WATER TREATMENT HANDBOOK.pdf

Water Treatment Handbook

Contents CHAPTER 1: INTRODUCTION ............................ 1-1 BACKGROUND ................................................................... 1-3 Existing Systems Designed for Old Waterfloods......... 1-3 A New System To Be Installed for a New Waterflood or EOR Project ......................................................... 1-4 OILFIELD WATER REQUIRING TREATMENT ................... 1-4 Water Sources ................................................................. 1-4 Characteristics of Waters That Affect Their Handling and Treatment .......................................... 1-5 Produced Waters: ........................................................ 1-5 Source Well Waters: .................................................... 1-6 Open Waters: ............................................................... 1-6 WATER TREATMENT OBJECTIVES .................................. 1-7 POSSIBLE TREATMENTS REQUIRED TO ACHIEVE OBJECTIVES ................................................................ 1-8 Treatment Objective — Injection ................................... 1-9 Filtration ....................................................................... 1-9 Removal of Free Oil from Water ............................... 1-10 Effective Corrosion, Scale, and Biological Control ............................................... 1-11 Separate Treatment of Waters .................................. 1-11 EOR Treatment Considerations in Addition to Those Listed Above ........................................... 1-12 Treatment Objective — Surface Disposal ................... 1-12 Additional Water Treatment Objectives ...................... 1-13 Corrosion, Scale, and Biological Control ................ 1-13 Recovery of Free Oil in Water and Lost Revenue ... 1-14 Special Treatment for EOR Requirements .............. 1-14 Nonroutine Treatments of “Special” Oilfield Waters ..................................................... 1-15 OILFIELD TREATMENT METHODS AND EQUIPMENT .. 1-15 GLOSSARY ....................................................................... 1-19

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CHAPTER 2: ANALYTICAL AND TEST METHODS .............................................. 2-1 WATER ANALYSIS.............................................................. 2-3 Reasons for Water Analysis ........................................... 2-3 Constituents Determined and Properties Measured ... 2-4 Significance of Components or Properties .................. 2-5 Cations ......................................................................... 2-5 Sodium, Na+ .............................................................. 2-5 Potassium, K+ ........................................................... 2-5 Calcium, Ca2+ ........................................................... 2-5 Magnesium, Mg2+ ..................................................... 2-7 Barium, Ba2+ ............................................................. 2-7 Strontium, Sr2+ ......................................................... 2-7 Iron, Fe ...................................................................... 2-7 Hardness ................................................................... 2-8 Anions .......................................................................... 2-8 Chloride, Cl- .............................................................. 2-8 Salinity, Chlorinity, and Chlorisity ........................... 2-9 Salinity ....................................................................... 2-9 Chlorinity ................................................................... 2-9 Chlorisity ................................................................. 2-10 “Organic Acids” ...................................................... 2-10 Alkalinity.................................................................. 2-11 Dissolved Gases ........................................................ 2-11 Oxygen, O2 .............................................................. 2-11 Carbon Dioxide, CO2 .............................................. 2-12 Hydrogen Sulfide, H2S ........................................... 2-12 Neutral Components ................................................. 2-12 Silica ........................................................................ 2-12 Bacterial Content .................................................... 2-12 Oil-in-Water Content ............................................... 2-13 Total Residue .......................................................... 2-13 Suspended Solids................................................... 2-13 Total Dissolved Solids ............................................ 2-14 Properties ................................................................... 2-15 pH............................................................................. 2-15 Temperature ............................................................ 2-15 Turbidity .................................................................. 2-15 Color ........................................................................ 2-16 Density .................................................................... 2-16 Conductivity ............................................................ 2-16 Sampling ........................................................................ 2-16 Sample and System Identification ........................... 2-17 Sampling Procedures ................................................ 2-17 Field Measurements .................................................. 2-19 Preserved Samples.................................................... 2-20 Unpreserved Sample ................................................. 2-21 Oil-in-Water Content .................................................. 2-21 Analytical Methods ....................................................... 2-22 Chemical Properties .................................................. 2-22

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Physical Properties ................................................... 2-29 Standard Analytical Methods ................................... 2-29 Analytical Report .......................................................... 2-30 Sample Identification ................................................ 2-31 Methods of Presentation of Components ............... 2-31 Units of Measurement ............................................... 2-34 Concentration Units Based Upon Physical Properties .......................................... 2-37 Concentration Units Based On Chemical Properties......................................... 2-38 Units Used for Properties ...................................... 2-41 Hypothetical Salt Combinations .............................. 2-45 Solubility Calculations .............................................. 2-46 Composition Diagrams ............................................. 2-47 Quality Control .............................................................. 2-47 Anion/Cation Balance ............................................... 2-47 Calculated vs. Measured TDS ................................... 2-48 Calculated vs. Measured Specific Gravity ............... 2-49 Methods Using Electrolytic Conductivity ................ 2-50 Regions of pH and Carbonate Species.................... 2-53 Solubility Calculations .............................................. 2-54 Replicates, Standards, and Spiked Samples .......... 2-54 OIL-IN-WATER ANALYSIS................................................ 2-54 Free Oil vs. Dissolved Oil ............................................. 2-55 Dissolved Oil .............................................................. 2-55 Free Oil ....................................................................... 2-57 Sampling ........................................................................ 2-58 Analytical Procedures .................................................. 2-59 EPA Method 413.1. Oil and Grease. Total, Recoverable (Gravimetric, Separator Funnel Extraction) ........................................................... 2-60 EPA Method 413.2. Oil and Grease. Total Recoverable (Spectrophotometric, Infrared) .... 2-60 EPA Method 418.1 Petroleum Hydrocarbons. Total Recoverable (Spectrophotometric, Infrared) 2-61 API Recommended Practice for Analysis of Oilfield Waters, API RP 45 .................................. 2-62 Quality Control .............................................................. 2-62 SUSPENDED SOLIDS ...................................................... 2-64 Sampling and Analytical Procedures .......................... 2-64 National Association of Corrosion Engineers Standard Test Method TM 0173-84 .................... 2-65 X-Ray Diffraction Analysis ........................................ 2-66 X-Ray Fluorescence Analysis ................................... 2-66 Scanning Electron Microscopy ................................ 2-67 Other Procedures ...................................................... 2-67 Quality Control .............................................................. 2-67 REFERENCES................................................................... 2-69 GLOSSARY ....................................................................... 2-71

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CHAPTER 3: OIL/WATER SEPARATION ............ 3-1 PREFACE ............................................................................ 3-3 WATER QUALITY REQUIREMENTS .................................. 3-3 Injection Requirements .................................................. 3-3 Disposal Requirements .................................................. 3-5 Discharge Requirements................................................ 3-6 EOR Requirements ......................................................... 3-6 OILY WATER TREATING EQUIPMENT .............................. 3-8 General ............................................................................ 3-8 DEHYDRATION SEPARATORS ........................................ 3-10 SETTLING SKIM TANKS .................................................. 3-11 COALESCERS .................................................................. 3-12 Loose-Media Coalescers .............................................. 3-12 Fixed-Media Coalescers ............................................... 3-13 PLATE PACKS (INCLUDING SP-PACK AND VERTICAL TUBE COALESCER) ............................... 3-15 FLOTATION ....................................................................... 3-16 Dissolved Gas Flotation ............................................... 3-17 Induced or Dispersed Gas Flotation ........................... 3-18 Mechanical IGF Units ................................................ 3-19 IGF Selection ................................................................. 3-20 Eductor IGF Units ......................................................... 3-20 Dissolved Gas Flotation Units vs. IGF’s .................. 3-21 Factors Influencing Flotation Cell Performance ..... 3-21 Gas Concentration ................................................. 3-22 Salinity of Produced Water .................................... 3-22 Inlet Oil Concentration ........................................... 3-23 Temperature ............................................................ 3-23 Flotation Aids and Surface Chemistry .................. 3-24 HYDROCYCLONES .......................................................... 3-24 Design and Principle of Operation .............................. 3-25 Static Hydrocyclones ................................................ 3-25 Dynamic Hydrocyclones ........................................... 3-26 Factors Influencing Performance .......................... 3-26 Typical Performance ..................................................... 3-28 Static Hydrocyclones ................................................ 3-28 Dynamic Hydrocyclones ........................................... 3-29 Applications to Date ..................................................... 3-29 Hydrocyclone Selection ............................................... 3-30 FILTERS ............................................................................ 3-31 Downflow Sand/Multimedia Filters ............................. 3-31 Nutshell Filters .............................................................. 3-31 THE INTEGRATED TREATMENT SYSTEMS APPROACH TO COST-EFFECTIVE WATER TREATMENT ........... 3-32 PROCESS/EQUIPMENT SELECTION .............................. 3-35 MONITORING AND MEASUREMENT .............................. 3-37 General .......................................................................... 3-37 On-Line Methods .......................................................... 3-37 Infrared Light Scattering ........................................... 3-37 Infrared Light Absorption ......................................... 3-38

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Direct Absorption ................................................... 3-38 Solvent Extraction/Infrared Absorption ................... 3-39 Ultraviolet Absorption ............................................... 3-39 Laboratory Methods ..................................................... 3-40 REFERENCES................................................................... 3-41 GLOSSARY ....................................................................... 3-43 APPENDIX ......................................................................... 3-45

CHAPTER 4: FILTRATION ................................... 4-1 CHAPTER 5: SCALING AND WATER FORMED SOLIDS .............................. 5-1 INTRODUCTION ................................................................. 5-3 SCALES AND THEIR PREDICTION ................................... 5-3 Common Scales .............................................................. 5-4 Calcium Carbonate ...................................................... 5-4 Calcium Sulfate............................................................ 5-4 Barium Sulfate ............................................................. 5-7 Strontium Sulfate......................................................... 5-8 Iron Compounds .......................................................... 5-8 Predicting Scale Formation ........................................... 5-9 Solubility Calculations ................................................ 5-9 Saturation Index .......................................................... 5-9 Calcium Carbonate Scaling Calculation .................. 5-10 Calculations of Sulfate Scaling Tendencies ............ 5-11 Computer Programs for Scaling Tendency Calculations ......................................................... 5-11 SCALE PREVENTION....................................................... 5-12 Avoid Mixing Incompatible Waters .............................. 5-12 Adjusting Brine Chemistry .......................................... 5-13 Water Dilution ............................................................ 5-13 pH Control .................................................................. 5-13 Removal of Scale-Forming Gases............................ 5-13 Removal of Scale-Forming Ions ............................... 5-13 Addition of Chelators ................................................ 5-14 Environmental Controls ............................................... 5-14 SCALE INHIBITORS ......................................................... 5-14 Principle of Use............................................................. 5-14 Types of Scale Inhibitors.............................................. 5-15 Selection of Scale Inhibitors for Further Evaluation . 5-17 Scale Inhibitor Evaluation — Laboratory Performance Tests ........................................................................ 5-18 Scale Inhibitor Testing — Field Performance Monitoring ............................................................... 5-19 Application of Scale Inhibitors .................................... 5-20 Batch Treatments ...................................................... 5-20 Continuous Recirculation ......................................... 5-21 Scale Inhibitor Squeeze — Product Selection ........ 5-22 Squeeze Treatment Design ....................................... 5-24 SCALE REMOVAL ............................................................ 5-28 Scale Identification ....................................................... 5-28

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Chemical Removal ........................................................ 5-29 General Comments .................................................... 5-29 Calcium Carbonate .................................................... 5-30 Calcium Sulfate.......................................................... 5-31 Barium Sulfate ........................................................... 5-32 Iron Compounds ........................................................ 5-33 Mechanical Removal ..................................................... 5-34 Scale Removal From Surface Lines ......................... 5-34 Downhole Cleanout ................................................... 5-34 REFERENCES................................................................... 5-37 GLOSSARY ....................................................................... 5-43 APPENDIX ......................................................................... 5-47

CHAPTER 6: CORROSION EFFECTS ................ 6-1 INTRODUCTION ................................................................. 6-3 CORROSION AFFECTS WATER QUALITY ....................... 6-3 GENERAL CORROSION .................................................... 6-4 LOCALIZED CORROSION ................................................. 6-5 Pitting............................................................................... 6-5 Crevice Corrosion ........................................................... 6-6 Galvanic Corrosion ......................................................... 6-6 CORROSION RATE ............................................................ 6-7 Effect of Dissolved Gases .............................................. 6-7 Effect of Dissolved Solids .............................................. 6-9 Effect of Oil and Grease ................................................. 6-9 Effect of Flow and Suspended Solids ......................... 6-10 Effect of Water Treating Chemicals ............................. 6-10 Effect of pH.................................................................... 6-11 Effect of Temperature ................................................... 6-11 Effect of Deposits ......................................................... 6-12 MONITORING .................................................................... 6-12 Inspection ...................................................................... 6-13 Coupons and Spools .................................................... 6-13 Iron Counts.................................................................... 6-14 Electrical Resistance .................................................... 6-14 Linear Polarization........................................................ 6-15 Galvanic Probes ............................................................ 6-15 Hydrogen Monitors ....................................................... 6-16 Ultrasonic Surveys ....................................................... 6-16 CORROSION PREVENTION............................................. 6-16 Inhibitors ....................................................................... 6-18 Alloys ............................................................................. 6-18 Plastics and FRP’s ........................................................ 6-21 Cathodic Protection ...................................................... 6-21 Removal of Dissolved Gases ....................................... 6-22 Coatings ........................................................................ 6-24 Linings ........................................................................... 6-24 Pigging and Scraping ................................................... 6-25 GENERAL REFERENCES ................................................ 6-27 NACE Publications ....................................................... 6-27 Books ............................................................................. 6-27

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APPENDIX A INDEX TO CHEVRON CORROSION PROTECTION MANUAL ..................... 6-29 APPENDIX B INDEX TO CHEVRON COATINGS MANUAL............. 6-31 APPENDIX C INDEX TO CHEVRON PIPELINE MANUAL ............... 6-33

CHAPTER 7: MICROBIOLOGICAL PROBLEMS IN PRODUCTION OPERATIONS ..................... 7-1 INTRODUCTION ................................................................. 7-3 MICROBIOLOGICAL ACTIVITY CAUSES PROBLEMS .... 7-3 Plugging and Fouling ..................................................... 7-4 Microbial Reservoir Souring .......................................... 7-4 Microbiologically Influenced Corrosion ....................... 7-5 Environmental Concerns ............................................... 7-6 Chemical Consumption .................................................. 7-7 Water Chemistry ............................................................. 7-7 Formation Damage ......................................................... 7-8 MICROBIOLOGICAL ENERGETICS .................................. 7-8 MICROORGANISMS INVOLVED IN MICROBIAL PROBLEMS ................................................................ 7-11 Sulfate-Reducing Bacteria — SRB .............................. 7-11 Slime-Forming Bacteria ............................................... 7-16 Acid Producing Bacteria — APB ................................. 7-17 Iron Bacteria .................................................................. 7-17 Sulfur-Oxidizing Bacteria ............................................. 7-18 Planktonic vs. Sessile Bacteria ................................... 7-18 Planktonic Bacteria ................................................... 7-18 Sessile Bacteria ......................................................... 7-19 Bacteria Classified According to Habitat.................... 7-19 DETECTION OF BACTERIA ............................................. 7-20 Sampling Methods for Bacteria ................................... 7-21 Planktonic Bacteria ................................................... 7-22 Sessile Bacteria and Biofilms................................... 7-22 Test Procedures for Bacterial Types ........................... 7-23 Culturing Methods ..................................................... 7-23 Broth Bottles ........................................................... 7-25 Solid Culture Media ................................................ 7-26 Pour-Plate Method .................................................. 7-27 Spread-Plate Method .............................................. 7-27 Melt Agar Tube Method .......................................... 7-27 Direct Methods ........................................................... 7-28 ATP Assay ............................................................... 7-28 Epifluorescence/Cell Surface Antibody Methods. 7-29 APS Reductase Antibodies Method ...................... 7-29 Phospholipid Signature ......................................... 7-30 Radio-Respirometry ............................................... 7-30 Chemical Analysis .................................................. 7-31 Hydrogenase Enzyme Detection ........................... 7-32

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Sulfur Isotope Differentiation Method ..................... 7-32 Comparison of Field Kits for SRB ............................ 7-33 CONTROL OF BACTERIAL ACTIVITY ............................ 7-34 Bacterial Control by Mechanical Design .................... 7-35 Bacterial Control by Physical Cleaning ...................... 7-35 Bacterial Control by Chemical Cleaning..................... 7-36 Bacterial Control by Ultraviolet Radiation .................. 7-38 Bacterial Control by Biocides ...................................... 7-38 Types of Biocides ...................................................... 7-38 Biocide Selection .......................................................... 7-41 Time-Kill Procedure for Biocide Effectiveness .... 7-44 Estimation of Biocide Batch Frequency ............... 7-46 Factors Affecting Biocide Effectiveness ............... 7-47 Sessile Samples for Biocide Testing ....................... 7-49 Laboratory Recirculation Loops............................ 7-50 Field Side-Stream Test Loops ................................ 7-50 Field In-Line Probes ............................................... 7-52 Biocide Treatment Procedures ................................. 7-53 Biocide Toxicity ......................................................... 7-53 MONITORING METHODS FOR MICROBIAL ACTIVITY .. 7-55 REFERENCES................................................................... 7-57 GLOSSARY ....................................................................... 7-59

CHAPTER 8: CHEMICAL INJECTION ................. 8-1 INTRODUCTION ................................................................. 8-3 NATURAL COMPONENTS OF OILFIELD WATERS.......... 8-4 TYPES AND FUNCTIONS OF OILFIELD CHEMICALS ..... 8-5 General ............................................................................ 8-5 Scale Inhibitors ............................................................... 8-6 Corrosion Inhibitors ....................................................... 8-6 Biocides ........................................................................... 8-7 Emulsion Breakers ......................................................... 8-7 Reverse Breakers............................................................ 8-8 Coagulants and Flocculants .......................................... 8-8 Antifoamers ..................................................................... 8-9 Surfactants ...................................................................... 8-9 Paraffin Treating ............................................................. 8-9 Oxygen Scavengers ...................................................... 8-10 Sulfide Scavengers ....................................................... 8-10 Hydrate Inhibitors ......................................................... 8-11 Gas Dehydration Chemicals ........................................ 8-11 Well Stimulation Chemicals ......................................... 8-11 Acids ........................................................................... 8-11 Fracturing Fluids ....................................................... 8-12 Additives .................................................................... 8-12 Workover Fluids ............................................................ 8-13 Weighted Brines ........................................................ 8-13 Corrosion Inhibitors (see list above) ....................... 8-13 Biocides (see list above) ........................................... 8-13 Oxygen Scavengers (see list above) ....................... 8-13 Viscosifiers ................................................................ 8-13

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IONIC CHARACTER OF OILFIELD INJECTED CHEMICALS ............................................................... 8-14 CHEMICAL INTERACTIONS ............................................ 8-14 Cation/Anion Interactions Resulting in Scale Formation ..................................................... 8-15 Surfactant Interactions ................................................. 8-18 Demulsifier/Reverse Demulsifier Interactions ........ 8-19 Description of Demulsifier Chemistry ................... 8-19 Treatment Problems and Interactions ................... 8-20 Demulsifiers ......................................................... 8-20 Reverse Demulsifiers .......................................... 8-21 Other Surfactant Interactions ................................... 8-23 Biocide Reactions ......................................................... 8-24 Strong Acid Reactions ................................................. 8-24 SOME DO’S AND DON’TS WITH RESPECT TO CHEMICAL INTERACTIONS ...................................... 8-25 GLOSSARY ....................................................................... 8-27

CHAPTER 9: WATER/FORMATION ROCK INTERACTIONS ................................... 9-1 INTRODUCTION ................................................................. 9-3 Mechanisms of Formation Permeability Damage ........ 9-3 Formation Clay Deflocculation and Migration .......... 9-3 Formation Clay Structural Expansion ....................... 9-4 Mica Alteration ................................................................ 9-5 Differential Dissolution .................................................. 9-6 Dissolution and Reprecipitation .................................... 9-7 Precipitation .................................................................... 9-8 Identifying Potential Formation Permeability Damage ..................................................................... 9-8 Water and Rock Analyses .............................................. 9-9 Proper Salts and Concentrations ................................ 9-10 PREVENTING FORMATION DAMAGE IN THE FIELD .... 9-13 REFERENCES................................................................... 9-15 GLOSSARY ....................................................................... 9-17 APPENDIX ......................................................................... 9-19

CHAPTER 10: HANDLING SEPARATED WASTES ........................................................ 10-1 INTRODUCTION ............................................................... 10-3 ORIGIN OF WASTE STREAMS ........................................ 10-3 FACTORS IN HANDLING SEPARATED WASTE STREAMS ................................................................... 10-9 Minimizing Arbitrary Recycling ................................... 10-9 Incorporating Point-Source Treating Into the System Design...................................................... 10-10 Concentration of Separated Wastes ......................... 10-11 DISPOSAL OF THE SEPARATED WASTES .................. 10-14 Waste Disposal and the Environment ....................... 10-15 Environmental Regulations and Regulators ......... 10-16 Federal ...................................................................... 10-16

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State (California) ...................................................... 10-17 Local ......................................................................... 10-17 Federal ...................................................................... 10-17 State (California) ...................................................... 10-17 Classification and Relative Disposal of Wastes ... 10-18 REFERENCE ................................................................... 10-22 GLOSSARY ..................................................................... 10-23 APPENDIX ....................................................................... 10-25 INDEX ...................................................................................... I-1

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C H A P T E R

1 Introduction

Chapter 1: Introduction

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BACKGROUND Handling and treating of water in an oil field are important factors for successful, economical operation of the field. These factors become especially important as fields mature and the produced water cuts increase to levels where the volume of water treated, reinjected, or disposed of can be 10 to 50 times the volume of oil produced. Even in new, low-water-cut fields, at least as much water as oil produced may have to be treated and injected to maintain reservoir pressure and to control voidage. Enhanced oil recovery (EOR) projects require good-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 free oil from pore spaces and/or improve the sweep efficiency. 3. To be converted to steam and transfer heat needed to lower viscosity and mobilize heavy crudes. Water treating systems present some special challenges. The greatest challenge relates to the fact that oilfield waters change continually in terms of volume and chemical and physical properties. Also, because of its reactivity (corrosivity, scaling tendency, microbiological activity, etc.), water causes the treating system itself to change with time. The following discussion illustrates some problems involving water treating systems.

Water treating presents special challenges because oilfield waters change continually in volume and chemical and physical properties.

Existing Systems Designed for Old Waterfloods The system probably was designed and installed long before the current operating staff became involved. These persons are not familiar with the details and objectives of the system. The water has changed and the system has gone through multiple modifications. The system may not be able to handle the present water needs. A decision on making further modifications or designing a new system must be made. Whether the system is modified or rebuilt, it will probably have to handle increasing volumes of water. Should the new

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design be similar to the existing system? Or should it incorporate new technology? The problems with the present system must be diagnosed so that they are not incorporated into the new design or modifications. The possibility of a future EOR application may need to be considered. Input from geologists and from design and construction, gas and chemical, reservoir, and production engineers is needed for many of these decisions.

A New System To Be Installed for a New Waterflood or EOR Project A decision must be made about using a design that the operating people are familiar with or trying new technology. Again, input from geologists and from design and construction, gas and chemical, reservoir, and production engineers is needed to prevent repeating past errors; to consider capital, operating, and other costs; to anticipate future requirements; to incorporate reservoir factors; and to consider environmental concerns.

OILFIELD WATER REQUIRING TREATMENT Water Sources

Three categories of water sources are from oil or gas production, source wells, and open sources.

The waters handled in producing operations vary from field to field and during the life of any particular field. Water sources can be grouped into three general categories: oil or gas production, source wells, and open sources. Depending on the life of a waterflood, produced water is made up of a combination of natural formation waters and injected water, which itself may be a mixture of produced water, source well water, and waters from several open sources. Consequently, the proportions of these waters change during the life of the field. Likewise, salinity and other properties of the produced water change. Water from source wells is generally produced from aquifer formations separate from the reservoir being flooded. Open water sources include oceans and bays, rivers, canals, and lakes, as well as rain runoff collected on onshore fields and deck runoff from offshore platforms. Other sources of open water are waste waters generated by oilfield operations like filter backwash, induced gas

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flotation skimmings, pit water, and tank bottoms. These waters, although only a small fraction of the total water used in a field operation, are particularly detrimental to water 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 of suspended solids, oil, and/or sludge. Oilfield waters are complex mixtures that change with time and location. They require specific handling and treatment according to their intended use.

Characteristics of Waters That Affect Their Handling and Treatment The following lists give important characteristics of waters from the three sources discussed above that must be considered in their handling and treatment, whether for injection or for disposal.

Produced Waters: 1. Generally are corrosive as a result of elevated temperature and high salinity. 2. Usually contain dissolved gases (oxygen, carbon dioxide, and/or hydrogen sulfide), which increase corrosiveness. 3. Will vary in terms of physical and chemical properties with time, location, and field operations (wells shut in, brought on line, being worked over, stimulated, etc.).

Potential problems from handling produced waters include their corrosivity, variable composition, tendency to carry or form solids, and oil content.

4. Typically contain dissolved iron, which causes the water to be chemically unstable, leading to scale and/ or precipitate formation and interaction with other waters or chemical additives. 5. Contain suspended solids, including clays and other formation fines, iron sulfides, paraffins, and asphaltenes that are coated with oil, which causes them to agglomerate. 6. Contain various amounts of free oil and dissolved organic compounds.

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7. Are or readily become microbiologically active owing to the presence of dissolved organics, reducible oxygen sources, and other conditions required for biological growth. 8. Contain sufficient levels of dissolved solid to become sources of scaling solids caused by commingled waters or changes in temperature, pressure, or flow rate 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 hydrogen sulfide. 3. Have salinities and temperatures that cover wide ranges. 4. Generally have a low suspended solids content (with proper source well completion). 5. Tend not to be microbiologically active. 6. May have scaling tendencies generally caused by commingling of incompatible waters, affected by temperature, 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 high concentrations of suspended solids that may be organic or inorganic and can vary seasonally and/or with the oilfield operation that is the water source. 3. May have variable chemistry, depending on the water source. 4. Often are microbiologically active and potential sources of bacterial contamination in surface facilities, wellbores, and waterflooded formations. 5. May contain significant nutrients and reducible oxygen to facilitate bacterial growth.

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

WATER TREATMENT OBJECTIVES There usually are two general objectives for treating water in an oil field. The first is to prepare the water for injection. This could be in a conventional waterflood, as a requirement in an EOR project, or for subsurface disposal. In all three cases, filtration may be required to minimize wellbore plugging caused by suspended solids in the injected water. In addition, treatment may be needed to reduce free oil, to remove oxygen or other dissolved gases to control corrosion, to change the pH or water chemistry to allow chemicals to be added for EOR purposes, or to reduce the water hardness to prepare the water as steam generator feed. Subsurface injection for disposal may be required because of the imposition of a “zero discharge” environmental regulation. The second general objective is to prepare an oilfield water for surface disposal by discharge to an ocean, a river, a canal, or a municipal sewer system. As discharge regulations and questions of liability become increasingly strict, surface discharge will become less common (almost the exception). There are several additional objectives for treating oilfield waters. Actually, these objectives are not independent of the general objectives. 1. To control the detrimental effects of corrosion, scale formation, and biological activity on piping, tanks, other surface equipment and facilities, and downhole well equipment. 2. To recover oil and revenue lost because of ineffective oil/water separation.

Two general objectives for treating water in an oil field are to prepare the water for injection or disposal.

3. To provide the treatment required to use a water for EOR. 4. To meet the nonroutine treatment requirements for handling “special” oilfield waters (added to the injected water or disposed of separately). These special waters include:

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• Tank bottoms, sand dumps, induced gas flotation skimmings, 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 stimulation treatments. • Field or platform rain runoff. • Platform deck wash water. These special waters are best treated as small-volume “point sources” before being allowed to commingle together or with the main injection water. When commingled, their associated high solids and chemical loadings have an extreme negative impact on water quality. When handled separately, the special chemical treatment and solids removal requirements of these waters are met more effectively to minimize this negative impact. In addition, flow rates, chemistries, and solids loadings of these waters fluctuate greatly. Handling them separately (with special tanks, chemical additions, etc.) tends to level out the fluctuations before they affect the combined waters.

POSSIBLE TREATMENTS REQUIRED TO ACHIEVE OBJECTIVES Everything done to the water upstream affects everything that happens downstream. A total system approach must be taken.

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A variety of processes are available for treating oilfield waters to achieve the objectives described above. The water treating system may be as basic as adding chemicals to change the water chemistry. At the other extreme, the system could require the combination of chemical additions, tanks to provide required residence time, water softening, phase separation (filtration, oil removal), process regeneration (filter backwash, softener regeneration), and additional cleanup steps to treat waste streams (filter backwash, tank or flotation skimmings, spent regeneration brine, pit water) for disposal. Every-

Water Treatment Handbook

thing done to the water upstream affects everything that happens downstream. A total system approach must be taken. A total system approach considers the interactions of the separate parts of the system and their effect on the whole system. For example, a surfactant chemical added to the backwash to improve filter-bed cleanup could be an emulsion stabilizer. If the backwash water is returned to the system upstream of the oil/water separation equipment, the efficiency of that equipment will be lost. Or maximizing water removal from crude by adding chemicals may increase the oil content in the water to a level that fouls the filter media and destroys filter efficiency.

Treatment Objective — Injection

Filtration 1. Economical water injection requires that lives of the injection wells to be maximized. Economical justification of filtration must consider more than the capital and costs of the filters. Filtration costs must be compared with costs for drilling new wells, working over or redrilling plugged wells, or stimulating partially plugged wells. An effective stimulation treatment does more than just increase injectivity one time only. The number of times an injector can be stimulated successfully must also be considered. This includes the detrimental effects of acids on well equipment and the effect of the treatment on injection profile. There is also the question of whether permits may be secured from regulatory agencies to drill new wells. Regulations are becoming more restrictive for disposal wells. A proper decision to install filters must have input from reservoir, production, gas and chemical, and design and construction engineers, as well as from environmental coordinators.

Economical justification for filtration must consider its costs versus the benefits of increased injector life and improved waterflood sweep efficiency.

2. The need to maintain profile control (sweep) by removing the suspended solids that plug tight zones is another factor to include in considering filtration.

Chapter 1: Introduction

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3. As a general rule, a clean water handling system (with minimum suspended solids) is required to maintain good water quality for injection throughout the life of a waterflood. • Solids that drop out in pipes, tanks, process equipment, injection lines, and tubing hinder corrosion and scale inhibitor and biocide effectiveness. Thus, they reduce water quality (further accumulation of scale, corrosion, and biological reaction products). • Accumulation of solids in lines also causes water quality to decline as water flows through the system and solids are dislodged owing to pressure surges, flow-rate variations, or water chemistry changes. • Poor water quality, caused by ineffective water treatment in the early life of a waterflood with resulting accumulations of solids in the injection lines and tanks, leaves the system so dirty that subsequent installation of filters and other water treating equipment often cannot overcome the deleterious effect that the dirty system has on water quality. At that point, it is usually too late, unless special steps are taken to clean up the injection water lines and/or to install filters at the wellheads. • Similarly, a water handling system should be kept clean in anticipation of later EOR projects where water- quality requirements may be even more stringent. These earlier solids accumulations tend to slough off when they come into contact with surface-active chemicals (surfactants), carbon dioxide, miscellars, low-salinity water, and high temperatures associated with EOR.

Removal of Free Oil from Water 1. Free oil in water often is associated with sludge and agglomerated solids (iron sulfides, other scales, formation fines, paraffins, and asphaltenes) that plug injection wells.

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Water Treatment Handbook

2. Free oil interferes with scale and corrosion inhibitors and biocides, resulting in poor water quality. 3. Oil and sludge damage the efficiency of filtering. 4. Oil and sludge around an injector wellbore reduce relative permeability to water.

Effective Corrosion, Scale, and Biological Control 1. The by-products of poor control of corrosion, scale, and biological activity reduce water quality (both chemistry and suspended solids) and cause injector plugging by solids and interactions between the water and the formation rock.

Separate Treatment of Waters 1. The following are general rules for treating different oilfield waters: • Waters of different qualities (in terms of both chemistry and suspended solids) should not be mixed before treatment (or before potential interactions are identified). The quality of the resulting combined water will be no better than that of the worst water in the mixture.

Waters of different qualities should be treated separately as a “point source.”

• Treat each water separately as a “point source” of suspended solids, corrosion, scale, and bacteria. • If following the above steps is impossible and the waters are mixed before treatment, sufficient residence time must be provided (1) to allow the mixed water to come to chemical equilibrium for all interactions to occur and (2) to stabilize the water to maximize particulate formation before filtration. • Once treated by chemical or mechanical processes, waters must not be allowed to come into contact with air (oxygen). Contact with oxygen causes additional particulates (iron compounds particularly) to form. This is especially a problem with produced water. Benefits of corrosion control and filtration are nullified if contact with oxygen occurs downstream from the filters (from Chapter 1: Introduction

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

EOR Treatment Considerations in Addition to Those Listed Above 1. Added chemicals or changes made in water chemistry to meet an EOR objective may interfere or interact with chemicals added for other purposes. The result is a loss of water quality at a time when an improvement in water quality is needed for a successful EOR project. Such interferences include but are not limited to: • Surfactants counteracting (e.g., a wetting agent stripping off a filming corrosion inhibitor). • Polymers and surfactants interacting. • Biocides (aldehyde type) reacting with a polymer. • Scale and corrosion inhibitors and biocides becoming ineffective at low-pH (CO2 injection) conditions. Note that other state and federal regulations must be met, in addition to considerations for treating a water for injection. In fact, the regulations themselves may be the motivation for injection.

Treatment Objective — Surface Disposal Surface disposal is controlled by the conditions specified in a discharge permit obtained from a state or federal regulatory agency. The permit sets the environmental discharge standards and/or limits including but not limited by: 1. The “oil and grease” content (defined by the method specified for measuring the concentration of hydrocarbons/organics in the water). 2. The “toxicity” (in turn defined by the toxic effect of the water on the mortality of one or more biological species based on a test method acceptable to the state or federal agency and specified in the discharge permit).

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Water Treatment Handbook

3. A list of effluent components with maximum allowable concentrations (absolute or relative to ambient). • Effluent components include (in addition to oil and 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 oil removal and other equipment besides that needed for injection. In some cases, special processes, such as activated carbon adsorption, have been required to remove organics (e.g., phenols). Drinking water standards, groundwater protection, and air pollution controls are becoming more important in state and federal surface discharge permitting processes.

Additional Water Treatment Objectives

Corrosion, Scale, and Biological Control 1. An effective water treating program to control problems caused by corrosion, scale, and bacteria must be based on two equally important perspectives. Both the equipment and the water must be considered. First, all the field equipment — including system piping, pumps, tanks, process equipment (separators, filters, deaerators, flotation units, filters, etc.), wellheads, and tubing — need to be protected from the deleterious effects of all three problems. Second, the interrelated effects of corrosion, scale, and bacteria on the quality of water flowing through the system must be considered. For example, a corrosion rate that is acceptable in terms of equipment life may be unacceptable in terms of its effect on water quality. Dissolved iron released by corrosion reactions comes out of solution to form particulates and scale when it comes into contact with air or H2S. Suspended solids content also is increased by scale formation and biological activity.

Chapter 1: Introduction

It is important to control corrosion, scale, and bacteria growth both to protect equipment and maintain good water quality.

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2. The chemicals added to the water to control corrosion, scale, or biological activity may not be compatible. Included are surfactants of all types, polymers, reducing agents, and oxidizing agents. The combination of chemicals used and the points where they are added must be evaluated carefully.

Recovery of Free Oil in Water and Lost Revenue The value of the crude oil recovered can more than pay for the recovery equipment, plus improve the water quality.

1. The value of crude oil is an important factor in the economics of recovering additional free oil from produced water. The increased revenue from the oil is compared with the costs of installing additional oil/ water separation equipment or improving existing separation equipment through design or chemical changes. Even the choice of a filter design can be affected by the filter ’s ability to recover oil and to remove suspended solids. 2. Some equipment or operation changes to improve oil separation include the use of coalescers, improved tank design to increase residence time for better oil/ water separation, increased gas flotation capacity, a change in coalescing or coagulation chemical type or point of addition, and use of other types of separators.

Special Treatment for EOR Requirements 1. 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 water may be necessary. 2. Softening the water may require the oil and suspended solids content of the water to be reduced further to prevent fouling of the softener resin bed and solids deposition on steam generator tubes. 3. The added EOR chemicals may affect water chemistry and pH so much that the corrosion and scale inhibitors must be changed to be effective at the new conditions. Similarly, the biocide (particularly an oxidizing type) will no longer be usable in the presence of

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Water Treatment Handbook

polymers added for EOR. Also, polymers will increase the biological activity of the system, requiring re-evaluation of biocides. 4. Finally, added surfactants and pH changes for EOR will dislodge scales and other deposits from pipes and vessels. Secondary filtration or filter modifications will be needed.

Nonroutine Treatments of “Special” Oilfield Waters 1. As stated earlier, these “special” waters (tank bottoms, flotation skimmings, pit waters, spent softener regeneration brine, etc.) are best treated as smallvolume “point sources.” As such, the treatment of each water must be tailored to its specific chemical and physical properties and destination (handled separately or mixed with other waters for injection or open discharge). Consequently, a complete spectrum of mechanical and chemical treatment procedures can be involved.

OILFIELD TREATMENT METHODS AND EQUIPMENT The following outlines mechanical and chemical methods and equipment used to treat oilfield waters to achieve the objectives discussed above. The length of the list illustrates the large number of options available. Details are given in succeeding chapters. 1. Mechanical (Physical) Methods With or Without Chemicals and Heat Added A. Oil/Water Separation 1. 2. 3. 4.

Free-water knock-out vessels Two- and three-phase separators Skimmer tanks and vessels Pits

5. Coalescers 6. Combinations of coalescers and skimmers

Chapter 1: Introduction

1-15

7. Precipitators 8. Flotation units a. Dissolved gas b. Dispersed gas 9. Disposal piles (on platforms) 10. Hydrocyclones — liquid/liquid a. Static b. Dynamic B. Filtration (suspended solids) 1. “Sand” filters a. Upflow b. Downflow c. Duoflow d. High and low rate e. Single and multimedia f. Coalescing g. Horizontal and vertical 2. Precoat filters (diatomaceous earth) 3. Cartridge filters a. Disposable cartridge b. Backwashable 4. Fluidized bed, regeneration-type filters a. Walnut-shell media b. Pecan-shell media 5. Hydrocyclones — solid/liquid 6. Flotation units (see Item A-1-h) 7. Dry cake filters a. Precoat and body feed on wire-wrap screen 1. Diatomaceous earth 2. Pearlite 3. Walnut and pecan shells b. Rotary drum filters c. Plate-and-frame filters C. De-aeration (oxygen removal)

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Water Treatment Handbook

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 Chemistry) A. Surfactant Addition 1. Emulsion breakers for oil/water separation 2. Filter cleaners in backwash water 3. Relative permeability modifiers to improve water 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 2 , HSO −32 , SO −3 2 ) 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

Chapter 1: Introduction

1-17

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 organic compounds 2. Increase a. Neutralizing weak acid softener spent regenerant 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 Activated Charcoal I. Addition of Polymers 1. Filteraids 2. Coagulants 3. Polymer flood (EOR)

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Water Treatment Handbook

GLOSSARY incompatible waters — waters when mixed form solid precipitates. total system approach — considering effects in the entire treatment system.

Chapter 1: Introduction

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Water Treatment Handbook

C H A P T E R

2 Analytical and Test Methods

Chapter 2: Analytical and Test Methods

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Water Treatment Handbook

WATER ANALYSIS Reasons for Water Analysis Chevron produces roughly 10 times as much water as crude oil. This water causes many problems in producing operations and in treating for use or disposal. Waterrelated 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 type and amount of dissolved and suspended material in the water and the physical, chemical and microbiological properties of the water. Water analysis is a first step in a diagnostic procedure (1) to ascertain the possibility of problems, (2) to determine the existence of problems, (3) to test possible physical and chemical remedial treatments, and (4) to measure the effectiveness of these treatments.

Critical components: dissolved solids, suspended solids, physical, chemical, and microbiological properties.

Water is a major component of all EOR projects. In caustic and steamfloods, we must know the types and amounts of hardness and alkalinity and the total salinity to determine the type and extent of softening required to minimize the formation of plugging precipitates and fouling scale deposits in steam generators. Knowledge of hardness, alkalinity, and total salinity is necessary to predict the effectiveness and compatibility of chemical floods with surfactants or foams. With CO2 floods, knowing the changing chemistry of CO2-acidified injection water (as it moves through and reacts with the producing formation) helps us identify formation rock

Chapter 2: Analytical and Test Methods

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dissolution reactions and potential corrosion and scaling problems in producing wells and surface treating equipment. The composition of produced water can sometimes indicate the source sand or formation for the produced fluids. When compared with the compositions of injection and connate waters, produced-water composition can indicate the time and extent of injection-water breakthrough. Composition changes across a facility for production, separation, treating, and injection can pinpoint locations and types of problems. Chemical analysis can help diagnose the problems and determine the effectiveness of treatment schemes. Dissolved oxygen measurements can indicate the need for and effectiveness of mechanical and chemical de-aeration. Monitoring oil-in-water content or the types and amounts of suspended solids mirrors the performance of the chemical treatment or process equipment. It also confirms whether environmental discharge requirements are met. Because of the importance of oil-in-water concentration and suspended solids in fouling equipment and plugging injection or disposal wells, the sampling for and analysis of these two items are treated separately in this chapter. Bacteria and bacterial fouling problems are discussed Chapter 7.

Constituents Determined and Properties Measured This chapter focuses on those major components and properties of water that are important in recognizing and treating of water-related problems in producing operations. Characterizing waters for trace elements, as in an extensive geochemical analysis, is not covered. Simpler procedures and techniques are used; major components are determined; fewer properties are measured; and the emphasis is on rapid, reproducible, relatively accurate procedures and methods for “sampling” and analysis. Table 1 lists the components determined and properties measured for the purposes of problem solving. Not all components are determined nor all properties measured

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Water Treatment Handbook

in each analysis. Emphasis is on those components pertinent to the system or problem under study. Those factors of importance for each type of situation are discussed next.

Significance of Components or Properties

Cations Sodium, Na+ • Is the principal monovalent cation in most waters. • All commonly occurring sodium compounds are soluble, although sodium chloride may precipitate from highly concentrated, nearly saturated brines.

Cations are positively charged ions that moved towards the cathode in an electrolysis cell.

• Should be determined analytically, not calculated by difference, as was common in many “older” analyses. • Is the primary cation contributor to total dissolved solids (TDS) and ionic strength. • Used in cation/anion balance as a quality-control check.

Potassium, K+

Sodium ions are the major cations in normal produced or connate waters.

• Is usually present at lower concentrations than sodium. • High levels may indicate sample contamination from drilling or completion fluids. • All commonly occurring potassium compounds are soluble. • May be combined with and reported as equivalent amount of sodium ions.

Calcium, Ca2+ • Usually is the principal divalent cation. • Contributes to and may be reported as water hardness. • Combines with sulfate or carbonate ions to form suspended solids or adherent scale deposits.

Chapter 2: Analytical and Test Methods

Calcium and magnesium are the principal “hardness ions” in produced waters.

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Table 1

Primary Components and Properties of Oil Field Waters

Cations

Sodium, Na + Potassium, K 2+ Calcium, Ca 2+ Magnesium, Mg 2+ Barium, Ba 2+ Strontium, Sr 2+ Iron, Fe Hardness, as CaCO3

Anions

Chloride, Cl Salinity, Chlorinity, and Chlorosity Carbonate, CO 2-3 and Bicarbonate, HCO −3 Sulfate, SO 24− Organic Acids, as Acetate Alkalinity, as CaCO3

Dissolved Gases

Oxygen, O2 Carbon Dioxide, CO2 Hydrogen Sulfide, H2S

Neutral Components

Silica Bacterial Content Oil-in-Water Total Residue Total Dissolved Solids Suspended Solids Amount Type Particle Size Analysis

Properties

pH (field and lab) Temperature Turbidity Color Density (or Specific Gravity) Conductivity (or Resistivity)

+

-

Water Treatment Handbook

Magnesium, Mg2+ • Frequently is present in smaller amounts than calcium except in seawater or connate waters derived from seawater. • Contributes to and may be reported as water hardness. • May form insoluble magnesium hydroxide at high pH. • Readily forms ion pairs with sulfate ions, thereby decreasing the activity of free sulfate ions and increasing the apparent solubility of sulfate scales and precipitates.

Barium, Ba2+ • Is frequently found in produced waters but at a lower concentration than calcium or magnesium. • Combines with sulfate ions to form extremely insoluble barium sulfate deposits that are difficult to remove. • May indicate the presence of other radioactive alkaline earth cations (e.g., radium).

Strontium, Sr2+ • Usually is associated with but at lower concentrations than barium. • Forms insoluble strontium sulfate or mixed strontium/barium sulfate precipitates.

Iron, Fe

NORM (naturally occurring radioactive material) is usually radioactive divalent cations included in sulfate scales.

• Usually is determined and reported as soluble iron and total iron (soluble + insoluble). • May occur naturally in some waters and formations but frequently indicates corrosion of producing and treating equipment. • Is present initially in the reduced form, Fe2+ or Fe(II), in produced water.

Soluble iron may be an indication of corrosion.

• Reduced iron, Fe2+ or Fe(II), is more soluble than oxidized iron, Fe3+ or Fe(III). Chapter 2: Analytical and Test Methods

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• Reduced iron oxidizes easily by contact with air or other oxidants. • “Iron counts” are useful in detecting and monitoring corrosion only in “sulfide-free” waters. • “Red water” — suspended iron oxide and hydroxides, usually found in oxidizing environments. • “Black water” — suspended iron sulfides, usually found in reducing environments with measurable sulfide levels. • Iron sulfides and oxides cause severe formation plugging and may be difficult to remove by acidizing. • Iron sulfides are readily oxidized upon exposure to air 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 per liter (mg/L) as calcium carbonate. Calcium and magnesium are the principal hardness ions and form an insoluble scum with soaps.

• Composed primarily of calcium and magnesium ions but 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 chemical analysis or calculated by conversion of di- and trivalent cation concentrations to chemically equivalent amounts of calcium carbonate (CaCO3).

Anions Chloride, Cl• Major anion in many waters. Anions are negatively charged ions that move towards the anode in an electrolysis cell.

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• High concentrations increase water corrosivity. • Stable anion, useful for identifying and tracing water flow.

Water Treatment Handbook

Salinity, Chlorinity, and Chlorisity • Terms frequently used to describe the amount of dissolved solids, in terms of Cl- or Cl- equivalents, in seawater or waters derived from seawater by dilution or concentration. • Should not be used for waters with anion composition ratios differing from those of seawater, e.g., waters with high ratios.

Salinity

Salinity, chlorinity, and chlorisity are used only for waters similar in composition to seawater.

• Total solids after all carbonate and bicarbonate have been converted to oxide, all bromide and iodide have been replaced by the equivalent amount of chloride, and all organic matter has been oxidized. • Usually reported as grams per kilogram (g/kg) of solution or parts per thousand (ppt, ‰) • Calculated from chlorinity only for seawater and seawater-like waters by the following empirical relationship:1 salinity, ‰ = 0.03 + 1.805 x (chlorinity, ‰). • Calculated from measured chlorisity by using Table 210:IV of Ref. 2 (1980) (Pages 109-20). • Experimentally determined by measuring temperature-corrected specific gravity with a hydrometer and converting to salinity by means of density/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 precipitate the 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 ) -

Chapter 2: Analytical and Test Methods

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Chlorisity • Obtained by multiplying chlorinity by the density of water at 20°C. • Similar to chlorinity except chlorisity is a weight-pervolume concentration term.

Carbonate and Bicarbonate, CO 32 - and HCO3− • Major component (along with organic acids) of alkalinity. 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.

• Forms scale deposits with calcium ions. • Relative proportions of CO 23 − − HCO −3 − CO 2 are pHdependent. • Decomposes at high temperatures to yield carbon dioxide in the vapor (steam) phase and hydroxide ions in the liquid phase. • Carbonates are sometimes referred to as phenolphthalein alkalinity; bicarbonates as methyl orange alkalinity.

Sulfate, SO 42 − • Forms insoluble deposits with calcium, barium, strontium, and other alkaline earth cations. • Electron acceptor (oxidizing agent) in the biogenic or thermal production of hydrogen sulfide. • Barium sulfate (barite) is a common component of drilling muds and may appear as a contaminant in produced water.

“Organic Acids” Organic acids can be a carbon and energy source for bacterial activity.

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• Major component (along with carbonates and bicarbonates) of alkalinity in some produced waters. • Generally are low-molecular-weight (C2 to C4) aliphatic acids or naphthenic acids (saturated acids with five- and six-membered rings of carbon atoms).

Water Treatment Handbook

• Low-molecular-weight aliphatic acids are readily soluble in moderately basic waters. • Acetic acid (or acetate ions) is the most commonly occurring organic acid in produced water and may be present in concentrations as high as thousands of milligrams per liter. • Naphthenic acids have low water solubilities, especially at pH less than 4 to 5. • May have been formed by bacterial action or by thermal decomposition of more complex organic material 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 hydrogen ions from an acid. • Made up primarily of carbonate, bicarbonate, and organic acid anions, with minor contributions from other acid anions (e.g., bisulfide, borate, phosphate) and weak bases (e.g., ammonia). • Is a major factor in fixing the pH and buffer capacity of the water. • Is usually determined by titration with standard acid and then broken down into component parts by other analytical and calculation methods.

Dissolved Gases Oxygen, O2 • Can cause severe corrosion if present in even low levels. • Recommended levels 20 parts per billion (ppb) to minimize corrosion. • Oxidizes soluble iron to precipitate iron oxides.

Dissolved oxygen is a major contributor to the corrosivity of oilfield waters.

• Can oxidize dissolved sulfides to form colloidal sulfur. • Promotes growth of aerobic, slime-forming bacteria.

Chapter 2: Analytical and Test Methods

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Carbon Dioxide, CO2 • Acid gas that decreases pH of water. • High concentrations increase corrosion rates. • Influences formation and dissolution of carbonate scales.

Hydrogen Sulfide, H2S • Is highly toxic. Hydrogen sulfide, a toxic gas with the smell of rotten eggs, is frequently produced by bacteria in oilfield production systems.

• Acid gas that decreases pH at high concentrations. • Increases water corrosivity. • Reacts with oxygen or other oxidizing agents to form highly corrosive solution. • Causes mechanical failure of steel components. • May indicate active sulfide-producing bacterial (SPB) population. • Reacts with soluble iron to form plugging deposits; corrosive precipitates; and oil-wet, emulsion-stabilizing deposits.

Neutral Components Silica • Is usually present in low amounts ( ≅9.5 and all 2− alkalinity is due to CO 2− 3 and only CO 3 . In all other cases, use of this standard method will underestimate the weight of dissolved solids contained in the alkalinity term by up to one-half.

The criterion for acceptance based on calculated and measured TDS is 1.0 <

measured TDS < 1.2 calculated TDS

Measured TDS is more likely to be greater than calculated TDS (1) because a significant component may have been omitted in the analysis and hence in the calculated TDS or (2) because of contamination or incomplete dehydration. If the ratio of measured/calculated TDS ratio is 1.2, components in the smaller of the ion sums should be reanalyzed.

Calculated vs. Measured Specific Gravity When materials are dissolved in water, the specific gravity of the resulting solution is increased in proportion to the amount of material dissolved. The expected specific gravity of a solution can be estimated from the measured (or calculated) TDS content. Table 12 gives empirical equations for estimating specific gravity.

Specific gravity is a reliable measure of TDS only for high TDS solutions.

Patton10 (Appendix 5, Page 320) presents a graphical relationship between TDS and specific gravity. This graph has a curvature and a set of outside lines to indicate the expected spread in data. This method is not sensitive for low-TDS solutions ( alkadienes > alkenes > alkanes.

Chapter 2: Analytical and Test Methods

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Table 14

Solubility of Hydrocarbons in Water at Room Temperature

Class Alkane

Alkene

Alkyne

Cyclic

Aromatic

Compound Propane n-Hexane n-Octane Propene 1-Hexene 1-Octene 1, 5-Hexadiene Propyne 1-Hexyne 1-Octyne Cyclohexane Cyclohexene Cyclooctane Benzene Toluene Naphthalene

Formula C3H8 C6H14 C8H18 C3H6 C6H12 C8H16 C6H14 C3H4 C6H10 C8H14 C6H12 C6H10 C8H16 C6H6 C7H8 C10H 8

Solubility, ppm 62.4 ± 2.1 9.5 ± 1.3 0.66 ± 0.06 200 ± 27 50 ± 1.2 2.7 ± 0.2 169 3640 ± 125 94 ± 3 24 ± 0.8 156 ± 9 213 ± 10 7.9 ± 1.8 1780 ± 45 515 ± 17 34

Aromatic hydrocarbons are more soluble than any other hydrocarbon of the same carbon content. Using the C6 hydrocarbons as an example, solubilities can be summarized as follows: Benzene

Cyclohexene

Hexadiene

Cyclohexane

Hexyne

Hexene

Hexane

1780 ppm >

213 ppm >

169 ppm >

156 ppm >

94 ppm >

50 ppm >

9.5 ppm

Aromatics, unsaturates, and oxygen-containing organic molecules have high water solubilities.

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Hetero-atoms (e.g., oxygen, nitrogen, and sulfur) that can form hydrogen bonds with water will increase the aqueous solubility of organic molecules. This is true whether the hetero-atom is within the carbon chain (ethers and heterocyclics), at the end of a carbon chain (alcohols, aldehydes, and acids), or a side element (ketones). The carboxylic acid grouping deserves special mention. The free, un-ionized or undissociated acid, R-COOH, that exists in solutions of low pH, has a much greater solubility that the paraffin hydrocarbon with the same number of carbon atoms. In solutions of higher pH, where the

Water Treatment Handbook

acid is dissociated into its base form (R-COO-), the solubility increases by approximately three orders of magnitude over the undissociated acid form. Thus, for the C12 dodecane series, the variation in water solubilities is: Dodecanoate (Laurate), C11H 23COO -

Dodecanoic (Lauric) Acid, C11H 23COOH

Dodecane C 12H26

42,000 ppm >

55 ppm >

0.01 ppm*

* Solubilities for dodecane were estimated from Figure 4 of Reference 15. Until now, this discussion has been concerned with the solubility of the pure organic compound in water. In oilfield waters, the organic compounds are in contact with both a produced-water phase and a crude oil phase. The “soluble organics,” in this case, partition between the aqueous phase and the organic phase. The partition coefficient, which indicates the extent of distribution of a species between the two phases, is influenced by the solubilities of the species in each phase. The materials under discussion, except for the lower-molecular-weight acids in their anion (ionized or dissociated) form, R-COO-, prefer the organic (crude oil) phase to the aqueous phase. The net result is that soluble organics in the water phase, except for the acid anions, are present in the tens of ppm range, considerably less than their saturation amounts. However, the acid anion, R-COO-, has a high affinity for the aqueous phase and may be present in the thousands of ppm range.

Free Oil Crude oil may also exist as a discrete, immiscible phase in produced water. Oil droplet diameters range from submicrometers to 100 micrometers or larger. The larger droplets tend to be unstable and coalesce into still larger droplets that rapidly separate and rise to the top of the system. Although there are fewer large droplets than the small droplets, the large droplets contain the bulk of the volume or weight of the dispersed oil. Because of

Chapter 2: Analytical and Test Methods

The water solubility of most organics is affected by their tendency to partition between the produced water and the crude oil phases.

Most of the dispersed oil is contained in larger, readily separated oil droplets. Smaller droplets are more difficult to separate but contain smaller fractions of total oil.

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their size, they usually are easily removed by conventional separation equipment — gravity separators, flotation units, liquid/liquid hydrocyclones, filters, etc. The small oil droplets tend to form stable dispersions. According to Stoke’s law, the rise velocity of lighter oil droplets in water is proportional to the square of the droplet radius. The low rise velocity of small droplets is easily surmounted by convective currents within the system from temperature gradients and fluid flow and mixing. The small droplets become stirred within the system and do not rise to the top. Small drops can be stabilized and kept from coalescing to more readily separated larger drops by a variety of solid particles and added or naturally occurring surfactants. Small droplets frequently have large surface charge densities that further impede coalescence. Although the number of these droplets is high, the oil volume contained in them is usually a small fraction of the total free oil. Small droplets are difficult to remove with conventional separation equipment. Despite their small size, they may cause extensive reservoir plugging by altering the nature of the surfaces in the pores of the reservoir rock and by acting as a glue for other particulates present (e.g., corrosion products, scale particles, formation fines, spent acids, and precipitated asphaltenes).

Sampling Sampling procedures for oil-in-water analyses are very critical for obtaining results that are truly representative of the bulk water stream. Free oil readily adsorbs onto and contaminates most surfaces. All glassware used for sampling and testing should be thoroughly cleaned and then rinsed with the extracting solvent before use. Samples should be taken and stored directly in glass bottles with metal-foil-lined, screw-cap closures. Plastic containers should never be used because free oil readily adsorbs onto plastic surfaces and is difficult to remove even with repeated solvent washes. See the previous section on sampling for chemical analysis for precautions about shipping samples in glass containers.

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1. Sample from a well-mixed, flowing stream with a thoroughly flushed sample cock and lines. Do not sample from regions with low or no velocity. Samples from the upper portions of pipes and vessels may contain larger amounts of free oil than the bulk of the system because of gravity separation. 2. Fill the sample bottle nearly to the top. Do not overflow the sample bottle. Leave an air space on the top of the sample bottle. 3. Fill out the sample identification form (Table 2), label the sample bottle, and mark the position of the water meniscus on the bottle for subsequent measurement of sample volume. If the sample cannot be analyzed within a few hours, preserve it by adding 5 mL of 1:1 HCl per liter of sample and refrigerating at 4°C. 4. Collect a separate 1-L sample for the oil-in-water determination. This sample should not be used for any other analytical procedures. Do not transfer the sample to another container before analysis.

Analytical Procedures Several methods, differing in complexity, specificity to oil and possible interferences, are available. The method of choice is usually dictated by the ultimate use of the acquired data; for example, to satisfy regulatory agencies for NPDES permitting, U. S. Environmental Protection Agency (EPA) Method 413.1 must be used. A measure of free or dispersed oil (not including dissolved organics) as given by the API colorimetric method or a modification is more useful for evaluating oil water treating chemicals and equipment. Filtering the water sample before analysis is said to distinguish between free oil and dissolved oil. The unfiltered sample is said to contain “total oil” (free + dissolved); the filtrate is said to contain “dissolved oil.” This method of separation is not reliable or complete because significant amounts of free oil may bleed through the filter media and appear in the filtrate, especially when the samples contain large amounts of free oil. Multiple filtrations may be necessary to remove all the

Chapter 2: Analytical and Test Methods

The distinction between free oil and dissolved oil is not always possible in an analytical procedure.

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All oil and grease methods that use a chlorofluorocarbon solvent are being phased out because of possible detrimental effects of the solvent. Replacement solvents have not been approved as of June 1994.

EPA Method 413.1 is usually the only acceptable procedure for NPDES permits.

free oil. The additional filtration steps increase the possibility that some dissolved oil will be lost because of adsorption on surfaces.

EPA Method 413.1. Oil and Grease. Total, Recoverable (Gravimetric, Separator Funnel Extraction) The U.S. EPA Method 413.1 (Ref. 9, Page 413.1-1) is also described in APHA/AWWA/WPCF Standard Method 503A, “Oil and Grease, Partition — Gravimetric,” (Ref. 2, 15th edition, Page 461) or ASTM D 4281-83, “Standard Test Method for Oil and Grease (Fluorocarbon Extractable Substances) by Gravimetric Determination,” (Ref. 16). This method is the only one approved by and acceptable to the EPA for NPDES permits. The method involves acidifying the water sample, extracting with a fluorocarbon solvent, and gravimetrically determining the residue in the evaporated extractant. In addition to dispersed oil, the method may pick up dissolved oil, other dissolved organics, and extractable sulfur, thereby giving high results. For crude oils containing fractions with limited solubility in the fluorocarbon solvent, extraction is incomplete and low results are obtained. Light hydrocarbons (gasoline through No. 2 fuel oil fractions) and volatile extracted material may be lost during the prescribed 70°C evaporation step, again giving low results.

EPA Method 413.2. Oil and Grease. Total Recoverable (Spectrophotometric, Infrared) EPA Method 413.2 usually recovers more “oil” than does 413.1. However, it may “over recover” some component such as organic acids.

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EPA Method 413.2 (Ref. 9, Page 413.2-1) is also described in APHA/AWWA/WPCF Standard Method 503A, “Oil and Grease, Partition-Infrared,” (Ref. 2, 15th edition, Page 462) or ASTM D 3921-85, “Standard Test Method for Oil and Grease and Petroleum Hydrocarbons in Water,” (Ref. 17). Extraction procedures are the same as in EPA Method 413.1, but the amount of material in the extractant is determined by infrared spectrophotometry rather than by evaporation and gravimetric analysis. A calibration curve of infrared absorption vs. oil concentration is prepared from known amounts of the crude oil in question in the extracting solvent. If the crude oil is not

Water Treatment Handbook

available, a reference oil is prepared by mixing nhexadecane, iso-octane, and chlorobenzene. Like Method 413.1, this method will detect dispersed and dissolved oil and other organics that are extractable and have carbonhydrogen groups that absorb infrared radiation in the region of measurement. Organic acids and other extractable materials may give high results if the calibration curve is prepared from only oil or standard hydrocarbon mixtures. (Organic acids form dimers in the extracting solvent. These dimer acids have a broad absorption band in the same region as the carbon-hydrogen bands and can cause interference if the proper background level is not selected.) This method usually gives higher results than Method 413.1 because of smaller losses of volatile, light hydrocarbons. The higher results could also be due to spectral interferences of the type indicated for dimer acids. Method 413.2 cannot be used for NPDES permitting.

EPA Method 418.1 Petroleum Hydrocarbons. Total Recoverable (Spectrophotometric, Infrared) EPA Method 418.1 (Ref. 9, Page 418.1-1) is also described in APHA/AWWA/WPCF Standard Method 503E, “Hydrocarbons,” (Ref. 2, 15th edition, Page 465) or ASTM D 3921-85, “Standard Test Method for Oil and Grease and Petroleum Hydrocarbons in Water,” (Ref. 17). This method is similar to Method 413.2, except polar organic materials are removed from the fluorocarbon extract by adsorption onto silica gel before the infrared determination. This method is more specific for dispersed and dissolved oil because many other dissolved organics in water are polar enough to be removed by the silica gel. Methods 413.2 and 418.1 are frequently combined to give an oil and grease and a petroleum hydrocarbon measurement on the same sample. This method is widely used in Europe but is not acceptable in the U. S. for NPDES permitting.

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API Recommended Practice for Analysis of Oilfield Waters, API RP 45 API RP 45 colorimetric method is particularly suitable for evaluating the efficiency of separation equipment because it responds primarily to dispersed oil.

The API colorimetric method (Ref. 8) uses a chlorinated or a hydrocarbon solvent to extract dispersed and dissolved oil from an unacidified water sample. This method then determines the amount of extracted oil by colorimetry or spectrophotometry in the visible region. Because the extracting solvent is not specified and can have carbon-hydrogen bonds (as is the case with the infrared methods), a greater choice of extracting solvents is available, and extraction efficiencies or recoveries of hydrocarbon can be higher. The extracted oil must absorb radiation in the spectral region of interest. The method is more sensitive for dark crude oils. Extracted materials that are colorless (do not absorb significantly at the analytical wavelength) are not detected. Extraction is from an unacidified water sample, so many soluble, polar organic acids in the water are in the ionized (base) form. These anion forms are not extracted to a great extent. Thus, they are not detected by this method. We can control sensitivity and concentration ranges determined somewhat by properly selecting the wavelength used for the absorption measurements. This is commonly done by determining the absorption spectra while preparing the calibration curve. A calibration curve must be prepared for each oil to be determined because of wide variations in spectra and absorption coefficients of different crude oils.

Quality Control Five issues are involved in quality control for an oil-inwater analysis: 1. Sampling procedure. How representative is the analyzed sample of the system being studied? 2. Sample container material. How much of the oil in the sample is irreversibly lost to the walls of the sample container? 3. Extraction efficiency. The three EPA procedures discussed specify the extraction conditions and do not permit variations. The designated fluorocarbon solvent was chosen because of its relatively low 2-62

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toxicity (compared with carbon tetrachloride) and its lack of carbon-hydrogen bonds (a necessary condition for infrared analyses). Using this solvent also means that one specified solvent is used for all three methods. However, some crude oils are not completely soluble in or extracted by this solvent. Under these conditions, low analytical results would be expected. On the other hand, some materials other than oil, such as sulfur and certain organic acids, are soluble in and extracted by the fluorocarbon, leading to high results. Modification of the API colorimetric method permits use of a more efficient extractant as long as the extracting solvent is colorless in the region of the analytical wavelength. With the option of a more efficient and selective extractant, analytical results would be expected to be more representative of actual oil content, with less interference from colorless non-oil components extracted from the sample. 4. Test accuracy and repeatability. Measurement repeatability (precision) is best achieved by consistently and completely following a prescribed set of steps in both sampling and analysis procedures. Even when these precautions are followed, there can be considerable variations between different operators. Personal variations can be minimized by using the same personnel for all tests in a given series. Precision can be ascertained by separate analysis of replicate samples, if there is reasonable assurance that there has been no change in oil content between samples. Accuracy is more difficult to assess. Accuracy depends significantly on the type and properties of the oil in the sample, on the recovery efficiency of the extracting solvent, on the volatility of the extracted components, and on the specificity of the extracting solvent and the measurement procedure for crude oil. Accuracy would be expected to improve by using solvents with greater extraction selectivity and efficiency for crude oil components, by using measurement procedures that retain more of the volatile components in the extract, and by calibrating the method with the crude oil in question. The accuracy of these determinations cannot be measured directly

Chapter 2: Analytical and Test Methods

Accuracy — closeness of determined value to the correct or true value Precision — repeatability of measurements.

Recovery factors, rather than accuracy, are usually specified for oil and grease methods.

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for natural water samples. Recovery factors, rather than accuracy figures, are usually specified. The EPA methods list recovery factors of 93% to 99% for samples spiked with fuel oil and a vegetable oil. These factors are not representative of recovery factors or accuracy for produced-water systems where there are potentially more extractable, non-oil materials present than in the refined products used for the recovery studies. None of the described analytical procedures measures a property specific to oil. In each procedure, oil is defined as whatever is detected or measured by that method.

5. Significance of the measured quantity as truly being oil. No property specific to oil alone is measured in any of the described procedures. In each procedure, oil is defined as whatever is measured or detected by that method. Thus, EPA Method 413.1 defines oil as any weighable material, dissolved or dispersed, extracted from an acidified water sample by the fluorocarbon solvent that is not lost by volatilization or decomposition during evaporation of the extracting solvent at 70°C. The spectrophotometric method in API RP 45 gives results that are more specific to or representative of a colored crude oil itself. This is perhaps the best and simplest method for measuring dispersed oil for tests to determine separation efficiency of equipment or chemicals. This test procedure cannot be used for tests involved in NPDES permitting. The objective of a suspended solids analysis is to determine the types and amounts of suspended solids in the water. This information can suggest sources of and solutions to plugging, fouling, bacterial, corrosion, and scaling problems. This discussion focuses on gravimetric techniques to determine how much suspended solids are present and qualitative techniques to identify the types of solids. Particle-size analysis is not discussed.

SUSPENDED SOLIDS Sampling and Analytical Procedures A variety of analytical procedures can be used, depending on the type and sophistication of the information desired. The sampling procedures for all analytical methods for suspended material have one common goal:

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the amount and composition of the suspended solids sampled should be as representative as possible of those in the system sampled. Therefore, fluid flow in the system should be close to normal operating conditions. The sampling valve and lines must be thoroughly flushed with many volumes of fluid before the analytical sample is taken. For suspended material in water samples that is to be collected on a filter for subsequent analysis, filtration should be performed in the field with the filter mounted in a suitable holder and directly attached to the sampling line. If this is not practical, pressure filtration should be performed in the field immediately after sampling. Do not take the sample in a separate container and perform the filtration later. The amount and composition of suspended solids can change significantly in a relatively short time.

National Association of Corrosion Engineers Standard Test Method TM 0173-84 The National Association of Corrosion Engineers (NACE) Standard Test Method TM 0173-84, “Methods for Determining Water Quality for Subsurface Injection Using Membrane Filters”18 or a modification is frequently used to determine qualitatively and quantitatively the suspended solids (nonfilterable residue) in water. A known volume of water is filtered through a washed and preweighed membrane filter of a specified pore size (usually 0.45 µm). The solids retained on the filter are washed, dried, and weighed to give the amount of total suspended solids. The residue is then washed with a suitable organic solvent (toluene, methyl chloroform, etc.), dried, and reweighed. The weight loss upon washing with the organic solvent gives the hydrocarbon-soluble suspended solids (primarily oil and organic material). The weight loss upon subsequent washing with acid gives the acid-soluble suspended solids (primarily carbonates, acidsoluble sulfides, and iron-containing corrosion products). The residue after acid washing is the acid-insoluble suspended solids (primarily sulfate scales, acid-insoluble sulfides such as CuS and FeS2, silicates, other formation materials, and anything else that is not soluble in the organic solvent and the acid). By varying the type and concentration of acid used for washing, we can subdivide Chapter 2: Analytical and Test Methods

NACE TM 0173-84 can be used to determine the amount and the types of suspended solids in a water sample.

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the acid-soluble suspended solids into carbonates and iron compounds. The hydrocarbon-soluble suspended solids are frequently identified as dispersed oil. However, this method is not quantitative for dispersed oil because oil can bleed through the membrane filter. Dispersed oil is not completely retained by the membrane filter when the sample contains more than a few milligrams per liter of oil. Hydrocarbon-soluble suspended solids are not equivalent to dispersed oil.

Frequently, these procedures listed in this NACE standard are also used to measure water quality for injection by determining the filtration rate of a water sample through a membrane filter under specified conditions. These tests are discussed in Chapter 4. Ref. 18, included as an Appendix in Chapter 4, gives specific details for test performance and interpretation of results.

X-Ray Diffraction Analysis X-ray diffraction identifies crystalline compounds present in a solid sample.

X-ray diffraction (XRD) can be used for the qualitative identification of the crystalline, chemical compounds present in significant amounts (>1 to 2 wt%) in a sample of solid material recovered from the system. Amorphous and very finely divided solids cannot be identified because they do not give a recognizable diffraction pattern. XRD requires extensive methods development (use of internal standards, elimination or minimization of interferences and matrix effects) to quantify the amount of each compound present. In some cases, XRD has been combined with wet chemical analysis to yield better quantitative information about the mineral composition of a solid sample.

X-Ray Fluorescence Analysis X-ray fluorescence analysis identifies chemical elements in a solid sample.

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X-ray fluorescence (XRF) can determine the chemical elements in a solid sample. XRF cannot identify the chemical compounds or how the elements are combined to form compounds. Sometimes, a map of the elements present can be used to suggest the presence of a chemical compound — e.g., calcium and sulfur in close proximity may indicate a calcium sulfate compound. Low-atomicnumber elements — those with atomic numbers less than sodium (atomic number 11) — are not detected.

Water Treatment Handbook

Scanning Electron Microscopy In some cases, experienced personnel can identify the chemical compounds in a sample from the crystal size and shape using a scanning electron microscope (SEM). More frequently, the SEM is used to generate X-rays characteristic of the chemical elements present. This procedure, scanning electron microscopy/energy dispersive spectra (SEM/EDS), is similar to XRF but on a microscopic scale. SEM procedures use high vacuum, so samples must be dry and free of oil and other volatile materials.

Other Procedures Patton gives simple field tests suitable for qualitative analysis of many scale deposits (Ref. 10, Pages 90-91; Ref. 11 Pages 75-76). For more detailed characterization, specific laboratory procedures using wet chemical analysis, either alone or in combination with XRD (PETROCHEM analysis), are available for many solid components. ASTM19-23 has published various procedures for sampling and analyzing many water-formed deposits that appear in oilfield systems.

Quality Control Specific procedures to assess the accuracy and precision of suspended solids analyses are not available. Duplicate samples may show considerable variations and are not reliable as quality-control checks. Strict and reproducible adherence to established procedures will usually improve precision. Some suspended solids are unstable when dried or exposed to air. For example, iron sulfide may be pyrophoric and rapidly revert to sulfur dioxide and iron oxides when exposed to air. Samples for analysis should be fresh and/or suitably preserved so that there is reasonable assurance that we are analyzing what was originally present in the system. When identifying the composition of the solids is more important than knowing the amount of solids present, field chemical tests may be more suitable than laboratory analysis for samples that might undergo changes.

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REFERENCES 1. Ford, W. L. and Deevy, E. S. Jr.: “The Determination of Chlorinity by the Knudsen Method,” Woods Hole Oceanographic Inst., Woods Hole, MA (1946). 2. Standard Methods for the Examination of Water and Waste Water, American Public Health Assn./American Water Works Assn./Water Pollution Control Federation, 15th edition (1980) and 17th edition (1989). 3. Strumm, W. and Morgan, J. J.: Aquatic Chemistry, second edition, John Wiley & Sons, New York City (1981). 4. Thomas, N. L. and Campbell, W. L.: “Technical Memorandum. Assembly and Operation of the Automatic Pressure Filtration Apparatus,” COFRC TM89000551 (June 1989). 5. Carpenter, A. B. and Campbell, W. L.: “Introduction to Inorganic Geochemistry. Appendix C — Procedures for Sampling and Chemical Analysis of Formation Waters,” COFRC LN89000516 (1989). 6. Subcasky, W. J.: “Final Report — Evaluation of Sulfide Ion Selective Electrode,” COFRC TS88000784 (July 1988). 7. Annual Book of ASTM Standards, Section 11 — Water and Environmental Technology, American Soc. for Testing and Materials, listed annually. 8. RP 45, Recommended Practice for Analysis of Oilfield Waters,” American Petroleum Inst., Dallas (1968). 9. “Methods for Chemical Analysis of Water and Waste,” U.S. Environmental Protection Agency, EPA-600/4-79020 (March 1983). 10. Patton, C. C.: Applied Water Technology, first edition, Campbell Petroleum Services, Norman, OK (1986). 11. Patton, C. C.: Oilfield Water Systems, second edition, Campbell Petroleum Services, Norman, OK (1981). 12. Ostroff, A. G.: Introduction to Oilfield Water Technology, second edition, Natl. Assn. of Corrosion Engineers, Houston (1979).

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13. Oppenheimer, J. and Eaton, A. D.: “Quality Control in Mineral Analysis,” Proc., American Water Works Assn. Water Quality Technology Conference, Houston (Dec. 8-11, 1985). 14. Jones, L. W.: Corrosion and Water Technology for Petroleum Producers, OGCI Publications, Tulsa, OK (1988). 15. McAuliffe, C.: “Solubility in Water of Paraffin, Cycloparaffin, Olefin, Acetylene, Cycloolefin, and Aromatic Hydrocarbons,” J. Physical Chemistry (April 1966), 70, No. 4, 1267. 16. Standard Test Method for Oil and Grease (Fluorocarbon Extractable Substances) by Gravimetric Determination, ASTM D 4281-83, American Soc. for Testing and Materials (1987) 11.02. 17. Standard Test Method for Oil and Grease and Petroleum Hydrocarbons in Water, ASTM D 3921-85, American Soc. for Testing and Materials (1987) 11.02. 18. Standard Test Method — Methods for Determining Water Quality for Subsurface Injection Using Membrane Filters, Standard TM 0173-84, Item No. 53016, Natl. Assn. of Corrosion Engineers (1984). 19. Sampling Water-Formed Deposits, ASTM D 887-82, American Soc. for Testing and Materials (1987) 11.02. 20. Identification of Crystalline Compounds in Water-Formed Deposits by X-Ray Diffraction, ASTM D 934-80, American Soc. for Testing and Materials (1987) 11.02. 21. Preparation and Preliminary Testing of Water-Formed Deposits, ASTM D 2331-80, American Soc. for Testing and Materials (1987) 11.02. 22. Analysis of Water-Formed Deposits by Wavelength-Dispersive X-Ray Fluorescence, ASTM D 2332-84, American Soc. for Testing and Materials (1987) 11.02. 23. Reporting Results of Examination and Analysis of Deposits Formed From Water for Subsurface Injection, ASTM D 4025-81, American Soc. for Testing and Materials (1987) 11.02.

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GLOSSARY Accuracy — combination of bias and precision of an analytical procedure, which reflects the closeness of a measured value to a true value. Acid-insoluble suspended solids — the amount of suspended solids retained by a membrane filter after an acid wash in NACE Standard Test Method TM 1073-84. Acid-soluble suspended solids — the amount of suspended solids removed by an acid wash in NACE Standard Test Method TM 1073-84. Acidity — a measure of the capacity of a water to react with the hydroxide ions of an added base. Alkalinity — a measure of the capacity of a water to react with the hydrogen ions of an added acid. Analyte — the component or material being determine in a chemical analysis procedure. Anion — negatively charged ions in solution that move towards the anode (electrode at which oxidation occurs) in an electrolysis cell. Anion/cation balance — a primary method of checking the reliability of an analysis. This procedure is based on the fact that aqueous solutions are electrically neutral and therefore the sum of the concentrations of anions must equal the sum of the concentrations of cations (all concentration are expressed in milliequivalents per liter). Anode — electrode at which oxidation (loss of electrons) takes place. Atomic weight — relative weight of an atom of the element compared with the weight of the carbon-12 atom. Black water — suspended iron sulfides, usually found in reducing environments with measurable sulfide levels. Cathode — electrode at which reduction (gain of electrons) takes place.

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Cation — positively charged ions in solution that move towards the cathode (electrode at which reduction occurs) in an electrolysis cell. Chlorinity — term used to describe the amount of dissolved solids, in terms of Cl- or Cl- equivalents, in seawater or waters derived from seawater by dilution or concentration. Defined, in parts per thousand, as the number of grams of silver necessary to precipitate the Cl- and Br- in 328.5233 g of seawater. Chlorisity — term used to describe the amount of dissolved solids, in terms of Cl- or Cl- equivalents, in seawater or waters derived from seawater by dilution or concentration. Calculated by multiplying the chlorinity by the density of water at 20°C. Colorimetric analysis — a method of chemical analysis where the analyte is determined by measuring the amount of light of a particular wavelength (color) either emitted or absorbed by the analyte or a compound chemically equivalent to it. Also called spectrophotometric analysis. Conductivity, mho/cm or µmho/cm — a measure of the ability of an ionic solution to conduct an electric current. The standard unit of conductance is conductivity, k, defined as the reciprocal of the resistance, at a specified temperature, of a solution contained between two parallel electrodes, each 1 cm2 in cross section and 1 cm apart. The unit of k is reciprocal ohms (mhos) per cm. Conductance is now stated in siemens/cm, the SI unit, where 1 mho = 1 siemen. Density, g/mL — the weight in grams of one milliliter of solution (numerically equal to the weight in kilograms of one liter of solution). Dispersed oil — a discrete, immiscible liquid hydrocarbon phase separate from the water phase. Dissolved solids — material in a liquid sample that passes through a specified filter. Also called filterable residue.

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Duplicate samples — a quality control procedure used in chemical analysis where two samples taken at the same time from one location and submitted for analysis. Electrochemical analysis — a method of chemical analysis in which some electrochemical property of the analyte is measured and related to concentration (activity). Endpoint — the point in a volumetric analysis where the “indicator” undergoes a significant and measurable change. For accuracy in volumetric analyses, the end point and the equivalence point must be nearly identical. epm — see equivalents per million. Equivalence point — point in a volumetric analysis when the amount of added reagent is chemically equivalent to the amount of the analyte. Not necessarily equal to the end point as measured by an indicator. Equivalent weight — the weight of a compound that will react with or is chemically equivalent with some reaction standard. For acid-base reactions, the standard is the hydrogen ion; for oxidation-reduction reactions, the standard is one electron. Equivalents per million (epm) — the number of milliequivalents of the stated substance contained in one kilogram of solution. Field measurements (analysis) — sample properties and components that must be measured or determined in the field immediately after sampling because they change rapidly with time and cannot be adequately stabilized (preserved) for latter laboratory analysis. Free oil — see dispersed oil. Gpg — see grain per gallon. Grains per gallon (gpg) — the weight in grains (1 grain = 64.8 milligram) of stated substance in one gallon (1 gallon = 3.785 liter) of solution.

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Gravimetric analysis — a method of chemical analysis where the amount of the sought material is determined by weighing a separated, pure phase of known composition that either contains the sought phase or is chemically equivalent to it. Gravimetric factor — numerical factor used to convert the weight of one chemical compound to the weight of another equivalent compound. Hardness — divalent cations, primarily calcium and magnesium, in solution. Originally named for the divalent cations that form an insoluble precipitate (scum) with soap. Hydrocarbon-soluble suspended solids — the amount of suspended solids removed by an organic solvent wash in NACE Standard Test Method TM 1073-84. m — see molality. M — see molarity. Meq/L — see milliequivalents per liter. Mg/L — see milligrams per liter. mg/L as CaCO3 — see milligrams per liter as Calcium Carbonate. Milliequivalents per liter (meq/L) — the number of milliequivalents of the stated substance per liter of solution. Milligrams per Liter (mg/L) — weight, in milligrams, of the stated substance contained in one liter of solution. Milligrams per liter as Calcium Carbonate (mg/L as CaCO3) — the weight of the stated substance, in milligrams, converted to an equivalent weight of calcium carbonate and expressed in terms of 1 liter of solution. Molality (m) — the number of moles (weight of substance in grams divided by molecular weight in grams) in one kilogram of solvent. Molarity (M) — the number of moles (weight of substance in grams divided by molecular weight in grams) per liter of solution.

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Mole — an amount of a compound equal to its molecular weight. Molecular weight — relative weight of a single molecule compared with the mass of the carbon-12 atom. N — see normality. Normality (N) — the number of equivalents (weight of a substance divided by the weight per equivalent) contained in one liter of solution. Oil-in-water content — measured amount is defined by the analysis method used. Organic acids — low-molecular-weight (C2 to C4) aliphatic acids or naphthenic acids (saturated acids with five- and six-membered rings of carbon atoms), a major contributor to alkalinity in some produced waters. Oxidation — loss of electrons. Particle-size distribution — gives fraction of total number (or volume) of particles having a given size; does not estimate the total number (or volume) of particles present. Particle-size population — gives number (or volume) of particles of a given size. Particulate — suspended solids or dispersed oil in a water sample. Parts per million (ppm) — weight, in milligrams, of the stated substance contained in one kilogram of solution. Parts per thousand (ppt) — weight, in some units, of the stated substance in 1,000 weight parts of solution. pH — the negative logarithm of the hydrogen ion activity (concentration). Pure water, where the activities of the hydrogen ions and hydroxyl ions are equal, is neutral and has a pH of 7. Acid waters have pH7. ppm — see parts per million. ppt — see parts per thousand.

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Precision — a measure of the degree of agreement among replicate analyses of a sample, usually expressed as the standard deviation. Preserved samples — samples subjected to specified physical and chemical treatments that stabilize properties or components for latter analysis. Quality control — in the broadest sense, the sum total of all methods, procedures, and practices used to determine and maintain the quality of the analytical data produced by a laboratory. Here, quality control is used in a more limited sense to indicate correctness of analysis. Recovery factor — the amount of additional material determined in an analytical procedure on a spiked sample. Red water — suspended iron oxides and hydroxides in water, usually found in oxidizing environments. Reduction — gain of electrons. Resistivity, ohm-m — the opposition of an ionic solution to carry an electric current. Resistivity is equal to the reciprocal of the conductance. Salinity — term used to describe the amount of dissolved solids, in terms of Cl- or Cl- equivalents, in seawater or waters derived from seawater by dilution or concentration. Total solids after all carbonate and bicarbonate have been converted to oxides, all bromide and iodide have been replaced by the equivalent amount of chloride, and all organic matter has been oxidized. Soluble oil — crude oil, or its individual components, truly dissolved as individual molecules in produced water and existing in a single liquid phase. Specific conductance — see conductivity. Specific gravity — the ratio of the sample density to water density, each density measured at some specified temperature. Specific resistivity — see resistivity. Spectrophotometric analysis — see colorimetric analysis.

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Spiked samples — a quality control procedure used in chemical analysis where known additions of one or more of the analytes are added to regular samples. Suspended solids — material in a liquid sample retained by a specified filter. Also called nonfilterable solids. Total residue — the amount of solid material left after evaporating a water sample and drying the residue at a specified temperature, also called total solids. Total suspended solids — the total amount of suspended solids retained by a membrane filter in NACE Standard Test Method TM 1073-84. Turbidity — a measure of the cloudiness or opacity of a water sample, caused by scattering or absorption of light by particulates (suspended solids and dispersed oil). Volumetric analysis — a method of chemical analysis that determines the amount of a sought component by measuring the volume of a standard solution of known concentration that is chemically equivalent to the sought component. All volumetric analysis procedures require an indicator to determine when the equivalence point has been reached. Water quality — the sum total of the physical, chemical and microbiological properties needed for a water to be suitable for a particular application. Weight percent (wt %) — weight, in some unit, of the stated substance in 100 weight parts of solution. wt % — see weight percent. X-ray diffraction analysis (XRD) — a chemical analysis procedure be used for the qualitative identification of the crystalline, chemical compounds present in significant amounts (>1 to 2 wt %) in a sample of solid material. X-ray fluorescence analysis (XRF) — a chemical analysis procedure be used for the qualitative identification of the chemical elements in a solid sample.

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C H A P T E R

3 Oil/Water Separation

Chapter 3: Oil-Water Separation

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PREFACE This chapter discusses the removal of dispersed oil from water for reinjection, discharge, downhole disposal, or reuse in EOR projects. Much of the chapter focuses on the processes used to remove oil from water. However, like the rest of this handbook, this chapter does not give detailed design information on specific processes. The oil removal processes and technologies are explained in detail. The information presented is sufficient for selecting a specific process technology but not for designing a process in detail. An important part of this chapter is dedicated to integrated treatment systems and equipment selection. If you are designing, optimizing, or troubleshooting a water treatment facility, this philosophy will help you meet your goal of cost-effective water treatment. This chapter also forms the basis for the Chevron Oil/ Water Separation Seminar. The seminar notes, available from your colleagues who have attended, are another source of information.

WATER QUALITY REQUIREMENTS This section focuses on how clean produced water needs to be for reinjection, discharge, and use in EOR. The quality requirements for discharge are usually dictated by regulations that set an acceptable parts-per-million (ppm) level of oil in water. For injection, the water quality in terms of residual oil is not defined as well, but is usually set by the reservoir’s tolerance to oil in the injection water. For EOR, the quality is usually set by the processing facilities.

Injection Requirements The effect of residual oil in injection water on the permeability of subsurface formations is currently not well understood. In certain reservoirs, the effects of emulsion formation in the wellbore are known and injectivity loss can be predicted. However, these emulsions are not usually formed by the oil droplets in the injection fluid, but by residual oil/injection water interactions. Our

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ability to predict the effect of discrete, nonemulsified oil droplets on well injectivity lacks a scientific basis, but some general guidelines exist. The water quality required for injection into a subsurface formation varies from location to location. An acceptable quality is usually defined by the amount of permeability decline that is acceptable while the water is injected. In other words, what is an acceptable loss in injectivity, and how fast does that acceptable loss occur? Identifying this parameter will determine the type and degree of treatment required. Loss in injectivity is usually attributed to solids fouling, although the influence of oil can be significant. The effect of oil-wet solids is also not well defined, although it is usually characterized in the same manner as “normal” solids fouling — i.e., through filtration and permeability theory. Corefloods set the criteria for solids removal but are not used to determine oil removal requirements.

Traditional methods of determining acceptable water quality for injection have ignored the effects of oil. In most coreflood procedures, oil is removed from the water before it enters the core. Therefore, results from corefloods do not set a criterion for oil removal, but they do enable us to set a realistic filtration requirement and help identify any water sensitivity problems. There is no predefined limit for the amount of oil that should be injected with our waters. In the past, we set specifications based on equipment capabilities. For example, in many onshore fields, oil concentrations in injection water have been below 10 ppm, with no injectivity impairment. Therefore, 10 ppm is adopted as a specification because the flotation devices typically used to remove oil can achieve this concentration if operated correctly. In our operations, we also remove oil as a precursor to solids removal. This is done to minimize fouling of the filtration systems. Hence, some of our specifications for oil removal are not decided by the reservoir but by equipment in the treating process. It is well known that sand filters are susceptible to “mud balling.” Oil, solids, and filter material form an agglomerate that is rounded during backwash. These mud balls are often stabilized by chemical coagulants and, over

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Water Treatment Handbook

time, will cause poor filter performance. Because of mud balling, many filter manufacturers impose oil concentration limits on filter influent. These limits are specific for different types of filters but tend to range from 5 to 15 ppm. Hence, this operating restriction can set oil concentration limits. (Chapter 4 gives more details.) In most two-stage injection systems where filtration follows oil removal, injection-water oil concentrations usually range from 1 to 5 ppm and hence are acceptable for most reservoirs.

Disposal Requirements When defining disposal of oily waters, we generally talk about subsurface disposal into a specific zone or reservoir. Surface disposal of oily waters is considered discharge. Subsurface-disposal water-quality requirements are similar to those for injection. The water must meet the quality constraints set by the disposal zone. Again, injectivity loss must be minimized and filtration equipment protected. Disposal wells can be drilled into zones identified as suitable for disposal. Or existing wells within an existing reservoir can be recompleted to disposal standards. In both cases, the water will probably be treated to a low level of oil,