This type of corrosion occurs in both gas-condensate and oil production as well as in produced water handling systems.. DESCRIPTION OF DAMAGE Chemistry of Reaction Corrosion in gas-conde
GENERAL ASPECTS OF CORROSION
Corrosion significantly reduces the useful life of oilfield equipment Recent advancements in corrosion detection and mitigation techniques have been made specifically for the oilfield industry This book aims to present this valuable information in an accessible format.
Corrosion is the process of metal deterioration caused by chemical or electrochemical reactions with the surrounding environment Understanding corrosion rates is essential for assessing the longevity and integrity of metal structures.
1 Carbon steel will usually corrode faster than corrosion resistant al- loys used in the oilfield There are notable exceptions, such as the failure of strong alloy steels in H 2 S systems
2 The major corrodents encountered in the oilfield are carbon dioxide, hydrogen sulfide, organic acids, hydrochloric acid, and oxygen dissolved in water
3 Films or scales at the interface between metal and c01ãrodent influ- ence corrosion rates These films include corrosion products, mill scale, and corrosion inhibitors
Environmental factors, including the chemical composition of water, temperature, and velocity, significantly influence the rate of corrosion Additionally, natural inhibitors found in produced fluids can substantially decrease corrosion rates.
5 Impressed voltages and stray electrical currents are often a source of serious corrosion damage
6 Velocity of the flowing media plays an important role in erosion/ corrosion It exhibits mechanical wear effects at high velocities, particu- larly when the media contains solids in suspension
For practical considerations, corrosion in oil and gas well production can be classified into four main types, each of which will be discussed in a following chapter
CO2 corrosion, commonly known as Sweet Corrosion, arises from the presence of carbon dioxide and is significant in gas-condensate and oil production, as well as in produced water handling systems.
2 H2S corrosion is also referred to, and will be referenced in this book as, Sour Conãosion It is designated as corrosion in oil and gas wells pro-
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2 CoRROSION OF OIL- AND GAS-WELL EQUIPMENT ducing even trace quantities of hydrogen sulfide These wells may also contain oxygen, carbon dioxide, or sulfate reducing bacteria
Oxygen corrosion is prevalent in environments where equipment is exposed to atmospheric oxygen, particularly in offshore installations, brine handling and injection systems, and shallow producing wells with air intrusion Even minimal traces of oxygen in produced fluids containing CO₂ can significantly accelerate the corrosion rate.
Electrochemical corrosion refers to the type of corrosion where corrosion currents are easily measurable or can be reduced through the application of current, particularly in cases like soil corrosion.
The annual cost of corrosion and its protection in the United States is estimated at around eight billion dollars, focusing solely on direct expenses This estimate excludes indirect costs related to lost production, safety, and environmental impacts, as well as specific corrosion costs associated with oil and gas well production, only addressing refinery and pipeline issues within the oil industry.
Effective identification of costly corrosion issues allows for the implementation of mitigation strategies, leading to significant savings for the industry However, developing a robust and scientifically-based corrosion control program demands substantial effort from both corrosion experts and field personnel.
While we often wish for a magical solution to eliminate corrosion and its associated issues, there is no quick fix or universal treatment that can prevent all corrosion problems effectively.
Importance of Field Personnel in Corrosion-control Programs
Corrosion research and engineering laboratories have developed key principles and procedures for corrosion control Nonetheless, the ultimate success in combating corrosion relies heavily on the efforts of field operating personnel, whose responsibilities are crucial to the effectiveness of these programs.
Field personnel play a crucial role in identifying the early signs of corrosion, as they are acutely aware of rising pulling and equipment maintenance costs Their routine maintenance and inspection activities provide them with valuable opportunities to assess the condition of critical components such as tubing, Christmas trees, casing, and pumps.
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Effective record keeping is essential for understanding the true costs of corrosion, as these costs often remain hidden without accurate and up-to-date documentation specifically focused on corrosion control The evaluation of the costs and effectiveness of corrosion-control measures relies heavily on maintaining good records, which can only be managed and assessed by field personnel.
Effective control procedures are essential for the value of a control system in oilfield equipment, as even the best-designed systems require careful, regular, and diligent application to ensure optimal performance.
An experienced corrosion specialist is always available to assist with field problems, although they typically cannot implement solutions themselves They can guide the selection of effective corrosion mitigation techniques, such as inhibition, metallurgy, coatings, and cathodic protection This book serves as a comprehensive guide for field operators to understand corrosion issues, assess their severity, and select and apply appropriate control measures.
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SWEET CORROSION
In recent years, the definitions of "sour crude" and "sweet crude" have evolved, as production personnel previously used these terms to differentiate between corrosive and noncorrosive fluids Many wells once deemed noncorrosive due to the absence of hydrogen sulfide have now become corrosive, diminishing the relevance of this distinction Sweet corrosion refers to corrosion in oil or gas wells that do not exhibit iron sulfide corrosion products or the odor of H2S, although some sweet wells may still contain trace amounts of sulfides.
Corrosion control in gas-condensate wells has been a critical challenge for the industry, leading to costly workover operations, reservoir damage, and safety risks for personnel To address this issue, various solutions such as chemical inhibitors, protective coatings, and specialized metal alloys have been implemented.
Corrosion in sweet oil wells typically intensifies after several years of production, particularly when there is a significant increase in salt water output The corrosive nature of oil wells often emerges as water production escalates.
Corrosion in gas lift wells is a significant concern, with estimates suggesting that 40 to 50 percent of the total fluid may contribute to this issue The industry could face millions of dollars in annual losses due to corrosion damage, highlighting the urgent need for effective management strategies.
DESCRIPTION OF DAMAGE Chemistry of Reaction
Corrosion in gas-condensate wells is primarily caused by carbon dioxide and organic acids In the absence of liquid water, carbon dioxide (CO2) is noncorrosive; however, when water is present, CO2 dissolves and creates carbonic acid, leading to corrosion issues.
C02 + H20 -t)lllr~ H2C03 Carbon dioxide Water Carbonic acid
This carbonic acid causes a reduction in pH of the water which makes it quite corrosive to steel
Iron Carbonic acid Iron carbonate
Low molecular-weight organic acids, like acetic acid, play a significant role in corrosion alongside the acidity from carbon dioxide However, these acids are often overlooked as the main contributors to sweet corrosion.
In general, the preceding statements apply to both oil and gas wells
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Corrosion has been observed in certain high-pressure sweet oil wells in the Louisiana Gulf Coast, particularly those that produce minimal water This issue is linked to the deposition of a porous scale that contains both chlorides and sulfates A photograph illustrating the typical scales responsible for this corrosion is provided in Figure 1, which also shows the condition of the pipe after scale removal and the extent of pitting.
Carbon dioxide significantly influences sweet corrosion, and its solubility is affected by several key factors: pressure, temperature, and water composition Increased pressure enhances carbon dioxide solubility, while lower temperatures reduce it Additionally, the presence of dissolved minerals can buffer the water, preventing pH reduction In gas-condensate wells, where dissolved minerals are minimal and temperatures are relatively high, pressure becomes the primary factor affecting carbon dioxide solubility Consequently, the partial pressure of carbon dioxide serves as an effective indicator for predicting the corrosiveness of gas-condensate wells.
The partial pressure of carbon dioxide can be determined by the formula:
Partial pressure= total pressure X percent carbon dioxide
For example, in a well with a bottom-hole pressure of 3,500 psi and gas containing 2 percent C02:
Partial pressure= 3,500 X 0.02 = 70 psi at the bottom of the well
Using the partial pressure of carbon dioxide as a yardstick to predict corrosion, the following relationship has been found:
1 A partial pressure above 30 psi usually indicates a corrosive condition
2 A partial pressure between 3 and 30 psi may indicate a corrosive condition
3 A partial pressure below 3 psi is considered non-corrosive
Salt water from sweet oil wells often contains dissolved minerals, and the typical relationship between these elements may not always hold true Corrosion is frequently observed in environments with high carbon dioxide levels To estimate the corrosivity of sweet oil wells, the partial pressure of carbon dioxide serves as a valuable indicator Figure 4 illustrates the calculated solubility of CO2 in a standard sweet well.
Corrosion in gas-condensate well tubing often manifests as deep pitting, characterized by sharp, well-defined pits that can quickly penetrate the wall.
6 CORROSION OF OIL- AND GAS-WELL EQUIPMENT
(b) Appearance of Pipe after Removal of Scale
Fig 1 -Tubing Corrosion from Wells with Very
Fig 2 - Effect of C0 2 Partial Pressure on pH of
Fig 3 - Effect of Temperature on pH
Fig 4 - Solubility of C0 2 at Various Depths of a
Fig 5 -Gas-condensate Well Tubing -Severe
Sweet corrosion occurs over time due to acidic gases that dissolve in water droplets on the tubing wall, leading to pitting Tubing located below the condensation point tends to experience less corrosion damage.
"Ringworm" corrosion is a specific type of corrosion that occurs in gas-condensate well tubing, typically a few inches from the upset This corrosion can manifest as either smooth surfaces or severe pitting near the upset area The primary cause of ringworm corrosion is linked to the upsetting process, where the heat alters the grain structure of the tubing, creating a transition zone that is more prone to corrosion To mitigate this issue, it is essential to fully normalize the tubing after the upsetting process, as normalizing provides a uniform grain structure This corrosion is particularly prevalent in J-55 tubing, while other types such as N-80, L-80, and P-110 are normalized to prevent its occurrence.
Sand-cutting, also known as erosion, is a type of corrosion damage that typically results from a combination of mechanical action and corrosion This damage often occurs near restrictions, such as chokes, where velocities and turbulence are elevated, leading to the removal of corrosion products that usually inhibit further corrosion Erosion/corrosion is also prevalent in areas where flow is disrupted, such as tees and short radius elbows A recommended solution is to use a tee with a bull plug in the running end Damage of this nature is most commonly found in wellhead fittings, but increased gas velocity significantly impacts corrosion rates; for instance, a 3.7-fold increase in gas velocity can lead to a fivefold increase in corrosion rate.
Corrosion in sucker rods within sweet oil wells can manifest as severe pitting or subtle fine cracks, leading to significant operational issues Additionally, pin-and-coupling failures are a prevalent concern in many regions, contributing to the overall challenges faced in maintaining these systems.
15 to 20, incl.) Fig 21 and 22 show body corrosion-erosion of a coupling and alloy rod
Damage to pumping well tubing can manifest as pitting, rod wear, or a combination of both In sweet oil wells, pitting resembles that found in gas-condensate wells Failures linked to rod wear typically stem from both rod wear and corrosion The interaction between the sucker rod and tubing removes corrosion products, which can exacerbate the corrosion process.
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CORROSION OF OIL- AND GAS-WELL EQUIPMENT
Fig 8 (left) -Corrosion-Erosion of Ell
Fig 9 (right) - Corrosion- Erosion of Choke Body
Fig 7 - Corrosion-Erosion of Cross-over Tee
Fig 10- Corrosion-Erosion of Tubing Wall Opposite Tubing Perforation
SOUR CORROSION
Oxygen corrosion, exemplified by the rusting of steel, is the most prevalent form of corrosion Its rate is influenced by several factors, including temperature, metal surface erosion, corrosion films, and the type and availability of electrolytes A critical factor is the presence of water, which acts as an electrolyte; generally, atmospheric corrosion intensifies with higher humidity levels Additionally, oxygen corrosion tends to be more pronounced in salt water compared to fresh water.
To mitigate oxygen corrosion in steel, it is effective to limit oxygen exposure, which can be achieved through methods such as painting The rate of corrosion is significantly influenced by geographic location; for instance, equipment in the Gulf Coast experiences rapid corrosion, while similar equipment in the Mid-Continent area shows minimal corrosion The financial impact of corrosion is contingent upon the value of the affected equipment Additionally, corrosion poses risks beyond economic loss, including potential safety hazards for operating personnel and negative effects on the equipment's appearance.
DESCRIPTION OF DAMAGE Chemistry of Oxygen Corrosion
Although some details of the chemistry of oxygen corrosion are not fully understood, the chemical reaction can be explained as follows:
Iron reacts with oxygen and water to produce rust, identifiable by the yellow FeO(OH) and orange Fe₂O₃ corrosion products on steel The corrosion rate is influenced by the characteristics of the corrosion product, determining if it is protective or porous Additionally, exposure to acid gases like carbon dioxide and hydrogen sulfide from natural gas, as well as salts from brine, typically accelerates the corrosion process in oil wells.
Oxygen corrosion requires the presence of air or oxygen, making it unlikely to occur in subsurface oil-well equipment.
38 CORROSION OF OIL- AND GAS-WELL EQUIPMENT
Water produced alongside oil typically lacks dissolved oxygen, even when fresh While most hydrocarbons remain unreactive with oxygen at reservoir temperatures, crude oil comprises various organic compounds that readily react with oxygen Consequently, any oxygen initially present in the reservoir is likely consumed by these organic compounds.
Oxygen corrosion can occasionally occur in downhole well equipment, typically due to improper operating techniques or malfunctioning equipment A frequent source of oxygen infiltration in pumping wells is an open annulus.
In certain industries, extracting gas from the casing under vacuum is a standard procedure This method can allow oxygen to infiltrate the annulus when wells are being pulled Additionally, the air lifting of production can introduce oxygen into the well, especially if the gas compressor's suction falls below atmospheric pressure during the gas lifting operation.
The presence of carbon dioxide and hydrogen sulfide significantly accelerates oxygen corrosion, while the introduction of oxygen into well equipment further exacerbates this corrosion rate.
Oxygen exposure and fluctuating stresses are the primary contributors to drill pipe failure Corrosion pits from oxygen and service-related scars, like slip marks and mechanical scratches, intensify local stresses, leading to crack initiation under varying loads Additionally, during drilling operations, the presence of oxygen in the mud exacerbates fatigue, further compromising the integrity of the drill pipe.
Fig 72 (right) - Fatigue Cracks at Base of Pits in Drill Pipe
Fig 73 (below) - Cross Section of Fatigue
Cracks at Base of Pit in Drill Pipe
Oxygen corrosion, also referred to as corrosion fatigue, leads to accelerated cracking as corrosion pits deepen This creates a vicious cycle where each process exacerbates the other Failure occurs when a crack or pit penetrates the pipe wall, allowing fluid to escape The escaping fluid can rapidly enlarge even a small perforation, resulting in a significant hole Consequently, the weakened pipe may easily break or twist off.
Exterior corrosion of drill pipe is less likely to cause localized pitting due to constant friction against the hole's sides In contrast, internal corrosion pits are more common, leading to fatigue failures that typically initiate from the pipe's interior.
Oxygen corrosion primarily affects the exterior of primary production equipment, particularly in high humidity environments where significant pitting and overall corrosion can occur Accumulated solids, like salt, can retain moisture from the air, further accelerating the corrosion process by keeping surfaces damp.
Fig 74 (left) -Severe Pitting of Pumping Unit Exposed in Area of High Humidity
Fig 77 (right) - Severe Pitting of a Gas Line Exposed to Spray from a Cooling Tower
Oxygen Corrosion of Stock-tank Deck
40 CORROSION OF OIL- AND GAS-WELL EQUIPMENT
The underside of stock-tank decks is prone to significant oxygen corrosion due to the interaction of air with condensed moisture on the steel surface Additionally, the presence of hydrogen sulfide and carbon dioxide accelerates this corrosion process, as previously detailed in Chapter 3.
Surface piping may show the same general attack as other equipment Corrosion of pipe exposed to water spray, such as piping in cooling towers, may become extremely severe (Fig 77)
Oxygen present in oilfield brine or flood water significantly contributes to equipment corrosion The restricted availability of oxygen can lead to the development of distinct formations known as tubercles This corrosion results in a soft, jelly-like substance, which can create deep, sharp-bottom pits beneath the surface.
(b) In flowline Fig 78- Tubercules of Oxygen Corrosion Product Caused by Iron Bacteria
Oxygen corrosion can lead to rapid metal perforation, flow obstruction, and plugging due to corrosion products, which can be surprisingly voluminous and cause more damage than the oxygen levels suggest Even small amounts of these products can clog equipment and formations at injection wells Additionally, if the injected water contains dissolved iron or manganese compounds, oxygen can oxidize them into insoluble products, further contributing to injection well plugging.