IRON SULFIDE CLEANING FORMULATION AND METHODS OF USE THEREOF

CROSS REFERENCE TO RELATED APPLICATIONS

[0001] This application claims the benefit of U.S. Provisional Application No. 60/719,443 entitled "Iron Sulfide Cleaning Formulation and Methods of Use Thereof filed September 22, 2005.

BACKGROUND OF THE INVENTION

Field of the Invention

[0002] The present invention relates to a cleaning formulation acting as an iron sequesterant and methods of use thereof for the removal of black powder deposited in wet or dry hydrocarbon pipelines and associated pipeline equipment. Description of Related Art

[0003] The presence of black powder in hydrocarbon pipelines is a well-known problem faced by pipeline owners and operators. Black powder deposits on surfaces throughout the interior of the piping, pipe-fittings, instrumentation, and valves, which causes the costly reduction of flow efficiency of hydrocarbon movement through the pipeline. In 1996, the natural gas pipeline industry formally recognized the problems associated with black powder deposits in pipelines and sought to address the problems. A research study was commissioned by Gas Machinery Research Council (GMRC) to identify the origin and composition of black powder deposits in pipelines. The research findings published as Report No. TA 97-4, "Technical Assessment: Black Powder in the Gas Industry - Sources, Characteristics and Treatment" (1998), reported that black powder is a composition comprised primarily of iron sulfide deposits mixed with other contaminants. [0004] Black powder has noteworthy and varied characteristics. It may be loose or adhered to an interior surface of a pipeline. It may be dry (appearing as a smoke-like powder) or wet, similar to the consistency of tar. The powder may be combustible under certain conditions. Iron sulfide, the primary component of black powder deposits in pipelines generally originates from one of two sources. Iron sulfide deposits are caused by a chemical reaction of components in the pipeline, such as hydrogen sulfide present in natural gas, reacting with the iron component of the piping to form iron sulfide. In addition, iron sulfide deposits can be a result of microbiologically influenced corrosion (MIC). In the case of MIC effect on pipelines, a potential culprit is sulfate-reducing bacteria, which consume sulfates

present in the pipeline to produce hydrogen sulfide that is capable of quickly reacting with the iron component of the piping of a pipeline.

[0005] Several approaches seek to address the problem of iron sulfide deposits in hydrocarbon pipelines. One approach is a preventative measure to remove iron sulfide particulates present in the pipeline with a filtration system. A filtration system is positioned in a pipeline either before a compressor station or processing plant to maximize the amount of iron sulfide particulate captured for removal. Another approach is a cleaning protocol to remove iron sulfide deposits from the pipeline for subsequent treatment and disposal. The modes of cleaning iron sulfide deposits from a pipeline include mechanical contact with a pig and/or other abrasive substance and chemical contact with a cleaning agent. These modes for cleaning iron sulfide deposits from a pipeline may be used either alone or in combination to maximize cleaning efficiency. The use of a pig for cleaning a pipeline, also known as "pigging", entails a scraping action provided by the pig as it travels through a pipeline to remove deposits and push the same to a collection point of the pipeline for removal. Other abrasive substances used to scrape the inside of a pipeline include nut shells and sand. Cleaning agents typically used include water, diesel fuel, alcohol and specialty cleaning agents. In cases where pipeline cleaning involves a combination of the mechanical and chemical modes, a cleaning agent and optional abrasive substances are either pushed ahead of a trailing pig on a pigging run or, alternatively, held between two pigs during a pigging run through a pipeline.

[0006] Various forms of cleaning agents are commercially available for pipeline cleaning operations to remove iron sulfide. One form of cleaning agent is a surfactant. A commercially available surfactant is a water-based, anionic, surfactant solution sold as Alpha-Clean™ SQW pipeline cleaner by Clearwater International, LLC. Surfactants act to release solid deposits, which remain in a solid or semi-solid state during a pigging run. However, the solids and semi-solids suspended in solutions tend to clog valves, filters and instrumentation of a pipeline. Additionally, a condensate forms as a combination of the surfactant, hydrocarbons and water present in the pipeline form an emulsification that must be collected and disposed of in a manner that is not a hazard to the environment. The costs associated with cleaning a pipeline with a surfactant are generally high due primarily to the expenses associated with disposal of the emulsification.

[0007] Another form of a cleaning agent is an acid or acid-blended chemical composition. One commercially available acid-blended chemical composition is a formulation of organic and inorganic acids, including quaternary ammonium chloride and amine ethoxylates, sold as

Alpha 2792 acid cleaner by Clearwater International, LLC. Acids or acid-based chemical compositions are inexpensive, yet the risks and effects of using such chemicals are significant. Acids and acid-blended chemical compositions are corrosive to pipelines and also, during cleaning, raise the level of hydrogen sulfide gas present in a pipeline. Acids tend to leave iron sulfide in a state that promotes spontaneous ignition when exposed to air, which can cause significant injury to workers as well as significant damage to pigs and pipes. [0008] Yet another form of a cleaning agent is a hybrid blend of acids, surfactants and/or dispersants. One commercially available hybrid blend is a formulation of organic acids and anionic surfactants sold as Clear-Clean ^® 62 surfactant cleaner by Clearwater International, LLC. Another commercially available hybrid blend is the combination of surfactants, wetting agents, and dispersants sold as IntegraShield III pipeline cleaners by LubChem Inc. These hybrid blends pose similar risks as those of surfactants and acids. [0009] While these various forms of available cleaning agents may reduce black powder in a pipeline, the cleaning agents fail to provide a qualified indication of the post-treatment cleanliness of the pipelines. Clearly, the presence of larger solids and particulates in the cleaning agents after a pigging run indicates a degree of removal of macro-deposits of iron sulfide. However, there is no indication of the degree of pipeline cleanliness from removal of micro-deposits of iron sulfide.

[0010] More recently, an iron sulfide cleaning agent has been proposed that includes an aqueous solution of [tetrakis(hydroxymethyl)ρhosphonium] sulfate (termed THPS) or [tetrakis(hydroxymethyl)phosphonium]chloride (termed THPC) with an ammonium salt. This solution has a short shelf life unless it is retained in a container under an inert atmosphere such as a nitrogen blanket. If exposed to normal atmosphere, the effectiveness of the solution can drop by 65-70% over thirty days. A nitrogen blanket minimizes the loss of effectiveness to 5-10%. However, the need to maintain the solution in an inert atmosphere adds to the production cost thereof.

[0011] Yet another problem exists with the commercially available forms of cleaning agents. It is difficult to determine when a cleaning agent has been flushed from a pipeline, either traveling alone or in combination with pigs.

SUMMARY OF THE INVENTION

[0012] A cleaning formulation and method of use thereof is provided for use to reduce and deplete iron sulfide deposits in hydrocarbon pipelines.

[0013] The cleaning formulation of the present invention comprises water, which may be filtered water, [tetrakis(hydroxymethyl)phosphonium] sulfate or, alternatively, chloride (THPS or THPC) provided as an iron sequesterant, an ammonium salt, fluorescein provided as a visual cleanliness indicator, and/or potassium hydroxide provided as a buffer and as a tracer mechanism to identify the presence of the cleaning formulation at the end of a cleaning run, all of which is provided at a stabilized pH. The cleaning formulation is capable of solubilizing iron sulfide deposits in pipelines, while providing a qualifiable pipeline cleanliness indication and analytical tracer mechanism.

[0014] The method of the present invention comprises placing an effective amount of the cleaning formulation in a pipeline to saturate iron sulfide deposits for iron sequestration and removal. This is accomplished by either continuous injection process or by batch treatment followed by pigging.

[0015] After pigging with either process, the characteristics of the effluent may be visually and/or qualitatively analyzed to determine the degree of iron sulfide deposit removal and the cleanliness of the pipeline. The effluent is also analyzed to determine the presence of the tracer to ensure that the cleaning formulation is traveling through the pipeline during pigging.

DETAILED DESCRIPTION OF THE INVENTION

[0016] A cleaning formulation and method of use thereof is provided for use to solubilize iron sulfide deposits mixed with other contaminants in hydrocarbon pipelines. The term pipelines includes conduits and related components used in transport or handling of hydrocarbons.

[0017] The cleaning formulation of the present invention includes water, a sequestering agent such as [tetrakis(hydroxymethyl)phosphonium] sulfate or, alternatively, chloride (THPS or THPC), an ammonium salt, a buffering agent and an optional visual tracer component. [0018] In one embodiment of the invention, the cleaning formulation is produced using filtered water. The filtered water contains less than 0.05 ppm of contaminants, including chlorine and/or iron. Filtration of water may be performed using activated carbon adsorbtion systems available from Tigg Corporation of Bridgeville, Pennsylvania. It has been found that use of filtered water avoids the need for a nitrogen blanket to extend shelf life of the formulation.

[0019] The sequestering agents THPS and THPC are commercially available compounds sold by, for example, Rhodia Inc. of Cranberry, New Jersey. The cleaning formulation may contain 1-10 wt.% THPS or THPC and 0.05-1 wt.% ammonium salt, such as ammonium

chloride or ammonium sulfide. Formulations may be produced with less than 1 wt.% THPS or THPC consistent with the present invention, but with reduced effectiveness per unit volume, thereby requiring greater quantities of the formulation for treatment of a pipeline. Formulations containing more than 10 wt.% THPS or THPC may be corrosive and negatively impact the interior of a pipeline, but are not necessarily outside the scope of the present invention, hi another embodiment, the THPS or THPC is present in an amount of 5-7 wt.%, such as 6 wt.%.

[0020] The cleaning formulation is provided at a stabilized pH in a range of 4.5 to 7.2. The pH may be adjusted with a buffering agent such as potassium hydroxide, sodium hydroxide or the like.

[0021] Potassium hydroxide is particularly suited for use in the present invention as it may serve two roles upon dissolution in the formulation. In one role, the hydroxide functionality is a buffering agent that prevents a lowering of pH by the formulation. Use of a formulation with an acidic pH is desirably avoided to minimize corrosion of the pipeline undergoing treatment for iron sulfide deposits, hi a second role, the potassium ion may serve as a tracer component. Potassium ions are not commonly present in systems treated for iron sulfide deposits. As such, when the formulation of the present invention containing potassium hydroxide is used, the effluent of a treated pipeline will contain potassium ions. The presence of potassium ions may be detected via a quantitative analysis of effluent or of material adhering to a pig following a pigging run. For example, if the formulation of the present invention containing potassium hydroxide is administered into a pipeline and quantitative analysis of the effluent and/or material adhering to a pig does not indicate the presence of potassium, this is an indication of insufficient treatment of the pipeline warranting further administration thereto of the formulation. Alternatively, if qualitative analysis indicates presence of potassium ions, this is an indication that the formulation has been administered to the pipeline in a sufficient amount to flow therethrough. [0022] hi another embodiment, the cleaning formulation may further include a visual tracer component for identifying the presence of the cleaning formulation in the effluent of a conduit being treated. The tracer material may be fluorescent such as fluorescein, a greenish- yellow dye that is visible even when highly diluted. Fluorescein is commercially available from Texas Alkyd Dye Company and Pylam Products Company, Inc. In one embodiment, fluorescein is included in the formulation in an amount of less than 1 wt.%, such as 0.05 wt.%. hi use, as iron sulfide deposits are removed from a pipeline, the effluent generally exhibits a reddish brown color until the iron sulfide deposits are depleted. At that point, the

greenish-yellow color of the fluorescein becomes visible thereby indicating successful removal of the iron sulfide deposits.

[0023] The cleaning formulation may have various physical characteristics., The cleaning formulation may be provided in liquid form with a fluorescent greenish-yellow coloring. The cleaning formulation has a specific gravity in a range of 1.03 to 1.04. The cleaning formulation has a density of 8.67 pounds per gallon. The cleaning formulation is soluble in fresh water and brine water and is insoluble in oil. The cleaning formulation is environmentally friendly and capable of solubilizing iron sulfide deposits present in pipelines for subsequent removal.

[0024] The method of the present invention comprises determining an effective amount of the cleaning formulation to saturate and solubilize iron sulfide deposits in a pipeline. An effective amount of the cleaning formulation is determined by several factors. Those factors include consideration of the diameter and length of the pipeline to be cleaned, the level of iron sulfide contamination determined by the years in service of the pipeline and other means known by those skilled in the art, and the iron sulfide suspension capabilities of the cleaning formulation. In one embodiment, one gallon of the cleaning formulation, at normal ambient temperature, is capable of suspending in solution about 28 to 29 grams of iron sulfide in approximately 10-11 hours.

[0025] Once an effective amount of the cleaning formulation is determined, the method includes the further step of pigging with either a continuous injection process or batch treatment process.

[0026] The step of pigging with a continuous injection process involves the further steps of selecting an upstream point of a pipeline encumbered with iron sulfide deposits and continuously injecting a quantity of the cleaning formulation into the line. After the product has been injected for a period of time determined by persons skilled in the art, one of two procedures is generally followed. The line is depressurized and a pig placed in the line at or near the injection point and launched by pressurizing the line. The pig is later retrieved at a pig receiver downstream. The effluent that resulted from the process is collected in a downstream separator and/or holding tank which provides access to the effluent for visual and/or analytical analysis, and repeating the process until a sufficient amount of iron sulfide deposits and other contaminants are removed from the pipeline being cleaned. The process of continuous injection pigging is known by those skilled in the art.

[0027] Alternatively, the steps of pigging with a batch treatment process generally follow one of two procedures. The process involves the steps of depressurizing and opening a

pipeline encumbered with iron sulfide deposits, then inducing a quantity of the formulation, determined by a person skilled in the art, into the line followed by insertion of a pig. The pig is then launched by pressurizing the line. The pig should be propelled as slowly as possible in order to allow maximum exposure of the formulation to the inherent black powder. The pig is later retrieved at a pig receiver downstream. The effluent that results from this process is collected in a downstream separator and/or holding tank. Another process is the batch pig pill process that includes depressurizing the line, inserting a pig and positioning the pig at a pre-determined position downstream in the line. A quantity of the formulation, determined by a person skilled in the art, is induced into the line followed by insertion of another pig to maintain a majority of the cleaning formulation between two pigs. The pig pill is then launched by pressurizing the line. The pigs are later retrieved at a pig receiver downstream. The effluent that results from this process is collected in a downstream separator and/or holding tank for visual and analytical analysis. The process can be repeated until a sufficient amount of iron sulfide deposits and other contaminants is removed from the pipeline. [0028] After pigging with either continuous injection process or batch treatment process, the step of collecting the effluent for visual and analytical analysis is generally the same. The color of the effluent is analyzed to determine the degree of iron sulfide deposit removal and cleanliness of the pipeline after a pigging run by way of either pigging process. The fluorescent component of the cleaning formulation renders the cleaning formulation a clear greenish-yellow color before use. When iron sulfide is solubilized and suspended in the cleaning formulation during a pigging run, the effluent appears as a cloudy reddish brown solution. During the process of pigging, the effluent will generally appear as a reddish brown solution until a majority of any iron sulfide deposits and other contaminants is removed, at which time, the effluent generally appears as similar to or the same as the greenish-yellow color of the cleaning formulation originally placed in the pipeline. An effluent appearing with a greenish-yellow color indicates that a majority of the iron sulfide deposits have been removed from the pipeline cleaned in accordance with the method of the present invention. [0029] Use of the method of the present invention to clean iron sulfide mixed with other contaminants from hydrocarbon pipelines provides numerous benefits. In particular, the benefits of using the cleaning formulation include the capability to interact with iron sulfide to suspend deposits, the avoidance of metal depletion of the inner surface of the pipeline due in part to the generally neutral pH, the avoidance of the release or increase of hydrogen sulfide gas during the cleaning process, the easily manageable disposal of effluent containing the cleaning formulation, and the reduction of ignition levels of iron sulfide. In addition, the

benefits include the use of the method during normal pipeline operations if mechanical separation is available, the ability to safely handle the cleaning formulation, the reduction of pig damage associated with normal pigging operations, the reduction of landfill costs for handling the effluent, and the decrease of compressor station, filter and instrument maintenance and replacement costs.

[0030] As used herein, unless otherwise specified, all numbers such as those expressing values, ranges, amounts of percentages may be read as if prefaced by the word "about", even if the term does not expressly appear. Any numerical range recited herein is intended to include all sub-ranges subsumed therein. Plural encompasses singular and vice versa. [0031] The present invention is explained in more detail by the following example, which does not restrict the scope of the present invention.

EXAMPLE

[0032] An iron sulfide cleaning formulation of the present invention may be produced by charging about one-half of the filtered water to a reactor or the like. The sequestering agent is added to the reactor and mixed with minimal introduction of air, e.g., via stirring with a magnetic stir bar or a paddle. The remaining water is added, followed by the ammonium salt. The buffering agent is added until the pH stabilizes at about 6.8-7.0. A fluorescein dye is added last. The components of one formulation of the present invention include by wt.%, 94% filtered water, 6% THPS, 0.05-0.1% ammonium chloride, KOH as needed for buffering and less than 1% fluorescein.

[0033] While the present invention is satisfied by embodiments in many different forms, there is described in detail herein the preferred embodiments of the invention, with the understanding that the present disclosure is to be considered as exemplary of the principles of the invention and is not intended to limit the invention to the embodiments illustrated. Various other embodiments will be apparent to and readily made by those skilled in the art without departing from the scope and spirit of the invention. The scope of the invention will be measured by the appended claims and their equivalents.