iron to form pluggingdeposits; corrosive precipitates; and oil-wet,emulsion-stabilizing deposits.

Neutral Components

Silica Is usually present in low amounts (


Acid-producing bacteria (APB) form corrosive organicacids (e.g., acetic acid).

Contributes to localized (pitting) corrosion and en-hanced corrosion rates.

Decarboxylates organic acids and decomposes otherorganic material to form CO2.

Usually exists in consortia or microniches where onetype of bacteria provides the carbon and energysources and the necessary environment for othertypes of bacteria.

May convert soluble material [e.g., soluble iron(II)] toinsoluble precipitates and scales.

Biofilms and biogenic deposits can contribute tounder- deposit corrosion.

Predominant factor in reservoir souring.

Oil-in-Water Content Must be low and meet environmental criteria for

discharge to surface waters.

May decrease injectivity by forming emulsionblocks in the pores of the formation or by increasingthe oil saturation and thereby reducing the relativepermeability to water.

Acts as a cementing material for other suspendedsolids.

Can be used to estimate efficiency of separators andoily water treatment equipment.

Total Residue Is the amount of solid material left after evaporating a

water sample and drying the residue at a specifiedtemperature.

Composed of nonfilterable residue (suspended solids)plus filterable residue (dissolved solids).

Suspended Solids Particulates that may plug injection wells, foul surface

equipment, or induce turbidity in receiving waters.


Amount of suspended solids.

Usually inversely related to water quality.

Determined gravimetrically or by particle-size analy-sis.

Type of suspended solids.

May be corrosion products, scale deposits, insolubleprecipitates from incompatible waters or treatmentchemicals, bacteria and biomass, or formation fines

Identification of type of suspended solids may indi-cate source.

Determines plugging properties: large, crystalline,uniform-sized particles produce high-permeabilityfilter cakes; hydrated, small particles form low-permeability filter cakes.

Particle-size analysis.

Particle-size population gives number (or volume)of particles of a given size.

Particle-size distribution gives fraction of totalnumber (or volume) of particles having a given size;does not estimate the total number (or volume) ofparticles present.

Population measurements are more useful than distri-bution measurements.

Used to estimate plugging potential of suspendedsolids, filtration requirements for injected waters, andremoval efficiencies of treatment chemicals and sepa-ration equipment.

Total Dissolved Solids Either measured gravimetrically or calculated from

the sum of concentrations of dissolved components.

Affects corrosion rates and apparent solubilities bychanging total ionic strength and activity coefficients.

High dissolved solids content usually indicates highcorrosion rates and increased solubilities of precipi-tates or scales.

Suspended solids, along

with dispersed oil, are the

major cause of plugging

of injection wells.


Properties

pH Defined as the negative logarithm of the hydrogen ion

activity (concentration).

Affects solubility of carbonate, hydroxide, and sulfideprecipitates or scales.

Corrosion rate increases as pH decreases.

Low pH may indicate presence of corrosive acidgases, CO2 and H2S.

Usually determined by the amount and type of weakacids and bases present (or organic acid/organic acidanion).

May change rapidly in a poorly buffered system fromloss or gain of acid gases.

Best measured in place in a pressurized system or inthe field immediately after sampling.

Laboratory-measured pH may differ significantlyfrom field measurements because of changes in acidgas concentration, hydrolysis reactions, precipitationof basic and acidic components, or bacterial degrada-tion of organic material.

Temperature Must be measured in the field.

Strongly affects corrosion rates, precipitate solubili-ties, and efficiencies of oil/water separations.

Turbidity Is a measure of water cloudiness or opacity.

Is caused by scattering and absorption of light byparticulates (suspended solids and dispersed oil).

Can be related to suspended solids and/or oil contentonly if the system is well characterized and unchang-ing.

Is an indirect measure of water quality (high turbidityindicates low water quality).

Neutral waters have a pH

of 7. Acid waters have

pHs less than 7. Alkaline

or basic waters have pHs

greater than 7.


Color Is produced by dissolved, colloidal, or suspended

colored material in water.

Is an indirect measure of water purity (low color maymean high purity or at least the absence of coloredimpurities).

Perception of color strongly influenced by strengthand color of incident light.

Density Is defined as weight per unit volume.

Specific gravity is the ratio of the sample density towater density, each at some specified temperature.

Densities greater than pure solvent indicate the pres-ence of dissolved and suspended solids.

Correction factor used for some concentration conver-sions.

Can be used as a quality-control parameter becausedensity and total dissolved solids content are related.

Conductivity Measure of the dissolved ionic components.

Resistivity (reciprocal of conductivity) used for welllogging.

Can be a quality-control parameter because conduc-tivity is related to ionic concentration.

SamplingSample location and identification, as well as samplingprocedures and preservation techniques, are as importantas the choice of analysis procedure. The sample mustrepresent the operating system at some set of conditions.The sample should be uniquely identified, and the loca-tion and operating conditions at the time of samplingshould be recorded. Finally, multiple samples may benecessary: field analysis and specially preserved samplesfor unstable components, unpreserved samples for stablecomponents, and separate samples for specialty analyses.

Density and specific

gravity are numerically

equal only when the

reference water has a

density of exactly

1.0000 g/mL.

Steps in chemical

analysis:

1. sample preparation

2. sample preservation

3. chemical analysis

4. reporting


Sample and System IdentificationSample and system documentation are essential forsample tracing. We need sufficient information to iden-tify where, when, how, why, and by whom the samplewas taken. System operating conditions at the time ofsampling should be listed. This is especially important ifthe system is not operating under normal conditionswhen the sample is drawn. Table 2 shows the type andextent of information needed.

Sampling ProceduresThe sample must be representative of the operatingsystem. The system sampled should be operating asclose as possible to normal conditions of flow rate, pres-sure, temperature, etc. Any departures should be notedon the sample identification form. The sample should betaken from a flowing, well-mixed stream, unless thepurpose of the sampling is to look at subnormal operat-ing conditions.

Some system components or properties change rapidlywith time and cannot be adequately preserved or stabi-lized for later laboratory determinations. These compo-nents or properties must be measured or determined inthe field as close in time and location to the sample pointas possible. Other components may change with timebut can be preserved for later analysis. Still other com-ponents are reasonably stable and do not need specialpreservation techniques. A complete analysis involvesfield analysis for some components and laboratory analy-ses with an unpreserved sample and with several spe-cially treated samples for the remainder.

All liquid samples for analysis or preservation should befield-filtered as soon after sampling as possible. Thepurpose is to remove dispersed oil and suspended solids(scale deposits, corrosion products, formation fines, etc.)present in the original sample. Chevron personnel devel-oped an automatic pressure filtration apparatus4 suitablefor field filtration. Carpenter and Campbell5 gave spe-cific details for field sampling and filtration. Multiplefiltrations may be necessary if dispersed oil concentra-

Filtration in the field is an

essential step in sampling

and sample preparation.


Table 2 Information for Water Sample and SystemDescription

Sample LocationField, lease, well, section, state, country,

gathering station, tank battery, pipeline,pit, etc.

Date and Time of Sample

Sampled By

Sample DescriptionSource, zone, or formationColor, presence of oil and/or solids, odor, any

unusual features

Sample ConditioningFiltration, refrigeration, special preservatives

(type and amount)

System OperationNormal, abnormal, shut inFlow rate and pressure at sample pointTreatment chemicals (type and amount)

presentAny unusual or abnormal factors

Field Analyses PerformedTypes of analyses, location of results

tions are high. Dispersed oil, even when present inmoderate quantities, quickly saturates and bleedsthrough most membrane filters.

The only exceptions to field filtration are measurementsfor turbidity and color. These measurements must bemade in the field with unfiltered samples. Turbidity andfrequently color result from suspended or colloidalmaterial that could be removed by filtration.

For laboratory analysis, we prefer using a glass bottlethat was washed with acid, rinsed with deionized water,and dried. Place samples in individual glass bottles for


shipment to remote laboratories in a waterproof mailingtube with enough packing material to prevent breakage.Temperature-sensitive samples may need to be shippedin insulated containers.

Note: Many oilfield samples contain materials considereddangerous or hazardous. Contact the postal service or shippingcompany for restrictions and necessary packaging and docu-mentation before sending samples by commercial carriers. Tofacilitate sample transport, use washed and rinsed plasticbottles for all samples, except those for oil-in-watercontent measurements. Place the plastic sample bottle ina protective mailer, too. Trace amounts of some heavymetal ions may irreversibly adsorb onto the plastic sur-face and be unavailable for analysis. Again, acid-washedglass bottles are best for these samples.

Field MeasurementsThe following components must be measured in the fieldimmediately after sampling and filtration:

pH.

Temperature.

Turbidity (must be done with an unfiltered sample).

Color (must be done with an unfiltered sample).

Total alkalinity.

Dissolved O2.

CO2.

Bisulfide, HS- (see Ref. 6 for a field analysis procedurefor low sulfide concentrations. As an alternative,stabilize a separate sample with basic zinc solution).

Soluble iron(II).

Total suspended solids (primary filtration and wash-ing with water performed in the field; subsequentwashings and weighings may be performed in thelaboratory).

Bacteria filtered or cultured from the sample in thefield with subsequent incubation and enumeration inthe laboratory.

Shipment of samples by

commercial carriers

requires special

precautions.


Preserved SamplesBefore sampling begins, consult the laboratory perform-ing the analysis to determine acceptable preservationtechniques compatible with the laboratorys analyticalmethods.

Cation Analysis A field-filtered sample preservedwith either hydrochloric acid or citric acid5 is taken forlaboratory analysis of the following cations:

Sodium, Na+.

Potassium, K+.

Calcium, Ca2+.

Magnesium, Mg2+.

Barium, Ba2+.

Strontium, Sr2+.

Iron(II), Fe2+.

Alkalinity Determination Alkalinity is a measure ofthe ability of a solution to react with hydrogen ions (H+)from an added acid. Alkalinity is not a measure of anyone particular system component; it is a measure of asystem property. Components commonly contributing toalkalinity in oilfield brines are carbonate and bicarbonateions, water-soluble aliphatic and cyclic acid anions, andbisulfide ions (HS-). Sulfide ions (S2-) usually do notcontribute because the pH of most oilfield waters is toolow for measurable amounts of sulfide ions to be present.

Ammonia (NH3), not ammonium ion ( NH4+ ), borate, and

phosphate ions can contribute to alkalinity if their con-centrations are high and the solution pH is such thatthese materials are in their base forms.

Current field analytical procedures are not sensitiveenough to distinguish the different forms of alkalinitythat might be present in a produced-water sample. Aseparate sample is taken and preserved for laboratoryanalysis by adding a known amount of standard hydro-chloric acid (HCl) sufficient to decrease the pH of aknown volume of sample to at least 2.5. At pH 2.5, alldissolved bases have been converted to acids, and HCl ispresent in excess. In the laboratory, the volatile acids,

Many produced waters

contain components in

addition to bicarbonate

and carbonate that

contribute to the

alkalinity of a water.


primarily carbonic (H2CO3) and hydrogen sulfide (H2S),are removed by inert gas sparging or vacuum boiling.The excess HCl added in the field for stabilization andthe nonvolatile acid content are determined by titrationwith standard base. The first endpoint at pH 3.5 to 4 isrelated to the excess acid; the second endpoint at pH 7 isrel

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