WO2025014498A1

WO2025014498A1 - Mitigation of iron sulfide fouling using organic carbonates

Info

Publication number: WO2025014498A1
Application number: PCT/US2023/027674
Authority: WO
Inventors: Enrico T. NADRES; Justin Thomas PORTER; Sankaran Murugesan
Original assignee: Baker Hughes Oilfield Operations LLC
Current assignee: Baker Hughes Oilfield Operations LLC
Priority date: 2023-07-13
Filing date: 2023-07-13
Publication date: 2025-01-16
Anticipated expiration: 2026-01-13

Abstract

A system and method for treating iron sulfide fouling with organic carbonates includes creating an iron sulfide treatment formulation. The iron sulfide treatment formulation includes at least one organic carbonate selected from the group consisting of dialkyl carbonates, methyl carbonates, cyclic carbonates, and combinations thereof, and optionally a co-solvent or chelating agent. The iron sulfide treatment formulation can be combined with a carrier fluid to provide an iron sulfide treatment system. The iron sulfide treatment formulation can be used to remediate iron sulfide scaling in wellbores and on surface-based process equipment, piping and facilities.

Description

MITIGATION OF IRON SULFIDE FOULING USING ORGANIC CARBONATES

FIELD OF THE INVENTION

[001] The present application is generally directed at methods and compositions for the mitigation of iron sulfide fouling and more particularly, but not by way of limitation, to compositions and methods for using organic carbonates in the treatment of iron sulfide deposits.

BACKGROUND

[002] Iron sulfide is a significant problem in oil and gas production, imparting widespread damage to metal equipment such as well tubulars, pipelines, downhole equipment, and storage tanks. For example, in the case of refineries, the accumulation of iron sulfide deposits can restrict flow through heat exchangers and other process equipment.

[003] Tn the upstream production of petroleum products, scaling can occur rapidly , and the damage caused by the scaling can be very expensive. Production can fall from tens of thousands of barrels per day to zero in a very short period because of scaling caused by changing conditions in the well. The cost for cleaning out a single well and putting it back on production can be approximately the same as the chemical costs to treat the entire field. While not all wells are susceptible to such momentous penalties for permitting scaling to occur, it is apparent that scale prevention, formation, and remediation have associated costs.

[004] It is expected that oilfield scaling problems will continue to worsen and become more expensive over time due to increased use of longer tieback liners, increased implementation of “smart” wells where integrity is more critical, increased gas production since gas well formations tend to be more sensitive, an increased need to use greener chemicals, and increasing amounts of produced water.

[005] Iron sulfide (FeS) scales are among the most common and difficult to remediate, both in oilfield operations and within refineries. Iron sulfide scales are commonly encountered when hydrogen sulfide (H2S) is produced - often the result of tubular corrosion in the presence of hydrogen sulfide. The chemistry is complicated; more than one iron sulfide phase can be present. The physical properties of the phases vary (sometimes dense, sometimes not), and the phase composition can change with time. Due in part to its low solubility, iron sulfide precipitates more easily than other common oilfield scales, making the problem of iron sulfide formation and deposition particularly difficult to solve.

[006] It is essential to apply appropriate mitigation and remediation techniques for iron sulfide fouling to avoid costly mechanical interventions and shutdowns. Where descaling efforts are unsuccessful, the affected equipment may need to be replaced in its entirety.

[007] Depending on the location of the scale, it may be removed mechanically. Mechanical methods, including milling and jetting, are among the most successful methods of scale removal in tubulars. Mechanical descaling, however, is often expensive and risks damage to downhole tubulars.

[008] Chemical dissolution of certain wellbore scales is expensive but can be used when mechanical removal methods are ineffective or more costly. Iron sulfide deposits may be quickly dissolved with hydrochloric acid (HC1), which is easily sourced. Treatment with hydrochloric acid has the disadvantage of promoting corrosion, however, thereby producing greater amounts of hydrogen sulfide and precipitating sulfur that aggravates the long-term issue of iron sulfide fouling. To remediate these issues, HC1 treatments must be accompanied with high levels of corrosion inhibitors and H2S scavengers, which entail both high cost and the risk of additional formation damage to the system.

[009] Chelating agents - such as THPS, EDTA, DTP A, and HEDTA - have been proposed as an alternative to hydrochloric acid for dissolving iron sulfide scales. Although these chemicals are effective in dissolving and removing iron sulfide scales, they have environmental and practical drawbacks. For example, THPS is toxic to aquatic organisms, and EDTA is more effective in aqueous solutions with a pH range higher than the optimal range for production fluid. Chelating agents may also create unwanted precipitants that require dissolution through solubilizing acids. Additionally, chelating agents are often expensive.

[0010] The above mechanical and chemical removal methods are reactive, not proactive. The proactive use of scale inhibitors to initially prevent or mitigate scaling is generally preferred over reactive approaches. Most inhibitors for inorganic scales are phosphorous compounds: inorganic polyphosphates, organic phosphate esters, organic phosphonates, organic aminophosphates, and organic polymers. Although widely available from many companies, these phosphorous-based compounds may have problematic impacts when discharged in the environment.

[0011] It is, therefore, a continuing goal to improve the dissolution and inhibition of iron sulfide scales in such a more environmentally acceptable manner, while also reducing the costs of operations and materials. SUMMARY OF THE INVENTION

[0012] The embodiments disclosed herein are generally directed to the inhibition and dissolution of iron sulfide deposits. Some embodiments include an iron sulfide treatment formulation that includes at least one organic carbonate selected from the group consisting of dialkyl carbonates, methyl carbonates, cyclic carbonates, and combinations thereof. The iron sulfide treatment formulation optionally includes a co-solvent.

[0013] For other embodiments, the present disclosure is directed at an iron sulfide treatment system that includes an iron sulfide treatment formulation and a carrier fluid. The iron sulfide treatment formulation includes at least one organic carbonate selected from the group consisting of propylene carbonate, ethylene carbonate, glycerol carbonate, dimethyl carbonate, diethyl carbonate, dibutyl carbonate, and combinations thereof. The iron sulfide treatment formulation optionally includes a co-solvent.

[0014] In yet other embodiments, the present disclosure is directed at a method for treating an iron sulfide scale target. In these non-limiting embodiments, the method includes the steps of preparing an iron sulfide treatment formulation and contacting the iron sulfide scale target with the iron sulfide treatment formulation for a contact period. The step of preparing the iron sulfide treatment formulation includes the steps of selecting one or more organic carbonates from the group consisting of propylene carbonate, ethylene carbonate, glycerol carbonate, dimethyl carbonate, diethyl carbonate, dibutyl carbonate, and combinations thereof, and adding a cosolvent to the one or more organic carbonates. The iron sulfide treatment formulation can be combined with a carrier fluid before the step of contacting the iron sulfide scale target with the iron sulfide treatment formulation. BRIEF DESCRIPTION OF THE DRAWINGS

[0015] FIG. 1 illustrates the anti-fouling properties of propylene carbonate when charged in vials with iron sulfide deposits.

[0016] FIG. 2 further illustrates the anti-fouling properties of propylene carbonate when charged in vials with iron sulfide deposits and from which free-floating iron sulfide was removed.

[0017] FIG. 3 shows a series of vials wherein iron sulfide deposits have been treated with propylene carbonate, THPS, and EDTA.

DETAILED DESCRIPTION

[0018] It has been discovered that certain organic carbonates present an environmentally friendly solution for preventing the formation of iron sulfide deposits and for dissolving existing deposits, thereby enhancing the productivity of oil and gas equipment. Organic carbonates are biodegradable. Iron sulfide scaling mitigation with organic carbonates can reduce an operator or refiner’s carbon footprint, avoid introducing corrosive materials into equipment, and replace environmentally adverse phosphorous-based compounds. Further, the use of these carbonates avoids the precipitates and side reactions that are characteristic of current iron sulfide treatments where there is a high level of total dissolved solids (TDS). These organic carbonates, therefore, offer a desirable alternative to current methods and compositions for treating iron sulfide scales.

[0019] In one form, an iron sulfide treatment formulation includes an organic carbonate component, where the organic carbonate component includes one or more organic carbonates. The iron sulfide treatment formulation optionally includes a co-solvent. [0020] Suitable organic carbonates include dialkyl carbonates, methyl carbonates, cyclic carbonates, and combinations of thereof. Suitable organic carbonates include, but are not necessarily limited to, propylene carbonate, ethylene carbonate, glycerol carbonate, dimethyl carbonate, diethyl carbonate, dibutyl carbonate, and combinations thereof. In one nonembodiment, the organic carbonate component includes about 25 weight (wt.) % glycerol carbonate in propylene carbonate (the balance). In another embodiment, the organic carbonate component includes about 25 wt.% ethylene carbonate in propylene carbonate (the balance). In yet another embodiment, the organic carbonate component includes about 21 wt.% gly cerol carbonate in dimethyl carbonate (as the balance).

[0021] For embodiments in which the iron sulfide treatment formulation includes a co-solvent, the co-solvent can be a glycol, an ether, a short chain alcohol having between 1 and 8 carbon atoms, or a combination of the same. Suitable co-solvent alcohols include ethanol, butanol, isopropyl alcohol, and combinations thereof. It will be appreciated that it is desirable to avoid co-solvents that significantly modify the pH of the iron sulfide treatment formulation. For most embodiments, it is desirable to maintain the pH of the iron sulfide treatment formulation in a range of between 3 to 10.

[0022] In some embodiments, it is desirable to include a chelating agent within the iron sulfide treatment formulation. Through combination with the organic carbonate component, the quantity of the chelating agent component in the iron sulfide treatment formulation may be less than the amount of chelating agent typically used to treat iron sulfide scaling on its own. This reduction in the amount of chelating agent can lower both cost and environmental harm. For embodiments in which the iron sulfide treatment formulation includes a chelating agent component, suitable chelating agents include THPS, EDTA, DTPA, HEDTA, and combinations thereof.

[0023] In one embodiment, the iron sulfide treatment formulation includes between about 0.01 wt.% to about 100 wt.% organic carbonate and between about 0 wt.% to about 99.99 wt.% cosolvent. In another embodiment, the iron sulfide treatment formulation includes between about 0.01 wt.% to about 50 wt.% organic carbonate and between about 0 wt.% to about 49.9 wt.% co-solvent. In yet another embodiment, the iron sulfide treatment formulation includes about 0.1 wt.% organic carbonate and about 99.9 wt.% co-solvent.

[0024] In one embodiment that includes a chelating agent, the iron sulfide treatment formulation includes between about 0.1 wt.% to about 99.9 wt.% organic carbonate; between about 0 wt.% to about 99.9 wt.% co-solvent; and between about 0.1 wt.% to about 50 wt.% chelating agent. In another embodiment, the iron sulfide treatment formulation includes between about 0.01 wt.% to about 99.9 wt.% organic carbonate; between about 0.1 wt.% to about 90 wt.% co-solvent; and between about 0.1 wt.% to about 50 wt.% chelating agent. In yet another embodiment, the iron sulfide treatment formulation includes about 60 wt.% organic carbonate; about 30 wt.% co-solvent; and about 30 wt.% chelating agent. It will be understood that, as used herein, a range of X wt.% to Y wt.% will be interpreted to include the disclosure of each discrete integer value between X and Y (e.g., X, X+l, X+2... .Y-l, Y).

[0025] In some embodiments, the iron sulfide treatment formulation is delivered in a concentrated form. For wellbore applications, the concentrated form can be applied to the impacted region by injection through capillary tubing, chemical injection plunger, or other treatment chemical deliv ery mechanisms. For application to surface-based equipment or facilities, the concentrated iron sulfide treatment formulation can be applied by pumping, spraying, soaking, or otherwise contacting the iron sulfide scales with the concentrated iron sulfide treatment formulation.

[0026] In alternative embodiments, the iron sulfide treatment formulation is mixed with a suitable carrier fluid to form an iron sulfide treatment system and pumped into the wellbore or through surface-based facilities and equipment. The carrier fluid may be water, brine, or another aqueous solution. In some embodiments, the iron sulfide treatment formulation is mixed into the carrier fluid in a concentration range of between about 10 ppm to approximately 10,000 ppm (iron sulfide treatment formulation/carrier fluid). In other embodiments, the iron sulfide treatment formulation is present in the carrier fluid in concentrations ranging from about 1 0 ppm to approximately 5,000 ppm. In other embodiments, the iron sulfide treatment formulation is present in the carrier fluid in concentrations ranging from approximately 700 ppm to approximately 1,000 ppm. In yet other embodiments, the iron sulfide treatment formulation is present in the earner fluid in a concentration of about 1,000 ppm.

[0027] In certain applications, it may be useful to deploy the concentrated or diluted forms of the iron sulfide treatment formulation to the iron sulfide scale target and then allow the iron sulfide treatment formulation to soak into the iron sulfide scales over a period of time. For example, in some applications, it is useful to emplace the iron sulfide treatment formulation onto the iron sulfide scale target, allow the iron sulfide treatment formulation to contact the iron sulfide scales for a contact period of between about 1 and about 12 hours, and then flush the iron sulfide treatment formulation and dissolved iron sulfide scales with an aqueous wash. [0028] To prevent the reprecipitation of iron sulfide deposits and to ensure the continued dissolution of the scale, the iron sulfide treatment formulation can be applied in multiple treatments. Once the accumulated scales have been removed, a maintenance program can be adopted in which smaller quantities or concentrations of the iron sulfide treatment formulation are applied to the wellbore or surface equipment to mitigate or slow the formation of new iron sulfide scales. Depending on the available data, certain embodiments of the method include the step of determining an optimal frequency for treating the metal equipment with the iron sulfide treatment formulation to prevent recurring formation of iron sulfide scales. The iron sulfide treatment formulation may then be strategically injected into the metal equipment at established time intervals that reflect the optimal frequency.

[0029] It will be appreciated that the iron sulfide treatment formulation may be injected into various metal equipment or parts, including but not limited to wellbore tubulars, pipelines, wellheads, production tubing, downhole equipment, process equipment, process tanks and conduits, and storage tanks to address the problem of iron sulfide fouling.

EXAMPLE I

[0030] Tests were performed to demonstrate the overall anti-foulmg properties of propylene carbonate (CrHeOs). As depicted in FIG. 1, three glass vials 100a, 100b, 100c of the same size were obtained. Within each vial 100, 1 equimolar amount (eq.) of powdered iron sulfide was charged, and water was added. The first vial 100a was set aside as a control. The second and third vials 100b, 100c were treated, respectively, with 1 eq. of propylene carbonate and 5 eq. of propylene carbonate. All three vials 100 were then magnetically stirred at 90 °C for three (3) hours, at which time a significant amount of iron sulfide deposits (scaling) was visible on the walls within the first vial 100a. The vials 100 were inverted, as shown in FIG. 1, to better visualize and gauge the scaling. The results showed that the vials 100b, 100c treated with propylene carbonate contained significantly less scaling on the walls of the glass vials than did those of the first vial 100a.

EXAMPLE II

[0031] Further testing was performed to focus on the anti-fouling properties of propylene carbonate in reducing established iron sulfide deposits. As depicted in FIG. 2, three glass vials 102a, 102b, 102c of the same size were obtained. Each vial 102 was charged with 1 eq. of powdered iron sulfide and water. All three vials 102 were magnetically stirred at 90 °C until a significant amount of iron sulfide had deposited on the walls of the glass vials 102 At this time, the vials 102 were each emptied and rinsed with water until all free-floating iron sulfide was removed from the vials 102. The vials 102 were then again filled with water. The first vial 102a was set aside as a control. The second and third vials 102b, 102c were treated, respectively, with 1 eq. and 5 eq. of propylene carbonate. All three vials 102 were again magnetically stirred at 90 °C. After only one (1) hour of stirring, signs of the removal of iron sulfide deposits w ere visible in the two vials treated with propylene carbonate 102b, 102c. The vials 102 were magnetically stirred until visual inspection indicted that a significant amount of the iron sulfide deposits had been removed within the vials 102b, 102c treated with propylene carbonate. This experiment suggests that the propylene carbonate was effective at limiting the formation of iron sulfide scales on the walls of the vials 102b, 102c. EXAMPLE III

[0032] The anti-fouling properties of propylene carbonate were compared with those of known antifoulants tetrakis(hydroxymethyl)phosphonium sulfate (THPS) ([(CH2OH)4P]2SO4) and ethylenediaminetetraacetic acid (EDTA) ([CH2N(CH2CO2H)2]2). As depicted in FIG. 3, four glass vials 104a-104d of the same size were obtained and treated with iron sulfide according to the same procedure in Example II, wherein all free-floating iron sulfide was removed prior to treatment with the antifoulants. The first vial 104a was designated as the control, the second vial 104b was treated with 1 eq. of propylene carbonate, and the third and fourth vials 104c, 104d were treated, respectively, with conventional antifoulants THPS and EDTA. All vials 104 were heated to 90 °C for one (1) hour while magnetically stirring. Visible iron sulfide removal was observed in the vial 104b treated with propylene carbonate, though the effects were less pronounced than those of the vials containing THPS and EDTA 104c, 104d. Although the initial effects of THPS and EDTA were more pronounced than those of propylene carbonate, these chelating agents often create other unwanted precipitants with time, thus requiring the addition of solubilizing acids. By contrast, propylene carbonate inhibits and removes iron sulfide deposits without the need for subsequent treatment with acids. Propylene carbonate is also a less costly and more environmentally friendly alternative to THPS and EDTA.

[0033] In the foregoing specification, the invention has been described with reference to specific embodiments thereof. However, it will be evident that various modifications and changes can be made thereto without departing from the broader scope of the invention as set forth in the appended claims. Accordingly, the specification is to be regarded in an illustrative rather than a restrictive sense. For example, different organic carbonate solvents, co-solvents and chelating agents, scale inhibitor treatment procedures, proportions, dosages, temperatures, and amounts not specifically identified or described in this disclosure or not evaluated in a particular Example are still expected to be within the scope of this invention.

[0034] The present invention may suitably comprise, consist of, or consist essentially of the elements disclosed and may be practiced in the absence of an element not disclosed. As used herein, the singular forms “a,” “an,” and “the” are intended to include the plural forms as well, unless the context clearly indicates otherwise. As used herein, the term “about” in reference to a given parameter is inclusive of the stated value and has the meaning dictated by the context (e.g., it includes the degree of error associated with measurement of the given parameter). As used herein, the term “and/or” includes any and all combinations of one or more of the associated listed items.

Claims

[0035] It is claimed:

1. An iron sulfide treatment formulation comprising at least one organic carbonate selected from the group consisting of dialkyl carbonates, methyl carbonates, cyclic carbonates, and combinations thereof.

2. The iron sulfide treatment formulation of claim 1, wherein the at least one organic carbonate is selected from the group consisting of propylene carbonate, ethylene carbonate, glycerol carbonate, dimethyl carbonate, diethyl carbonate, dibutyl carbonate, and combinations thereof.

3. The iron sulfide treatment formulation of claim 1, wherein the at least one organic carbonate comprises: about 25 wt.% glycerol carbonate; and about 75 wt.% propylene carbonate.

4. The iron sulfide treatment formulation of claim 1, wherein the at least one organic carbonate comprises: about 25 wt.% ethylene carbonate; and about 75 wt.% propylene carbonate.

5. The iron sulfide treatment formulation of claim 1 , wherein the at least one organic carbonate comprises: about 21 wt.% glycerol carbonate; and about 79 wt.% dimethyl carbonate.

6. The iron sulfide treatment formulation of claim 1 comprising: between about 0.01 wt.% to about 100 wt.% organic carbonate; and optionally, a co-solvent present in an amount not exceeding about 99.99 wt.%.

7. The iron sulfide treatment formulation of claim 1 further comprising a cosolvent.

8. The iron sulfide treatment formulation of claim 7, wherein the co-solvent is selected from the group consisting of glycols, ethers, short chain alcohols having between 1 and 8 carbon atoms, and combinations thereof.

9. The iron sulfide treatment formulation of claim 7, wherein the co-solvent is an alcohol selected from the group consisting of ethanol, butanol, isopropyl alcohol, and combinations thereof.

10. The iron sulfide treatment formulation of claim 1 further comprising a chelating agent.

11. The iron sulfide treatment formulation of claim 10 comprising: between about 0.1 wt.% to about 99.9 wt.% organic carbonate; between about 0.1 wt.% to about 50 wt.% chelating agent; and optionally, a co-solvent present in an amount not exceeding about 99.9 wt.%.

12. An iron sulfide treatment system comprising: an iron sulfide treatment formulation, wherein the iron sulfide treatment formulation comprises at least one organic carbonate selected from the group consisting of propylene carbonate, ethylene carbonate, glycerol carbonate, dimethyl carbonate, diethyl carbonate, dibutyl carbonate, and combinations thereof; and a carrier fluid.

13. The iron sulfide treatment system of claim 12, wherein the iron sulfide treatment formulation is present in the carrier fluid at a concentration ranging from approximately 10 ppm to approximately 10,000 ppm.

14. The iron sulfide treatment system of claim 12, wherein the iron sulfide treatment formulation further comprises a co-solvent.

15. A method for treating an iron sulfide scale target, the method comprising the steps of: preparing an iron sulfide treatment formulation, wherein the step of preparing an iron sulfide treatment formulation comprises: selecting one or more organic carbonates from the group consisting of propylene carbonate, ethylene carbonate, glycerol carbonate, dimethyl carbonate, diethyl carbonate, dibutyl carbonate, and combinations thereof; and adding a co-solvent to the one or more organic carbonates; and contacting the iron sulfide scale target with the iron sulfide treatment formulation for a contact period.

16. The method of claim 15, wherein the step of preparing the iron sulfide treatment formulation further comprises adding a chelating agent to the one or more organic carbonates.

17. The method of claim 15, further comprising the step of combining the iron sulfide treatment formulation with a carrier fluid before the step of contacting the iron sulfide scale target with the iron sulfide treatment formulation.

18. The method of claim 17, wherein the step of combining the iron sulfide treatment formulation with the carrier fluid comprises adding the iron sulfide treatment formulation to the carrier fluid in a concentration range of between about 10 ppm and 10,000 ppm (iron sulfide treatment formulation/carrier fluid).

19. The method of claim 15, wherein the step of contacting the iron sulfide scale target comprises contacting the iron sulfide scale target with the iron sulfide treatment formulation for a contact period of between about 1 and about 12 hours.

20. The method of claim 15, further comprising the step of flushing the iron sulfide treatment formulation from the iron sulfide scale target with an aqueous wash.