Typical phosphonate scale inhibitors[1] to treat carbonate and sulfate scales.
Scale deposition in production tubing.

The term Scale inhibitor is used to refer to a chemical that stops or interferes with inorganic scale nucleation, precipitation and adherence to production conduit, completion system or processing facilities, the three key elements susceptible to scale problems. Scale Inhibitor performance is impacted by the pH, temperature, calcium and magnesium ion levels, and the presence of other chemicals (e.g. corrosion inhibitor) in the scaling brine mixtures. Its threshold level for a defined level of inhibition is called minimum inhibitor concentration (MIC) or minimum effective dose (MED), which is typically 0.5 to 20ppm[2]. However, the MIC for high temperature high pressure (HTHP) fields that have severe scale problems can be on the order of a few hundred ppm[3].

In oilfield, scale inhibitors are typically continuously injected via capillary or subsea umbilical tubes to the tree or downhole depending on the location and severity of the scaling risks. Alternatively periodic scale sqeeze treatments may be required to place the inhibitor in the reservoir matrix if the scaling risk occurs in the near wellbore region or at the completion.

Scale Inhibitor Chemistry

Commonly used scale inhibitors and their bio-degradation data.

Scale inhibitor chemistries used in the oil industry generally fall into three main types:

Inorganic Phosphates

These compounds are both cheap and easily prepared. They are readily soluble in water, non-toxic and effective at low treatment concentrations (typically 0.5 to 20 ppm), particularly in controlling calcium carbonate scale. However, their oilfield applications are limited because, even at fairly modest temperatures, they hydrolyse in water to form orthophosphates that have little scale inhibitor activity.

Organophosphorous Compounds

Organophosphorus compounds are degradable organic compounds containing carbon–phosphorus bonds (thus excluding phosphate and phosphite esters, which lack this kind of bonding)

Organic Phosphate Esters

Phosphate esters are more tolerant of acid conditions than polyphosphates. Stable to temperatures of 150°F-160°F (65-71°C), they can withstand temperatures of 180°F (82°C) - 200°F (93°C) for a few hours.

Within these temperature limitations, phosphate esters are generally very effective calcium carbonate (CaCO3) and calcium sulfate (CaSO4) inhibitors. Except in acid environments (pH < 5.5), they also provide excellent control of strontium sulfate (SrSO4) and barium sulfate (BaSO4) precipitation. In general, phosphate esters are soluble in and compatible with high-calcium brines.


Several different types of phosphonates are used as scale inhibitors. Each has different characteristics of thermal stability, calcium tolerance and efficiency relative to scale type. A broad range of characteristics are available because phosphonate scale inhibitors are supplied in acid form or with any portion of the acidity neutralized by ammonia, amines or alkaline hydroxides. They are commonly deployed as scale inhibitors for calcium, strontium and barium scales.

Organic Polymers

Organic polymers are chiefly crystal distorters although they also reduce precipitation in typical oilfield brines. By modifying or distorting crystal shapes, organic polymers (primarily low molecular weight polyacrylics) prevent scales from growing and adhering to equipment surfaces.

Polycarboxylic acids are commonly used in oilfield applications. Effective polymers tend to have a low molecular weight (typically 1000-5000) and have regularly spaced ionisable groups. These compounds have excellent thermal and hydrolytic stabilities. The most common classes of inhibitors include polyacrylates, polyphosphinocarboxylates, polymaleates, polyvinylsulphonates and polyacrylamides.

Stable to 400°F (204°C) or higher, polymers are generally effective at very low concentrations for control of CaCO3 and BaSO4 in waters containing low concentrations of scale-forming ions. They are also effective under acidic conditions, particularly in the control of BaSO4. Polymers are often blended with other types of scale inhibitors to obtain a single product with a broader range of applications.

Blending Scale Inhibitors

Some synergistic behaviour between different scale inhibitors (particularly the polyacrylates and phosphonates) has been observed. The reasons for this synergism could be that different chemical types act via different mechanisms. One possible explanation is that the anionic polymer chain interferes with the nucleation process whilst the smaller phosphonate molecule adsorbs onto crystal nuclei, blocking active growth sites and preventing further crystal growth.

Bio-degradation of Scale Inhibitors

Over the past several decades, the water treatment industry, as well as those applying its products, has been increasingly concerned about the environmental impact of scale inhibitors, along with that of other chemicals.

Scale Inhibitor Mechanisms

Scale Nucleation and Growth

The first stage of the scale forming process is nucleation, either in solution (homogeneous nucleation) or on a substrate (heterogeneous nucleation). Typical substrates in the oilfield include sand grains, clay (and other) minerals, metallic surfaces and scale crystals themselves (the latter called secondary nucleation). Nucleation is the creation of a sub particle or ion cluster consisting of several individual scaling ions. These form either in bulk solution or on a substrate. The size of the cluster can vary but is generally of the order of about 10 ions. Smaller ion clusters are thermodynamically unstable and break apart. Once formed, the cluster can grow along well defined crystal planes as more ions or more ion clusters become attached to the growing crystal surfaces. Once the crystal is sufficiently large, it can not be held in suspension and will fall out of the fluid due to gravity. Many crystals dropping out lead to scale deposits. Nucleation will only occur once the concentration of the scaling ions exceeds the solubility limit of the mineral scale in question within the physical conditions imposed. Scale growth can continue, gradually removing scaling ions from solutions, until the concentration of the scaling ions falls below saturation.

Inhibition Mechanisms

There are many proposed mechanisms by which scale inhibitors operate. Generally they interfere with either nucleation and/or with crystal growth. At the nucleation stage, threshold scale inhibitors bind with scale-forming ions, but unlike chelants, the bound ions must be available to interact with their counter ions. This disrupts the ion cluster at the early equilibrium stages of crystal formation, disrupting them before they reach the critical size for nucleation. As a result, the ions dissociate, releasing the inhibitor to repeat the process. At the growth stage, growth inhibitors slow the growth of the scale by blocking the active edges of the crystal.

Good crystal growth inhibitors have a strong affinity for the active growth sites, but should readily diffuse over the crystal surface to other active sites as they form. Once the inhibitor has bound to the lattice, the crystal will form much more slowly and be distorted. Often they are more rounded in shape, which makes them less likely to adhere to surfaces and more easily be dispersed throughout the system. At the deposition stage, dispersants prevent new crystals from coming together to form a large body of scale material. Dispersant-type inhibitors interact with the surface and repulse other charged particles to prevent binding.

All scale inhibitors operate in a 'threshold' manner, ie. at concentrations below the level required to react directly with scaling ions. Typical inhibitor concentrations recommended for deployment in the field would be 5-50 ppm.

Lab Evaluation of Scale Inhibitors

There are many techniques used to study scale deposition and inhibition but few testing standards have been laid down within the oil industry. Test methodologies and interpretation of results can vary widely from company to company. However, there are some common tests which are similar in approach, if not in detail, to evaluate scale inhibitor performance in the laboratory prior to deployment in the field. These are discussed below. Perhaps the single most important conclusion is that a chemical which shows excellent activity in one water chemistry may not necessarily perform well in another. That is, there is no universal scale inhibitor system.

Static Scale Precipitation Tests

This procedure is an adaption of the NACE Standard Testing Method for screening scale inhibitors. Synthetic brines (cation containing and anion containing) are prepared in the laboratory and mixed in defined ratios and pH values in the presence and absence of scale inhibitors. The brine compositions or mixing ratios are chosen to represent the variety of scale risks that may be encountered in terms of scale formation for the application of field under investigation. A common approach is to perform laboratory evaluations using the 'worst case' in terms of scaling risk as identified from computer scale predictions. Once mixed, the brines are stored at an appropriate temperature for defined time periods (usually 2 and 24 hours). After these periods the supernatant is filtered and analysed for scaling ions remaining in solution. The effectiveness of a chemical is then determined by its ability to retain scaling ions in solution compared to the supernatants from uninhibited bottles.

This test is quick and cheap and, when used in conjunction with microscopy and spectrometry techniques, can provide information on the nature of the deposit and the effect of the inhibitor on crystal growth. The test can however be less accurate for water chemistries with very high concentrations of scaling cations. If relatively small amounts of scale are deposited from these, then the difference in concentration of supernatant scaling ions could be very small compared to the magnitude of the concentration. Here, gravimetric analysis of the scale deposits themselves can be valuable.

Dynamic Scale Precipitation Test (Tube Blocking Test)

In the dynamic scale loop test, scale deposition would reduce the bore size of the test coil, indicated by an increase in pumping pressure.

Unlike the static scale precipitation test, this test takes into account the adherence of scale to pipework to certain extend. Synthetic brines (cation containing and anion containing) are pumped separately at temperature and pressure into an oven where they mix and flow through a coiled capillary tube. Any build up of scale in the coil is detected by a differential pressure transmitter which monitors the pressure drop across the coil. At a differential pressure increase of >1 psi the coil is judged to be blocked and the apparatus automatically shut down. The time taken for the coil to block in the presence and absence of scale inhibitors is noted and in this way a suitable ranking of scale inhibitors can be achieved, and optimum inhibitor dosage concentrations identified.

These tests are more complex and thus more expensive, but have the benefit in approaching field conditions of temperature, pressure and can be conducted in the presence of dissolved gases such as CO2.

Core Flood

In these tests, the main purpose is to determine the behaviour of chemical inhibitors in reservoir substrate. The test is performed primarily to simulate the injection of a scale inhibitor squeeze treatment into a sample of field core and evaluate the potential for formation damage due to the injection of a particular inhibitor or squeeze package. The test can also be used to rank inhibitors in terms of potential squeeze lifetime by analysis of effluent for residual scale inhibitor to determine when concentration falls below the MIC established in tube blocking tests. This monitoring of scale inhibitor residuals allows an adsorption/desorption isotherm to be generated which is particularly useful in designing scale inhibitor 'squeeze' treatments where the elution characteristics of scale inhibitors flowing through porous media determine the timing between successive squeeze treatments.design of scale inhibitor squeeze treatments.

Apparatus available ranges from simple core flooding at ambient conditions to full reservoir condition rigs that can operate up to 150°C and 10000psi and in the presence of live crudes. Tests of this nature are usually labour intensive, but provide vital data for optimising scale inhibitor deployment.

Scale Inhibitor Applications

Scale inhibitors should be used wherever a risk of scale damage is predicted (or known to exist from past experience). For example, inhibitors are often incorporated into drilling muds, completion brines, and process water used for sandwashing or desalting. Scale inhibitors have been used in injection water that is incompatible with the formation brine present in the zones into which the water is being injected. Continuous injection of scale inhibitors into production systems is commonly practised, and batch (squeeze) treatment of production wells is now a routine operation.

A good scale inhibitor must be:

  • Efficient: i.e. it must be able to inhibit the scale in question, irrespective of the mechanisms operating;
  • Stable: it must be sufficiently stable under the conditions imposed;
  • Compatible: it must not interfere with the action of other oilfield chemicals, nor be affected itself by them. It must be compatible with the chemical injection system under operating conditions.

In order to optimise the field performance, a chemical must be deployed correctly. For example, injection of a scale inhibitor into a production header is wasted if it does not contact incompatible waters before they mix in the production system. In some cases it may be necessary to install continuous injection facilities downhole to ensure proper deployment of scale inhibitor.

Scale Squeeze

After a well has suffers sea water breakthrough, scale formation could occur in the near wellbore region, across perforations or in the tubing. Whilst downhole injection of an inhibitor may protect the tubing, squeeze treatments may be needed to ensure protection of perforations and near wellbore. In this technique production is stopped and a concentrated solution of scale inhibitor is pumped into the well and out into the formation. After a shut in period of usually 6~24 hours, production is resumed, and the scale inhibitor leaches back into produced fluids, giving protection against scale formation until the scale inhibitor is exhausted, when the well is re-squeezed.

Following a squeeze, the concentration of scale inhibitor in produced fluids falls off exponentially. Successful treatments have as long a treatment life as possible to minimise intervention frequency and the associated costs.

There are many factors controlling the rate of inhibitor returns and effectiveness of squeeze treatments such as:

  • Adsorption/desorption behaviour of scale inhibitor on reservoir rocks and minerals. Work from Heriot-Watt university suggests a very steep rise in the adsorption isotherm at low inhibitor concentrations is a prerequisite for good squeeze lives.
  • Precipitation of scale inhibitor in the reservoir. A precipitation/resolution mechanism can increase the squeeze lifetime over adsorption/desorption treatments. However, the precipitation process must be carefully controlled in order to avoid blocking pore throats and suffering irreversible loss of chemical.
  • Entrapment of scale inhibitors in the formation for other reasons, such as changes in relative permeabilities of fluid mobilities as a result of actually applying the treatment;
  • Modification of inhibitor properties by the porous media.

Experience within the industry is increasing, and as new chemicals are developed, an improvement in squeeze treatments can be expected. Computer models have been developed, such as the Heriot-Watt SQUEEZE and ASSIST models which can be used to design or optimise squeeze treatments to maximise the lifetime before retreating becomes necessary.

Lessons Learned

  • Scale inhibitors and corrosion inhibitors can interfere with each others performance.
  • Scale inhibitor needs to be assessed for brine compatibility
  • Scale inhibitors can increase corrosion risk.


  1. S.J. Dyer, C.E. Anderson, G.M. Graham, 'Thermal stability of amine methyl phosphonate scale inhibitors", Journal of Petroleum Science and Engineering, Volume 43, Issues 3–4, August 2004, Pages 259–270
  2. K.S. Sorbie, Heriot-Watt University; N. Laing, BP Exploration, "How Scale Inhibitors Work: Mechanisms of Selected Barium Sulphate Scale inhibitors Across a Wide Temperature Range", SPE International Symposium on Oilfield Scale, 26-27 May 2004, Aberdeen, United Kingdom
  3. Chunfang Fan, Wei Shi, Ping Zhang, Haiping Lu, Nan Zhang, Sarah Work, Hamad A. Al-Saiari, Amy T. Kan and Mason B. Tomson, Rice University, "Ultra-HTHP Scale Control for Deepwater Oil and Gas Production", SPE International Symposium on Oilfield Chemistry, 11-13 April 2011, The Woodlands, Texas, USA