Among my country's proven oil and gas fields, sour oil and gas fields account for a considerable proportion, and mid-to-high sour gas fields in natural gas fields are close to 50%. Hydrogen sulfide, carbon dioxide, and chloride ions are often accompanied by corrosive media in the gathering and transportation of oil and gas in sour oil and gas fields. In the presence of water and steam, they can cause serious corrosion of pipeline steel.

Based on the environment and characteristics of gathering and transportation pipelines, this paper proposes the design of a new type of anti-H2S, CO2, CL-corrosion coating (ACME7918). Proved by the test: test condition 1: temperature 150℃; H2S partial pressure: 1.5MPa; CO2 partial pressure: 0.5MPa; Cl- content: 100g/L; total pressure 15MPa; test time 168 h; test condition 2: temperature 148℃ ; NaOH solution with pH 12.5, total pressure 70MPa, test time 16h; after high temperature and high pressure immersion test, there is no change in appearance and adhesion.

1 Introduction

Among my country's proven oil and gas fields, sour oil and gas fields account for a considerable proportion, and mid-to-high sour gas fields in natural gas fields are close to 50%. In recent years, the newly developed large-scale oil and gas fields such as Tarim, Jilin, Luojiazhai and Puguang, as well as cooperation with Sudan, Kazakhstan, Uzbekistan, Turkmenistan, Indonesia, and Myanmar, are also mostly acid and high-acid oil and gas fields.

The corrosion of the sour oil field has serious consequences: At 22:04 on December 23, 2003, the Luojia 16H well located in Kaixian, which was drilled by the Sichuan Petroleum Administration Chuandong Drilling Company, suffered a natural gas blowout during the tripping process. , A large amount of natural gas containing high concentrations of hydrogen sulfide spewed from the well was diffused and diffused, causing 243 deaths due to hydrogen sulfide poisoning, 2142 hospitalizations due to hydrogen sulfide poisoning, and direct economic losses of 64,323,100 yuan.

The corrosive environment of oil and gas fields is becoming more and more severe: the main manifestations are (1) the later stage of oil well exploitation: the increase of water content; (2) the development of deep wells and ultra-deep wells lead to: temperature/pressure increase; (3) the development of oil wells in strong corrosive environments: CO2, H2S and The increase in Cl- content has caused more serious corrosion in oil and gas fields.

Corrosion of oil and gas gathering pipes, oil pipes, and oil-water separation tanks is the main part of oil and gas field corrosion. The corrosion of petroleum pipes and equipment is divided into internal corrosion and external corrosion: external corrosion is mainly caused by soil, groundwater, stray current, etc.; internal corrosion is caused by internal media, which is one of the difficult and hot issues in the current research of corrosion science. .

1.1 The common features of corrosion in sour oil and gas fields:

(1) Corrosion types are diverse: stress corrosion caused by H2S, electrochemical corrosion caused by CO2, O2 and Cl-, and bacterial corrosion and under-scaling corrosion in some gas wells.

(2) Corrosion mechanism is complicated: the corrosion of most gas wells is the result of the combined effect of H2S, CO2, Cl- and other factors, and some gas wells still have bacteria (SRB) corrosion;

(3) Corrosion scope is universal: acid oil and gas fields have certain corrosion under the action of different corrosive factors;

(4) Corrosion results are serious: the results of corrosion directly lead to perforation, rupture, or even fracture of downhole tubing and casing, gathering and transportation equipment, etc., causing serious economic losses and safety accidents.

1.2 There are four notable characteristics of internal corrosion of petroleum pipes and equipment:

(1) Multiphase flow corrosive medium with gas, water, hydrocarbon and solid coexisting;

(2) High temperature and/or high pressure environment;

(3) H2S, CO2, O2, Cl and moisture are the main corrosive substances; H2S, CO2, O2 are corrosive agents, water is the carrier, and Cl- is the catalyst;

(4) In the development of high-sulfur gas fields, elemental sulfur becomes an important corrosive substance.

In order to control the corrosion of corrosive media such as hydrogen sulfide, carbon dioxide and chloride ions in oil and gas, in recent decades, domestic and foreign efforts have been devoted to research in this area. In addition to adopting strict oil and gas quality and checking the intermediate links of transportation, European and American countries have also Anti-corrosion coating is used. The anti-corrosion practice of various countries in the world also proves that the coating anti-corrosion is an effective, economical and universal method. For the three high (high Cl-, high CO2, and high H2S) oil and gas fields, the choice of ordinary steel + non-metallic overburden-we have also made useful explorations in this area for more than 8 years, and achieved phased results.

2. Corrosion mechanism

2.1 H2S corrosion mechanism

Dry H2S has no corrosive and destructive effect on metal materials, and H2S is corrosive only when it is dissolved in an aqueous solution. H2S dissolves in water and immediately ionizes, and the released hydrogen ions can easily capture electrons at the cathode, which promotes the dissolution of anode iron and leads to corrosion. The iron sulfide corrosion product (FexSy) generated by the anode reaction is usually a defective structure, and the adhesion on the steel surface is poor and easy to fall off. In addition, FexSy is also conductive and has a higher potential. It can be used as a cathode to form an active micro-battery with the steel matrix to continue to corrode steel.

There are three common types of corrosion in oil and gas containers and pipelines containing H2S:

(1) Sulfide Stress Cracking (SSC)

The main damage characteristics are:

① The material is subjected to tensile stress, and the partial pressure of hydrogen sulfide in the environment is higher than 0.0003MPa;

②The form of destruction is material cracking, which often causes blasting and fire;

③Broken under stress, without warning, short period, and fast crack growth;

④ The main crack is perpendicular to the force direction, in the form of intergranular and transgranular, with branches;

⑤Crack occurs in the stress concentration part or the martensitic structure part;

⑥High material hardness, HRC≧22.

(2) Hydrogen Induced Cracking (HIC) Hydrogen Blistering (HB) and Stress Oriented HIC (SOHIC)

The main damage characteristics are:

① The partial pressure of H2S in the environment is higher than 0.002MPa;

②The material is not subjected to external stress or tensile stress;

③Crack occurs in the banded pearlite inside the pipe, which is step-shaped and parallel to the rolling direction of the pipe;

④ Failure after the crack is connected;

⑤The crack growth rate is slow, which promotes the expansion under the action of external force (SOHIC);

⑥ It often occurs in low-strength steel, steel with high S and P content and many inclusions;

⑦The surface is often accompanied by hydrogen bubbling;

⑧ Occurs at room temperature.

(3) Electrochemical weightless corrosion, including uniform corrosion, pitting corrosion, etc.

Its main damage characteristics:

①There is a black corrosion film on the surface, mostly FeS, FeS2, Fe9S8, etc.;

②The pipe surface is evenly thinned and corroded in local pits, which is severely ulcerated;

③The corrosion rate is affected by factors such as the concentration of H2S, the pH value of the solution, the temperature, and the shape and structure of the corrosion film;

④ CO2 and Cl- in the system will accelerate corrosion;

⑤The liquid accumulation in the container or pipe, the low-lying place, the elbow section and the low gas flow rate, the gas-carrying liquid scouring section is easy to accelerate corrosion.

2.2 CO2 corrosion mechanism

Dry CO2 itself is not corrosive, but CO2 is easily soluble in water, condensate and crude oil. CO2 dissolves in water and reacts to form H CO3- and CO32-. The latter will react with iron electrochemically to form ferrous carbonate. The main corrosion phenomena are bit corrosion, pit corrosion, abscess-like terrace corrosion and long groove-shaped groove corrosion. There are many factors that affect CO2 corrosion, including media water content, temperature, CO2 partial pressure, pH value, ion concentration (Cl-, HCO3-, Ca2+, Mg2+), H2S content, O2 content, microorganisms, media flow rate, and alloy composition of the material Wait.

Carbon dioxide corrosion damage behavior is different at the cathode and anode. The continuous dissolution of iron at the anode leads to uniform corrosion or local corrosion, which is manifested by the increasing wall thickness of metal facilities or local corrosion damage such as pitting and perforation. The local corrosion rate is generally more uniform. The corrosion rate is hundreds of times higher, and the harm is great; at the cathode, carbon dioxide dissolves in water to form carbonic acid and release hydrogen ions. Hydrogen ion is a strong depolarizer, it is easy to deprive electrons to reduce, promote the dissolution of anode iron and cause corrosion. At the same time, hydrogen atoms enter the steel and cause the cracking of metal components.

The factors that affect CO2 corrosion can be divided into two categories: One is environmental factors: mainly including the partial pressure of CO2, the chemical properties of the solution medium, the pH value, the temperature, the flow rate, the fouling condition of the metal surface and the applied load. The second is the material factor: mainly including the type of material and the content of alloying elements.

Through a large number of corrosive experiments and studies, the following three points of understanding have been preliminarily drawn to the changing laws of environmental factors affecting CO2 corrosion rate.

(1) CO2 corrosion is the result of the combined effects of various influencing factors. In fact, CO2 corrosion is often manifested as corrosion and a typical localized corrosion underneath the deposit. Corrosion products (FeCO3) and fouling products (CaCO3) or different product films on the surface of steel, the coverage of different areas is different, and the areas with different coverages form corrosion couples with strong autocatalytic properties, CO2 The local corrosion is the result of this corrosion.

(2) Temperature, flow rate and pressure have a great influence on the corrosion product film. Different structures and different forms of corrosion products are generated at different temperatures, and the integrity of these corrosion products and the degree of compactness and looseness lead to different corrosion rates. At the same time, the flow rate has a decisive influence on the existence of corrosion products. When the flow rate is high, the corrosion product film becomes thinner and the corrosion rate becomes larger. At low flow rates, loose corrosion products are easier to adhere to the metal surface and form pitting corrosion. The high partial pressure of CO2 will also cause the corrosion product film to thicken and at the same time increase the corrosion rate.

(3) The factors affecting the corrosion rate of CO2 are sorted from high to water into pressure, flow rate and temperature. The performance of pressure on the corrosion rate is that the greater the pressure, the higher the corrosion rate; with the increase of the flow rate, the corrosion rate will gradually increase. Under high flow rate conditions, uniform corrosion is dominant, and under low flow rates, local corrosion is dominant; the corrosion rate varies with The temperature increases with height, and reaches a large value at 80°C. When it exceeds 120°C, the corrosion rate decreases.

Among the many factors affecting CO2 corrosion, PCO2 plays a decisive role. Generally speaking, when the temperature is constant, the greater the PCO2 value, the faster the corrosion of the material.

With the development of high-sulfur gas fields, the corrosive environment of high temperature, high pressure and high content of H2S and CO2 is increasing, and the environment for the service of materials in underground, ground and natural gas treatment plants is becoming more and more demanding. Especially when elemental sulfur is present, the service of the material faces many new cathode reduction processes, resulting in a great increase in the severity of corrosion.

3. The design idea of the new polymer temperature-resistant and high-permeability coating

The new polymer temperature-resistant and high-permeability coating is a new modified resin powder coating, which has a molecular structure and is used in high-temperature environments. It has excellent corrosion resistance and can effectively resist the corrosion of metals by H2S, CO2, and Cl-. It has good high temperature resistance, and the coating has good adhesion in oil, water, acid gas and other complex oilfield operating environments.

It has a high-density molecular cross-linked structure, has a very low gas permeability, and can be used in a natural gas environment containing 60% H2S. Because of its smooth surface and low friction characteristics, it can improve fluid efficiency in drilling operations and surface equipment.

Comprehensive characteristics: good finish, strong impact resistance, good adhesion, corrosion resistance, low gas permeability.

In order to meet these demanding conditions of use, heavy-duty anti-corrosion coatings must have unique properties:

● Sticky and old: First, it must be close to the protected substrate in a heavily corrosive environment, without falling off, peeling, cracking, etc., in order to play a protective role;

●Impermeability: Secondly, it should be able to resist the penetration of various strong corrosive media to protect the substrate, and the thickness of the coating should be adapted to different requirements;

●Functionalization: Third, the coating should be able to withstand a variety of mechanical stresses and have a long service life; later, in order to meet the requirements of use, the coating should also have more functions such as drag reduction, temperature resistance, energy saving, etc. …….

3.1 The design idea of the new polymer temperature-resistant and high-permeability coating

●Improve the structure of the curing agent: use a new variety of functional group curing agents to improve the high temperature stability and high temperature peel resistance of the coating.

●Choose new resins: use high and low molecular weight, multifunctional modified resins to replace existing resins, thereby improving the high temperature permeability and wet adhesion performance of the coating.

●Design and control of coating microstructure: use interspersed network-like elastic structure, organic/inorganic nano-particle semi-rigid structure to reduce the cohesion of the coating due to temperature changes and increase the packing density of the active channel of the coating system , To further improve the bonding strength and permeability of the coating.

3.2 Technical route and implementation plan

Basis: Screen the series of heavy anti-corrosion coatings that have been originally developed and developed-compare the permeability, adhesion and mechanical properties of the coatings, and select the basic system coatings with better protection performance in the three-high environment .

Modification: Use relevant analysis methods to rationally modify and optimize the above-mentioned coating systems with better performance, and develop new types of coatings. And conduct accelerated corrosion research experiments to simulate the three-high environment in the laboratory.

Process and equipment: Research the appropriate coating process and coating equipment, and conduct comprehensive performance evaluation and testing of the new coating developed.