Corrosion Inhibitors | oilfield-chemicals

Corrosion

CORROSION CONTROL PRODUCTS

Weschem Production Technologies Ltd. manufactures a wide variety of corrosion inhibitors that control each of the following types of corrosion:

SOUR CORROSION

SWEET CORROSION

OXYGEN CORROSION

BACTERIAL CORROSION

H2S SCAVENGERS

EROSION CORROSION

Weschem Production Technologies Ltd.. manufactures the following types of corrosion inhibitors

OIL SOLUBLE INHIBITORS

OIL SOLUBLE, WATER DISPERSIBLE INHIBITORS

WATER SOLUBLE INHIBITORS

WATER SOLUBLE, OIL DISPERSIBLE INHIBITORS

VAPOUR PHASE INHIBITORS

NEUTRALIZING INHIBITORS

Weschem Production Technologies Ltd corrosion control products are used by the following types of industries:

REFINERIES

METAL WORKING INDUSTRIES

WATER TREATING

OIL AND GAS PRODUCTION

SERVICE AND TECHNICAL EXPERTISE

Weschem Production Technologies Ltd will analyze your application to help determine the most effective and economical methodology and product.

CORROSION CONTROL GENERAL DISCUSSION

CORROSION is defined as the deterioration of a metal or its properties because of electrochemical reaction with its environment.

Before corrosion can occur, there must be both anodes and cathodes present to form a corrosion cell. The anodes and cathodes must be connected or in contact so that a current can flow and there must be an electrolyte (water) present to complete the circuit or cell.

Metal dissolves at the anode and forms water soluble ions. This releases electrons, which flow through the metal to the cathode. Electrons are removed at the cathode by reaction with the cations (such as hydrogen) in solution. This completes the circuit of electrical current flow and allows corrosion to proceed.

The corrosion rate is affected by environmental characteristics such as temperature, salts, and other dissolved solids, pressure, fluid velocity, deposits such as scale and paraffin, and the oil/water ratio.

Corrosion can be controlled or stopped by prevention of the cathodic reaction, removal of the electrolyte or by isolating the electrolyte from the anode and cathode. Controlling the anodic reaction by passivation is difficult and dangerous.

CORROSION encountered in the oilfield can be generally be classified as either:

1.) Electrolyte and galvanic corrosion

2.) Sweet corrosion

3.) Sour corrosion

4.) Oxygen corrosion

5.) Bacterial corrosion

6.) Erosion corrosion

ELECTROLYTE CORROSION occurs when there is a difference in potential between two areas on a metal surface or object. This can be caused by strong currents from an external source or from an oxygen concentration cell or differential - one area higher in oxygen concentration than another

GALVANIC CORROSION is similar in that higher than normal corrosion current is flowing, however, it is caused by dissimilar metals in contact, or between areas of different potential on a metal surface caused by non-homogeneous metallurgy. Electrolytic and galvanic corrosion may be severe and are often difficult to control with inhibitors.

SOUR CORROSION is the result of hydrogen sulfide reacting with steel:

Fe + H 2 S ( H20) FeS ¯ + H2

(water must be present for the reaction to proceed).

SWEET CORROSION is caused by the presence of organic or mineral acids or by dissolved carbon dioxide (carbonic acids) which react with steel as follows.

Fe + C02 + H20 ® Fe (HCO2) 2 + H2

Sweet corrosion is usually in the form of generalized attack over the entire surface, or localized shallow attack , usually free from corrosion deposits.

In addition to severe metal loss and deep pitting, the steel may be embrittled by absorption of the liberated atomic hydrogen into the grain boundaries. This is signified by cracking and blistering of the metal (called hydrogen embrittlement). Sulfide Stress Corrosion (SSC) is also found in sour systems.

OXYGEN CORROSION is caused by the reaction of oxygen with a metal in water or a moist atmosphere:

2 Fe + 02 + H20 ® Fe2 03 + H2

Most oil production does not normally contain oxygen, but it can be introduced into closed systems by pump suction leaks, inadequate blanketing of tanks, systems on vacuum and wells pumping off. The presence of trace amounts of oxygen greatly aggravates other types of corrosion be depolarizing the cathodes (reacting with and removing the hydrogen film normally formed). This increases the cathodes reaction and the corrosion rate.

Oxygen corrosion is typified by heavy attacks and pitting in crevices, underneath scale, or other areas where oxygen concentration cells can be formed. Oxygen should be removed from the system by chemical scavenging agents or deaeration, since most inhibitors are ineffective in controlling oxygen corrosion.

BACTERIAL CORROSION is caused by the presence of micro organisms such as sulfate reducing bacteria, iron bacteria and slime-forming- bacteria

Sulfate reducers are anaerobic (live in the absence of oxygen). They remove hydrogen from the metal surface and use it to reduce sulfate present in the water to corrosive hydrogen sulfide. Removal of hydrogen increases the cathodic reaction and the hydrogen sulfide formed greatly increases corrosion attack.

Iron bacteria and other aerobic (live in the presence of oxygen) micro organisms that form deposits cause corrosion be setting up differential and oxygen concentration cells underneath the deposits. Once the deposits are set up, the anaerobic area underneath may support the growth of sulfate reducing bacteria.

Bacterial corrosion usually causes localized attack and pitting, but positive identification of the offending type of organism is required for confirmation.

EROSION CORROSION is caused by the movement of high velocity gases, liquids and/or solids over the surface to be protected, usually at high velocities in a manner that removes the metal and any protective surface. Usually this will also mechanically remove any chemical inhibitor, unless the inhibitor itself is extremely tenacious.

CHEMICAL TREATMENT of corrosion involves utilizing properties of chemical compounds to greatly reduce or eliminate the corrosion reaction, the flow of corrosion current and /or to terminate bacterial growth.

The best chemical treatment with amine film-forming corrosion inhibitors can be obtained by preventing the anodic corrosion cell reaction. These amines greatly reduce or eliminate the anodic corrosion cell reaction by chemically absorbing on to the metal surface and isolating it electrically from the electrolyte (water).

Weschem Production Technologies Ltd. corrosion inhibitors form a tough persistent film on metal surfaces that effectively prevents corrosion when applied properly. In order to achieve maximum and economical protection, there must be enough inhibitor used initially to completely cover all steel surfaces. After initial application and filming, enough inhibitor must be added as required to replenish portions of the film that have been desorbed, eroded or washed away.

APPLICATIONS:

Corrosion inhibitors are applied to achieve filming and replenishing of the film. The different types of application are batch treatment, continuous treatment and squeeze treatment or variation thereof.

BATCH TREATMENT:

STANDARD BATCH ordinarily used in producing wells that do not have packers installed. The inhibitor is introduced into the annulus by dumping by hand, pumped from a truck, or by a lubricator. (This operation is sometimes automated to respond to corrosion detection devices). The well is circulated completely or partially down the annulus. The inhibitor can be added undiluted or diluted with a suitable solvent such as diesel, crude oil, brine, or fresh water.

Dilution rate is usually 1 part inhibitor to 10 parts solvent or diluent. At least 1,000 ppm inhibitor should contact the surface to be treated. Depending upon the severity of corrosion and other requirements, the well is circulated at least one time, and longer when needed to achieve filming. The well is treated often enough to maintain protection, consistent with severity of attack and production rate.

ANNULUS SLUG

Consists of the dumping of water or brine dilution of a water soluble or water dispersible (Dilute inhibitor 1:9 with water or brine). This allows the mixture to fall through the oil in the annulus and be produced back up the tubing. Treating rate is usually more frequent than the standard batch. No production time is lost because the well is not circulated.

EXTENDED BATCH TREATMENT

High fluid level wells can be treated successfully by dumping a high concentration (1 to 3 drums) of inhibitor down the annulus and circulating the inhibitor around one time, leaving the inhibitor in the annulus. The inhibitor then feeds back slowly to replenish the film. Frequency of treating and treating rate is determined by monitoring corrosion rates with coupons or probes. Pipelines can be batch treated by pushing a solution of inhibitor and suitable diluent between two pigs down the line. The inhibitor should be diluted from one part inhibitor to ten to twenty parts of diluent.

CONTINUOUS TREATMENT

Pipelines, flowlines, injection wells, and producing wells can be treated continuously by injecting inhibitor directly into the system at a rate of 10 to 100 parts per million based upon flow or production. In producing wells the inhibitor can be injected into a line that by-passes a small fraction of the production back into the annulus or down a macaroni string.

Chemical can be injected through an atomizer into gas pipelines and gas lift systems at 1/4 to 1 litre of inhibitor per each million cubic feet of gas.

Inhibitor can also be added to power oil of subsurface hydraulic pumps.

SQUEEZE TREATMENT

Wells can be squeeze-treated by pumping inhibitor directly into the producing formation. Tests should be conducted on the formation to ensure that the well is not plugged or killed. Treating rates are usually from once every two to three months to once every eighteen months.

Inhibitor (from 1 to 10 drums) is dissolved in a suitable diluent at 10 to 25% concentration and displaced down the tubing into the formation. It should be over-flushed with from 25 to 100 barrels of diluent to place the inhibitor back away from the wellbore.

Emulsion tendencies of the crude and inhibitor should be checked and , if necessary, 5 to 25 gallons of demulsifier added to the inhibitor solution. The amount of inhibitor required is based upon the desired concentration in the produced fluid and the production rate of the well.

After the well is squeezed it is shut in for 24 hours. After being put back on production, the inhibitor concentration will be high initially, which films the system, and drops off quickly to a steady return rate that constantly replenishes the film.

The treatment is monitored by amine counts in the produced fluid, corrosion coupons and/or probes.

TUBULAR DISPLACEMENT

Wells that cannot be squeezed and have packers can be treated by tubular displacement. This method is similar to squeezing, only without the overflush. Typically, a 10% solution of inhibitor in the displacement fluid is used to fill the tubing from the perforation to the surface. Leave the well shut-in for 3 to 6 hours after the displacement is accomplished.

Depending on the severity of corrosion and the total volume of fluids, tubular displacement can be effective from 1 month to 6-9 months. Iron counts, corrosion coupons and amine residuals can all be used to monitor the well.

RECOMMENDED TREATMENTS:

FLOWING OIL WELLS can be treated by tubing displacement, squeezing or annular slug for wells not completed with a packer.

GAS LIFT WELLS can be treated by tubing displacement, squeezing, or continuous treatment by injecting inhibitors into the lift gas.

PUMPING WELLS can be batch treated, squeezed and treated continuously.

HIGH RATE PRODUCTION WELLS (over 100 bbls/day) can be treated by standard and extended batch treatments.

LOW PRODUCTION RATE WELLS with low fluid levels may be treated with annular slugs, and low production rate wells with high fluid levels can be treated continuously through a macaroni string, squeezing or batching with circulation.

GAS WELLS are treated by tubing displacement, batch squeeze or both. Typically an analysis is performed to determine optimal batch versus continuous treatments or both.

WATER INJECTION WELLS are treated by continuous injection of inhibitor. Injection wells are usually treated simultaneously with scale inhibitors or biocides, and compatibility of these Energy Company at the actual use rate should be checked. Oxygen scavenging will aid considerably in reducing corrosion rate.

The inhibitors should be sufficiently soluble so that formation permeability is not impaired.

SURFACE EQUIPMENT may be protected by the inhibitor used to protect the downhole system. Heater treaters and separators may be treated continuously as needed. Storage tank bottoms can be batched with a suitable water soluble inhibitor.

PIPELINES are usually treated continuously. They may be batched treated with slugs of inhibitor between pigs.

Continuous treatment with occasional batching to maintain a good film is particularly effective . Your Westhaven representative will analyze the optimal treatment methods.

PACKER FLUIDS are treated on a one-time basis with a high concentration of inhibitor which must last for a long period of time. Oxygen scavenger should be added at a concentration sufficient to remove dissolved oxygen and maintain an excess sulfite content of 500 ppm.