SYSTEM FOR PIPELINE DRYING AND FREEZING POINT SUPPRESSION

Info

Publication number: 20140283583
Type: Application
Filed: Jun 5, 2014
Publication Date: Sep 25, 2014
Inventors: Alan Sweeney (Housont, TX), Brian Hallett (Houston, TX)
Application Number: 14/297,252

Abstract

Method for dewatering, pressure testing, hydrotreating, suppressing methane hydrate formation and suppressing solution freezing point in pipeline operations have been disclosed, where the solution used in the operations includes an effective amount of a metal formate salt. The metal formate salt solutions have a low viscosity, have a high density, have a low metals corrosivity, are non-volatile, have a low solubility in hydrocarbons, are readily biodegradable, have a low toxicity, are non-hazardous, have a low environmental impact, have a freezing point depression property forming water/formate eutectic point mixtures, and have a water-structuring and water activity modification property.

Description

Description

RELATED APPLICATIONS

This application is a continuation of U.S. patent application Ser. No. 13/347,819 filed Jan. 11, 2012, now U.S. Pat. No. 8,746,044 issued Jun. 10, 2014, which is a divisional of U.S. patent application Ser. No. 12/167,645 filed Jul. 3, 2008, now U.S. Pat. No. 8,099,977 issued Jan. 24, 2012, which is a Continuation-in-Part of U.S. patent application Ser. No. 11/767,384 filed Jun. 22, 2007, now U.S. Pat. No. 8,065,905 issued Nov. 29, 2011.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates to a method and a use of an aqueous, metal ion formate salt composition for reducing a residual water film on an interior of a pipeline during pipeline dewatering operations, which may involve the use of a pig or a plurality of pigs, for pipeline pressure testing operations, for freezing pointing suppression for sub-freezing temperature pipeline testing operations, i.e., operation at temperatures below 0° C. The present invention also relates to a gelled, aqueous, metal ion formate salt composition for the prevention of seawater ingress during subsea pipeline tie-in operations and for the removal of seawater and conditioning of residual seawater film left on the pipewall during and following pipeline or flowline dewatering operations, which may involve the use of a pig or a plurality of pigs.

More particularly, the present invention relates to a method and a use of an aqueous metal ion formate salt composition for pipeline operations. The method includes the step of contacting an interior of a pipeline with an effective amount of an aqueous metal ion formate salt composition, where the effective amount is sufficient to reduce substantially all or part of a residual water film from the interior of the pipeline during a dewatering operation. The metal ion formate salt composition includes a concentration of metal ion formate salt sufficient to dilute a water concentration of a residual film in a pipeline formed during a dewatering operation, where the dewatering operation may involve the use of a pig or multiple pigs. The present invention also relates to a method and a use of an aqueous metal ion formate salt composition in pipeline pressure testing operations. In sub-freezing point operations, the composition includes an amount of the metal ion formate salt sufficient to suppress a freezing point of fluid during repair and/or pressure testing operations to a desired temperature below a freezing point of ordinary water. The present invention also relates to a method and a use of an aqueous metal ion formate salt composition in all other sub-freezing temperature operations, including wet hydrocarbon transmission in sub-freezing temperature environments. More particularly, the present invention relates to a method and a use of a gelled metal ion formate composition for pipeline or flowline operations. In certain embodiments, the metal ion formate starting solution is a concentrated metal ion formate solution including at least 40 wt. % of a metal ion formate or mixture thereof. The method includes the step of filling an interior or a section of a pipeline, flowline, pipeline jumper or flowline jumper with the gelled composition, where the composition includes a metal ion formate solution and an effective amount of a gelling agent sufficient to gel the solution and where the composition reduces substantially all or part of a residual water film from the interior of the pipeline, flowline, pipeline jumper or flowline jumper during a dewatering operation, or minimize or prevent the ingress of seawater into open pipeline systems or components during tie-in operations of jumpers or additional pipe, valving, manifolds, subsea pipeline architecture or flow conduits. The gelled metal ion formate salt composition is effective in reducing a water concentration of a residual film in a pipeline formed during a dewatering operation, where the dewatering operation may involve the use of a pig or multiple pigs. A slug of the gelled metal ion formate salt composition can be added to the dewatering pig train in order to achieve an improved result.

2. Description of the Related Art

Large volumes of methanol and glycol are routinely injected into gas transport pipelines to inhibit the formation of gas hydrates. These chemicals are derived from hydrocarbons and pose a potential environmental risk for the user. Companies commonly apply conditioning agents such as these for pipeline pre-commissioning operations.

Thermodynamic gas hydrate inhibitors are widely used for a number of applications. They essentially reduce the equilibrium temperature of hydrate formation by acting on the chemical potential of water in the aqueous phase. Chemicals such as methanol and glycol which fall into this category are generally dosed at relatively high concentrations (10-15% w/w) in the aqueous phase. Methanol is, on mass basis the most efficient of the conventional thermodynamic hydrate inhibitors. It is cheap and readily available, but it is a volatile chemical and losses of the inhibitor to the hydrocarbon phase can be considerable. In addition, the handling of methanol is complicated by its toxicity and flammability. While ethylene glycols are far less flammable, and their losses in the hydrocarbon phase are lower, they possess similar toxicity issues.

Despite the widespread use of brines in drilling fluids as gas hydrate inhibitors they are rarely used in pipelines. This is because conventional brines are corrosive, prone to crystallization and generally less effective than either methanol or glycol.

Pipelines that are used for transportation of hydrocarbon gases should be free of water. There are various reasons for this including: (1) prevention of hydrate formation, (1) prevention or reduction of corrosion, and (3) meeting gas sale specifications. Newly constructed pipelines are typically hydrotested; it is, therefore, necessary to dewater and condition the pipeline. This often involves the use of “conditioning” chemicals such as ethylene glycol or other similar glycols or methanol. These chemicals present the industry with certain toxicity problems, which prevents them from being discharged into marine environments. Further, methanol presents another problem; it is highly flammable in air.

To date fluids such as methanol and glycols including in gelled form are utilized for dewatering pipeline or flowline applications offshore and constantly exceed the acceptable limitations for both subsea and overboard discharge. A liquid product that Weatherford International, Inc. supplies made up of a concentrated metal ion formate solution including at least 40 wt. % of a metal ion formate or mixture thereof of potassium formate is a newly accepted liquid product generally utilized to provide hydrate control; however, the establishment of a potassium formate gel provides equally good performance in regards to dewatering applications or minimization or prevention of seawater ingress in addition to hydrate control, while being less hazardous, and less environmentally damaging.

Historically, methanol and glycols, both of which pose immediate safety concerns as well as being potentially hazardous, have been utilized for dewatering pipelines and flowlines offshore. Secondly, these fluids are considered to be toxic for overboard discharge.

Thus, there is a need in the art for an improved system and method for dewatering and conditioning pipelines and for a new fluid for use in repair and pressure testing at temperatures below the freezing point of pure water, which are environmentally friendly and have similar thermodynamic hydrate inhibition properties and similar freezing point suppressant properties compared to methanol and glycols and a need in the art for compositions that address these safety issues as well as overboard discharge problems associated with chemicals for dewatering pipelines in addition to an increase in dewatering performance capabilities/potentials.

SUMMARY OF THE INVENTION

The present invention provides an improved system for dewatering and conditioning pipelines, where the system includes an aqueous composition comprising an effective amount of a metal ion formate salt, where the effective amount is sufficient to reduce an amount of bulk water and/or an amount of residual water in the pipeline, to reduce an amount of a residual water film in a pipeline below a desired amount or to remove substantially all of the residual water in the pipeline.

The present invention also provides a method for dewatering a pipeline including the step of pumping an aqueous composition comprising an effective amount of metal ion formate salt, where the effective amount is sufficient to reduce an amount of a residual water film in the pipeline, to reduce an amount of the residual water film in a pipeline below a desired amount or to remove substantially the residual water film in the pipeline. The method can also include the step of pumping the spent solution into a marine environment without pretreatment. The method can also include the step of pressure testing the pipeline with an aqueous fluid including a metal ion formate salt in a concentration sufficient to reduce or eliminate hydrate formation after pressuring testing and during initial hydrocarbon production. In sub-freezing point operation, the concentration of the metal ion formate salt is sufficient to lower the freezing point of the fluid to a desired temperature below the freezing point of pure water so that the pressure testing or hydrotesting can be performed when the ambient temperature is below the freezing point of pure water (a sub-freezing temperature) without a concern for having to clean up material lost from leaks.

The present invention also provides a method for pressure testing a pipeline including the step of filling a pipeline or a portion thereof with an aqueous composition including a metal ion formate salt, where the composition is environmentally friendly, i.e., capable of being released into a body of water without treatment. The method is especially well suited for pressuring testing a pipeline at sub-freezing temperatures, where an effective amount of the metal ion formate salt is added to the aqueous composition to depress the composition's freezing point temperature to a temperature below the operating temperature, where operating temperature is below the freezing point of pure water.

The present invention also provides a method for installing a pipeline including the step of filling a pipeline with an aqueous metal ion formate salt composition of this invention. After the pipeline is filled, the pipeline is laid, either on a land site or a subsea site. After laying the pipeline, the pipeline is pressurized using an external water source. After pressure testing, the pipeline is brought on production by displacing the composition and the pressuring external water, which can be discharged without treatment. In certain embodiments, the pipeline is laid subsea and the pressurizing external water is seawater, where the composition and pressurizing seawater are discharged into the sea as it is displaced by production fluids. By using the composition of this invention, hydrate formation is precluded during the composition displacement operation. In certain embodiments, the pressure testing is performed at a pressure that is a percentage of the maximum allowable operating pressure or a specific percentage of the pipeline design pressure. In other embodiments, the pressure testing is performed at a pressure between about 1.25 and about 1.5 times the operating pressure. Of course, an ordinary artisan would understand that the pressure testing can be at any desired pressure.

The present invention provides an improved system for dewatering and conditioning pipelines or flowlines, where the system includes a composition comprising a metal ion formate solution and an effective amount of a gelling agent, where the effective amount is sufficient to gel the composition and the composition is effective in reducing an amount of bulk water and/or an amount of residual water in the pipeline or flowline, reducing an amount of a residual water film in a pipeline or flowline below a desired amount, removing substantially all of the residual water in the pipeline or flowline, or effectively preventing seawater ingress into open pipeline systems or components during tie-in operations of jumpers or additional pipe, valving, manifolds, subsea pipeline architecture or flow conduits.

The present invention also provides a method for dewatering a pipeline or flowline including the step of pumping, into a pipeline or flowline, pipeline jumper or flowline jumper, a composition comprising a metal ion formate solution and an effective amount of a gelling agent, where the effective amount is sufficient to gel the composition and the composition is effective in reducing an amount of a residual water film in the pipeline, flowline, pipeline jumper or flowline jumper, reducing an amount of the residual water film in a pipeline, flowline, pipeline jumper or flowline jumper below a desired amount, removing substantially the residual water film in the pipeline, flowline, pipeline jumper or flowline jumper or preventing ingress of seawater. into open pipeline systems or components during tie-in operations of jumpers or additional pipe, valving, manifolds, subsea pipeline architecture or flow conduits The method can also include the step of recovering the gelled composition, breaking the gelled composition, filtering the gelled composition and reformulating the gelled composition for reuse. Because the potassium formate compositions are considered to be environmentally benign, some or all of the composition can be pumped into a marine environment without pretreatment.

The present invention also provides a method for installing a pipeline or flowline including the step of filling a pipeline, flowline, pipeline jumper or flowline jumper with a gelled composition of this invention. After the pipeline, flowline, pipeline jumper or flowline jumper is filled, the pipeline is installed, at a subsea location. After installation the pipeline, flowline, pipeline jumper or flowline jumper on occasion may be pressurized using an external water source. After pressure testing, the pipeline is brought on production by displacing the composition and the fill medium of the pipeline, flowline, pipeline jumper or flowline jumper, with production fluids or gases to the ocean without the need for treatment. By using the composition of this invention, hydrate formation is precluded during the composition displacement operation. In certain embodiments, the pressure testing is performed at a pressure that is a percentage of the maximum allowable operating pressure or a specific percentage of the pipeline design pressure. In other embodiments, the pressure testing is performed at a pressure between about 1.25 and about 1.5 times the operating pressure. Of course, an ordinary artisan would understand that the pressure testing can be at any desired pressure.

BRIEF DESCRIPTION OF THE DRAWINGS

The invention can be better understood with reference to the following detailed description together with the appended illustrative drawings in which like elements are numbered the same:

FIG. 1 depicts a plot of hydrate suppression of a potassium formate solution of this invention compared to a methanol solution and an ethylene glycol solution.

FIG. 2 depicts a plot of freezing point suppression versus salt concentration in wt. % for various salts including potassium formate.

FIG. 3 depicts a plot of freezing point suppression versus salt concentration in ions:water, mol/mol for various salts including potassium formate.

FIG. 4 depicts a plot of freezing point suppression versus various concentrations of potassium formate.

FIG. 5 depicts hydrate suppression using potassium formate at various concentrations.

FIG. 6A a plot of testing of a clarified Xanthan-CMHPG gelled formate composition.

FIG. 6B a plot of the testing of FIG. 6A through the first 330 minutes.

FIG. 7 a plot of testing of a 80 ppt CMHPG dry polymer gelled formate composition.

FIG. 8 a plot of the testing of a CMHPG-Xanthan 80-20 w-w gelled formate composition.

FIG. 9 a plot of the testing of a CMHPG-130 gelled formate composition.

FIG. 10 a plot of the testing of a CMHPG-130 gelled formate composition@ 100/s.

FIG. 11 a plot of the testing of a 20 gpt WGA-5L gelled formate composition.

FIG. 12 a plot of the testing of a HPG gelled formate composition.

FIG. 13A a plot of rheological data for a gelled formate composition of this invention.

FIG. 13B a plot of rheological data for a gelled formate composition of this invention.

DEFINITIONS USED IN THE INVENTION

The term “substantially” means that the actual value is within about 5% of the actual desired value, particularly within about 2% of the actual desired value and especially within about 1% of the actual desired value of any variable, element or limit set forth herein.

The term “residual film” means a water film left in a pipeline, flowline, pipeline jumper or flowline jumper after a pig bulk dewatering operation. For carbon steel pipelines, a water residual film of about 0.1 mm is generally left in the pipeline. The present composition is used to change the make up of the residual film coating the pipeline to a film having at least 70% w/w of the aqueous, metal ion formate salt composition of this invention and 30% w/w residual water. In certain embodiments, the residual film comprises at least 80% w/w of the aqueous, metal ion formate salt composition of this invention and 20% w/w residual water. In certain embodiments, the residual film comprises at least 90% w/w of the aqueous, metal ion formate salt composition of this invention and 10% w/w residual water. In certain embodiments, the residual film comprises at least 95% w/w of the aqueous, metal ion formate salt composition of this invention and 5% w/w residual water. In certain embodiments, the residual film comprises at least 99% w/w of the aqueous, metal ion formate salt composition of this invention and 1% w/w residual water. Of course, for other pipeline, flowline, pipeline jumper or flowline jumper materials, the film make up can vary, but generally it will be within these ranges. Of course, the final make up of the residual film coating the pipeline will depend on operating conditions and is adjusted so that the water content is below a dew point of pure water under the operating conditions.

The term “formate” means the salt of formic acid HCOO⁻.

The term “metal ion formate salt” means the salt of formic acid HCOOH⁻M⁺, where M⁺ is a metal ion.

The term “sub-freezing temperature” means a temperature below the freezing point of pure water.

The term “gpt” means gallons per thousand gallons.

The term “ppt” means pounds per thousand gallons.

The term “HPG” means hydroxypropyl guar.

The term “CMHPG” means carboxymethylhydroxypropyl guar.

DETAILED DESCRIPTION OF THE INVENTION

The inventors have found that a new fluid can be formulated for use in pipeline dewatering, conditioning, pressuring testing, and/or sub-freezing temperature testing operations, where the new fluid is capable of being used without environmental consideration. The new fluid includes an aqueous solution including a metal ion formate. These solutions are well suited for pipeline dewatering operations, pipeline repair operations, pipeline pressure testing operations, pipeline conditioning operations, pipeline hydrotesting operations or other pipeline operations without being concerned with collecting and disposing of the fluid as is true for competing fluids such as glycol containing fluids or alcohol containing fluids. The new fluid is also especially well suited for sub-freezing temperature operations.

The inventors have found that metal ion formate solutions such as potassium formate, marketed as Superdry 2000 by Weatherford International, is an alternative for many pipeline water removal or sub-freezing temperature applications. The formate solutions have similar conditioning properties to currently used fluids such as methanol and glycols, without the hazards associated with methanol and glycols. Formate solutions, such as potassium formate solutions, are known to be non-toxic and suitable for discharge directly into marine environments, without further processing. The ability to discharge formate solutions directly into marine environments is of particular benefit as it avoids the handling of typically large volumes of methanol or glycol containing fluids. In addition, metal ion formates lower the freezing point of water so that these solutions are suitable for use in low temperature applications, where freeze point suppression is needed, e.g., pressure testing or hydrotesting pipelines when the ambient temperature is below the freezing point of water or other sub-freezing temperature pipeline operations.

Metal ion formate salts, such as potassium formate, are very soluble in water forming a brine system, especially a concentrated brine system, with unique fluid properties. These properties include (1) a low viscosity, (2) a high density, (3) a low metals corrosivity, (4) low volatility, (5) a low solubility in hydrocarbons, (6) readily biodegradable, (7) a low toxicity, (8) nonhazardous, (9) a low environmental impact, (10) a freezing point depression property forming water/formate eutectic point mixtures, and (11) a water-structuring and water activity modification property.

The inventors have found that metal ion formate salts are soluble in water up to their saturation point, which is about 75% w/w in water for potassium formate. Metal ion formate salt solutions, including from about 5% w/w of a metal ion formate salt to water up to a saturated or supersaturated aqueous solution of the metal ion formate salt solutions, are well suited as powerful hydrate inhibitors comparable to conventional inhibitors. Of course, the concentration of the brine system needed for any given application will depend on the operation being undertaken or on the sub-freezing temperature operation being undertaken.

Potassium formate solutions display similar low viscosities as monoethylene glycol. Potassium formate solutions have low hydrocarbon solubility and have a specific gravity of about 1.57. Thus, in a two-phase system, metal ion formate salt solutions will more readily migrate with the heavier aqueous phase than compared with inhibitors such as methanol and glycol, which have substantial solubilities in hydrocarbons.

With an alkaline pH in the range of 10, concentrated metal ion formate salt solutions exhibit very low corrosivity to metals, while hydrocarbons and hazardous volatile organics have a very low solubility in the concentrated formate solutions at high pH, further reducing the corrosive effects of such organics, which often cause corrosive problems in other aqueous fluids, which tend to absorb the volatile compounds such as carbon dioxide, hydrogen sulfide, thiols, sulfides, hydrogen cyanide, etc.

Although not all metal ion formate salt solutions have been toxicity tested, potassium formate solutions are categorized as nonionic, non flammable and are rated nonhazardous for transport and handling purposes. The nontoxic properties of potassium formate solutions extend to aquatic organisms, where these solutions are readily biodegradable in dilute solution or acts as a biostat in concentrated solutions. Thus, the formulations of this invention have an OCNS Category E rating in Europe.

Potassium formate solutions have been subject to Mysidopsis bahia and Menidia beryllina larval survival and growth toxicity testing in an 800 mg/L control solution. Both microorganisms passed the normality tests at this concentration. The toxicity limit for subsea fluids in the OCS General Permit (GMG 290000) requires the survival NOEC to be >50 mg/L. The testing performed was an order of magnitude, i.e., 16 times greater than the permit requirements.

Further, metal ion formate salt solutions display similar eutectic properties to glycol-water solutions. For example, a 50% w/w solution of potassium formate in water has a freezing point of around −60° C.

It is common practice to condition deepwater pipelines using fluids such as glycols or methanol. The former is more common because it does not have the safety issues associated with the low vapor pressures of methanol. Such fluids are used to mitigate the risk of forming methane hydrates during startup operations. Methane hydrates form under certain pressure and temperature conditions. In deepwater systems, these conditions can exist at the extremities of the pipeline. High well head operating pressures and low subsea temperatures are perfect conditions for the creation of hydrates. Thus, it is common practice to heavily dose the tree with methanol or glycol during startup as a mitigating measure in the prevention of hydrate formation. This dosing is typically performed in conjunction with a chemical swabbing dewatering operation, and provides the pipeline with adequate protection throughout the system to prevent the formation of hydrates. However, dosing during startup on a pipeline system that has been “bulk dewatered” (i.e., unconditioned with chemicals) can still result in the formation of a hydrate. Hydrate formation in this setting is due to the initial adiabatic drop in pressure occurring across the well in conjunction with a high flowrate, and thus, methane gas may come into contact with free water further upstream of the chemical injection point. In such instances hydrates may form.

Many operators wish to avoid the use of hydrocarbon-based chemistry for this application, but as a general rule these systems are widely used due to lack of viable alternatives. The metal ion formate salt solutions of this invention provide the operators with an environmentally friendly, viable alternative with the added benefit that hydrate formation is mitigated during startup operations. Further, the metal ion formate salt solutions of this invention are also more cost effective than traditional fluids, because capture and subsequent disposal of the treating fluid is not required. The metal ion formate salt solutions can be discharged overboard in accordance with the relevant MMS permits.

Thus, the present invention also provides a method for conditioning deepwater pipelines comprising the step of filling the pipeline with an aqueous composition including an effective amount of a metal ion formate salt, where the effective amount is sufficient to reduce gas hydrate formation, especially methane hydrate formation.

The metal ion formate salt compositions of this invention are ideally suited for replacing traditional chemicals used in pig dewatering operations such as methanol and glycols, which have toxicity issued and must be treated or recovered. In dewatering operations, a pig or a pig train, where a pig train includes at least two pigs. In pig trains, the dewatering operation also includes at least one slug of a pipeline residual water film treatment introduced between at least two adjacent pigs. The lead pig or pigs push out the bulk water in the pipeline. However, remaining on the surface of the pipeline interior wall is a film of water. The film thickness will vary depending on the type of metal used to make the pipeline and on the tolerance of the pig-pipeline match. The slug of treatment is adapted to reduce or eliminate the water film or to replace the film with a film comprising at least 70% w/w of a formate salt composition of this invention. Other embodiments of film composition are listed above. The pig train can include a number of pigs with a number of treatment slugs traveling with the train between adjacent pigs. In certain embodiments, at least two slugs of treatment are used. The first treatment slug changes the film make up and pulls out excess water, while subsequent slugs dilute the film make up to a desired low amount of water. As set forth above, the low amount of water is less than about 30% w/w with the formate salt composition comprising the remainder. In other embodiments, the low amount of water is less than about 20% w/w. In yet other embodiments, the low amount of water is less than about 10% w/w. In still other embodiments, the low amount of water is less than about 5% w/w. It should be recognized that in actuality the formate solution is being diluted by the water and the film is becoming a diluted formate salt film. However, the goal of these treatments is to change the film composition sufficiently to reduce a dew point of the remaining water in the film below a dew point of water or seawater at the operating conditions. Therefore, the amount of formate composition will be sufficient to achieve this desired result. Of course, the amount of formate composition needed will also depend on the initial concentration of formate salt in the composition. In many dewatering embodiments, the initial formate composition will be a saturated or slightly supersaturated formate composition, where the term slight supersaturated means that the composition contains about 0.1 to 5% formate salt in excess of the saturation concentration, where residual water will dilute the formate concentration into a saturated or sub-saturated formate composition.

The inventors have found that a new gelled composition can be formulated for use in pipeline, flowline, pipeline jumper or flowline jumper dewatering, conditioning or preventing ingress of seawater. into open pipeline systems or components during tie-in operations of jumpers or additional pipe, valving, manifolds, subsea pipeline architecture or flow conduits and/or pressure testing operations, where the new fluid is capable of being used without environmental consideration. The new gelled composition comprises a gelled metal ion formate solution. These compositions are well suited for pipeline flowline, pipeline jumper or flowline jumper dewatering operations, pipeline flowline, pipeline jumper or flowline jumper repair operations, pipeline flowline, pipeline jumper or flowline jumper pressure testing operations, pipeline flowline, pipeline jumper or flowline jumper conditioning operations, pipeline flowline, pipeline jumper or flowline jumper hydrotesting operations or other pipeline flowline, pipeline jumper or flowline jumper operations without being concerned with collecting and disposing of the compositions as is true for competing dewatering fluids such as glycol containing fluids or alcohol containing fluids. Moreover, the gelled compositions are also recyclable, where the gel can be broken, filtered and the recovered formate solution regelled. Of course, the formate ion concentration may need adjusting.

The inventors have found that gelled compositions of metal ion formates such as potassium formate, marketed as Superdry 2000 by Weatherford International, is an alternative for many pipeline applications. The gelled formate compositions have similar conditioning properties to currently used fluids such as methanol and glycols, without the hazards associated with methanol and glycols. Non-gelled formate solutions, such as potassium formate solutions, are known to be non-toxic and suitable for discharge directly into marine environments, without further processing. The ability to discharge formate solutions directly into marine environments is of particular benefit as it avoids the handling of typically large volumes of methanol or glycol containing fluids. In a previous application, assignee's employees demonstrated that formate solutions are well suited in pipeline applications as a substitute for alcohol and glycol dewatering and testing fluids, U.S. patent application Ser. No. 11/767,384, filed Jun. 22, 2007, incorporated herein by reference, even though all references are incorporated by reference through the last paragraph before the claims.

The use of a gelled metal formate compositions for dewatering pipelines flowline, pipeline jumper or flowline jumper or preventing ingress of seawater. into open pipeline systems or components during tie-in operations of jumpers or additional pipe, valving, manifolds, subsea pipeline architecture or flow conduits proved to have an added benefit compared to fluids such as methanol and glycols due to the formation of a gel column. In addition, the gel column established is compatible with all metal alloys and elastomers. Furthermore, the gelled formate compositions can be reused by breaking the gel column, filtering the debris out of the resulting fluid, and regelling the recovered formate solution with or without the adjustment of formate concentration, pH, etc.

The gel column established using of the gelled formate compositions of this invention provides a 100% (360 degree) coverage of the pipewall, compared to only about 60% coverage with the use of fluids, thus improving the dewatering capabilities/potentials. Dewatering applications constantly are in high demand in the Gulf of Mexico and improved product performance are of extreme and immediate interest.

Chemicals such as biocides, corrosion inhitors, oxygen scavangers, dyes, polymers or surfactants can optionally be added to the composition as needed for the intended application.

Purpose

To date fluids such as methanol and glycols utilized for dewatering pipeline, flowline, pipeline jumper or flowline jumper applications offshore constantly exceed the acceptable limitations for both subsea and overboard discharge. Potassium formate solutions are generally utilized to provide hydrate control; however, more recently, formate solutions have been used in dewatering application. Such formate solutions likely will not suffer from the same regulatory restrictions as do methanol and glycol and do not suffer from other problems associated with alcohols and glycols. However, these formate solutions are not gelled and do not form gel columns. Gelled compositions have significant advantages over solutions as they are less prone to leakage, are less prone to flowing, and represent a more controlled dewatering environment especially for off shore and sub sea applications.

The purpose of this project is to develop and confirm gelled formate compositions. A gelled formate composition would effectively increase the efficiency as well as the viscosity of pipeline fluid(s), where the gel found result from gelling a formate solution having at least about 50 wt. of a metal formate or mixture of metal formates. In certain embodiments, the formate solution includes at least 60 wt. % of a metal formate or mixture of metal formates. In other embodiments, the formate solution includes at least 70 wt. % of a metal formate or mixture of metal formates. These gelled compositions are designed for, but not limited to, use in pipeline drying or cleaning processes/applications. These gelled composition are designed to maintain viscosity for several hours at temperatures between about 70° F. and about 75° F. under shear rates ranging from about 40/s to 100/s without any significant viscosity degradation.

Suitable Reagents

Suitable metal ion formate salts for use in this invention include, without limitation, a compound of the general formula (HCOO⁻)_nMⁿ⁺ and mixtures or combinations thereof, where M is a metal ion as set forth above and n is the valency of the metal ion.

Suitable metal ions for use in this invention include, without limitation, alkali metal ions, alkaline metal ions, transition metal ions, lanthanide metal ions, and mixtures or combinations thereof. The alkali metal ions are selected from the group consisting of Li⁺, Na⁺, K⁺, Rd⁺, Cs⁺, and mixtures or combinations thereof. The alkaline metal ions are selected from the group consisting of Mg²⁺, Ca²⁺, Sr²⁺, Ba²⁺ and mixtures or combinations thereof. In certain embodiments, the transition metal ions are selected from the group consisting of Ti⁴⁺, Zr⁴⁺, Hf⁴⁺, Zn²⁺ and mixtures or combinations thereof. In certain embodiments, the lanthanide metal ions are selected from the group consisting of La³⁺, Ce⁴⁺, Nd³⁺, Pr²⁺, Pr³⁺, Pr⁴⁺, Sm²⁺, Sm³⁺, Gd³⁺, Dy²⁺, Dy³⁺, and mixtures or combinations thereof.

Suitable polymers for use in the present invention to gel a formate solution includes, without limitation, hydratable polymers. Exemplary examples includes polysaccharide polymers, high-molecular weight polysaccharides composed of mannose and galactose sugars, or guar derivatives such as hydropropyl guar (HPG), hydroxypropylcellulose (HPC), carboxymethyl guar (CMG), carboxymethylhydropropyl guar (CMHPG), hydroxyethylcellulose (HEC) or hydroxypropylcellulose (HPC), carboxymethylhydroxyethylcellulose (CMHEC), Xanthan, scleroglucan, polyacrylamide, polyacrylate polymers and copolymers or mixtures thereof.

Compositional Ranges

For dewatering applications, the general concentration range of metal ion formate salt in water is between about 40% w/w to saturation. In certain embodiments, the concentration range of metal ion formate salt in water is between about 45% w/w to saturation. In other embodiments, the concentration range of metal ion formate salt in water is between about 50% w/w to saturation. In other embodiments, the concentration range of metal ion formate salt in water is between about 55% w/w to saturation. In other embodiments, the concentration range of metal ion formate salt in water is between about 60% w/w to saturation. In other embodiments, the concentration range of metal ion formate salt in water is between about 65% w/w to saturation. In other embodiments, the concentration range of metal ion formate salt in water is between about 70% w/w to saturation. Of course one of ordinary art would understand that the concentration will depend on the required reduction in the amount of bulk and/or residual water left in the pipeline. In certain embodiments, the amount of metal ion formate salt in water can result in a supersaturated solution, where residual water in the pipeline will dilute the solution form supersaturated to saturated or below during the dewatering operation.

For sub-freezing pipeline applications, the general concentration range of metal ion formate salt in water is between about 5% w/w to saturation. In certain embodiments, the concentration range of metal ion formate salt in water is between about 15% w/w to saturation. In other embodiments, the concentration range of metal ion formate salt in water is between about 25% w/w to saturation. In other embodiments, the concentration range of metal ion formate salt in water is between about 35% w/w to saturation. In other embodiments, the concentration range of metal ion formate salt in water is between about 45% w/w to saturation. In other embodiments, the concentration range of metal ion formate salt in water is between about 55% w/w to saturation. In other embodiments, the concentration range of metal ion formate salt in water is between about 65% w/w to saturation. Of course, one of ordinary art would understand that the concentration will depend on the sub-freezing temperature needed for the application and the concentration can be adjusted dynamically to depress the freezing point to a temperature at least 5% below the sub-freezing operating temperature. In certain embodiments, the concentration of metal ion formate salt is sufficient to depress the freezing point to a temperature at least 10% below the sub-freezing operating temperature. In certain embodiments, the concentration of metal ion formate salt is sufficient to depress the freezing point to a temperature at least 15% below the sub-freezing operating temperature. In certain embodiments, the concentration of metal ion formate salt is sufficient to depress the freezing point to a temperature at least 20% below the sub-freezing operating temperature.

For dewatering or the prevention of seawater ingress applications, the general concentration range of metal ion formate salt in water is between about 40% w/w and supersaturation. In certain embodiments, the concentration range of metal ion formate salt in water is between about 45% w/w and supersaturation. In other embodiments, the concentration range of metal ion formate salt in water is between about 50% w/w and supersaturation. In other embodiments, the concentration range of metal ion formate salt in water is between about 55% w/w and supersaturation. In other embodiments, the concentration range of metal ion formate salt in water is between about 60% w/w and supersaturation. In other embodiments, the concentration range of metal ion formate salt in water is between about 65% w/w and supersaturation. In other embodiments, the concentration range of metal ion formate salt in water is between about 70% w/w and supersaturation. In other embodiments, the concentration range of metal ion formate salt in water is sufficient to prepare a supersaturated solution. Of course one of ordinary art would understand that the concentration will depend on the required reduction in the amount of bulk and/or residual water left in the pipeline. In certain embodiments, the amount of metal ion formate salt in water can result in a supersaturated solution, where residual water in the pipeline will dilute the solution form supersaturated to saturated or below during the dewatering operation.

EXPERIMENTS OF THE INVENTION

Referring now to FIG. 1, a plot of methane hydrate suppression properties with methanol, ethylene glycol and potassium formate. The data shows that the potassium formate solution of this invention suppresses hydrate formation to an extent between ethylene glycol and methanol. Thus, the potassium formate solution of this invention is well suited for the suppression ofinethane hydrate in pipelines, especially during startup operations.

Referring now to FIG. 2, a plot of freezing point suppression verses salt concentration in wt. % for various salts including potassium formate.

Referring now to FIG. 3, a plot of freezing point suppression verses salt concentration in ions:water, mol/mol for various salts including potassium formate.

Referring now to FIG. 4, a plot of freezing point suppression verses various concentrations of potassium formate.

Referring now to FIG. 5, a plot of hydrate suppression using potassium formate at various concentrations.

The above data clearly shows that metal ion formate salts are well suited for dewatering, testing, hydrotesting, hydrate suppression, and/or sub-freezing temperature pipeline operations.

Introduction

Assignee has used aqueous potassium formate solutions in pipeline drying or dewatering application and other pipeline application as set forth in U.S. patent application Ser. No. 11/767,384, filed Jun. 22, 2007. However these fluids suffer dilution over the course of pipeline dewatering resulting in loss of effective transport of water as the drying process proceeds to completion. We then set out to increase the viscosity of these formate solutions to more effectively allow the fluid to convey water or other debris through the pipeline as it is being dried or cleaned. Earlier efforts at drying with high viscosity compositions revolved around formulation using biopolymers like xanthan gum. Xanthan gum has been one of the polymers effectively use used in pipeline cleaning and drying, for example in gel pigging. Formulations including mixtures of Xanthan and other polysaccharides have higher viscosity over a broad shear rate range. Such formulations have demonstrated their cost effectiveness in other technologies. Graft copolymers of polysaccharides and polyacrylates have also proven to be effective formulations in other technologies.

Xanthan Gum Chemistry

Xanthan gum is produced by fermenting glucose or sucrose in the presence of a xanthomonas campestris bacterium. The polysaccharide backbone comprises two β-d-glucose units linked through the 1 and 4 positions. The side chain comprise two (2) mannose residues and one (1) glucuronic acid residue, so the polymer comprises repeating five (5) sugar units. The side chain is linked to every other glucose of the backbone at the 3 position. About half of the terminal mannose residues have a pyruvic acid group linked as a ketal to its 4 and 6 positions. The other mannose residue has an acetal group at the 6 positions. Two of these chains may be aligned to form a double helix, giving a rather rigid rod configuration that accounts for its high efficiency as a viscosifier of water. The molecular weight of xanthan gums varies from about one million to 50 million depending upon how it is prepared. An idealized chemical structure of xanthan polymer is shown below:

Guar Gum Chemistry

Guar Chemistry-Guar gum (also called guaran) is extracted from the seed of the leguminous shrub Cyamopsis tetragonoloba, where it acts as a food and water store. Structurally, guar gum is a galactomannan comprising a (1→4)-linked β-d-mannopyranose backbone with branch points from their 6-positions linked to α-d-galactose (that is, 1→6-linked-α-d-galactopyranose). There are between 1.5-2 mannose residues for every galactose residue. Guar gums molecular structure is made up of non-ionic polydisperse rod-shaped polymers comprising molecules made up of about 10,000 residues. Higher galactose substitution also increases the stiffness, but reduces the overall extensibility and radius of gyration of the isolated chains. The galactose residues prevent strong chain interactions as few unsubstituted clear areas have the minimum number (about 6) required for the formation of junction zones. Of the different possible galactose substitution patterns, the extremes of block substitution and alternating substitution give rise to the stiffer, with greater radius of gyration, and most flexible conformations respectively (random substitution being intermediate). If the galactose residues were perfectly randomized, it unlikely that molecules would have more than one such area capable of acting as a junction zone, so disallowing gel formation. A block substitution pattern, for which there is some experimental evidence, would allow junction zone formation if the blocks were of sufficient length. Enzymatic hydrolysis of some of the galactose side chains is possible using legume α-galactosidase. An idealized chemical structure of a guar gum is shown below:

Derivatized guar polymer can be obtained by reaction with propylene oxide and/or chloracetic acid producing hydroxypropylguar (HPG) and carboxymethylhydroxypropylguar (CMHPG). These reaction products have enhanced hydration properties. The carboxyl functionality allows for polymer crosslinking at low pH levels less than 7. Idealized structure of HPG and CMHPG are shown below:

Guar gum is an economical thickener and stabilizer. It hydrates fairly rapidly in cold water to give highly viscous pseudo plastic solutions of generally greater low-shear viscosity when compared with other hydrocolloids and much greater than that of locust bean gum. High concentrations (1%) are very thixotropic but lower concentrations (˜0.3%) are far less so. Guar gum is more soluble than locust bean gum and a better emulsifier as it has more galactose branch points. Unlike locust bean gum, it does not form gels but does show good stability to freeze-thaw cycles. Guar gum shows high low-shear viscosity but is strongly shear-thinning. Being non-ionic, it is not affected by ionic strength or pH but will degrade at pH extremes at temperature (for example, pH 3 at 50° C.). It shows viscosity synergy with xanthan gum. With casein, it becomes slightly thixotropic forming a biphasic system containing casein micelles. Guar gum retards ice crystal growth non-specifically by slowing mass transfer across solid/liquid interface.

General Preparation Method

We tested several formulations using a seventy (weight percent 70 wt. %) potassium formate base fluid and a polymer to form composition having significantly improved viscosity properties. Several polymers were tested along with combinations of polymers to study their properties. The polymer tested were guar, hydroxypropyl guar (HPG), carboxymethylhydroxypropyl guar (CMHPG) and “clarified” xanthan gum. We also discovered that the pH of formate solutions was generally above about pH 9. This high pH was found to inhibit polymer hydration when using certain natural polysaccharide polymers. The inventors found that by adjusting the pH of the base formate fluid to a pH between about 7 and about 7.5 using an acetic anhydride-glacial acetic acid composition improved polymer hydration and gel formation.

Polymers were then dispersed into the pH adjusted formate solution, while the formate solution was mixed. In certain embodiments, mixing was performed at 2500 rpm using an O.F.I.T.E. constant speed mixer apparatus. The mixing continued for about 5 minutes. The inventors also found polymer slurries or suspensions were more efficiently disperse into the formate solution than dry polymers. However, dry polymers can be used with additional mixing and/or shearing.

After preparation, a small aliquot of the gelled composition was taken, and the viscosity stability of the aliquot was measured versus time at about 75° F. for more than 900 minutes. Shear sweeps were made at 30 minutes intervals during the 900 minute test period. The viscosity measurements were made using an automated Grace Instrument high temperature-high pressure rotational M5500 viscometer following standard testing procedures for that apparatus. The 900 minute period was used to simulate residence time that such a composition would be expected to encounter in a typical pipeline cleaning project. The rotor-bob geometry was R1:B1. The interim shear rates were 40 and 100 reciprocal seconds (s⁻¹) as shown in Tables 1A through 7C and graphically in FIGS. 6A through 12. Indices of n′ and k′ fluid flow and fluid consistency were calculated from shear stress measurements at varying shear rate.

TABLE 1A Test Description Test Name: TEST-5207 Fluid ID: Hydro Gel 5L PIPELINE Rotor Number: R1 Bob Number: B1 Bob Radius (cm) 1.7245 Bob Eff. Length (cm): 7.62 Pre-Test pH: 0 Post-Test pH: 0 Description: SHEAR RATE: 50/S

TABLE 1B Formulation and Test Conditions Additives Concentration Units Lot Number Conditions 70% KCOOH 1000 GPT zero time @ temperature = 1.1 minutes BIOCLEAR 200 0.05 GPT Russia maximum sample temperature = 79.0° F. Hydro Gel 5L 16 GPT Batch K06-420 time at excess temperature = 0.0 minutes Hydro Buffer 552L 10 GPT total test duration = 935.1 minutes Clarified Xanthan Gum 4 GPT L0110012 initial viscosity = 413.3 cP cool down viscosity = N.R. cP cool down temperature = N.R. ° F.

TABLE 1C Test Data Time Temp Kv K′ K′ Slot Calc. cP Calc. cP Calc. cP (min) (° F.) n′ dyne-s^n′/cm² R² dyne-s^n′/cm² dyne-s^n′/cm² @40 (1/s) @100 (1/s) @170 (1/s) 5 77 0.4045 0.0951 0.9363 0.0916 0.1077 573 332 242 35 75 0.2997 0.2618 0.9970 0.2506 0.2978 1077 567 391 65 74 0.2749 0.3130 0.9990 0.2992 0.3559 1174 604 411 95 74 0.2770 0.3212 0.9991 0.3071 0.3652 1214 626 427 125 75 0.2713 0.3322 0.9990 0.3175 0.3776 1229 631 428 155 75 0.2683 0.3379 0.9992 0.3228 0.3840 1237 632 429 185 75 0.2662 0.3410 0.9993 0.3257 0.3874 1238 632 428 215 75 0.2674 0.3389 0.9991 0.3238 0.3852 1236 632 428 245 75 0.2666 0.3398 0.9984 0.3246 0.3861 1236 631 428 275 74 0.2633 0.3460 0.9992 0.3305 0.3931 1243 633 428 305 74 0.2659 0.3415 0.9994 0.3263 0.3881 1239 632 428 335 75 0.2678 0.3380 0.9995 0.3230 0.3842 1235 631 428 365 75 0.2646 0.3427 0.9991 0.3274 0.3894 1237 631 427 395 75 0.2635 0.3435 0.9995 0.3281 0.3902 1235 629 425 425 75 0.2609 0.3482 0.9993 0.3326 0.3956 1240 630 425 455 74 0.2604 0.3488 0.9989 0.3331 0.3963 1239 629 425 485 74 0.2623 0.3485 0.9997 0.3329 0.3959 1247 635 429 515 73 0.2601 0.3510 0.9996 0.3352 0.3987 1246 632 427 545 73 0.2597 0.3538 0.9995 0.3379 0.4019 1254 636 430 575 73 0.2601 0.3547 0.9996 0.3387 0.4029 1259 639 431 605 73 0.2576 0.3581 0.9995 0.3419 0.4067 1259 638 430 635 72 0.2594 0.3583 0.9997 0.3422 0.4070 1268 643 434 665 72 0.2543 0.3649 0.9999 0.3483 0.4143 1267 640 431 695 72 0.2577 0.3606 0.9997 0.3443 0.4095 1268 642 433 725 72 0.2559 0.3630 0.9997 0.3466 0.4123 1268 641 432 755 72 0.2664 0.3506 0.9993 0.3350 0.3984 1274 650 441 785 72 0.2562 0.3641 0.9986 0.3476 0.4135 1273 644 434 815 72 0.2605 0.3596 0.9995 0.3434 0.4084 1278 649 438 845 72 0.2620 0.3575 0.9996 0.3415 0.4062 1278 650 439 875 71 0.2591 0.3614 0.9991 0.3452 0.4106 1278 648 438 905 72 0.2535 0.3685 0.9997 0.3518 0.4184 1276 644 433 935 71 0.2642 0.3552 0.9995 0.3393 0.4036 1280 652 442

TABLE 2A Test Description Test Name: TEST-5206 Fluid ID: CMHPG PIPELINE Rotor Number: R1 Bob Number: B1 Bob Radius (cm) 1.7245 Bob Eff. Length (cm): 7.62 Pre-Test pH: 7.55 Post-Test pH: 0 Description: SHEAR RATE: 50/S

TABLE 2A Formulation and Test Conditions Additives Concentration Units Lot Number Conditions 70% KCOOH 1000 gpt zero time @ temperature = 1.1 minutes BioClear 200 0.05 gpt Russia maximum sample temperature = 79.0° F. CMHPG-130:Xanthan 80 ppt Batch #L0222098 time at excess temperature = 0.0 minutes (80:20 w/w) Hydro Buffer 552L 10 gpt total test duration = 935.1 minutes initial viscosity = 413.3 cP cool down viscosity = N.R. cP cool down temperature = N.R. ° F.

TABLE 2C Test Data Time Temp Kv K′ K′ Slot Calc. cP Calc. cP Calc. cP (min) (° F.) n′ dyne-s^n′/cm² R² dyne-s^n′/cm² dyne-s^n′/cm² @40 (1/s) @100 (1/s) @170 (1/s) 5 75 0.3444 0.1736 0.9653 0.1666 0.1973 842 462 326 35 74 0.2899 0.2700 0.9973 0.2583 0.3071 1071 559 383 65 75 0.2781 0.2969 0.9991 0.2839 0.3376 1127 582 397 95 75 0.2773 0.3047 0.9990 0.2912 0.3464 1153 595 405 125 74 0.2677 0.3198 0.9995 0.3055 0.3634 1168 597 405 155 75 0.2762 0.3107 0.9988 0.2970 0.3532 1171 603 411 185 75 0.2713 0.3151 0.9998 0.3011 0.3581 1166 598 406 215 74 0.2661 0.3208 0.9974 0.3065 0.3645 1164 594 403 245 73 0.2666 0.3252 0.9985 0.3107 0.3696 1183 604 409 275 73 0.2727 0.3185 0.9991 0.3044 0.3621 1185 609 414 305 74 0.2668 0.3244 0.9993 0.3100 0.3687 1181 603 409 335 74 0.2682 0.3237 0.9989 0.3093 0.3678 1184 606 411 365 73 0.2650 0.3265 0.9996 0.3119 0.3710 1180 602 408 395 74 0.2691 0.3214 0.9990 0.3071 0.3653 1180 604 410 425 74 0.2699 0.3200 0.9988 0.3058 0.3637 1178 603 410 455 74 0.2639 0.3274 0.9986 0.3127 0.3719 1178 600 406 485 73 0.2665 0.3259 0.9993 0.3114 0.3704 1185 605 410 515 73 0.2639 0.3305 0.9981 0.3157 0.3755 1190 606 410 545 73 0.2655 0.3297 0.9987 0.3150 0.3747 1194 609 413 575 72 0.2624 0.3331 0.9986 0.3182 0.3784 1193 607 410 605 72 0.2610 0.3367 0.9986 0.3216 0.3825 1199 609 412 635 72 0.2627 0.3364 0.9982 0.3213 0.3822 1206 614 415 665 72 0.2617 0.3376 0.9981 0.3224 0.3835 1205 613 414 695 72 0.2609 0.3391 0.9981 0.3239 0.3852 1207 613 414 725 72 0.2693 0.3298 0.9995 0.3152 0.3749 1212 620 421 755 72 0.2594 0.3428 0.9986 0.3274 0.3894 1214 616 416 785 72 0.2594 0.3428 0.9980 0.3274 0.3894 1213 616 416 815 72 0.2663 0.3344 0.9991 0.3195 0.3800 1215 620 420 845 72 0.2607 0.3411 0.9994 0.3258 0.3875 1214 616 416 875 72 0.2607 0.3436 0.9993 0.3282 0.3904 1222 621 419 905 72 0.2583 0.3468 0.9980 0.3311 0.3938 1222 620 418 935 71 0.2542 0.3519 0.9985 0.3360 0.3996 1222 617 415

TABLE 3A Test Description Test Name: TEST-5206 Fluid ID: HPG PIPELINE Rotor Number: R1 Bob Number: B1 Bob Radius (cm) 1.7245 Bob Eff. Length (cm): 7.62 Pre-Test pH: 7.55 Post-Test pH: 0 Description: SHEAR RATE: 50/S

TABLE 3B Formulation and Test Conditions Additives Concentration Units Lot Number Conditions 70% KCOOH 1000 gpt zero time @ temperature = 0.6 minutes BIOCLEAR 200 0.05 gpt Russia maximum sample temperature = 77.2° F. CMHPG-130:Xanthan 80 ppt Batch #L0222098 time at excess temperature = 0.0 minutes (80:20 w/w) Hydro Buffer 552L 10 gpt total test duration = 935.1 minutes initial viscosity = 619.7 cP cool down viscosity = N.R. cP cool down temperature = N.R. ° F.

TABLE 3C Test Data Time Temp Kv K′ K′ Slot Calc. cP Calc. cP Calc. cP (min) (° F.) n′ dyne-s^n′/cm² R² dyne-s^n′/cm² dyne-s^n′/cm² @40 (1/s) @100 (1/s) @170 (1/s) 5 75 0.3444 0.1736 0.9653 0.1666 0.1973 842 462 326 35 74 0.2899 0.2700 0.9973 0.2583 0.3071 1071 559 383 65 75 0.2781 0.2969 0.9991 0.2839 0.3376 1127 582 397 95 75 0.2773 0.3047 0.9990 0.2912 0.3464 1153 595 405 125 74 0.2677 0.3198 0.9995 0.3055 0.3634 1168 597 405 155 75 0.2762 0.3107 0.9988 0.2970 0.3532 1171 603 411 185 75 0.2713 0.3151 0.9998 0.3011 0.3581 1166 598 406 215 74 0.2661 0.3208 0.9974 0.3065 0.3645 1164 594 403 245 73 0.2666 0.3252 0.9985 0.3107 0.3696 1183 604 409 275 73 0.2727 0.3185 0.9991 0.3044 0.3621 1185 609 414 305 74 0.2668 0.3244 0.9993 0.3100 0.3687 1181 603 409 335 74 0.2682 0.3237 0.9989 0.3093 0.3678 1184 606 411 365 73 0.2650 0.3265 0.9996 0.3119 0.3710 1180 602 408 395 74 0.2691 0.3214 0.9990 0.3071 0.3653 1180 604 410 425 74 0.2699 0.3200 0.9988 0.3058 0.3637 1178 603 410 455 74 0.2639 0.3274 0.9986 0.3127 0.3719 1178 600 406 485 73 0.2665 0.3259 0.9993 0.3114 0.3704 1185 605 410 515 73 0.2639 0.3305 0.9981 0.3157 0.3755 1190 606 410 545 73 0.2655 0.3297 0.9987 0.3150 0.3747 1194 609 413 575 72 0.2624 0.3331 0.9986 0.3182 0.3784 1193 607 410 605 72 0.2610 0.3367 0.9986 0.3216 0.3825 1199 609 412 635 72 0.2627 0.3364 0.9982 0.3213 0.3822 1206 614 415 665 72 0.2617 0.3376 0.9981 0.3224 0.3835 1205 613 414 695 72 0.2609 0.3391 0.9981 0.3239 0.3852 1207 613 414 725 72 0.2693 0.3298 0.9995 0.3152 0.3749 1212 620 421 755 72 0.2594 0.3428 0.9986 0.3274 0.3894 1214 616 416 785 72 0.2594 0.3428 0.9980 0.3274 0.3894 1213 616 416 815 72 0.2663 0.3344 0.9991 0.3195 0.3800 1215 620 420 845 72 0.2607 0.3411 0.9994 0.3258 0.3875 1214 616 416 875 72 0.2607 0.3436 0.9993 0.3282 0.3904 1222 621 419 905 72 0.2583 0.3468 0.9980 0.3311 0.3938 1222 620 418 935 71 0.2542 0.3519 0.9985 0.3360 0.3996 1222 617 415

TABLE 4A Test Description Test Name: TEST-5192 Fluid ID: CMHPG PIPELINE Rotor Number: R1 Bob Number: B1 Bob Radius (cm) 1.7245 Bob Eff. Length (cm): 7.62 Pre-Test pH: 7.45 Post-Test pH: 7 Description: 50/S TEST

TABLE 4B Formulation and Test Conditions Additives Concentration Units Lot Number 70% KCOOH 1000 gpt zero time @ temperature = 0.6 minutes BioClear 200 0.05 gpt RUSSIA maximum sample temperature = 76.0° F. CMHPG-130 80 ppt LOT: H0601- time at excess temperature = 0.0 minutes 055-D (P176-01) Hydro Buffer 552L 10 gpt total test duration = 935.1 minutes initial viscosity = 659.8 cP cool down viscosity = N.R. cP cool down temperature = N.R. ° F.

TABLE 4C Test Data Time Temp Kv K′ K′ Slot Calc. cP Calc. cP Calc. cP (min) (° F.) n′ dyne-s^n′/cm² R² dyne-s^n′/cm² dyne-s^n′/cm² @40 (1/s) @100 (1/s) @170 (1/s) 5 72 0.3156 0.2120 0.9184 0.2031 0.2411 924 494 343 35 73 0.2424 0.4562 0.9947 0.4353 0.5175 1514 756 506 65 75 0.2205 0.5265 0.9993 0.5018 0.5958 1609 788 521 95 76 0.2174 0.5407 0.9994 0.5153 0.6116 1632 797 526 125 75 0.2194 0.5428 0.9994 0.5173 0.6141 1651 808 534 155 74 0.2164 0.5537 0.9989 0.5276 0.6261 1665 812 536 185 74 0.2146 0.5581 0.9997 0.5317 0.6310 1667 812 535 215 75 0.2150 0.5553 0.9993 0.5290 0.6278 1661 809 533 245 75 0.2139 0.5574 0.9998 0.5310 0.6301 1661 808 532 275 75 0.2169 0.5532 0.9987 0.5272 0.6257 1667 813 537 305 75 0.2166 0.5554 0.9984 0.5292 0.6281 1671 815 538 335 74 0.2154 0.5578 0.9979 0.5314 0.6307 1671 814 537 365 74 0.2146 0.5600 0.9990 0.5336 0.6331 1673 815 537 395 74 0.2137 0.5583 0.9998 0.5319 0.6311 1662 808 533 425 74 0.2183 0.5493 0.9984 0.5234 0.6214 1664 813 537 455 74 0.2167 0.5518 0.9990 0.5258 0.6241 1661 811 535 485 74 0.2162 0.5531 0.9996 0.5270 0.6255 1662 811 535 515 74 0.2174 0.5516 0.9987 0.5256 0.6239 1665 813 537 545 74 0.2185 0.5493 0.9987 0.5235 0.6214 1666 814 538 575 74 0.2157 0.5540 0.9991 0.5278 0.6264 1662 810 534 605 74 0.2168 0.5526 0.9993 0.5266 0.6250 1665 812 536 635 74 0.2163 0.5519 0.9980 0.5259 0.6242 1659 809 534 665 74 0.2172 0.5508 0.9991 0.5249 0.6230 1662 811 535 695 74 0.2139 0.5583 0.9991 0.5319 0.6311 1663 809 533 725 73 0.2119 0.5613 0.9994 0.5347 0.6343 1659 806 530 755 73 0.2151 0.5574 0.9996 0.5311 0.6302 1668 812 536 785 73 0.2110 0.5651 0.9996 0.5383 0.6386 1665 808 532 815 73 0.2164 0.5556 0.9990 0.5295 0.6284 1671 815 538 845 73 0.2128 0.5628 0.9992 0.5362 0.6362 1669 811 534 875 73 0.2150 0.5591 0.9985 0.5327 0.6322 1673 815 537 905 73 0.2139 0.5609 0.9985 0.5344 0.6342 1671 813 536 935 73 0.2158 0.5561 0.9993 0.5298 0.6288 1669 813 536

TABLE 5A Test Description Test Name: TEST-5191- Fluid ID: HPG PIPELINE Rotor Number: R1 Bob Number: B1 Bob Radius (cm) 1.7245 Bob Eff. Length (cm): 7.62 Pre-Test pH: 7.45 Post-Test pH: 7 Description: 100/S TEST

TABLE 5B Formulation and Test Conditions Additives Concentration Units Lot Number Conditions 70% KCOOH 1000 gpt zero time @ temperature = 0.5 minutes BIOCLEAR 200 0.05 gpt Russia maximum sample temperature = 76.0° F. CMHPG-130 80 ppt Lot: H0601-055- time at excess temperature = 0.0 minutes D (P176-01) Hydro Buffer 552L 10 gpt total test duration = 935.1 minutes initial viscosity = 179.9 cP cool down viscosity = N.R. cP cool down temperature = N.R. ° F.

TABLE 5C Test Data Time Temp Kv K′ K′ Slot Calc. cP Calc. cP Calc. cP (min) (° F.) n′ dyne-s^n′/cm² R² dyne-s^n′/cm² dyne-s^n′/cm² @40 (1/s) @100 (1/s) @170 (1/s) 7 85 0.3485 0.1675 0.6514 0.1608 0.1904 824 454 321 37 72 0.2533 0.4550 0.9976 0.4344 0.5166 1574 794 534 67 75 0.2414 0.4868 0.9980 0.4644 0.5521 1610 804 537 97 76 0.2440 0.4876 0.9986 0.4653 0.5532 1629 815 546 127 75 0.2408 0.5012 0.9960 0.4782 0.5685 1654 825 552 157 74 0.2427 0.5054 0.9962 0.4822 0.5734 1680 839 562 187 74 0.2413 0.5141 0.9964 0.4905 0.5831 1700 848 567 217 75 0.2396 0.5156 0.9984 0.4918 0.5847 1694 844 564 247 75 0.2416 0.5146 0.9976 0.4909 0.5837 1704 850 569 277 75 0.2378 0.5243 0.9976 0.5002 0.5945 1711 851 568 307 75 0.2320 0.5416 0.9981 0.5165 0.6137 1729 855 569 337 74 0.2353 0.5368 0.9983 0.5120 0.6085 1735 861 574 367 73 0.2389 0.5365 0.9961 0.5118 0.6084 1758 875 584 397 73 0.2355 0.5458 0.9971 0.5206 0.6187 1765 876 584 427 73 0.2357 0.5488 0.9983 0.5234 0.6221 1777 882 588 457 73 0.2350 0.5527 0.9987 0.5271 0.6265 1784 885 590 487 72 0.2330 0.5598 0.9978 0.5339 0.6345 1794 888 591 517 73 0.2349 0.5588 0.9973 0.5330 0.6334 1803 895 596 547 72 0.2377 0.5544 0.9982 0.5288 0.6286 1808 899 600 577 72 0.2336 0.5685 0.9957 0.5422 0.6443 1826 905 602 607 72 0.2355 0.5627 0.9958 0.5367 0.6379 1820 904 602 637 73 0.2344 0.5671 0.9973 0.5409 0.6428 1827 906 603 667 73 0.2270 0.5877 0.9976 0.5603 0.6655 1841 907 602 697 73 0.2254 0.5932 0.9980 0.5655 0.6716 1847 908 602 727 73 0.2300 0.5858 0.9968 0.5586 0.6637 1856 916 609 757 73 0.2299 0.5886 0.9964 0.5613 0.6669 1864 921 612 787 73 0.2304 0.5901 0.9978 0.5627 0.6685 1872 925 615 817 73 0.2315 0.5926 0.9982 0.5651 0.6715 1888 933 621 847 73 0.2321 0.5935 0.9965 0.5660 0.6725 1895 938 624 877 73 0.2283 0.6040 0.9981 0.5759 0.6842 1901 937 622 907 73 0.2222 0.6197 0.9982 0.5906 0.7013 1905 934 618 937 73 0.2276 0.6071 0.9974 0.5788 0.6876 1906 939 623

TABLE 6A Test Description Test Name: TEST-5175 Fluid ID: Hydro Gel 5L PIPELINE Rotor Number: R1 Bob Number: B1 Bob Radius (cm) 1.7245 Bob Eff. Length (cm): 7.62 Pre-Test pH: 7.67 Post-Test pH: 0 Description: SHEAR RATE: 50/S

TABLE 6B Formulation and Test Conditions Additives Concentration Units Lot Number Condition 70% KCOOH 1000 gpt zero time @ temperature = 0.6 minutes BIOCLEAR 200 0.05 gpt Russia maximum sample temperature = 77.0° F. Hydro Gel 5L 80 ppt Batch K070315 time at excess temperature = 0.0 minutes Hydro Buffer 552L 10 gpt total test duration = 935.1 minutes initial viscosity = 1420.0 cP cool down viscosity = N.R. cP cool down temperature = N.R. ° F.

TABLE 6C Test Data Time Temp Kv K′ K′ Slot Calc. cP Calc. cP Calc. cP (min) (° F.) n′ dyne-s^n′/cm² R² dyne-s^n′/cm² dyne-s^n′/cm² @40 (1/s) @100 (1/s) @170 (1/s) 5 73 0.1454 0.8335 0.9974 0.7919 0.9272 1897 867 551 35 74 0.1467 0.8248 0.9978 0.7836 0.9179 1888 864 549 65 74 0.1447 0.8326 0.9986 0.7910 0.9260 1890 863 548 95 74 0.1438 0.8384 0.9989 0.7965 0.9321 1896 865 549 125 73 0.1449 0.8375 0.9966 0.7956 0.9314 1902 869 552 155 73 0.1437 0.8427 0.9986 0.8006 0.9369 1906 870 552 185 73 0.1436 0.8426 0.9987 0.8005 0.9367 1904 869 551 215 73 0.1441 0.8423 0.9992 0.8002 0.9365 1908 871 553 245 73 0.1445 0.8430 0.9986 0.8008 0.9374 1912 873 555 275 73 0.1438 0.8463 0.9980 0.8040 0.9409 1914 874 555 305 73 0.1425 0.8508 0.9976 0.8082 0.9454 1914 872 553 335 73 0.1428 0.8515 0.9985 0.8089 0.9463 1918 874 555 365 73 0.1430 0.8545 0.9985 0.8117 0.9497 1927 879 558 395 74 0.1422 0.8566 0.9989 0.8137 0.9518 1925 877 556 425 74 0.1427 0.8537 0.9987 0.8110 0.9488 1922 876 556 455 74 0.1418 0.8575 0.9991 0.8146 0.9527 1924 877 556 485 74 0.1425 0.8561 0.9984 0.8132 0.9513 1926 878 557 515 74 0.1442 0.8507 0.9979 0.8082 0.9459 1928 880 559 545 74 0.1434 0.8538 0.9978 0.8111 0.9491 1928 879 558 575 74 0.1445 0.8508 0.9977 0.8083 0.9461 1930 881 560 605 74 0.1444 0.8512 0.9990 0.8087 0.9466 1930 881 560 635 74 0.1442 0.8521 0.9983 0.8095 0.9474 1930 881 560 665 74 0.1439 0.8531 0.9985 0.8104 0.9485 1931 881 559 695 74 0.1443 0.8547 0.9985 0.8120 0.9504 1937 884 562 725 74 0.1417 0.8614 0.9988 0.8182 0.9569 1932 880 558 755 74 0.1435 0.8576 0.9983 0.8147 0.9533 1937 884 561 785 74 0.1428 0.8590 0.9980 0.8161 0.9547 1935 882 560 815 75 0.1442 0.8548 0.9977 0.8121 0.9505 1937 884 561 845 75 0.1432 0.8585 0.9987 0.8156 0.9543 1937 883 561 875 76 0.1432 0.8550 0.9982 0.8122 0.9504 1930 880 559 905 77 0.1458 0.8464 0.9982 0.8041 0.9416 1930 882 561 935 75 0.1437 0.8568 0.9986 0.8140 0.9526 1937 884 561

TABLE 7A Test Description Test Name: TEST-5162 Fluid ID: HPG PIPELINE Rotor Number: R1 Bob Number: B1 Bob Radius (cm) 1.7245 Bob Eff. Length (cm): 7.62 Pre-Test pH: 7.69 Post-Test pH: 7.68 Description: SHEAR RATE: 50/S

TABLE 7B Formulation and Test Conditions Additives Concentration Units Lot Number Conditions 70% KCOOH 1000 gpt zero time @ temperature = 0.6 minutes BioClear 200 0.05 gpt Russia maximum sample temperature = 77.0° F. HPG-400DG 80 ppt Batch #L0222098 time at excess temperature = 0.0 minutes Hydro Buffer 552L 10 gpt total test duration = 935.1 minutes initial viscosity = 279.7 cP cool down viscosity = N.R. cP cool down temperature = N.R. ° F.

TABLE 7C Test Data Time Temp Kv K′ K′ Slot Calc. cP Calc. cP Calc. cP (min) (° F.) n′ dyne-s^n′/cm² R² dyne-s^n′/cm² dyne-s^n′/cm² @40 (1/s) @100 (1/s) @170 (1/s) 5 75 0.5424 0.0344 0.9985 0.0334 0.0382 338 222 174 35 74 0.5372 0.0356 0.9985 0.0345 0.0395 343 225 176 65 74 0.5363 0.0358 0.9984 0.0348 0.0398 345 225 176 95 73 0.5369 0.0361 0.9982 0.0351 0.0402 348 228 178 125 73 0.5335 0.0369 0.9982 0.0359 0.0411 352 230 179 155 73 0.5414 0.0362 0.9986 0.0351 0.0402 354 233 183 185 73 0.5290 0.0374 0.9965 0.0363 0.0417 351 228 178 215 73 0.5213 0.0383 0.9989 0.0372 0.0427 350 226 175 245 73 0.5373 0.0364 0.9973 0.0354 0.0405 352 230 180 275 73 0.5348 0.0369 0.9977 0.0358 0.0411 353 231 180 305 73 0.5304 0.0374 0.9971 0.0363 0.0417 353 229 179 335 73 0.5243 0.0385 0.9989 0.0373 0.0429 355 230 178 365 73 0.5242 0.0386 0.9976 0.0374 0.0430 356 230 179 395 73 0.5266 0.0382 0.9981 0.0371 0.0426 356 230 179 425 73 0.5252 0.0386 0.9977 0.0374 0.0430 357 231 180 455 73 0.5307 0.0380 0.9982 0.0369 0.0423 359 233 182 485 72 0.5272 0.0384 0.9980 0.0373 0.0428 358 232 181 515 72 0.5276 0.0384 0.9977 0.0373 0.0428 358 233 181 545 72 0.5251 0.0388 0.9983 0.0376 0.0432 359 232 181 575 72 0.5389 0.0371 0.9969 0.0360 0.0413 361 236 185 605 72 0.5484 0.0347 0.9987 0.0337 0.0385 348 230 181 635 73 0.5559 0.0338 0.9981 0.0329 0.0375 349 232 183 665 73 0.5595 0.0330 0.9982 0.0321 0.0365 345 230 182 695 73 0.5512 0.0339 0.9988 0.0330 0.0377 344 228 180 725 73 0.5607 0.0332 0.9980 0.0323 0.0367 348 233 184 755 73 0.5509 0.0344 0.9979 0.0334 0.0382 349 231 182 785 73 0.5536 0.0338 0.9989 0.0328 0.0375 346 230 181 815 73 0.5390 0.0357 0.9963 0.0347 0.0397 347 228 178 845 73 0.5513 0.0344 0.9968 0.0335 0.0382 349 232 183 875 73 0.5529 0.0344 0.9983 0.0334 0.0382 351 233 184 905 72 0.5477 0.0352 0.9986 0.0342 0.0391 353 233 183 935 73 0.5532 0.0343 0.9981 0.0333 0.0380 350 233 183

Additional rheological properties are shown in Tables 8A&B and graphically in FIGS. 13A&B.

TABLE 8A Rheology @ 200° F. (93° C.) time K′ μ_a@ 100/s minute n′ lb_f· s^n′/ft² cP 0 618 521 15 0.390 0.2233 590 493 30 0.380 0.2209 565 471 45 0.374 0.2195 544 452 60 0.370 0.2185 527 438 75 0.367 0.2177 512 427 90 0.365 0.2171 501 420 105 0.363 0.2165 492 415 120 0.361 0.2160 486 412 135 0.359 0.2156 481 411 150 0.358 0.2153 479 412 165 0.356 0.2149 479 414 180 0.355 0.2146 481 417 195 0.354 0.2143 484 420 210 0.353 0.2141 488 423 225 0.352 0.2138 494 425 240 0.351 0.2136 500 427 255 0.350 0.2134 507 427 270 0.349 0.2132 515 426 285 0.349 0.2130 522 422 300 0.348 0.2128 530 416

TABLE 8B Rheological Conditions and Results R = less10% gel Q = 30# gel μ_a= −1E−05*t³+ 0.0087*t²− 2.0024*t + 617.83 μ_a= −2E−05*t³+ 0.0115*t²− 1.9994*t + 520.93

Table 9 tabulates a summary of pre and post test conditions, test values, components used, etc. set forth in Table 1A-8B above.

TABLE 9 Testing Results of Gelled Compositions of This Invention Additive or measurement Gellant Loading Variance KCl Loading Variance gallon/1,000 gallon gallon/1,000 gallon Test Number (1) (4) (5) (6) (7) (1) (2) (3) variable parameter % 0% 10% −10% 20% −20% 2% 4% 7% water Sparkletts Distilled Water Sparkletts Distilled Water Bio-Clear ® 200 0.05 0.05 KCl [% (lbm)] 2 (167) 2 (167) 4 (334) 7 (583) WNE-342LN^‡ 1.0 1.0 WPA-556L^‡ 0.25 0.25 WGA-11L^‡ 7½ 8¼ 6¾ 9 6 7½ hydration pH 4.78 4.75 4.72 4.72 4.76 4.78 4.75 4.87 base gel viscosity (cP) 32.1 33.4 25.6 41.0 19.5 32.1 29.7 29.1 WGA-160L^‡ 1.5 1.5 WPB-584L^‡ 2.0 2.0 buffer pH 11.58 11.60 11.63 11.72 11.56 11.58 11.58 11.87 WXL-101L^‡ 1.0 1.0 crosslink pH 11.54 11.54 test temperature [° F. (° C.)] 200 (93) 200 (93) post test pH 11.04 11.04 ^‡These products are available from Clearwater International, LLC of Elmendorf, Texas

Field Mixing

The gelled composition can be prepared in the field using dry polymer, but using dry polymer required high shear to active a desired gelled composition. In certain embodiments, the dry polymer is encapsulated in a gel membrane to assist in hydration as the encapsulate erodes. In other embodiments, polymer slurries or suspensions are readily dispersed with little shear. In other embodiments, field mixing of the formulations is accomplished using an “on the fly” or “continuous mix” process. In this type of process, all additives are metered concomitantly at strategic points as the formate solution is injected into the pipeline. A detailed field mixing procedure as shown in attachment 1 is recommended for delivery of these formulations.

Xanthan—CMHPG Formulation

This example illustrates a pipeline fluid mixing procedure for preparing a gelled potassium formate composition of this invention.

Chemicals

The following chemical were used in the preparation of the composition:

70% w/w potassium formate (KCOOH)

Hydro Buffer 552L (hydration buffer)

Hydro Gel 5L (mineral oil base gelling agent)

Clarified xanthan gum slurry (mineral oil base)

Equipment

The following pieces of equipment were used in the preparation of the composition:

Positive displacement injection (metering) pumps or peristaltic pumps

Multi-stage Centrifugal Pump

Static Mixers (In line static mixers)

Additive micro-motion flow meters

Mass flow meter

Potassium Formate Storage Tank(s)

The composition was prepared in a “continuous mix” process, where all components are be injected concomitantly into the formate solution at a volume ratio base on formate injection rate.

The injection points for all components to be metered into the process flow line are disposed after the single stage centrifugal pump and before the centrifugal pump. Static mixers were installed between each centrifugal pump and downstream of each chemical additive injection point to facilitate mixing and to assure additive dispersion while the fluid stream is transiting to the pipeline.

Meter the 70 wt. % potassium formate base solution (first component) from the storage tank using a single stage centrifugal pump into the pipeline at the predetermined rate using a multistage centrifugal pump (FIG. 5).

Inject hydration buffer Hydro Buffer 552L (second component) at 10 gallons per thousand gallons (gpt) or 10 liters per cubic meter (10 L/m³) into the potassium formate solution. The total or combined rate of the chemical(s) being injected is maintained equal to the initial potassium formate rate, requiring the potassium formate rate to be decreased by the volume of hydration buffer being injected into the stream. Delivering the additives in this manner ensures a constant delivery of the final blended formulation. In certain embodiments, micromotion flow meters are used to maintain accurate injection rates of additive being deliver to the pipeline process flow stream.

Inject the gelling agent Hydro Gel 5L (third component) to the formulation downstream of the hydration buffer Hydro Buffer 552L and a first static mixer at a rate of 16 gpt (16 L/m³). Reduce the rate of the formate solution as described in step three of this procedure.

Inject the clarified xanthan gum slurry (forth and final component) of the formulation downstream of gelling agent Hydro Gel 5L and a second static mixer at a rate of 4 gpt (4 L/m³). Reduce the rate of the formate solution as described in step three of this procedure.

Meter the final composition through the multistage centrifugal pump to ensure rapid hydration of the gelling agent and the polymer slurry and fast fluid viscosity development of the final composition without the need for a hydration holding tank.

Inject this final hydrated mixture into the pipeline for drying.

CONCLUSION

Adjusting the pH of the potassium formate solutions to pH between about pH 7 and pH 7.5 permits effective and efficient hydration of guar and/or guar derivative polymers.

Highest viscosity stability at 935 minutes and at 70° F. to 75° F. was demonstrated with carboxymethylhydroxypropylguar and carboxymethylhydroxypropylguar xanthan polymer blends.

Generally, the polymer or polymer blend is added to the format solution in an amount of at least 40 pounds of polymer per thousand gallons of total solution (ppt). In other embodiments, the polymer or polymer blend is added to the format solution in an amount of at least 50 ppt. In other embodiments, the polymer or polymer blend is added to the format solution in an amount of at least 60 ppt. In other embodiments, the polymer or polymer blend is added to the format solution in an amount of at least 70 ppt. In other embodiments, the polymer or polymer blend is added to the format solution in an amount of at least 80 ppt.

In certain embodiments, a dry polymer or dry polymer blend is used, generally accompanied by high shear mixing with or without a holding tank to ensure complete gellation. In other embodiments, polymer suspensions in an oil such as mineral oil or a glycol is used to disperse the polymer or polymer blend into the formate solution.

All references cited herein are incorporated by reference. Although the invention has been disclosed with reference to its preferred embodiments, from reading this description those of skill in the art may appreciate changes and modification that may be made which do not depart from the scope and spirit of the invention as described above and claimed hereafter.

Claims

1. An improved system for use in conditioning and/or pressure testing pipelines comprising

an aqueous composition comprising an effective amount of a metal ion formate salt,

where the aqueous composition fills a pipeline or portion thereof pressurized to a desired test pressure and the effective amount is sufficient to reduce an amount of bulk water and/or an amount of residual water in the pipeline below desired amounts and/or to depress a freezing point of the aqueous composition to a temperature below an operating temperature of a pipeline, where the operating temperature of the pipeline is below the freezing point of pure water, and where the aqueous composition is directly discharged into the environment without further processing or treatment.

2. The system of claim 1, wherein the effective amount is sufficient to remove substantially all of the bulk water and residual water in the pipeline.

3. The system of claim 1, wherein the metal ion formate salt is a compound of the formula (HCOO−)nMn+ and mixtures thereof, where M is a metal ion and n is the valency of the metal ion.

4. The system of claim 3, wherein the metal ion is selected from the group consisting of an alkali metal ion, an alkaline metal ion, a transition metal ion, a lanthanide metal ion, and mixtures thereof.

5. The system of claim 4, wherein the alkali metal ion is selected from the group consisting of Li+, Na+, K+, Rd+, Cs+, and mixtures thereof.

6. The system of claim 5, wherein the alkali metal ion is K+.

7. The system of claim 4, wherein the alkaline metal ion is selected from the group consisting of Mg+, Ca+, Sr2+, Ba2+ and mixtures thereof.

8. The system of claim 4, wherein the transition metal ion is selected from the group consisting of Ti4+, Zr4+, Hf4+, Zn2+ and mixtures thereof.

9. The system of claim 4, wherein the lanthanide metal ion is selected from the group consisting of La3+, Ce4+, Nd3+, Pr2+, Pr3+, Pr4+, Sm2+, Sm3+, Dy2+, Dy3+, and mixtures thereof.

10. The system of claim 1, wherein the effective amount is at least about 5% w/w of metal ion formate salt to water and a saturation solution of the metal ion formate salt in water.

11. The system of claim 1, wherein the effective amount is at least about 25% w/w of metal ion formate salt to water and a saturation solution of the metal ion formate salt in water.

12. The system of claim 1, wherein the effective amount is at least about 45% w/w of metal ion formate salt to water and a saturation solution of the metal ion formate salt in water.

13. The system of claim 1, wherein the effective amount is at least about 65% w/w of metal ion formate salt to water and a saturation solution of the metal ion formate salt in water.

14. The system of claim 1, wherein effective amount comprises a saturated or slightly supersaturated formate composition so that the amount of residual water will dilute the formate concentration into a saturated or sub-saturated formate composition.