WO2014178914A1 - Formulations and methods for aggregating oil-wet solids in aqueous suspensions - Google Patents

Abstract

The invention is directed to a method for aggregating oil-wet solids in an aqueous suspension, comprising: providing an aqueous suspension containing oil-wet solids; and treating the aqueous suspension with an effective amount of a formulation comprising an aggregation aid, thereby aggregating the oil-wet solids as removable aggregates.

Description

FORMULATIONS AND METHODS FOR AGGREGATING OIL-WET SOLIDS

IN AQUEOUS SUSPENSIONS

RELATED APPLICATION

[0001] This application claims the benefit of U.S. Provisional Application Serial No. 61/817,485 filed April 30, 2013. The entire contents of the above-referenced application are incorporated by reference herein.

FIELD OF APPLICATION

[0002] This application relates generally to aggregation of oil-wet solids in aqueous suspensions.

BACKGROUND

[0003] In a variety of industrial applications, aqueous systems containing suspended solids are clarified using mechanical equipment such as clarifiers, settling basins, ponds, centrifuges, screens, filters and the like. The clarified water is typically captured for reuse, processing, discharge, or disposal. The rate or efficiency of these separations is commonly aided by the addition of high molecular weight flocculants such as charged polyacrylamides. Additionally, charged coagulants such as cationic polymers or metal salts are used to enhance the separation of the slurries. When the slurries contain hydrophobic solids or the suspended solids become contaminated with hydrophobic materials such as oil, the suspended solids can be oil-wet, and these oil-wet solids can be unresponsive to the conventional treatment with flocculants and coagulants.

[0004] For example, in the process of drilling oil wells, aqueous streams such as water- based drilling fluids can become contaminated with oil and suspended solids following drilling operations. The drilling fluid is generally held in an "active pit" tank or tanks, where it is drawn by a pump and circulated through the drill bit, then it returns to the surface and passes through a shale shaker to screen out coarse drill cutting particles or "cuttings"; finally, the fluid is returned to the active pit for reuse. When the drilling process penetrates an oil-bearing reservoir, hydrocarbon contaminants and fine particulates can become entrained into the drilling fluid, altering the properties of the fluid. The presence of these hydrophobic contaminants can render the drilling fluid unusable, especially when the contaminants accumulate during many passes through the underground drill bit; in some cases the oil contamination is significant enough that it alters the density of the drilling fluid so the fluid might not have sufficient mud weight to counterbalance the reservoir pressure. Removing oil from the drilling fluid stream along with removing other contaminating solids can allow the fluid to be reused as a drilling fluid or otherwise recycled or disposed of, decreasing the expense of disposal and transportation, or perhaps eliminating the need for disposal entirely. However, the oil- contaminated drilling fluid is difficult to separate by conventional treatment with flocculants so the contaminated fluid is often disposed of. Improved separation methods are needed to allow aggregation and separation of oil- wet solids from contaminated drilling fluids. As another example, treatment of oil-wet solids, tank bottoms, spent catalysts, or waste sludges in the oilfield can offer the advantages of waste minimization, environmental compliance, hydrocarbon recovery, and cost savings. In certain oil production operations, a waste slurry containing oil, water, and insoluble solids is generated during the hot water or steamflood extraction of heavy oil. These aqueous slurries of oil-wet solids are an environmental liability and a challenge for waste management. An effective means of aggregating the oil-wet solids in these wastes would allow for lower disposal and transportation costs of the waste slurry.

[0005] In the case of salt water or brine-based muds, for example with total dissolved solids (TDS) content above 10,000 ppm, the effectiveness of consolidation processes with conventional flocculants is diminished. Also, as water based muds become contaminated with oil during drilling operations, the presence of oil, for example above 500 ppm oil, can cause the suspended solids to be less responsive to treatment by conventional flocculation processes. Some water based drilling fluids are known to become contaminated with much higher oil levels, such as 1 to 40% by volume. In these extreme conditions, the water based drilling fluid has become highly compromised in its suitability as an aqueous drilling fluid due to altered density, altered filtration or viscosity properties. The problem of oil contamination can lead to operational problems during drilling operations, since the density, or mud weight, of the fluid must be maintained within a well-defined range. When the density drops below a critical level, the pressure of the oil and gas containing reservoir can cause leakage or blowouts. The contaminated drilling fluid containing brine, solids, and oil can also have higher hazards for health and safety, and for environmental impact, resulting in higher transportation and disposal costs. In the case of either high brine content or high oil content, the treatability by conventional flocculation is compromised. It is an object of the invention to render these contaminated drilling fluids more treatable for the purpose of consolidation and minimization of the wastes generated. Another object of the invention is to enable the treatment of these contaminated drilling fluids during their use or after their use in drilling oil and gas wells. It is a further object of the invention to recover the water based fluid or brine from these drilling fluids.

Although the treatment of the contaminated drilling fluids with water soluble polymer flocculants is often hindered by the presence of the contaminants, we have discovered that aggregation surfactants can improve the separation of contaminants from these fluids.

SUMMARY

[0006] The invention encompasses a method for aggregating oil-wet solids in an aqueous suspension, comprising: providing an aqueous suspension containing oil-wet solids; and treating the aqueous suspension with an effective amount of a formulation comprising an aggregation aid, thereby aggregating the oil-wet solids as removable aggregates. In some embodiments, the method further comprises removing the removable aggregates. In some embodiments, the method comprises providing a flocculant and adding the flocculant to the aqueous suspension before, during or after the step of treating the aqueous suspension with the effective amount of the formulation comprising an aggregation aid. In certain embodiments, the method further comprises providing a particulate formulation and adding the particulate formulation to the aqueous suspension, before, during or after the step of treating the aqueous suspension. In some embodiments, the aqueous suspension is treated with about 1000 to about 50,000 ppm of the aggregation aid, based on amount of actives. In certain embodiments, the aggregation aid is a nonionic surfactant having a HLB value between about 8 and 1 1. In some embodiments, the aggregation aid is an ionic surfactant selected from the group consisting of calcium alkylaryl sulfonates, sodium lauryl sulfates, dodecylbenzene sulfonic acids, benzethonium chlorides, sulfated propoxylated branched alcohols, sulfated castor oils, triceteareth-4 phosphates, and sodium caproyl lactylates. In some aspects of the invention, the aqueous suspension is derived from spent drilling fluid and optionally, the treatment of the aqueous suspension yields a reclaimable spent drilling fluid.

[0007] DETAILED DESCRIPTION

[0008] Disclosed herein, in embodiments, are methods for aggregating oil-wet solids in a suspension, comprising adding an effective amount of an aggregation aid to cause the formation of aggregates. Further disclosed herein, in embodiments, are methods for separating oil and/or solid contaminants from aqueous streams using an aggregation aid formulation.

[0009] While the coagulation of suspended solids by polymers has been described, it is unexpected that a certain class of polymers can act as aggregation aids to cause agglomeration of hydrophobic solids when added to suspensions of hydrophobic solids that are otherwise difficult to treat by conventional means.

[0010] In embodiments, an aggregation aid in keeping with these formulations and methods can include surfactants having a HLB (hydrophilic-lipophilic balance) value of about 8 to about 12, and preferably having a HLB of about 9 to about 1 1. In certain embodiments, the aggregation aid surfactant can be an ethoxylated surfactant comprising at least 5 moles of ethylene oxide. In embodiments, the ethoxylated aggregation aid surfactant can have an alkyl chain of at least 8 carbon atoms.

[0011] In embodiments, an aggregation aid can be selected from nonionic surfactants such as primary alcohol ethoxylates, secondary alcohol ethoxylates, ethoxylated sorbitan esters, alkylphenol ethers, ethoxylated fatty acids, copolymers of EO and PO, silicone glycol copolymers, phosphate esters, glucosides such as cetearyl glucoside, alkyl polyglucosides, and ethoxylated triglycerides. In other embodiments, the aggregation aids can be selected from ionic surfactants such as calcium alkylaryl sulfonate, sodium lauryl sulfate, dodecylbenzene sulfonic acid (DDBSA), benzethonium chloride, sulfated propoxylated branched alcohols, sulfated castor oil, triceteareth-4 phosphate, and sodium caproyl lactylate.

[0012] In embodiments, aggregation aids as disclosed herein can be deployed as formulations that may comprise other additives. For example, an aggregation aid formulation can further comprise dissolved additives that lower the freezing point of the formulation. Examples of the freezing point reducing additives include glycols, ethylene glycol, propylene glycol, glycerol, alcohols, salts, and urea.

[0013] In embodiments, aggregation aids and formulations can be used to consolidate oil and suspended solid contaminants from an aqueous suspension, allowing for their removal. In the case of brine-based drilling fluids, the contamination of the fluid with oil and suspended solids results in a disruption of the desired fluid properties. Without removal of these contaminants, the fluid can no longer be used as a drilling fluid and will have to be disposed of. The consolidation of the oil and solid contaminants can be achieved by the treatment of the fluid with an aggregation aid formulation. In

embodiments, the drilling fluids can be prepared with fresh water, or water containing relatively low salt content, such as about 1000 to about 20,000 ppm of total dissolved solids (TDS). In other embodiments, the drilling fluids can be prepared with brines such as salt water, seawater, KC1 brine, zinc chloride brine, produced brine, and the like; the TDS content of these brines can be in the range of about 10,000 to about 100,000 ppm and in some cases up to about 300,000 ppm.

[0014] To treat an aqueous stream containing oil-wet solids, the following method can be employed. The aggregation aid can be added to the aqueous stream either in the neat form, or dissolved, dispersed, or emulsified in a liquid, with the liquid being either aqueous or organic. In some cases it may be preferable to dissolve the aggregation aid in a liquid, either organic or aqueous, in order to effectively deliver it homogeneously throughout the aqueous stream of interest.

[0015] In an exemplary embodiment, this process of adding the aggregation aid can take place in a mixing vessel, and the aggregates formed thereby are denser than the fluid in the vessel. Such dense aggregates can settle to the bottom or otherwise be removed. In certain embodiments, the aggregates will contain sufficient mineral or inorganic content such that their density exceeds the density of the carrier fluid and the aggregates will tend to sink. In other embodiments, the aggregates can contain sufficient oil or organic matter, or attached air bubbles, such that the aggregates have a lower density than the

surrounding fluid and the aggregates will tend to float. In either case, the addition of aggregation aid can enable the formation of aggregates, and the appropriate separation equipment can be used to separate the aggregates from the fluid, whether by flotation or by sedimentation/sinking mechanisms.

[0016] In embodiments, a continuous settling process can be achieved by flowing the chemically treated fluid into a vessel where such chemical treatments (chemical treatments include treatments with aggregation aids, with other surfactants, with flocculants, and/or with solids particles) and allowing the oil and solid aggregates to settle to the bottom of the vessel.

[0017] In embodiments, the aggregation aid can be used in combination with a flocculant solution, such as an acrylamide polymer or the like. In embodiments, the flocculant can be added after the mixing of the aggregation aid with the contaminated fluid stream. Representative flocculants are commercially available and familiar to artisans of ordinary skill; for example, charged polyacrylamides are commercially available from SNF Inc., under the trade name of Flopam. [0018] In embodiments, the aggregation aid can be used in combination with solid particles, such as calcium carbonate or the like. As used herein, the term "particles" includes all known shapes of materials without limitation, such as spherical materials, elongate materials, polygonal materials, fibrous materials, irregular materials, and any mixture thereof. Suitable particles can include organic or inorganic materials, or mixtures thereof. In embodiments, inorganic particles can include one or more materials such as sand, graded sand, resin coated sand, bauxite, ceramic materials, glass materials, calcium carbonate, calcium silicate, dolomite, calcium sulfate, kaolin, talc, titanium dioxide, diatomaceous earth, aluminum hydroxide, fly ash, silica, alumina, fumed carbon, carbon black, graphite, mica, boron, zirconia, talc, other metal oxides, and combinations thereof and the like. Calcium carbonate is a preferred source of particles for this application. Organic particles can include one or more materials such as starch, modified starch, cellulose, walnut hulls, polymeric materials, polymeric spheres (both solid and hollow), resinous materials, rubber materials, and the like. In embodiments, the particles can include naturally occurring materials, for example nutshells that have been chipped, ground, pulverized or crushed to a suitable size (e.g., walnut, pecan, coconut, almond, ivory nut, brazil nut, and the like), or for example, seed shells or fruit pits that have been chipped, ground, pulverized or crushed to a suitable size (e.g., plum, olive, peach, cherry, apricot, etc.), or, for example chipped, ground, pulverized or crushed materials from other plants such as corn cobs. In embodiments, the particles can be derived from wood or processed wood, including but not limited to, woods such as oak, hickory, walnut, mahogany, poplar, and the like. In embodiments, aggregates can be formed, using an inorganic material joined or bonded to an organic material. Particle sizes can range from a few nanometers to few hundred microns. In a preferred embodiment, the particle size is in the range of about 10 to about 100 microns based on median particle diameter. In certain embodiments, macroscopic particles in the millimeter range may be suitable. Not to be bound by theory, solid particles can be used to aid in the formation of aggregates or floes, and additionally provide an increase in the aggregate density, rendering faster, more effective separation. The selected particles can be delivered in a solid form, for instance as a powder, and mixed into the fluid stream through a mixing hopper, such as a venture hopper.

[0019] The selected solid particles can be suspended in fluid to form a particulate formulation. One type of solid particles can be used for a particulate formulation, or more than one type may be used. In embodiments, for example, a particulate formulation can be prepared by adding the selected solid particle type(s) before or after the mixing of the aggregation aid with the contaminated fluid stream. In embodiments, a particulate formulation can be prepared as a slurry by dispersing the solid particles in an aqueous medium, such as, but not limited to, water, brine, salt water based drilling fluids, and salt water based drilling fluids contaminated with oil and or solids. In embodiments, the particulate formulation can comprise a slurry containing less than about 1% of the solid particles. In embodiments, the formulation can comprise a slurry containing between about 1% and about 50% of the solid particles. In embodiments, if the particulate formulation comprises solid particles dispersed in salt water based drilling fluids contaminated with oil and or solids, this particulate formulation can be treated with aggregation aids and additional chemicals, as disclosed herein.

[0020] In embodiments, the particulate formulations as disclosed herein can be mixed with the fluid stream to be treated, in order to control the amount of solid particles introduced in to the system in a controlled manner. In an exemplary embodiment, a particulate formulation comprises an about 20% slurry of calcium carbonate in a salt water based drilling fluids contaminated with oil and or solids is prepared; this slurry is agitated to prevent settling, and introduced into the primary salt water based drilling fluids contaminated with oil and or solids in resulting in fluid stream with a final calcium carbonate concentration of about 0.05 to about 10% by weight. In embodiments, the fluid stream is then treated with aggregation aid as described herein, followed by treatment with a water soluble flocculant, as described herein.

[0021] In embodiments the aggregation aid can be used in combination with chemicals that are commonly used to reduce foaming of fluids, such as fatty acids, fatty alcohols, silicone-containing materials and the like. Examples of these types of foam control agents include Dow Corning 5-7070 Emulsion, Dow 8194, oleic acid, lauric acid, lauryl alcohol, cetyl alcohol, ethylene bis stearamide, silica, hydrophobic silica, and EO/PO copolymers.

[0022] In embodiments, the pH of the fluid stream can be adjusted and/or the pH of the solutions containing the treatment chemicals can be adjusted to increase the efficacy of the treatment process. In an embodiment, the pH of the oil and solids contaminated fluid stream is adjusted to less than 6.5, or less than 6.0, and aggregate formation occurs more rapidly, or requires a lower treatment dose, or the resulting aggregates are more suitable for flocculation and separation. Similarly, the pH of the treatment chemical solutions can be adjusted to increase the efficacy of the treatment process. In embodiments, a solution containing treatment chemicals such as an aggregation aid or polymer can have improved performance if the solution pH is lowered by addition of an acid. Also, not to be bound by theory, introducing a treatment chemical solution with an elevated pH can increase the undesirable electrostatic repulsions between the clay particles and hinder the treatment efficacy.

[0023] In certain oil production operations, waste slurries containing oil, water, and insoluble solids are generated during waterflood or steamflood operations, from heavy oil production, from artificial lift oil production, and from cleanout of tanks, separators, and pipelines. Waterflood and steamflood operations are tertiary recovery methods practiced to enhance the recovery of oil from otherwise depleted reservoirs. When the oil is produced from these wells, it is often produced as a mixture with large volumes of produced water or condensate. The produced water, oil, and solids often present challenges in separation, and there is often a waste stream generated, containing oil-wet solids with water. In artificial lift operations, heavy oil is pumped to the surface using techniques and equipment such as positive displacement pumps that are capable of pumping viscous slurries containing oil, water, and solids. The oil production stream from artificial lift operations often is contaminated with insoluble solids and water; these materials are considered contaminants in the oil product, and they are removed by settling and other chemical and mechanical methods. In the cleanup of the produced solids from artificial lift operations, a waste slurry of oil, water, and insoluble solids is often generated. This waste stream contaminates the production site and new methods are needed to address these environmental concerns. Holding tanks, separator vessels, and pipelines that process crude oil often become laden with sludges that separate by gravitational settling. The equipment is cleaned out periodically to remove the sludges, and this presents a material handling and disposal challenge that would benefit from some kind of separation.

[0024] These waste slurries all contain a combination of oil, water, and insoluble solids. The goal of the treatment process can be to remove the oil and solids from the slurry, or to remove the oil from the water and the insoluble solids. In certain embodiments, the aggregation aids of the invention can be used to enhance the separation of oil and solids from a slurry, leaving behind a clarified water stream for recovery or disposal. This separation process with aggregation aids can be aided by the use of a water soluble flocculant polymer. This treatment process applies the same approach as used for treatment of salt water based drilling fluids, described above, to other oilfield wastes such as oil/water/solids slurries. In other embodiments, the aggregation aids of the invention can be used to release oil from oil-wet solids in the presence of water. In this treatment process, the oil is released in a form that contains less insoluble solids compared to the untreated slurry, and the oil can be recovered in a form that can be recovered for refining. Applications of the latter process include the treatment of waste sludges from steamflood, water flood, equipment cleanout, and artificial lift operations.

EXAMPLES

[0025] MATERIALS:

• Adogen 464, methyltrialkyl (C8-C10) ammonium chloride, from Sigma Aldrich

• Alfoterra L167-4S and 123-4S, alkoxylated alcohol sulfate, sodium salt, from Sasol

• Ammonium Lauryl Sulfate, from Sigma Aldrich

• Arquad 2HT-75, di(hydrogenated tallow)dimethylammonium chloride, from

Sigma Aldrich

• Benzethonium Chloride, from Sigma Aldrich

• Brij L4, O10, and 98, primary alcohol ethoxylates, from Sigma Aldrich

• CTAB, cetyl trimethylammonium bromide, from Sigma Aldrich

• DDBSA, dodecylbenzene sulfonic acid, from Sigma Aldrich

• Flopam 942AN anionic polyacrylamide, from SNF Inc.

• Igepal CO-520, CO-890, and DM-970, alkylphenol ethers, from Sigma Aldrich

• Kemelix 3515X, 3551X, 3697X, 3702X, 3725X, 3736X, 3738X, 3743X, 3744X, and D510, ethoxylated surfactants, from Croda

• Mirataine Bet 0-30, betaine surfactant, from Rhodia

• PEG-40 Hydrogenated Castor Oil, Cremophor CO-40, from BASF

• Pluronic F68, L31 , and L64, EO/PO copolymers, from BASF

• Sodium lauryl sulfate, from Sigma Aldrich

• Span 80, sorbitan monooleate, from Sigma Aldrich

• Synperonic PE/L101 and PE/L121, surfactants, from Croda

• Tergitol 15-S-3, 15-S-5, 15-S-7, 15-S-9, 15-S-12, 15-S-15, 15-S-30, and 15-S-40, secondary alcohol ethoxylates, from BASF

• Tetronic 304 and 901, alkoxylated diamines, from BASF • Triton X-l 14, tert-octylphenoxy poly(oxyethylene)ethanol, from Sigma Aldrich

• Tween 20, 80, 81 and 85, ethoxylated sorbitan esters, from Sigma Aldrich

[0026] Example 1 : Aqueous slurries of oil-wet solids

[0027] The oil contaminated brine slurries used in the examples were obtained from a drilling rig in North Dakota. The samples were characterized by retort to determine the relative volume percent of oil, water, and solids. The solids content includes both the dissolved and suspended solids in the fluid. The sample compositions are listed in Table I below.

TABLE I - Composition of Oil Samples by Retort

[0028] Example 2: Treatment of a slurry with solutions of aggregation aids

[0029] All trials in this example were performed at room temperature, about 20°C. For each of these trials, a 4.4% solution of aggregation aid actives was made in tap water. The term "actives" refers to the active ingredient of the formulation. A volume of this solution was added to 20 mL of a mud sample of Example Al, with the actives dose ranging from 1000 to 10,000 ppm. The sample vial was then shaken vigorously for a minute, and the formation of aggregates was noted. Aggregate formation was generally indicated by a darkening in color and the formation of micro floes. After aggregation, 0.05 mL of a 0.1% solution of Flopam 942AN was added and the vial was gently inverted 4 times. The reduction of initial bed height ("% Settling") was recorded after 10 minutes of settling. TABLE II

[0030] Example 3 : Treatment of a slurry with solutions of aggregation aids

[0031] All trials in this example were performed at room temperature, about 20°C. For each of these trials, a 4.4% solution of aggregation aid actives was made in tap water. A volume of this solution was added to 20 mL of a mud sample of Example A2, with the actives dose ranging from 1000 to 10,000 ppm. The sample vial was then shaken vigorously for a minute, and the formation of aggregates was noted. Aggregate formation was generally indicated by a darkening in color and the formation of micro floes. After aggregation, 0.05 mL of a 0.1% solution of Flopam 942AN was added and the vial was gently inverted 4 times. The reduction of initial bed height ("% Settling") was recorded after 10 minutes of settling.

TABLE III

Dose Aggregates

Test # Aggregation Aid % Settling

(mg/L) formed (Y/N)

3.1 none 0 No

3.2 Brij L4 8800 Yes 79%

3.3 Brij L4 12, 100 Yes 17% 3.4 Brij L4 5500 Yes 12%

3.5 DDBSA 8800 No 63%

3.6 DDBSA 12, 100 No 21%

3.7 Kemelix 3738X 8800 Yes 14%

3.8 Kemelix 3738X 12, 100 Yes 64%

3.9 Kemelix 3738X 5500 Yes 45%

3.10 Tergitol 15-S-5 8800 No 9%

3.1 1 Tergitol 15-S-5 12, 100 No 76%

3.12 Tween 85 8800 Yes 18%

3.13 Tween 85 12, 100 Yes 0%

3.14 Tween 85 5500 Yes 3%

[0032] Example 4: Treatment of a slurry with solutions of aggregation aids

[0033] All trials in this example were performed at room temperature, about 20°C. For each of these trials, a 4.4% solution of aggregation aid actives was made in tap water. A volume of this solution was added to 20 mL of a mud sample of Example A4, with the actives dose ranging from 1000 to 10,000 ppm. The sample vial was then shaken vigorously for a minute, and the formation of aggregates was noted. Aggregate formation was generally indicated by a darkening in color and the formation of micro floes. After aggregation, 0.05 mL of a 0.1% solution of Flopam 942AN was added and the vial was gently inverted 4 times. The reduction of initial bed height ("% Settling") was recorded after 10 minutes of settling.

TABLE IV

Dose Aggregates

Test # Aggregation Aid % Settling

(mg/L) formed (Y/N)

4.1 none 0 No

4.2 Brij L4 3300 No 72%

4.3 Brij L4 6600 Yes 74%

4.4 Brij L4 4400 No 78%

4.5 DDBSA 3300 No 72%

4.6 DDBSA 6600 Yes 54%

4.7 DDBSA 4400 No 64% 4.8 Kemelix 3738X 3300 No 76%

4.9 Kemelix 3738X 6600 No 41%

4.10 Kemelix 3738X 4400 No 33%

4.1 1 Tergitol 15-S-5 3300 No 22%

4.12 Tergitol 15-S-5 6600 Yes 53%

4.13 Tergitol 15-S-5 4400 No 58%

4.14 Tween 85 3300 Yes 37%

4.15 Tween 85 6600 Yes 83%

4.16 Tween 85 2200 No 43%

[0034] Example 5 : Treatment of a slurry with aggregation aids

[0035] All trials in this example were performed at room temperature, about 20°C. For each of these trials, the aggregation aid was added without dilution. A volume of this treatment was added to 20 mL of a mud sample of Example Al, with the dose ranging from 1000 to 10,000 ppm. The sample vial was then shaken vigorously for a minute, and the formation of aggregates was noted. After aggregation, 0.05 mL of a 0.1% solution of Flopam 942AN was added and the vial was gently inverted 4 times. The reduction of initial bed height ("% Settling") was recorded after 10 minutes of settling.

TABLE V

Dose Aggregates

Test # Aggregation Aid % Settling

(mg/L) formed (Y/N)

5.1 none 0 No

5.2 Igepal CO 520 3500 Yes 85%

5.3 Triton X-114 3500 No 63%

5.4 Brij L4 2500 Yes 84%

5.5 Tween 85 2500 Yes 64%

5.6 Tergitol 15-S-7 2500 No 82%

5.7 Tergitol 15-S-5 2500 Yes 78%

5.8 Kemelix 3738X 3500 Yes 55%

5.9 Kemelix 3743X 3500 No 100%

5.10 Kemelix 3515X 3500 Yes 100%

5.1 1 Kemelix 355 IX 3500 Yes 78% 5.12 Kemelix D510 3500 Yes 0%

Synperonic Yes

5.13

PE/L101 3500 68%

Synperonic Yes

5.14

PE/L121 3500 0%

5.15 Tween 81 1500 Yes 0%

[0036] Example 6: Treatment of a slurry with aggregation aids

[0037] All trials in this example were performed at room temperature, about 20°C. For each of these trials, the aggregation aid was added without dilution. A volume of this treatment was added to 20 mL of a mud sample of Example A7, with the dose ranging from 1000 to 10,000 ppm. The sample vial was then shaken vigorously for a minute, and the formation of aggregates was noted. After aggregation, 0.05 mL of a 0.1% solution of Flopam 942AN was added and the vial was gently inverted 4 times. The reduction of initial bed height ("% Settling") was recorded after 10 minutes of settling.

TABLE VI

[0038] Example 7: Treatment of a slurry with aggregation aids

[0039] All trials in this example were performed at room temperature, about 20°C. For each of these trials, the aggregation aid was added without dilution. A volume of this treatment was added to 20 mL of a mud sample of Example A8, with the dose ranging from 1000 to 10,000 ppm. The sample vial was then shaken vigorously for a minute, and the formation of aggregates was noted. After aggregation, 0.05 mL of a 0.1% solution of Flopam 942AN was added and the vial was gently inverted 4 times. The reduction of initial bed height ("% Settling") was recorded after 10 minutes of settling.

TABLE VII

[0040] Example 8: Treatment of a slurry with aggregation aids

[0041] All trials in this example were performed at room temperature, about 20°C. 20 mL of a mud sample of Example A5 were placed in a 40 mL vial. 2500 ppm of an aggregation aid was added to the mud in the range of about 1000 to 10000 ppm actives. The vial was then sealed and shaken vigorously by hand for 1 minute. The formation of aggregates was then noted. After aggregation, 0.05 mL of a 0.1% solution of Flopam 942AN was added and the vial was gently inverted 4 times. The reduction of initial bed height ("% Settling") was recorded after 2 days of settling. TABLE VIII

[0042] Example 9: Treatment of a slurry with aggregation aids

[0043] All trials in this example were performed at room temperature, about 20°C. 20 mL of a mud sample of Example A6 were placed in a 40 mL vial. 2500 ppm of an aggregation aid was added to the mud in the range of about 1000 to 10000 ppm actives. The vial was then sealed and shaken vigorously by hand for 1 minute. The formation of aggregates was then noted. After aggregation, 0.05 mL of a 0.1% solution of Flopam 942AN was added and the vial was gently inverted 4 times. The reduction of initial bed height ("% Settling") was recorded after 2 days of settling. TABLE IX

[0044] Example 10: Treatment of a slurry with aggregation aids

[0045] All trials in this example were performed at room temperature, about 20°C. For each of these trials, Tween 80 was the aggregation aid added (for those trials with aggregation aids), and it was added without dilution. A dose of the aggregation aid was added to 20 mL of a mud sample of Example A8 in a 40 mL vial. The sample vial was then shaken vigorously for a minute. After shaking, a volume of 0.1% solution of Flopam 942AN was added and the vial was gently inverted 4 times. The initial settling rate was recorded. The reduction of initial bed height ("% Settling") was recorded after 10 minutes of settling.

TABLE X

[0046] Example 1 1 : Treatment of a slurry with aggregation aids

[0047] All trials in this example were performed at room temperature, about 20°C. For each of these trials, Tween 80 was the aggregation aid added (for those trials with aggregation aids), and it was added without dilution. A dose of the aggregation aid was added to 20 mL of a mud sample of Example A 1 in a 40 mL vial. The sample vial was then shaken vigorously for a minute. After shaking, a volume of 0.1% solution of Flopam 942AN was added and the vial was gently inverted 4 times. The initial settling rate was recorded. The reduction of initial bed height ("% Settling") was recorded after 10 minutes of settling. TABLE XI

EQUIVALENTS

[0048] While this invention has been particularly shown and described with references to preferred embodiments thereof, it will be understood by those skilled in the art that various changes in form and details may be made therein without departing from the scope of the invention encompassed by the appended claims.

Claims

1. A method for aggregating oil-wet solids in an aqueous suspension, comprising:

providing an aqueous suspension containing oil-wet solids; and

treating the aqueous suspension with an effective amount of a formulation comprising an aggregation aid, thereby aggregating the oil-wet solids as removable aggregates.

2. The method of claim 1, further comprising removing the removable aggregates.

3. The method of claim 1, further comprising providing a flocculant and adding the flocculant to the aqueous suspension before, during or after the step of treating the aqueous suspension with the effective amount of the formulation comprising an aggregation aid.

4. The method of claim 1, further comprising providing a particulate formulation and adding the particulate formulation to the aqueous suspension, before, during or after the step of treating the aqueous suspension.

5. The method of claim 1, wherein the aqueous suspension is treated with about 1000 to about 50,000 ppm of the aggregation aid, based on amount of actives.

6. The method of claim 1, wherein the aggregation aid is a nonionic surfactant having a HLB value between about 8 and 11.

7. The method of claim 1, wherein the aggregation aid is an ionic surfactant selected from the group consisting of calcium alkylaryl sulfonates, sodium lauryl sulfates,

dodecylbenzene sulfonic acids, benzethonium chlorides, sulfated propoxylated branched alcohols, sulfated castor oils, triceteareth-4 phosphates, and sodium caproyl lactylates.

8. The method of claim 1, wherein the aqueous suspension is derived from spent drilling fluid.

9. The method of claim 8, wherein treating the aqueous suspension yields a reclaimable spent drilling fluid.

10. The method of claim 5, further comprising providing a particulate formulation and adding the particulate formulation to the slurry, before, during or after the step of treating the slurry.