Scales are deposits of many chemical compositions as a result of crystallization and precipitation of minerals from the produced water. The most common scale is formed from calcium carbonate. Scale is one of the most common and costly problems in the petroleum industry. This is because it interferes with the production of oil and gas, resulting in an additional cost for treatment, protection, and removal. Scale also results in a loss of profit that makes marginal wells uneconomical. Scale deposition can be minimized using scale inhibition chemicals.
Anti-scale magnetic treatment methods have been studied for the past several decades as an alternative. Acid washing treatments are also used for removal of scale deposits in wells. The solubility of individual scale species is dependent on the equilibrium constants of temperature and pressure; the activity coefficients, which are dependent on concentrations plus the temperature and pressure of each individual species; the bulk ionic strength of the solution; and the other ionic species present. Once the solution exceeds the saturation limit, scale will begin to precipitate.
- 1 Oilfield Scales
- 2 Operational Problems Due to Scales
- 3 Scale Management Options
- 4 Scale Inhibitors
- 5 Scale Control in Subsea Field
- 6 References
Oilfield scales are generally inorganic salts such as carbonates and sulfates of the metals calcium, strontium, and barium. Oil field scales may also be the complex salts of iron such as sulfides, hydrous oxides, and carbonates. Oil field scales may form in one of following two ways:
- Due to the change of temperature or pressure for brine during production, the solubility of some of the inorganic constituents will decrease and result in the salts precipitating.
- When two incompatible waters (such as formation water rich in calcium, strontium, and barium and seawater rich in sulfate) are mixed.
Scales formed under these conditions are generally sulfate scales.
Calcium carbonate, the most common scale in oil and gas field operations, occurs in every geographical area. Calcium carbonate precipitation occurs when calcium ion is combined with either carbonate or bicarbonate ions as follows,
The preceding equations show that the presence of CO2 will increase the solubility of CaCO3 in brine. IncreasingCO2 alsomakes thewatermore acidic and decreases the pH. The calcium carbonate scaling usually occurs with a pressure drop, for example, at the wellbore. This reduces the partial pressure of CO2, thereby increasing the pH and decreasing the CaCO3 solubility. The solubility of calcium carbonate decreases with increasing temperature.
Calcium SulfateThe precipitation of calcium sulfate is given by the reaction
is the most common scale in oil field brines. It is associated with lower temperatures. Anhydrite (CaSO4) may occur at high temperatures. Theoretically, anhydrite would be expected to precipitate above 100 F in preference to gypsum because of its lower solubility. However, gypsum may be found at temperatures as high as 212 F. With the passage of time, gypsum will dehydrate to anhydrite.
Barium SulfateThis scale is especially troublesome. It is extremely insoluble and almost impossible to remove chemically. Barium sulfate scaling is likely when both barium and sulfate are present, even in low concentrations.
Barium sulfate scale is common in North Sea and GoM reservoirs. These fields often have barium in the original formation brine. Seawater injection (high sulfate concentration) for secondary oil recovery causes the scale problem. As the water flood matures and the seawater breaks through, these incompatible waters mix and a barium scale forms. Generally, barium sulfate solubility increases with temperature and salinity. Similar to gypsum, BaSO4 solubility increases with an increase in total pressure and is largely unaffected by pH.
Strontium sulfate is similar to barium sulfate, except fortunately its solubilityis much greater:
Strontium sulfate solubility increases with salinity (up to 175,000 mg/L), temperature, and pressure. Again, pH has little effect. Pure strontium sulfate scale is rare except for some fields in the Middle East. SrSO4 deposits in producing wells where the strontium-rich formation water mixes with the sulfate-rich injected seawater.
Operational Problems Due to Scales
Scale deposits are not restricted to any particular location in the production system, although some locations are more important than others in terms of ease and cost of remedial treatment. The following are areas or events where scale formation is possible in production systems.
Scale can cause problems at this early stage if the drilling mud and/or completion brine is intrinsically incompatible with the formation water. For example, allowing a seawater-based mud to contact a formation water rich in barium and strontium ions would be undesirable, similar to allowing a high calcium brine to contact a formation water rich in bicarbonate.
Scale problems may be encountered when new water injection wells are commissioned if the injection water is intrinsically incompatible with the formation water. For example, seawater injection into an aquifer rich in strontium and/or barium ions could cause problems.
As soon as a well begins to produce water, the risk of carbonate scale formation arises, assuming that the produced water has a tendency to precipitate carbonate scale. The severity of the problem will depend on the water chemistry, the rate of drawdown, and other factors such as pressure and temperature.
HP/HTreservoirs have some potentially unique scaling problems due to the following characteristics:
- Total dissolved solids (TDS) up to 300,000þ ppm;
- Reservoir temperatures in excess of 350 F (175 C);
- Reservoir pressures in excess of 15,000 psi. Examples are the Eastern Trough Area Project and Elgin/Franklin
reservoirs in the North Sea.
Scale Management Options
Scale can be managed in several ways:
- Prevent deposition by using scale inhibitors, etc.
- Allow scale to form, but periodically remove it.
- Use pretreatments that remove dissolved and suspended solids.
The typical way of preventing scale deposition in oil field production is through the use of scale inhibitors.
Scale inhibitors are chemicals that delay or prevent scale formation when added in small concentrations in water that would normally create scale deposits. Use of these chemicals is attractive because a very low dosage (several ppm) can be sufficient to prevent scale for extended periods of time for either surface or downhole treatments. The precise mechanism for scale inhibitors is not completely understood but is thought to be following:
- Scale inhibitors may adsorb onto the surface of the scale crystals just as they start to form. The inhibitors are large molecules that can envelop these microcrystals and hinder further growth. This is considered to be the primary mechanism.
- Many oil field chemicals are designed to operate at oil/water, liquid/gas, or solid/liquid interfaces. Since scale inhibitors have to act at the interface between solid scale and water, it is not surprising that their performance can be upset by the presence of other surface active chemicals that compete for the same interface. Before deployment, it is important to examine in laboratory tests the performance of a scale inhibitor in the presence of other oil field chemicals.
- Because these chemicals function by delaying the growth of scale crystals, the inhibitor must be present before the onset of precipitation. Suspended solids (nonadherent scales) are not acceptable. This suggests two basic rules
in applying scale inhibitors:
(1) The inhibitor must be added upstream of the problemarea.
(2) The inhibitor must be present in the scalingwater on a continuous basis to stop the growth of each scale crystal as it precipitates.
Types of Scale Inhibitors
The common classes of scale inhibitors include:
- Inorganic polyphosphates;
- Organic phosphates esters;
- Organic phosphonates;
- Organic polymers.
Scale Inhibitor Selection
Following are criteria for the selection of scale inhibitor:
- Compatibility. The inhibitor must not interfere with other oil field chemicals nor be affected by other chemicals.
The detailed factors in the selection of scale inhibitor candidates for consideration in the performance tests include:
- Type of scale: The best scale-inhibitor chemistry based on the scale composition should be selected.
- Severity of scaling: Fewer products are effective at high scaling rates.
- Cost: Sometimes the cheaper products prove to be the most cost effective; sometimes the more expensive products do.
- Temperature: Higher temperatures and required longer life limit the types of chemistry that are suitable.
- pH: Most conventional scale inhibitors perform less effectively in a lowpH environment.
- Weather: The pour point should be considered if the inhibitor will be used in a cold-climate operation.
- Chemical compatibility: The scale inhibitor must be compatible with other treatment chemicals, such as oxygen scavengers, corrosion inhibitors, and biocides.
- Application technique: This is most important if the inhibitor is to be squeezed into the formation.
- Viscosity: This is important when considering long umbilical applications such as in remote subsea fields.
Scale Control in Subsea Field
The production wells of a HP/HTreservoir in the G0M have a potential for barium sulfate scale deposition in the formation at the near-wellbore location or within the tubing. These deposits occur due to mixing of injection seawater and formation water. Sulfates in the injected seawater react with naturally occurring barium in the formation water to induce barium sulfate scale. Barium sulfate is not soluble in acid, so prevention rather than remediation by acid treatment is the key.
- If left untreated, barium sulfate scale is likely to form downhole and possibly in the formation after produced water breakthrough. These areas are not treatable with continuous downhole chemical injection. For this reason the treatment method will consist of periodic batch scale squeeze treatments into each production well. It is estimated that each
production well will require treatment once per year.
- The barium sulfate scale control will depend on accurate well testing and analysis of produced fluids to detect whether there is adequate scale inhibitor in the near-wellbore area in order to prevent the formation of the scale. Well tests and fluid analysis will be required for each well at a frequency of once every 2 weeks.
Manifold and Pipeline
Both barium sulfate and calcium carbonate scale formation may occur at the manifold and in the pipelines due to comingling of incompatible produced waters from different reservoirs. Deposition in these areas will be controlled by scale inhibitor injection at the subsea tree. Scale inhibitor injection is required upstream of the subsea choke.
 C. de Waard, U. Lotz, D.E. Milliams, Predictive Model for CO2 Corrosion Engineering in Wet Natural Gas Pipelines, Corrosion vol. 47 (no12) (1991), pp. 976–985.
 Norwegian Technology Standards Institution, CO2 Corrosion Rate Calculation Model, NORSOK Standard No. M-506, 2005.
 R. Nyborg, Controlling Internal Corrosion in Oil and Gas Pipelines, Oil and Gas Review(Issue 2) (2005).
 A. Dugstad, L. Lunde, K. Videm, Parametric Study of CO2 Corrosion of Carbon Steel, Corrosion/94, NACE International, paper no.14, Houston, TX, 1994.
 National Association of Corrosion Engineers, Metals for Sulfide Stress Cracking and Stress Corrosion Cracking Resistance in Soul Oilfield Environments, NACE MR 0175 (December 2003).
 www.corrosion-doctors.org/Inhibitors/lesson11.htm.  D.A. Jones, Principles and Prevention of Corrosion, first ed., McMillan, New York, 1992, pp. 437–445.
 E.D. Sunde, Earth Conduction Effects in Transaction Systems, Dover Publishing, New York, 1968, pp. 70–73.
 Det Norsk Veritas, Cathodic Protection Design, DNV RP B401, 1993.
 W.H. Hartt, X. Zhang,W. Chu, Issues Associated with Expiration of Galvanic Anodes on Marine Structures, Paper 04093, Corrosion (2004).
 K. Bethune, W.H. Hartt, A Novel Approach to Cathodic Protection Design for Marine Pipelines: Part II -Applicability of the Slope Parameter Method, presented at Corrosion, paper no.00674, 2000.
 International Organization for Standardization, Pipeline Cathodic Protection-Part 2:Cathodic Protection of Offshore Pipelines, ISO/TC 67/SC 2 NP 14489, Washington, D.C, 1993.
 DeepStar, Flow Assurance Design Guideline, 2001.