Dissolved Solids

Key Takeaways

• Produced water from oil and gas wells is one of the largest waste streams generated by the petroleum industry, and its TDS concentration is the primary factor determining its treatment requirements and reuse or disposal options: onshore conventional oil wells typically produce water with TDS in the range of 10,000 to 300,000 mg/L (1 to 30 weight percent dissolved salts), with deep formations producing the most saline brines; unconventional shale wells produce flowback water during hydraulic fracturing that starts as the injected fresh hydraulic fracturing fluid (TDS of 1,000-10,000 mg/L from the added salts and chemicals) and progressively increases in TDS over days to weeks as the water interacts with the formation brine, reaching TDS values of 50,000 to 300,000 mg/L in some Permian Basin Wolfcamp and Marcellus Shale wells; the disposal of high-TDS produced water is one of the most significant operational and environmental challenges in oil and gas production, with the primary disposal method in the United States being underground injection into permitted disposal wells (Class II UIC wells) that receive billions of barrels of produced water annually; the induced seismicity caused by high-volume produced water disposal injection into certain geological formations (particularly in Oklahoma, Kansas, and Texas) has prompted regulatory scrutiny and injection rate restrictions that have driven interest in alternative disposal and treatment methods including evaporation ponds (in arid regions), membrane desalination (for TDS below approximately 70,000 mg/L), crystallization and zero-liquid-discharge (ZLD) processes (for very high TDS brines), and direct reuse in hydraulic fracturing operations without treatment.
• Scale formation driven by specific dissolved ion combinations is the primary operational problem caused by dissolved solids in petroleum production systems: calcium carbonate (CaCO3) scale forms when calcium-rich produced water experiences a pressure drop (which releases dissolved CO2, raising the pH and driving carbonate precipitation), a temperature decrease (carbonate solubility increases with temperature, so cooling water can deposit scale), or mixing with bicarbonate-rich water; barium sulfate (BaSO4) scale forms when barium-containing formation water is mixed with sulfate-containing injection water (seawater contains approximately 2,700 mg/L sulfate, while formation brines in many basins contain high barium concentrations of 10-2,000 mg/L with near-zero sulfate), a common problem in offshore waterfloods where seawater injection into barium-rich formation water triggers BaSO4 precipitation in the reservoir near the waterflood front, in production wells at the water-producing perforations, and in production tubing and surface facilities; calcium sulfate (CaSO4, gypsum and anhydrite) scale forms at elevated temperatures and high calcium and sulfate concentrations typical of some deep formation waters; scale deposits reduce effective tubing and flowline diameter, impede valve operation, insulate heat exchangers, and in severe cases completely plug production tubing, requiring expensive coiled tubing intervention to mechanically remove the scale or acid treatment to dissolve it; scale inhibitor injection (typically phosphonate or sulfonate-based chemicals at dosages of 5-50 ppm) prevents scale nucleation and crystal growth at concentrations well below the stoichiometric requirement, providing economical scale prevention that is far less expensive than remediation.
• Water quality analysis for dissolved solids characterization uses a standard suite of chemical measurements to identify the ionic composition of a water sample and to predict its compatibility with other waters and its tendency to form scale or cause corrosion: the complete water analysis includes major cation concentrations (sodium by difference or flame photometry, calcium and magnesium by EDTA titration or ICP, potassium and barium by ICP or AAS), major anion concentrations (chloride by potentiometric titration, sulfate by gravimetry or ion chromatography, bicarbonate and carbonate by alkalinity titration), and a cation-anion balance check (the sum of cation equivalents should equal the sum of anion equivalents within analytical error, typically plus or minus 2-5%; a large imbalance indicates missing ions, measurement errors, or significant organic acid contribution); TDS is measured by evaporation and weighing of the dry residue (total dissolved solids by gravimetry) or calculated from the sum of the individual ionic concentrations (which typically gives a result 5-15% lower than the gravimetric measurement because the calculation does not account for dissolved gases and organic species that evaporate during the gravimetric procedure); the water analysis is used as input to scale prediction software (ScaleChem, MultiScale, and similar programs based on the Pitzer equations for high-ionic-strength thermodynamics) that calculates the saturation index of each potential scale mineral and identifies the primary scale risk for the specific produced water composition and production system conditions.
• TDS in hydraulic fracturing water management affects friction reducer performance (the ability of polyacrylamide-based friction reducers to reduce turbulent friction in the wellbore during high-rate fracturing injection, which decreases with increasing TDS because salt ions screen the electrostatic repulsion between the anionic polymer chains and prevent them from extending fully in solution), crosslinker chemistry (boron and zirconium crosslinkers used in conventional fracturing fluids form metal complexes with guar polymer that are sensitive to ion concentrations and pH, and high TDS from produced water reuse requires reformulation of crosslinker packages), and biocide requirements (high TDS brines may require higher biocide dosages to control SRB and other bacteria that have adapted to saline environments): the increase in produced water volumes from unconventional wells has driven the oilfield services industry to develop water-tolerant friction reducers (slickwater additives that maintain performance at TDS up to 300,000 mg/L) and borate crosslinkers that function in produced water without requiring full dilution to fresh water TDS levels; operators who can reuse produced water with minimal treatment for hydraulic fracturing avoid both the cost of fresh water acquisition (a significant logistical challenge in the water-scarce Permian Basin) and the cost of produced water disposal into injection wells, improving the overall economics of unconventional well development.
• Salinity and TDS measurement methods include multiple techniques with different precision, cost, and applicability to field versus laboratory settings: electrical conductivity (EC) measurement (using a conductivity meter) provides a rapid estimate of TDS from the linear relationship between ion concentration and electrical conductivity (TDS in mg/L is approximately 0.55-0.7 times the conductivity in microsiemens per centimeter for most oilfield brines), suitable for real-time field monitoring but requiring a salinity-specific calibration factor for each brine composition; refractometry (measuring the bending of light as it passes through the brine, which depends on the dissolved solids concentration) provides a rapid field measurement of TDS in the range of 0-10% by weight, adequate for freshwater to moderate-salinity brines but insufficiently precise for high-salinity produced water; gravimetric TDS measurement (laboratory evaporation of a known sample volume and weighing of the dry residue) is the most accurate method for absolute TDS determination but requires laboratory facilities and is time-consuming; downhole formation water sampling using wireline formation testers (MDT, RCI) or drillstem tests provides in-situ formation brine samples at reservoir conditions, which when analyzed in the laboratory give the native TDS and ionic composition of the formation water without the contamination and dilution that can affect produced water samples from wells that have experienced drilling mud filtrate invasion or produced water mixing from multiple zones.