Secondary Recovery Operations
Equipment Used in Secondary Recovery
Carbon Dioxide injection
Carbon Dioxide Production Facilities
Injection Systems
Secondary recovery, or waterflooding, generally increases the corrosion problems in existing producing wells. It also creates a new set of problems because of the facilities required to reinject the produced water. This section will discuss the corrosion problems that are specific to the various types of environments or equipment used in secondary recovery, that is, producing wells, producing flow lines, separation facilities, tanks, injection pumps, injection lines, and injection wells. Although not specifically addressed, disposal wells (wells that are used for produced water disposal rather than reinjection into producing formations) are considered to be the same as injection wells. Corrosion mitigation methods and guidelines are then discussed for each type of environment.
Equipment Used in Secondary Recovery
Producing Wells. The corrosion mechanisms in secondary recovery are similar to those in primary production. The primary causes of corrosion are dissolved acid gases (H2S and CO2) in the produced fluids. Naturally occurring organic acids are often present and can aggravate H2S and C02 problems. Corrosion will generally increase in secondary recovery because of the large increase in water production caused by water flooding. The fraction of water produced, or water-cut, may increase to 90% or more. This increases the potential for corrosion, because more of the metal surfaces may be water-wet rather than oil-wet. The increased volume of water can increase pumping equipment stresses. Increased stress levels can cause more corrosion fatigue related failures.
Corrosion mechanisms may change during water flooding. For example, a normally sweet field (that is, the produced fluids contain no H2S) may begin to produce H2S because of the growth of sulfate-reducing bacteria in the formation. This can cause unexpected corrosion related to the H2S, pitting under sulfate-reducing bacteria deposits, or failures from sulfide-stress cracking in high-strength materials.
Mineral scale problems, such as the deposition of CaCO3, CaSO4, or BaSO4, may increase during waterflooding. This is usually the result of changes in the formation water brought about by injecting waters from sources other than the original reservoir. Although not strictly a corrosion problem, scale deposition can cause increased failures due to wear and under-deposit corrosion.
Corrosion control methods for secondary recovery are typically the same as those used for primary recovery. The particular method implemented will depend on the type of production method used (that is, beam lift, electric submersible pump, or gas lift), well design, and the economics of the individual situation.
Corrosion inhibitors are widely used to protect tubulars and other downhole equipment in all types of producing wells. The most common methods of sending the inhibitor downhole where it can protect the well equipment are referred to as squeeze treatment, batch treatment, and continuous treatment (see the discussions “Inhibitors” and “Primary Production” in this section). References 68 and 69 contain detailed descriptions of the various methods as well as guidelines for selecting a particular method. Regardless of the method used, the inhibitor must be effective against the particular type of corrosion occurring, that is, H2S, C02, or both. Laboratory tests should be performed if there are any questions regarding the effectiveness of the inhibitor for a given type of corrosion.
The type of corrosion inhibitor used (oil-soluble, oil-insoluble, water-dispersible, water-soluble, and so on) will depend on the treatment method. Batch treatment is a widely used method of treatment for beam lift wells. Corrosion inhibitor solutions are periodically injected into the casing-tubing annulus and flushed to the bottom of the well with produced fluids, diesel oil, or water. A water-dispersible inhibitor is normally used because of the high percentage of water in the well stream. However, increased water dispersibility can cause problems with oil/water separation because of the tendency for dispersion chemicals in the inhibitor to cause emulsions to form. Tests should be performed with actual well fluids to determine the emulsion tendency of the particular inhibitor being considered for use. Often, any one of several inhibitors may be able to provide the necessary corrosion protection; however, there will be vast differences in emulsion formation.
Continuous injection of inhibitor maybe necessary for wells with high fluid levels in the annulus above the pump. Water-soluble inhibitors are normally specified for this type of treatment. Studies have shown that continuous treatment may not be as effective as periodic batch treatment under most conditions (Ref 68). Emulsion problems are sometimes worse with water-soluble inhibitors than with oil-soluble or water-dispersible inhibitors because of the increased use of surfactants in water-soluble inhibitors.
The frequency of treatment and the quantity of inhibitor used will generally have to be increased during secondary production. In general, it is more effective to increase the frequency of inhibition (assuming a batch treatment procedure is used) rather than the quantity, although both may need to be adjusted in some cases. Treatment should be adjusted on the basis of corrosion-monitoring results and well equipment life. Corrosion monitoring can be accomplished in a variety of ways. Corrosion coupons installed in flow lines near the wellhead are the most common.
Downhole monitoring is more difficult. Preweighed, short (0.6 m, or 2ft) sucker rods can be used as downhole corrosion coupons, as can short joints of production tubing. Information on the preparation, installation, and evaluation of corrosion coupon data is provided in NACE RP07-75 (Ref 66).
Downhole equipment should be carefully examined for signs of corrosion whenever it is removed from the well. The occurrence of sucker rod failures is a common measure of downhole inhibition effectiveness in rod pumped wells (Ref 69). The number of failures that can be tolerated will depend on the economics of each producing situation. A general guideline is one corrosion-related failure per well per year. It should be remembered that corrosion fatigue failures of sucker rods are a function of corrosion and stress. Therefore, heavily loaded rods will tolerate less corrosion before failure than rods with lower stress levels.
Corrosion inhibitors are less effective in sucker rod pumps because of wear. Corrosion-related failures are generally controlled by changing the pump metallurgy. Guidelines for selecting pump materials are provided in NACE MR-0 1-76 (Ref 70). Galvanic corrosion problems can be quite severe in pumps and are best controlled by eliminating or reducing the extent of dissimilar metals in contact with each other in the pump. This also applies to coatings used for wear resistance, such as chromium and nickel plating. Rapid failure can often occur in underlying steel if these coatings become damaged by wear. If the wear resistance of chromium plating is required, it may be necessary to upgrade the base material to avoid galvanic corrosion problems.
Wear of sucker rod strings can be controlled through the use of centralizing rod guides. A variety of nonmetallic materials are molded or physically attached to the sucker rod to prevent it from contacting the tubing. Welded or metal guides should not l)e used.
Sucker rod couplings are normally coated with a corrosion-resistant alloy by flame spraying or similar techniques. This will provide both wear and corrosion protection. Similar coatings can be applied to the rods; however, these have not been widely used because of the high cost involved.
Fiber-reinforced plastic sucker rods can be used to reduce corrosion fatigue failures; however, their primary benefit comes from production concerns rather than corrosion, Corrosion inhibition is still necessary when FRP rods are used to protect the steel end connections of the rod and steel well tubulars. In addition, steel rods are not entirely eliminated from the string when FRP rods are used. Internal tubular coatings are not widely used in rod-pumped wells, because they rapidly fail from rod wear. Fiber-reinforced plastic tubing is not widely used for the same reason.
Electric submersible pump wells are treated in much the same way as rod-pumped wells. Electric submersible pump wells pose an additional problem in that the pump fluid intake is above the motor housing. This means that inhibitors injected into the annulus do not reach the housing. A variety of methods have been used to reduce the corrosion of housings, including applying corrosion-resistant coatings and selecting corrosion-resistant alloys for the housing. Special inhibitor injection systems using small-diameter tubing to release inhibitors below the motor have also been employed. Corrosion of electric submersible pump internal parts is not typically a problem because of the widespread use of corrosion-resistant alloys. Internal tubular coatings can be used with electric submersible pump wells, because they are not subject to wear. Fiber-reinforced tubing has found application in a limited number of electric submersible pump wells.
Gas-lift wells are commonly treated by atomizing inhibitor solutions into the lift gas. This can provide protection to the tubulars only above the lower operating gas-lift valve. Internal tubular coatings, FRP tubulars, and corrosion-resistant alloys can be used above or below the operating valve to provide corrosion protection.
Producing Flow Lines
Corrosion mechanisms in producing flow lines are similar to the mechanisms downhole, but generally occur at a lower rate because temperatures and pressures are lower at the surface. Corrosion is often localized to the bottom of flow lines if flow rates are low enough to permit water stratification, which allows the bottom of the line to be continuously water-wet. Under-deposit corrosion and sulfate-reducing bacteria related pitting are often severe under sludge or scale deposits that accumulate in the low flow rate lines.
Corrosion mechanisms in producing flow lines are similar to the mechanisms downhole, but generally occur at a lower rate because temperatures and pressures are lower at the surface. Corrosion is often localized to the bottom of flow lines if flow rates are low enough to permit water stratification, which allows the bottom of the line to be continuously water-wet. Under-deposit corrosion and sulfate-reducing bacteria related pitting are often severe under sludge or scale deposits that accumulate in the low flow rate lines.
Carryover from downhole corrosion inhibition is often sufficient to protect flow lines. In extremely corrosive conditions, additional inhibitor injection, either batch or continuous, may be required. Internal coatings can be used on flow lines; however, obtaining protection in the area of pipe joints can be difficult. A variety of methods have been developed to minimize damage to the coating even in welded lines. Fiber-reinforced plastic line pipe is becoming more widely used for flow lines, because it is inherently corrosion resistant. Polyethylene lines are also used in low-temperature low-pressure applications.
Oil/Water Separation Facilities
Corrosion in these facilities is normally related to attack by corrodents in produced fluids and deposit-related problems. Separation facilities are unique in that they often use heat to aid in oil/water separation.
Corrosion in these facilities is normally related to attack by corrodents in produced fluids and deposit-related problems. Separation facilities are unique in that they often use heat to aid in oil/water separation.
Heat transfer surfaces are usually subject to mineral scale deposition because of solubility changes caused by temperature increases. Scale deposition can result in severe under-deposit corrosion because metal surface temperatures increase due to the reduced heat transfer. Creep rupture failure can occur in direct fired heaters if deposition is severe enough to cause very high metal temperatures. Some separation equipment is open the atmosphere, thus allowing oxygen contamination of the produced fluids and causing increased corrosion in equipment handling the water phase.
Supplemental inhibitor injection is often used to help protect these facilities. In addition, vessels such as separators are often internally coated. Organic coatings are normally used, but platings such as electroless nickel are also employed. Noble platings, such as electroless nickel, can cause severe galvanic corrosion of underlying steel if the coating is cracked or otherwise damaged. Internal cathodic protection with sacrificial anodes is also used in vessels. Internal baffles and other pieces can be fabricated from corrosion-resistant alloys. Corrosion-resistant alloy linings can also be used.
Tanks/Water Storage
Tanks are subject to corrosion by acid gases (C02, H2S) carried over with the produced water. Under-deposit corrosion can be severe under accumulated sludge and debris in tank bottoms. These deposits are also prime areas for the growth of sulfate-reducing bacteria. Tank roofs often fail because of condensation. As water condenses on the roof, it will absorb acid gases from the tank fluids. This can cause severe pitting. Oxygen contamination often occurs in tanks. Obviously, open tanks are subject to contamination. Contamination can occur in normally closed tanks if hatches and vent systems are poorly maintained. Although oxygen can be somewhat corrosive by itself, its primary-role in waterflood system corrosion is to significantly increase the rate of attack of other corrodents already in the system.
Tanks are subject to corrosion by acid gases (C02, H2S) carried over with the produced water. Under-deposit corrosion can be severe under accumulated sludge and debris in tank bottoms. These deposits are also prime areas for the growth of sulfate-reducing bacteria. Tank roofs often fail because of condensation. As water condenses on the roof, it will absorb acid gases from the tank fluids. This can cause severe pitting. Oxygen contamination often occurs in tanks. Obviously, open tanks are subject to contamination. Contamination can occur in normally closed tanks if hatches and vent systems are poorly maintained. Although oxygen can be somewhat corrosive by itself, its primary-role in waterflood system corrosion is to significantly increase the rate of attack of other corrodents already in the system.
Internal coating is a common method of protecting tanks. Organic coatings are typically used. Steel tank life is often extended by the use of FRP linings, especially tank bottoms. Both chopped and mat systems are used. A variety of nonmetallic liners have also been used. Fiber-reinforced plastic tanks are becoming more popular in smaller sizes. Internal cathodic protection can also be used, normally in conjunction with internal coatings. Tanks should be periodically cleaned to remove the accumulated sludge and debris that hinder normal corrosion control methods and promote under-deposit and sulfate-reducing bacteria problems.
Tanks are usually the first source of oxygen contamination in the injection system. Open tanks and pits should be avoided. Various methods of excluding oxygen in open tanks have been attempted. Oil layers are ineffective. Several floating systems have been developed that are useful to some degree, but are not totally effective. It must be remembered that as little as 0.01 ppm oxygen is sufficient to cause major increases in corrosion rates. Oxygen also renders many corrosion inhibitors ineffective. Closed tanks can also allow oxygen entry. Poorly maintained hatch seals and venting systems are notorious as sources of contamination. The optimal method of excluding oxygen is to ensure that all openings to the tank are properly maintained and that a low-pressure inert gas blanket is used. Gas blanketing provides a slight positive pressure that will keep air from entering. Gas blankets can be part of the vapor recovery system, if used, or can be externally supplied from bottled gases, such as nitrogen.
Oxygen can enter the injection system in other ways. Often, additional water must be obtained to augment produced water volumes. Freshwater can be obtained from lakes, rivers, or wells drilled into aquifers. Seawater is used in offshore and coastal locations. All of these waters will have some amount of oxygen contamination.
Severe corrosion can result if this contamination is not removed. Common removal methods include the use of chemicals or scavengers, such as sodium sulfite or ammonium bisulfite, and vacuum or gas stripping (see the discussion “Environmental Control” in the section “Corrosion Control Methods” of this article).
Tanks are also excellent locations for the growth of sulfate-reducing bacteria. If tanks become contaminated with sulfate-reducing bacteria, they must be cleaned and sterilized with biocides. Cleaning is a necessity, because it is impossible for biocides to penetrate adequately the large amounts of sludge and debris on the tank bottom.
Injection pumps can fail by normal corrosion mechanisms as well as by cavitation and erosion. Pump intake piping design must take into account the presence of dissolved H2S and CO2 in the water. These gases can affect net positive suction head calculations. If sufficient net positive suction head is not provided, cavitation can occur. Erosion and erosion-corrosion can occur because of solids in the water. Solids normally consist of corrosion products, formation fines, and mineral scale particulates. Alloy materials such as type 304 and 316 stainless steels are often used for pump internal parts. These alloys can fail by chloride SCC in produced brines if temperatures are above 52 to 65 “C (125 to 150 “F). Pumps are subject to cyclic stresses. Corrosion fatigue failure can occur at sharp changes in cross section, grooves, and at pitted areas, all of which cause stress concentrations.
Corrosion-resistant alloys are widely used in injection pumps and ancillary equipment. The particular choice of materials used will depend on the nature of the fluids handled and the type of pump involved. Specific material recommendations are provided in NACE RP-04-75 (Ref7l).
Caution should be exercised, because this specification docs not address the temperature limitations of the materials. Chloride SCC can occur in 300-series stainless steels if they are used in saline waters above 52 to 65 oC (125 to 150 oF). Also, pitting of these materials can occur in aerated salt water if they are left stagnant in a pump. For example, it is common practice to have standby equipment piped into a system and to test the equipment periodically. Flushing the equipment with deaerated and inhibited freshwater is recommended to prevent pitting corrosion.
Injection Flow Lines and Wells. Corrosion mechanisms are generally the same for producing well flow lines and tubulars, that is H2S, C02, and organic acids. Under-deposit problems in the bottoms of lines and under mineral scales can also occur, as can problems with sulfate-reducing bacteria. Oxygen contamination will greatly accelerate all but the sulfate-reducing bacteria mechanism. Sulfate-reducing bacteria corrosion can still occur even in aerated systems because localized areas under scales, sludges, or aerobic bacterial shines can become anaerobic and thus support the growth of sulfate-reducing bacteria.
Injection wells and flow lines may require periodic acidizing to reduce pressure drops and to restore the injectivity lost because of the buildup of corrosion products and mineral scales. Severe corrosion can occur if acidizing fluids are not properly inhibited and flushed from the system.
All potential corrosion mechanisms must be dealt with to obtain acceptable service lives of injection systems. This includes corrosion by dissolved acid gases, growth of sulfate-reducing bacteria, oxygen contamination, and scale! sludge deposition.
Corrosion inhibitors can be used to control flow line and injection well corrosion. Treatment is usually continuous, but batch treatment can also be used. Both oil-soluble/highly water-dispersible and water-soluble chemicals are used. Flow lines can be internally coated with organic coatings.
Cement and other nonmetallic linings are also used. Fiber-reinforced plastic flow lines are widely used, even in high-pressure injection systems. The lack of an American Petroleum Institute (API) specification for high-pressure FRP line pipe and the lack of standardization in the FRP pipe industry have limited the use of these materials. Standardization of pressure rating methods and improved quality control of the products will greatly increase FRP use.
Injection well tubulars can be bare steel if corrosion inhibition is used. Internal coating is also widely used even with corrosion inhibition (see the discussion “Coatings” in this section). Care must be taken when handling internally coated tubing to prevent coating damage. Special guides must be used when the tubing is installed to prevent damage to the pin nose. Makeup equipment must not deform the tubing enough to crack the coating. Standard API couplings are routinely internally coated in the standoff thread area. The recent advent of flush joint tubing connections using nonstandard couplings has helped to make internally coated tubing applications more reliable. The new connections help to seal the end of the tubing joints in the coupling. This has long been a problem area in internally coated tubing because it is easily damaged during handling and installation.
Corrosion-resistant alloy tubulars are used on some occasions, but their high cost is usually prohibitive. Fiber-reinforced tubing is used to some extent; however, again, the lack of standardization has been a limiting factor. Handling and makeup procedures are critical for successful fiber-reinforced tubing application. Many failures have resulted from overtorquing of FRP connections by crews used to handling steel tubulars. No reliable method has been developed for accurately predicting the long-term performance of FRP tubulars subject to both internal pressure and axial load.
Injection wells frequently require acidizing to restore injectivity. Typical acids used are 15% HCI and 12% HCI-3% HF. Severe corrosion can result if these acids are not properly inhibited. Corrosion inhibitors are available from acid service companies.
Inhibitor concentration should be such that the corrosion rate of low-carbon steel is less than 245 g/m2 (0.05 lb/fl2) over the length of time the acid is to be in the well. It is good practice to ensure that the acid delivered to the job site actually contains the inhibitor and is the strength called for in the work over procedure. A simple test procedure for determining the presence or absence of inhibitor is given in API Bulletin D-15 (Ref 72). This test is not designed to determine inhibitor effectiveness at well conditions nor to compare different inhibitors. Laboratory testing is necessary to establish inhibitor effectiveness.
Acid exposure can have a wide range of effects on the internal tubular coatings that may be present. Laboratory testing should be conducted if there is any doubt regarding the ability of the coating to withstand the acid exposure without damage. Fiber-reinforced plastic tubulars can also be damaged by exposure to mineral acids. Although tubing manufacturers do not prohibit acid exposure, they all recommend that temperatures and exposure times be kept to absolute minimums. The use of hydrofluoric acid in acidizing fluids is not recommended if FRP tubing is installed.
Carbon Dioxide injection
Secondary recovery by water flooding can greatly increase the amount of oil recovered over primary production, but may still leave up to 80% of oil in place in the reservoir. Tertiary recovery by injecting CO2 will remove the oil not obtained by water flooding. Carbon dioxide can be used at much lower pressures than other gases, such as nitrogen or methane, because it dissolves readily in some crudes and can cause up to a tenfold viscosity reduction in heavy crudes.
Oils with an API gravity of 25 or higher are candidates for miscible flooding. This process can recover oil from low-permeability reservoirs. Oils with gravities down to API 15 are recovered by an immiscible process based on oil swelling and viscosity reduction.
Carbon dioxide injection uses gas from fields that produce almost pure CO2 from burning of lignite and recovered CO2 from industrial combustion gases. These gases are purified and compressed, and in some cases, they are pipelined for hundreds of miles to the fields to be flooded. The Texas Permian Basin, North Dakota, the Texas Gulf Coast , and the California
Because CO2 is an acid gas, production problems are encountered when CO2 is injected. Carbon dioxide ionizes in water to form carbonic acid and will react directly with car-bon steel. The corrosion rates can be quite high, and pumps can fail in a matter of days after breakthrough of the CO2 into producing wells. Some scaling problems may arise because carbonic acid may dissolve calcium carbonate from the formation. The calcium bicarbonate formed during this reaction may come out of solution in heaters and vessels as calcium carbonate when CO2 is lost. Calcium sulfate (CaSO4) will also dissolve and may cause scaling in surface equipment.
Emulsion treating characteristics may change when CO2 dissolves in oil. Asphaltenes may cause problems by dissolving in CO2 as it sweeps through the formation and then coming out of solution on the surface.
Elastomers must be selected with care, because they may swell or lose strength when exposed to CO2. Leaking packers due to seal failure will cause pressure on the annulus of CO2 injection wells and annular space corrosion.
Carbon Dioxide Production Facilities
Carbon dioxide source wells may produce from a few percent to almost pure CO2. They may produce both liquid and vapor phase CO2. The presence of water in the produced CO2 will cause hydrate formation and corrosion. Hydrate formation can be controlled by glycol dehydration, but special measures must be taken to control corrosion.
A corrosion inhibitor can be added to the producing well to control corrosion. Continuous injection downhole of a water-soluble filming amine inhibitor should protect the tubing and wellhead. The use of type 3 16L and 304L stainless steels and FRP for completions and flow lines is an alternative to inhibitor use.
In a typical CO2 production facility, the gas travels through a wellstream heater to a contactor in which water is removed, It is then scrubbed, compressed, and sent to the pipeline. Materials selection in the design of the system is the key to corrosion control in the processing plant. Corrosion-resistant alloys can be used in areas of high corrosion, and carbon steel is used where conditions allow its use. A maximum water content of 60% of saturation is obtained by dehydration so that corrosion of the pipeline is prevented. Dehydration also prevents hydrate formation when temperatures are low.
Injection Systems
Water and CO2 arc injected alternately in some systems, such as the SACROC unit in the Kelly Snyder field in west Texas
The distribution system consists of parallel separate lines for water and CO2 that are car-bon steel coated externally and cathodically protected.
Carbon dioxide in the line contains less than 50 ppm water, so internal corrosion is minimal. Valves in the system range from bare carbon steel to plastic coated with type 316 stainless steel trim. Fluorocarbon and nylon 0-rings have performed satisfactorily, and Buna N rubber is used for stem sealing, although these materials swell somewhat.
Water lines are cement lined with sulfate-resistant cements and artificial pozzolans, as specified in API RP- 10E. Most leaks have been due to the failure of asbestos gaskets. The use of grout instead of gaskets has been effective. Water-soluble inhibitors are added to protect voids in cement linings and plastic coatings.
Carbon dioxide injection systems have suffered corrosion problems when the mixing of water and CO2 at each cycle of alternate C02/water injection occurs. Plastic coating and type 316 stainless steel trim, ceramic gate valves with electroless nickel-coated bodies, and electroless nickel-coated check valves were tried. The type 316 stainless steel and ceramic gates performed well, but the other methods failed.
Injection wells originally used type 410 stainless steel wellheads and valves. Severe pitting occurred under deposits laid down from suspended solids in the injection water.
The type 410 stainless steel was plastic coated, and the gates and seats were changed to type 316 stainless steel to correct the problem.
Failures occurred in the couplings of the plastic-coated tubing in the injection wells when the seal rings failed. This was corrected by changing the coating on the couplings from an epoxy-modified phenolic to a polyphenylene sulfide.
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