A typical oilfield water analysis report

Water analysis is the analysis of the water chemistry and its properties. It is perhaps the single most valuable tool for diagnosing or predicting problems in oil and gas production systems, especially scale, corrosion, reservoir management, etc. The reported values and the quality of the data can have huge implications for both capital expenditure (CAPEX) and operational expenditure (OPEX) of an asset. Quantifying water chemistry also aids in the understanding of reservoir connectivity and in characterizing transition zones in carbonates, thereby impacting estimates of reservoir extent.

What is a water analysis?

Just as a blood analysis allows a doctor to check the health of a patient, a water analysis will allow you to detect potential problems in the system and the severity of existing problems. The water analysis reports valuable data about a representative sample from a specific well/system.

This report includes:

  • The concentrations and types of minerals dissolved in the water
  • The status of specific physical properties that influence how these minerals will affect the behavior of the water in the system

The listing below summarizes the types of data usually reported on a water analysis. It includes substances that may be found in water from a petroleum reservoir and certain properties that will influence how those substances may affect the water chemistry.

  • Dissolved components
    • Cations
      • Sodium (Na+)
      • Potassium (K+)
      • Calcium (Ca++)
      • Magnesium (Mg++)
      • Manganese (Mn++)
      • Strontium (Sr++)
      • Barium (Ba++)
      • Iron (Fe++/Fe+++)
    • Anions
      • Chloride (Cl-)
      • Sulphate (SO4)2-
      • Carbonate (CO3)2-
      • Bicarbonate (HCO3) -
      • Bromide (Br)-

The water may also contain dissolved gases, such as carbon dioxide [CO2] and hydrogen sulfide [H2S], nitrogen, organic acids (acetate, propionate, butyrate etc.), sulfur-reducing bacteria, dissolved and suspended solids and traces of hydrocarbon compounds.

It is important to pay attention to the reported units. Some are reported as mg/L, while others may be reported as mg/Kg or ppm.

What do they mean?


  • Sodium is a major constituent in oilfield waters, but does not normally cause any problems. About the only exception is the precipitation of sodium chloride (NaCl) from extremely salty brines.
  • The calcium ion is a major constituent of oilfield brines and may run as high as 80,000 mg/L although its concentration is normally considerably lower. The calcium ion is of major importance because it readily combines with bicarbonate, carbonate or sulfate ions and precipitates to form adherent scales or suspended solids.
  • Magnesium ions are usually present in much lower concentrations than calcium. They tend to add to calcium carbonate scaling problems by co-precipitating with the calcium ion. It is very common to find magnesium in calcium carbonate scales. Magnesium sulfate (MgSO4) is very soluble. Consequently, it is rare to see magnesium sulfate scale.
  • By nature, the iron content of water in the formation is normally quite low. The presence of iron in the water is usually indicative of corrosion. It may be present in solution as ferric (Fe+++) or ferrous (Fe++) ions, or it may be in suspension as a precipitated iron compound. “Iron counts” are often used to detect and monitor corrosion in a water system. The presence of precipitated iron compounds is one of the major causes of formation plugging.
  • Barium is of importance primarily because of its ability to combine with the sulfate ion to form barium sulfate, which is extremely insoluble. Even small quantities can present severe problems.
  • Strontium, like barium and calcium, can combine with the sulfate ion to form insoluble strontium sulfate. Although more soluble than barium sulfate, it is often found in scales mixed with barium sulfate.
  • Manganese concentration is also often pretty low. It can be used as a good indicator for corrosion, especially in a H2S containing environment where iron can be precipitated as FeS.


  • The chloride ion is nearly always the major anion in produced brines and is usually present as a major constituent in fresh waters too. The major source of the chloride ion is sodium chloride, so the chloride ion concentration is used as a measure of water salinity. Although salt deposition can be a problem, it is often of little consequence. The primary problem associated with the chloride ion is that it increases the corrosivity of the water by making it a stronger electrolyte, or more electrically conductive. The corrosivity of the water increases as it gets saltier. Also, the chloride ion is a stable constituent and its concentration is one of the easier ways of determining if waters from separate sources have mixed.
  • The sulfate ion is a problem because of its ability to react with calcium, barium or strontium to form insoluble scales. It also serves as a “food substance” for sulfate reducing bacteria.
  • The bicarbonate ion can react with calcium, magnesium, iron, barium and strontium ions to form insoluble scales. It is present in virtually all waters. Bicarbonate ion concentration is sometimes called methyl orange alkalinity.
  • Like the bicarbonate ion, the carbonate ion can also react with calcium, magnesium, iron, barium and strontium ions to form insoluble scales. Carbonate ions are rarely present in produced waters because the pH is usually too low (<8.3). Carbonate ion concentration is sometimes called phenolphthalein alkalinity.
  • Higher concentrations of bicarbonate and carbonate ions typically indicate that the water is more alkaline.

If and when these solids precipitate out of the water, they become solids that can join together. Any cation (+) is available to join with any anion (–) to form a solid substance, such as calcium carbonate, barium sulfate, sodium chloride, calcium sulfate, etc. Some of these compounds can deposit as scale. The term salts refers to solids, not just sodium chloride (table salt). It is a general term used to refer to products formed when cations complex with anions, such as calcium chloride, iron carbonate, etc.

An important thing to remember about salts is this: The least soluble salts deposit out first.

Dissolved gases

The following list outlines a few things to consider when interpreting the effects that dissolved acid gases can have on produced water:

  • CO2 and H2S will lower the pH of the water when in solution, which makes the water more corrosive.
  • O2 has a significant effect on the corrosivity of a water – much greater than that of CO2 or H2S.
  • Also, if there is dissolved iron in the water, oxygen can enter into the system and cause that dissolved iron to precipitate out as insoluble iron oxides. These can plug equipment and flowlines, especially for water injectors.
  • Oxygen also facilitates the growth of aerobic bacteria, which can cause their own set of problems.
  • CO2 influences pH, which affects both the water’s corrosivity and calcium carbonate scaling tendency.
  • When pH is low (acidic), dissolved solids such as chlorides remain in the water, making it more electrically conductive. But when pH is high (basic), the dissolved solids will come out of solution and be available as solids that can deposit as scale.
  • Dissolved H2S will increase water’s corrosivity. The H2S may be present naturally in the water, meaning that it has resided in the formation with the water for eons, or it may be generated by sulfate-reducing bacteria.
  • If a normally sweet (free of H2S) water begins to show traces of H2S, this indicates that sulfate-reducing bacteria are probably at work somewhere in the system busily corroding holes in your piping and vessels. In addition, iron sulfide will be generated as a corrosion product, and it is a very efficient plugging agent and can cause water treating problems.

Other reported data


  • As an indicator, pH can tell you whether the water is acidic (0-6), which means it has increased corrosive tendencies, or if the water is alkaline (8-14), which means it is more conducive to scale formation.
  • As a driver, pH shares a relationship with temperature and pressure that influences whether dissolved solids and dissolve gases will remain in solution or will come out of solution. As pressure decreases, dissolved gases typically come out of solution and pH goes up.
  • Typically, pH and scaling tendencies decrease and corrosive tendencies increase when acid gases and dissolved solids remain in solution. Conversely, pH levels and scaling tendencies increase and corrosion tendencies decrease as dissolved solids and acid gases come out of the water.

Specific gravity

  • Specific gravity is a direct indicator of the total amount of solids dissolved in the water. So, by comparing the specific gravity of several waters you can quickly estimate the relative amounts of solids dissolved in the waters.

Total dissolved solids

  • The total dissolved solids (TDS) is simply the total amount of matter dissolved in a given volume of water. It can be calculated by taking the sum of the concentrations of all cations and anions shown on the water analysis report, or it can be measured by evaporating a sample of water to dryness and weighing the residue.

Total suspended solids

  • The total suspended solids (TSS) is a measurement of the amount of solids in the water that are not in solution. These are typically measured by filtering a given volume of water through a 0.45μm pore-size membrane filter. This is one basis for estimating the plugging tendency of a water. Suspended solids can settle in any part of the system and cause problems.
    • In injection wells, where suspended solids can cause plugging and other problems, guidelines typically specify that the maximum amount of total suspended solids (TSS) be no more than 25mg/L when the water is passed through a 0.45 micron Millipore membrane filter at a pressure of 20 psi.
    • Determination of the composition of the suspended solids makes it possible to ascertain their origin (corrosion products, scale particles, formation sand, etc.) so that proper remedial action can be taken. Knowledge of their chemical composition is also important from the standpoint of designing a cleanout procedure should plugging occur.


  • Turbidity simply means that the water is not “clear” and that it contains undissolved matter such as suspended solids, dispersed oil or gas bubbles. It is a measure of the degree of “cloudiness” of the water. Turbidity indicates the possibility of formation plugging in injection operations. Turbidity measurements are often used to monitor filter performance.

Water quality

  • Water quality is a measure of the relative degree of plugging which occurs when a given volume of water is passed through a membrane filter of a given pore size. A cellulose acetate filter with pore size of 0.45μm (microns) from the Millipore Corporation is most commonly used. The value of water quality testing is primarily as a comparative measurement.
  • The presence of dispersed or emulsified oil in water often presents problems when injecting produced waters. Oil in water can cause decreased injectivity in several ways. It can cause “emulsion blocks” in the formation. It serves as an excellent glue for certain solids, such as iron sulfide, thereby increasing their plugging efficiency.
  • When water is being injected into an aquifer with no initial oil saturation, oil in the water can be trapped in the pores of the formation rock around the wellbore. This creates an oil saturation, which can reduce injectivity.
  • An analysis for oil content should be conducted on any water, regardless of origin. There are many ways in which water can become contaminated with oil.
  • When produced water is disposed into surface waters, the concentration of oil in the water is usually limited by government regulation.


  • Silica occurs in most well waters and can be a serious source of scale deposition in cooling waters and in steam boilers and in steam floods. It normally does not present any problems in water injection operations.