Iron sulfide removal in oilfield applications
阅读说明：本技术 油田应用中的铁硫化物移除 (Iron sulfide removal in oilfield applications ) 是由 陈涛 王齐伟 化权·弗兰克·张 于 2018-05-23 设计创作，主要内容包括：将在碳素钢管上的铁硫化物溶解以得到螯合铁通过用包含铁螯合剂和添加剂的组合物处理碳素钢管实现。添加剂包括氧化剂和碱中的至少一种。铁螯合剂与添加剂的重量比在50:1至5:1的重量范围内。(Dissolving the iron sulfide on the carbon steel tube to obtain chelated iron is achieved by treating the carbon steel tube with a composition comprising an iron chelator and an additive. The additive includes at least one of an oxidizing agent and a base. The weight ratio of the iron chelator to the additive is in the range 50:1 to 5:1 by weight.)
1. A composition for dissolving iron sulfide, the composition comprising:
an iron chelator; and
an additive, wherein the additive comprises at least one of:
an oxidizing agent; and
a base, a metal salt, a metal oxide,
wherein the weight ratio of the iron chelator to the additive is in the range 50:1 to 5: 1.
2. The composition of claim 1, wherein the concentration of the iron chelator in the composition is in the range of 10% to 80% by weight.
3. The composition of claim 1 or claim 2, wherein the additive comprises an oxidizing agent.
4. The composition of claim 3, wherein the concentration of the oxidizing agent in the composition is in the range of 0.05 wt.% to 15 wt.%.
5. The composition of any of the above claims, wherein the additive comprises an oxidizing agent, and the oxidizing agent comprises at least one of: potassium permanganate, ammonium nitrate, sodium bromate, sodium hypochlorite, sodium nitrite, sodium bicarbonate, potassium bicarbonate, ammonium carbonate, ammonium bicarbonate and iodine.
6. The composition of any of the above claims, wherein the additive comprises a base, and the concentration of the base in the composition is in the range of 1 wt.% to 60 wt.%.
7. The composition of claim 6, wherein the base comprises a strong, medium strong or weak base.
8. The composition of claim 7, wherein the base comprises a strong base and the strong base comprises at least one of potassium hydroxide and sodium hydroxide.
9. The composition of claim 7, wherein the base comprises a medium to strong base and the medium to strong base comprises at least one of potassium carbonate, sodium carbonate, potassium bicarbonate, ammonium carbonate, and ammonium bicarbonate.
10. The composition of any of the above claims, wherein the iron chelator comprises at least one of: ethylenediaminetetraacetic acid, diethylenetriaminepentaacetic acid, tetrasodium glutamate diacetate, tetrakis (hydroxymethyl) phosphonium sulfate, nitrilotriacetic acid, citrate, and pyrophosphate.
11. The composition of any of the above claims, wherein the composition is free of hydrochloric acid.
12. The composition of any of the above claims, wherein the pH of the composition is in the range of 3 to 14.
13. A method of treating a carbon steel pipe in a subterranean formation, the method comprising:
providing a composition comprising an iron chelator and an additive to the carbon steel tube, the additive comprising at least one of an oxidant and a base;
contacting the carbon steel tube with the composition for a length of time; and
dissolving iron sulfide on the carbon steel tube with the composition to obtain chelated iron.
14. The method of claim 13, wherein the weight ratio of the iron chelator to the additive is in the range of 50:1 to 5: 1.
15. The method of claim 13 or claim 14, wherein dissolving the iron sulfide does not result in the formation of hydrogen sulfide.
16. The method of any one of claims 13 to 15, wherein dissolving the iron sulfide comprises dissolving 5 to 100 weight percent of the iron sulfide.
17. The method of any one of claims 13 to 16, wherein the length of time is in the range of 4 hours to 72 hours.
18. The method of any one of claims 13 to 17 wherein the carbon steel tube has a corrosion of less than 0.05 lb/ft after the length of time2。
19. The method of any one of claims 13 to 18, comprising removing the composition from the subterranean formation after the length of time.
Technical Field
This document relates to methods for mitigating corrosion and surface scale deposition on carbon steel tubing in oil field applications, particularly in acid gas wells.
Background
Iron sulfide deposition on carbon steel tubing is a continuing problem in the oil and gas industry, particularly in sour gas wells. Iron ions released from the carbon steel pipe due to corrosion react with hydrogen sulfide in the acid gas, forming iron sulfide deposits in the pipe, affecting the well's supply capacity, interfering with well monitoring, and limiting well intervention. Iron sulfide deposits having low sulfur content (e.g., a weight ratio of iron to sulfur in the range of 0.75 to 1.25) may be removed with concentrated hydrochloric acid. However, the use of concentrated hydrochloric acid corrodes the production string and casing during scale removal and results in the production of hydrogen sulfide, toxic gases, and potential hazards during application. Alternative detergents are less corrosive and safer to use, but give poorer results than concentrated hydrochloric acid.
SUMMARY
In a first general aspect, a composition for dissolving iron sulfide includes an iron chelator and an additive. The additive comprises an oxidizing agent, a base, or both.
In a second general aspect, treating a carbon steel pipe in a subterranean formation comprises providing a composition comprising an iron chelator and an additive to the carbon steel pipe, contacting the carbon steel pipe with the composition for a length of time, and dissolving iron sulfide on the carbon steel pipe with the composition to obtain chelated iron. The additive includes at least one of an oxidizing agent and a base.
Implementations of the first or second general aspects may include one or more of the following features.
In some embodiments, the concentration of the iron chelator in the composition is in the range of 10 wt% to 80 wt%.
The additive may include an oxidizing agent. The concentration of the oxidizing agent in the composition is typically in the range of 0.05 wt.% to 15 wt.%. The oxidizing agent may include at least one of: potassium permanganate, ammonium nitrate, sodium bromate, sodium hypochlorite, sodium nitrite, sodium bicarbonate, potassium bicarbonate, ammonium carbonate, ammonium bicarbonate and iodine.
The additive may include a base. The concentration of the base in the composition is typically in the range of 1 to 60% by weight. The base may include a strong base, a medium strong base, or a weak base. Examples of strong bases include potassium hydroxide and sodium hydroxide. Examples of the medium and strong bases include potassium carbonate, sodium carbonate, potassium hydrogencarbonate, ammonium carbonate and ammonium hydrogencarbonate.
The iron chelator may comprise at least one of the following: ethylenediaminetetraacetic acid, diethylenetriaminepentaacetic acid, tetrasodium glutamate diacetate, tetrakis (hydroxymethyl) phosphonium sulfate, nitrilotriacetic acid, citrate, and pyrophosphate.
The composition is free of hydrochloric acid.
The pH of the composition is in the range of 3 to 14.
Implementations of the second general aspect may include one or more of the following features.
Dissolving iron sulfides generally does not result in the formation of hydrogen sulfide. Dissolving the iron sulfide generally includes dissolving 5 wt.% to 100 wt.% percent of the iron sulfide. The length of time is typically in the range of 4 hours to 72 hours. After this length of time, the carbon steel tube has corroded less than 0.05 lb/ft2. After the length of time, the composition may be removed from the subterranean formation.
The described embodiments advantageously foul the iron sulfide surface in carbon steel pipes without producing hydrogen sulfide. In addition, the corrosion of the carbon steel tube is reduced as compared to the corrosion of the carbon steel tube by concentrated hydrochloric acid. Furthermore, operating costs are reduced in the absence of hydrogen sulfide generation associated with treatment with concentrated hydrochloric acid, and capital expenditure is reduced by reducing corrosion of the carbon steel and thus improving the durability of the carbon steel.
Brief Description of Drawings
FIG. 1 depicts an exemplary system for dissolving iron sulfide in carbon steel pipe in a subterranean formation.
FIG. 2 is a flow chart illustrating operations in a first exemplary process for dissolving iron sulfide in carbon steel pipe in a subterranean formation.
Figure 3 shows iron sulfide dissolution with respect to a combination of hydrochloric acid and various dissolution agents (dispolvers).
Figure 4 shows iron sulfide dissolution over time with hydrochloric acid and a high pH chelating agent used with a base.
Figure 5 shows iron sulfide dissolution for a high pH chelating agent and a base used with various oxidizing agents.
Detailed description of the invention
Compositions for dissolving iron sulfides and other iron-containing compounds, such as iron carbonate, comprise an iron chelator and an additive that enhances the performance of the iron chelator. The composition may be in liquid or solid form. The liquid may be an aqueous liquid. The iron sulfide may comprise any suitable stoichiometric ratio of iron and sulfur. Examples include Fe where x ═ 0 to 0.2(1-x)S (pyrrhotite), FeS (merthiolate and marynodite), FeS2(pyrite), Fe3S4(greigite), FeS2(marcasite). An example of pyrrhotite is Fe7S8. The additive is at least one of an oxidizing agent and a base. The composition may be used to dissolve iron sulfides formed in carbon steel tubing in a subterranean formation, such as carbon steel tubing in an oil or gas well. The weight ratio of the iron chelator to the additive is in the range 50:1 to 5: 1. By adjusting the ratio of iron chelator to additive, the iron sulfide dissolution rate can be varied, e.g., increased or decreased.
The iron chelating agent dissolves iron sulfide scale, such as minerals containing iron sulfide, formed on the surface of the plain carbon steel tube by chelating the iron in the iron sulfide. Iron chelators may also chelate the more soluble forms of iron present in solution, such as iron oxides, iron carbonates, and the like. In some embodiments, the iron chelator comprises at least one of: ethylenediaminetetraacetic acid(EDTA), diethylenetriaminepentaacetic acid (DTPA), tetrasodium glutamate diacetate (GLDA), nitrilotriacetic acid (NTA), citrate, pyrophosphate (P)2O7) And tetrakis (hydroxymethyl) phosphonium sulfate (THPS). The concentration of the iron chelator in the composition is typically in the range of 1 weight% (wt%) to 80 wt%.
When present in the composition, the oxidizing agent oxidizes iron sulfides, which react in water to give more water-soluble compounds, such as iron oxides. The oxidant also oxidizes reaction products formed during dissolution of the iron sulfide, removing or converting the reaction products, thereby shifting the reaction equilibrium and increasing the dissolution rate of the iron sulfide. Increasing the dissolution rate shortens the length of time the composition must be contacted with iron sulfide to achieve the desired level of dissolution or descaling.
Suitable oxidizing agents include potassium permanganate, ammonium nitrate, sodium bromate, sodium hypochlorite, sodium nitrite, sodium chlorite, ammonium persulfate, sodium thiosulfate, and iodine. In some embodiments, the oxidizing agent is an acid. The acid may be a strong or weak acid. A suitable example of a strong acid is nitric acid. The concentration of the oxidizing agent in the composition is typically in the range of 0.05 wt.% to 15 wt.%.
The base may be a strong base, a medium strong base, a weak base, or a combination thereof. Suitable strong bases include sodium hydroxide and potassium hydroxide. Suitable moderately strong bases include potassium carbonate, sodium bicarbonate, potassium bicarbonate, ammonium carbonate, and ammonium bicarbonate. Suitable weak bases include EDTA at a pH of about 7 to 8. The concentration of the base in the composition is typically in the range of 1 to 60% by weight.
The pH of the composition is typically in the range of 3 to 14.
These compositions for iron sulfide dissolution, when provided to carbon steel pipes in subterranean formations, remove iron sulfide deposits and other iron-containing deposits, thereby restoring accessibility (accessibility) to the well and increasing productivity. These compositions can provide iron sulfide dissolving capacity comparable to hydrochloric acid without causing damage to well integrity or causing safety issues such as those associated with the generation of toxic hydrogen sulfide gas. By comparison, 1 moleHydrochloric acid (
Fig. 1 depicts an
Fig. 2 is a flow chart illustrating operations in a
Examples
Dissolution test-iron chelating agent used with alkali
The ability of various compositions to dissolve iron sulfide was evaluated by placing a sample of the iron sulfide mineral in a high temperature bath containing a control composition or a composition comprising an iron chelator and a base. In the following examples, the control composition as well as the composition comprising the iron chelator and the base are referred to as "dissolution agents". The contents of the high temperature tank are heated to a specified temperature for a specified length of time. After the specified length of time had elapsed, the contents of the high temperature tank were filtered, and the remaining solids were washed with deionized water and dried at 80 ℃ overnight. The dried solids were weighed and the percent dissolution of the sample was calculated by subtracting the mass of remaining solids from the initial sample mass and dividing by the initial sample mass.
20mL of the dissolution agent and 2g of pyrrhotite (having the formula Fe where x ═ 0 to 0.2) were mixed(1-x)S iron sulfide mineral) was placed in a high temperature bath and held at 14.7psi for 24 hours at 125 ℃. The remaining solids were dried and the percent dissolution was calculated. The composition (iron sulfide component) and pH of the dissolving agent are listed in table 1.
TABLE 1 dissolving agent
Dissolving agent
pH
Description of the invention
HCl (15 wt%)
<0
Strong acid
Low pH chelating agents
6-8
pH-neutralized (15% HCl) EDTA (10-20% by weight)
THPS
2-5
THPS (30 wt%)
High pH chelating agents
>12
EDTA (10-25% by weight) with KOH
Figure 3 shows the percent dissolution of pyrrhotite in the dissolution agent of table 1 after 24 hours at 125 ℃ and 14.7 psi. In the initial phase of the test, the fouling sample was rapidly dissolved by 15% HCl. After 24 hours, it dissolved about 88% of the soil. After 24 hours, the solubility properties of the high pH chelant exceeded the solubility properties of the low pH chelant and the THPS, which was about 73% dissolved compared to about 12% dissolved for the low pH chelant and 19% dissolved for the THPS.
Figure 4 shows the percent dissolution as a function of time from 2 hours to 24 hours at 125 ℃ and 14.7psi for 15% HCl (top) and high pH chelating agent (bottom) of table 1. In the initial phase of the experiment, 15% HCl rapidly dissolved the field fouled sample: about 80% of the soil was dissolved in the first two hours. The dissolution rate of the high pH chelant was slower over the first 8 hours and increased over time.
Corrosion test-iron chelating Agents used with bases
The mild steel C1010 specimens were cleaned with distilled water and acetone and then dried in air. The corrosion of steel coupons immersed in the solvent of Table 1 for 4 hours at 125 ℃ and 14.7psi was evaluated by the difference in coupon weight before and after immersion. Table 2 lists the dissolving agents of Table 1 in pounds per foot2Corrosion of the meter. As seen in Table 2, each of the dissolution agents showed less than 0.05 lb/ft at 125 deg.C over 4 hours, except hydrochloric acid2And the high pH chelant has a minimum value (0.001 lbs/ft)2). Hydrochloric acid showed very high corrosion with 0.45 lbs/ft2Corrosion of (2).
TABLE 2 Corrosion of low carbon steel C1010 specimens with various dissolution agents
Dissolving agent
Corrosion (pounds per foot)2)
THPS
0.041
Low pH chelating agents
0.015
15％HCL
0.45
High pH chelating agents
0.001
Dissolution test-iron chelating agent used with alkali and oxidizing agent
To increase the dissolution rate, especially in the initial phase of dissolution (less than 8 hours), the oxidizing agent was combined with the high pH chelator dissolution agent of table 1. The ability of various compositions to dissolve iron sulfide was evaluated by placing a sample of the iron sulfide mineral in a high temperature bath containing a control composition or a composition comprising a high pH chelating agent and an oxidizing agent. In the following examples, the control composition and the composition comprising the iron chelator used with the oxidant and the base are referred to as "dissolution agents". The contents of the high temperature tank are heated to a specified temperature for a specified length of time. After the specified length of time had elapsed, the contents of the high temperature tank were filtered, and the remaining solids were washed with deionized water and dried at 80 ℃ overnight. The dried solids were weighed and the percent dissolution of the sample was calculated by subtracting the mass of remaining solids from the initial sample mass and dividing by the initial sample mass.
20mL of a dissolving agent (high pH chelating agent of table 1 with or without an oxidizing agent) and 2g of pyrrhotite (Fe having the formula where x ═ 0 to 0.2)(1-x)S iron sulfide mineral) was placed in a high temperature bath and held at 14.7psi for 4 hours at 125 ℃. Each of the dissolving agents 1A, 2A, 3A, and 4A contained 0.0g of the listed oxidizing agent. Each of the dissolving agents 1B, 2B, 3B, and 4B contained 0.2g of the listed oxidizing agent. Each of the dissolving agents 1C, 2C, 3C, and 4C contained 0.6g of the listed oxidizing agent. Each of the dissolving agents 1D, 2D, 3D, and 4D contained 0.8g of the listed oxidizing agent. After four hours, the remaining solids were dried and the percent dissolution was calculated. The composition and pH of the dissolution agent are listed in table 3.
TABLE 3 dissolving agent
FIG. 5 shows chelating agents for high pH and NaNO2、KMnO4、NaClO2And NaBrO3Percent dissolution of oxidant after 4 hours at 125 ℃ and 14.7 psi. The high pH chelating agent used with the base dissolved about 5% of the pyrrhotite sample in 4 hours at 125 c and 14.7 psi. Oxidant KMnO4、NaClO2And NaBrO3It does not appear to improve the solubility of the lytic agent. However, NaNO2The presence of (2) improves the dissolution behavior, in a 4 hour test, 0.6g of NaNO2An increase from about 5% to about 8.2%, or an increase of over 60% is shown.
Definition of
In this document, the terms "a", "an" or "the" are used to include one or more than one unless the context clearly indicates otherwise. The term "or" is used to refer to a non-exclusive "or" unless otherwise indicated. The expression "at least one of a and B" has the same meaning as "A, B, or a and B". Also, it is to be understood that the phraseology or terminology employed in the present disclosure, and not otherwise defined, is for the purpose of description only and not of limitation. The use of any section headings is intended to aid in the reading of the document and should not be construed as limiting; information related to the chapter title may appear within or outside of that particular chapter.
The recitation of values by ranges is to be interpreted in a flexible manner to include not only the numerical values explicitly recited as the limits of the range, but also to include all the individual numerical values or sub-ranges encompassed within that range as if each numerical value and sub-range is explicitly recited. For example, a range of "about 0.1% to about 5%" or "about 0.1% to 5%" should be interpreted as: not only about 0.1% to about 5%, but also individual values (e.g., 1%, 2%, 3%, and 4%) and sub-ranges (e.g., 0.1% to 0.5%, 1.1% to 2.2%, 3.3% to 4.4%) within the indicated ranges. Unless otherwise indicated, the expression "about X to Y" has the same meaning as "about X to about Y". Likewise, unless otherwise indicated, the expression "about X, Y or about Z" has the same meaning as "about X, about Y, or about Z". The term "about" may allow for a degree of variability in a value or range, for example, within 10%, within 5%, or within 1% of the limit of the value or range.
The term "subterranean formation" refers to any material below the earth's surface, including below the bottom surface of the ocean. For example, a subterranean formation may be any portion of a wellbore and any portion of a subterranean oil or water producing formation or region that is in contact with a wellbore fluid. In some examples, the subterranean formation may be any subsurface region or any subsurface portion in fluid contact with which liquid or gaseous petroleum substances, water, or the like may be produced. For example, the subterranean formation may be at least one of: the zone requiring fracturing, the zone around the fracture or fracture, and the zone around the flow path or flow path, where the fracture or flow path may optionally be fluidly connected to a zone in the subsurface that produces oil or water, either directly or through one or more fractures or flow paths.
By "sour gas well" is meant a well that produces natural gas or any other gas containing significant amounts of hydrogen sulfide. In one example, a gas is considered acidic if it contains greater than 5.7mg of hydrogen sulfide per cubic meter of natural gas, or greater than 4ppm hydrogen sulfide by volume at standard temperature and pressure. In other examples, a gas is considered acidic if it contains greater than 24ppm by volume or 100ppm by volume hydrogen sulfide.
Other embodiments
It is to be understood that while the embodiments have been described in conjunction with the detailed description thereof, the foregoing description is intended to illustrate and not limit the scope of the invention, which is defined by the scope of the appended claims. Other aspects, advantages, and modifications are within the scope of the following claims.
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