WO2019023058A1

WO2019023058A1 - Treatment of drill cuttings

Info

Publication number: WO2019023058A1
Application number: PCT/US2018/043087
Authority: WO
Inventors: Paul C. PAINTER; Bruce G. Miller; Aron Lupinsky
Original assignee: Extrakt Process Solutions LLC
Current assignee: Extrakt Process Solutions LLC
Priority date: 2017-07-24
Filing date: 2018-07-20
Publication date: 2019-01-31
Anticipated expiration: 2020-01-24

Abstract

Processes of treating drill cuttings which include solids and drilling fluid to consolidate solids and/or separate drilling fluid and/or hydrocarbon are disclosed. The processes include mixing drill cuttings with a highly water soluble salt or an aqueous solution thereof to destabilize and consolidate solids in the cuttings. The process can also include treating the drill cuttings with a diluent to separate and recover hydrocarbon associated with the drill cuttings.

Description

TREATMENT OF DRILL CUTTINGS

CROSS-REFERENCE TO RELATED APPLIC ATIONS

[0001 ] This application claims the benefit of U.S. Provisional Application No.

62/611,232, filed 28 December 2017, and U.S. Provisional Application No. 62/536, 189, filed 24 July 2017, the entire disclosures of which are hereby incorporated by reference herein.

TECHNICAL FIELD

[0002] The present disclosure relates to dewatering and consolidation of drill cuttings, which are a by-product of drilling subterraneous formations for the recovery of hydrocarbons therefrom. Hydrocarbons that may be present in the drill cuttings can also be separated and recovered.

BACKGROUND

[0003] Hydraulic fracturing in shale formations such as the Marcellus and Bakken has allowed the exploitation of oil and gas reserves that were previously inaccessible and transformed the energy outlook, not only in the U.S., but worldwide. Drilling into these formations usually involves the use of drilling fluids, also referred to as drilling muds. These drilling muds can be oil based or water based and serve to provide hydrostatic pressure, cool the drill bit and flush out drill cuttings. Drill cuttings are the rock, soil, sand, shale or other minerals bought to the surface during drilling.

[0004] Oil based muds can withstand greater heat than water based muds and are based on petroleum products such as diesel. There are also synthetic muds, which use synthetic oils that are environmentally safer (although these are also usually based on petroleum products). Oil based muds are an invert-emulsion system, with oil or synthetic oil forming the continuous phase and water or brine as the internal phase. Chemical agents are used to stabilize the emulsion, making subsequent recover}' of the oil difficult. Oil and synthetic based muds are preferred when drilling into shale formations, because they do not swell clays, which would lead to shale instability. [0005] Boring the vertical and horizontal legs of a typical shale well brings oil covered drill cuttings to the surface as a result of using oil-based drilling muds in the drilling process. The drill cuttings are subsequently separated from the balance of the drilling muds and the muds are recycled into the drilling process. The amount of drill cuttings involved can be very large. For example, according to Anadarko Petroleum Corp., a typical horizontal Marcellus shale well produces more than 1,000 tons of cuttings, about 75 truckloads. Each drilling site or pad can contain 8-12 wells.

[0006] The disposal of oil and synthetic based cuttings is difficult - they are "dense and soupy". Complete separation of the oil from the cuttings can be achieved using thermal evaporation methods, but the process is expensive, because of the energy requirements involved. Consequently, industrial practice is to remove as much oil and water from the cuttings as possible and add a caking agent/solidifier of kiln dust, lime, or wood chips. The goal is to get the cuttings to 50-60 percent solids for ease in movement/transportation. The drill cuttings are then sent to engineered landfills at a significant and growing cost. Some landfills are experiencing problems with compaction due to the high liquid content of the drill cuttings.

[0007] There is a clear need for the development and deployment of a remediation technology that can remove oil or synthetic oil from drill cuttings. Recovered oil could be recycled to drilling muds or used as a fuel, while the cleaned solids and soil can be used for land reclamation, soil amendments, landfill cover that can be compacted.

SUMMARY OF THE DISCLOSURE

[0008] Advantages of the present disclosure include processes to treat drill cuttings, which include solids and drilling fluid, to consolidate the drill cuttings to produce high solids content materials. The drill cuttings can include an oil-based drilling fluid or a water-based drilling fluid. Additional advantageous can include separating the drilling fluid from the drill cuttings.

[0009] These and other advantages are satisfied, at least in part, by a process of consolidating drill cuttings. The process comprises treating the drill cuttings, which includes solids, some or all of which can be sized as fines, and drill fluid. Advantageously, the process can include treating the drill cuttings with the at least one highly water soluble salt or solution thereof to form a treated drill cuttings. Optionally the process can further include treating the drill cuttings with either or both of at least one polymer flocculant or solution thereof and/or coarse particles, e.g., sand, to form a treated cuttings. The treated cuttings can include a consolidated material in the drilling fluid. The drilling fluid then be advantageously separated from the consolidated material.

[0010] In practicing aspects of the processes of the present disclosure, drill cuttings that include hydrocarbon, such as from an oil based drilling fluid, including hydrocarbon lubricants, synthetic oils, petroleum oils or lubricants such as diesel, or oil or hydrocarbons from the subterranean formation made with the drilling mud, or combinations thereof, can be separated and recovered. The process can further comprise treating the drill cuttings with a diluent to dilute hydrocarbons therein and recovering the diluted hydrocarbon. Advantageously, the hydrocarbon directly separated from the drill cuttings can contain a low amount of fines or has low minerals content, e.g., less than about 1 wt% or no more than about 0.5 wt% or no more than about 0.1 wt%.

[0011] Implementations of the process of the present disclosure include, for example, (i) treating the drill cuttings with at least one highly water soluble salt to form a treated cuttings including a consolidated material in the drilling fluid, (ii) treating the drill cuttings with at least one highly water soluble salt and at least one polymer flocculant to form a treated cuttings including a consolidated material in the drilling fluid, (iii) treating the drill cuttings with at least one highly water soluble salt thereof, and coarse particles to form a treated cuttings including a consolidated material in the drilling fluid, and (iv) treating the drill cuttings with at least one highly water soluble salt, at least one polymer flocculant and coarse particles to form a treated cuttings including a consolidated material in the drilling fluid. Each of these implementations can include aqueous solutions of the salt and/or polymer flocculant to treat the cuttings and each of these implementations can include separating the aqueous solution from the treated cuttings. Each of these implementations can also include separating the drilling fluid from the consolidated material. [0012] In practicing aspects of the processes of the present disclosure and the various embodiments thereof, the process includes treating the drill cuttings with one or more aqueous solutions of the sait(s) and/or polymer flocculant(s). The process can further comprise one or more of: (i) recovering at least a portion of the separated aqueous solution including the salt(s) and/or polymer floccuiant(s); (ii) recycling at least a portion of recovered, separated aqueous solution to treat additional drill cuttings; (iii) purifying at least a portion of recovered aqueous solution and/or (iv) concentrating the at least one highly water soluble salt in recovered aqueous solution to form a brine and using the brine to treat additional drill cuttings. Such concentration can be carried out by reverse osmosis, for example.

[0013] Yet another aspect of the present disclosure includes recovering the consolidated materials from the drill cuttings,

[0014] In some embodiments, the at least one highly water soluble salt can have a solubility in water (a salt/water solubility) of at least about 5 g/100 g at 20 °C, e.g., at least about 10 g/ 100 g at 20 °C. In other embodiments, the at least one highly water soluble salt is a non- hydrolyzing salt. In still further embodiments, the at least one highly water soluble salt can have a monovalent cation and can include an ammonium based salt, a phosphate based salt, or a sulfate based salt. In other embodiments, treating drill cuttings include using a solution of one or more highly soluble salts sourced from a natural or existing source such as seawater or a body of hypersaiine water.

[0015] In some embodiments, the at least one polymer flocculant is a polyacryl amide or co-polymer thereof. In other embodiments, the cuttings also can be treated with coarse particles, e.g., sand. In certain embodiments, treating the drill cuttings can be carried out at ambient temperature, e.g., no more than about 2 °C to about 5 °C above ambient. In other embodiments, treating the aqueous coal waste composition can be carried out at a temperature of no more than about 50 °C, e.g., no more than about 40 °C or 30 °C.

[0016] In still further embodiments, the drilling fluid can be separated from the consolidated material by any one or more of decanting, filtering, vacuuming, gravity draining, etc. or combinations thereof. In various embodiments, separating the drilling fluid from the consolidated material can include mechanically dewatering the consolidated material, e.g.. mechanically dewatering the consolidated material by a dewatering screw. Once separated, the consolidated material can be transferred for further dewatering or disposal.

[0017] Additional advantages of the present invention will become readily apparent to those skilled in this art from the following detailed description, wherein only the preferred embodiment of the invention is shown and described, simply by way of illustration of the best mode contemplated of carrying out the invention. As will be realized, the invention is capable of other and different embodiments, and its several details are capable of modifications in various obvious respects, all without departing from the invention. Accordingly, the description is to be regarded as illustrative in nature, and not as restrictive.

DETAILED DESCRIPTION OF THE DISCLOSURE

[0018] The present disclosure relates to treating drill cuttings to consolidate the solids in the drill cuttings and/or separate hydrocarbons associated with the drill cuttings. As described in the background section, drill cuttings are a waste by-product of drilling subterraneous formations for the purpose of recovering hydrocarbons from such formations. The drill cuttings typically contain drilling fluid, which can be either water or oil-based, and various solid particles such as rocks, soil, shale, mineral matter, clays, fines, etc. The drill cuttings can contain up to 5, wt%, 10 wt%, 15 wt%, 30 wt%, 50 wt% or more of solids, e.g., between about 10 wt% to about 50 wt% solids. The solid particles are contaminated with oil from the drilling fluid which are oil- based and any oil in the formation being drilled. The proportion of solids and oil in the cuttings varies with the formation being drilled, the operator and the nature of the drilling mud being used. The drill cuttings also typically include a certain amount of water apart from the drilling fluid.

[0019] Advantageously, the process of the present disclosure can consolidate the solids of the cuttings to produce solids content initially in excess of about 50% by weight, e.g., solids content of greater than about 60 wt% or 70 wt%, or higher. In certain aspects, treating the drill cuttings can separate hydrocarbons associated with the drill cuttings. Such hydrocarbons include hydrocarbons from an oil based drilling fluid such as hydrocarbon lubricants, synthetic oils, petroleum oils or lubricants such as diesel, hydrocarbons from the subteiranean formation as a result of the drilling operation with the drilling mud, or combinations thereof. Advantageously, the hydrocarbon directly separated from the drill cuttings can contain a low amount of fines or has low minerals content, e.g., less than about 1 wt% or no more than about 0.5 wt% or no more than about 0.1 wt%.

[0020] The solids of drill cuttings are classified herein according to particle sizes. The term fines as used herein is consistent with the Canadian oil sands classification system and means solid particles with sizes equal to or less than 44 microns (μηι). Sand is considered solid particles with sizes greater than 44 μιη. The cuttings from oils sands extraction can also include a significant amount of fines by weight (>5 wt%) as their solids content.

[0021] The terms coagulation and flocculation are often used interchangeably in the literature. As used herein, however, coagulation means particle aggregation brought about by the addition of hydrolyzing salts, whereas flocculation means particle aggregation induced by flocculating polymers. Hydrolyzing salts undergo hydrolysis when added to water to form metal hydroxides, which precipitate from the solution, trapping fines and other minerals in the coagulating mass, Hydrolyzing salts typically have low solubility in water and are used as coagulants. Aggregation induced by flocculation, in contrast, is believed to be the result of the polymer binding to the particles thereby tying the particles together into a so called floe causing aggregation of the particles.

[0022] In practicing aspects of the present disclosure, drill cuttings, e.g., a composition of solids and drilling fluid, which can include hydrocarbon and water, can be consolidated by treating the drill cuttings with one or more highly water soluble sait(s) or an aqueous solution thereof to destabilize and consolidate solids in the cuttings, e.g., to destabilize and consolidate fines in the cuttings. Aggregation induced by the addition of salts is believed to be the result of destabilizing the particles suspended in the fluid by an alteration or a shielding of the surface electrical charge of the particles to reduce the inter-particle repulsive forces that prevent aggregation. The drilling fluid can then be separated from the consolidated material. Advantageously, the consolidated material has a solids content of at least 45% by weight, e.g., a soli ds content of greater than about 50% by weight. [0023] Salts that are useful in practicing the present disclosure include salts that are highly soluble in water, A highly water soluble salt as used herein is one that has a solubility in water of greater than 2 g of salt per 100 g of water (i.e., a salt/water solubility of 2g/100g) at 20 °C. Preferably the highly water soluble salt has a water solubility of at least about 5 g/100 g at 20 °C, e.g., at least about 10 g/100 g of salt/water at 20 °C.

[0024] In addition, the highly water soluble salts used in the processes of the present disclosure are preferably non-hydrolyzing. Hydrolyzing salts undergo hydrolysis when added to water to form metal hydroxides, which precipitate from the solution. Such hydrolyzing salts are believed to form open floes with inferior solids content and cannot be readily recycled for use with additional cuttings in continuous or semi-continuous processes. In addition, hydrolyzing salts typically have low solubility in water and are used at elevated temperatures to ensure sufficient solubility for aggregation, which is an energy intensive process. See US 4,225,433 which discloses the use of lime as a coagulating agent at a temperature of 75 °C.

[0025] Further, the highly water soluble salts are preferably not carboxylate salts since such organic acid salts tend to be more expensive than inorganic salts and can be deleterious to plant and/or animal life.

[0026] Highly water soluble salts that are not hydrolyzing and useful in practicing processes of the present disclosure include salts having a monovalent cation, e.g., alkali halide salts such as sodium chloride, potassium chloride; also salts with monovalent cations such as sodium nitrate, potassium nitrate, sodium and potassium phosphates, sodium and potassium sulfates, etc. are useful in practicing processes of the present disclosure. Other monovalent cationic salts useful in practicing processes of the present disclosure include ammonium based salts such as ammonium acetate (NH₄C₂H₃0₂), ammonium chloride (NH₄C1), ammonium bromide (NH₄.Br), ammonium carbonate ((NFL^COs), ammonium bicarbonate (NH₄HCQ₃), ammonium nitrate (NH₄NO₃), ammonium sulfate ({M i. _.'SO s ), ammonium hydrogen sulfate (NH₄HSO₄), ammonium dihvdrogen phosphate ( H₄H₂PO₄), ammonium hydrogen phosphate ((NH₄)₂HP0₄), ammonium phosphate ((NH₄)₃P0₄), etc. Mixtures of such salts can also be used.

[0027] Ammonium based salts are useful for practicing the present disclosure since residual ammonium based salts on the consolidated material after combining the salt with the drill cuttings are not harmful to plant life. In fact, many of the ammonium based salts are useful as fertilizers and are in fact beneficial to plant life, e.g., ammonium chloride, ammonium nitrate, ammonium sulfate, etc. Many of the monovalent sulfate and phosphate salts are also useful as fertilizers. In certain embodiments of the present disclosure, the highly water soluble salt or salts used in the processes of the present disclosure can preferably be non-toxic and beneficial to plant life to aid in environmental remediation and the restoration of mine sites.

[0028] In one aspect of the present disclosure, treating drill cuttings with a highly water soluble salt destabilizes and consolidates solids in the cuttings. Such a process can include mixing the drill cuttings, which includes solids, some or all of which are sized as fines, and drilling fluid, with a highly water soluble salt to consolidate the solids, and separating the drilling fluid from the consolidated fines to produce a high solids content, e.g., at least 45% by weight. In certain embodiments, the highly water soluble salt is an ammonium based salt.

[0029] Highly water soluble salts that can be used in practicing the present process can also include salts having multivalent cations. Such salts include, for example, divalent cation salts such as calcium and magnesium cation salts, such as calcium chloride (CaCl₂), calcium bromide (CaBr₂), calcium nitrate (CaiNO:);). magnesium chloride (MgCl?.), magnesium bromide (MgBr?), magnesium nitrate (Mg(N0₃)₂), magnesium sulfate (MgS0₄); and trivalent cation salts such as aluminum and iron (III) cation salts, e.g., aluminum chloride (A1C1₃), aluminum nitrate (A1(N0₃)₃), aluminum sulfate (A1₂(S0₄)₃), iron (III) chloride (FeCl₃), iron (III) nitrate (Fe(N0₃)₃), iron (III) sulfate (Fe₂(S0₄)₃, etc. As explained above, the highly water soluble salts used in the processes of the present disclosure are preferably non-hydroiyzing. Many of the multivalent cation salts are hydrolyzing and thus less preferred for the reasons stated above. Moreover, experimentation with multivalent salts showed increased fouling of containers and formation of less cohesive consolidated materials as compared to highly water soluble salts having monovalent cations. In addition, some multivalent salts, such as FeCl₃ and Fe₂(S0₄)₃, are particularly corrosive and Fe₂(S0₄) is formed from oxidizing pyrite and results in acid mine runoff, which make such salts less preferable for use in processes of the present disclosure.

[0030] The highly water soluble salt(s) can be used to treat drill cuttings as a solid, e.g., combining the salt as a solid in the form of a powder with the cuttings. Alternatively, the salt can be used to treat drill cuttings as a solution, e.g., combining an aqueous salt solution with the cuttings. In some aspects of the present disclosure, an aqueous solution of the highly water soluble salt can be used having a concentration of no less than about 1 wt%, e.g., greater than about 2 wt%, 3 wt%, 5 wt%, 7 wt%, 10 wt%, 20 wt%, 30 wt% and even as great as a 40 wt% or as an aqueous salt slurry.

[0031] In some embodiments of the present processes, it can be more advantageous to use a natural source of a highly soluble salt or salts such as in a natural body of water including such salts in sufficiently high concentration such as at least about 2 wt% and even at least about 3 wt% or greater. For example, ocean or seawater can be used as a source of highly soluble salts, which can significantly improve the economics of the process under certain conditions. The vast majority of seawater has a salinity of between 31 g/kg and 38 g/kg, that is, 3, 1 -3.8%. On average, seawater in the world's oceans has a salinity of about 3.5% (35 g/L, 599 mM). Seawater includes a mixture of salts, containing not only sodium cations and chlorine anions (together totaling about 85% of the dissolved salts present), but also sulfate anions and calcium, potassium and magnesium cations. There are other ions present (such as bicarbonate), but these are the main components. Another natural source of highly soluble salts that can be used as a source of highly soluble salts includes a hypersaline body of water, e.g., a hypersaline lake, pond, or reservoir. A hypersaline body of water is a body of water that has a high concentration of sodium chloride and other highly soluble salts with saline levels surpassing ocean water, e.g., greater than 3.8 wt% and typically greater than about 10 wt%. Such hypersaline bodies of water are located on the surface of the earth and also subsurface, which can be brought to the surface as a result of mining operations.

[0032] The drill cuttings and aqueous salt solution or slurry should be mixed at a ratio suffi cient to destabilize the cuttings and/or cause consolidation of the solids therein,

[0033] After mixing the drill cuttings with a highly water soluble salt to consolidate the solids therein, the liquid phase, e.g., drill fluid together with liquid hydrocarbon and/or water from the drilling operation, etc., can advantageously be separated from the consolidated solids. The consolidated solids can be separated from the liquid phase by gravity, such as in a settling tank, or more or less immediately such as by thermal or evaporative technics, or by physical technics, such as by centrifugation, filtration, electro-filtration, cross-flow filtration, dewatering screws and screens, etc. Once separated, the consolidated material can be transferred for further dewatering or disposal.

[0034] The process of the present disclosure allows for large-scale treatment of drill cuttings in a continuous or semi-continuous process. For example, the liquid phase separated from an initial cuttings treatment can advantageously include the highly water soluble salt, water or brine from the drilling mud, and oil from the mud or formation being drilled. The water or brine in oil emulsions in the original drilling mud are destabilized by the highly water soluble salt and the oil can be separated from the aqueous salt phase using techniques known to the art, such as settling tanks, stack centrifuges, etc. Brine solutions can be recycled for use in formulating drilling muds.

[0035] In one aspect of the process of the present disclosure, mixing the drill cuttings with the highly water soluble salt comprises in-line mixing, where a stream of the highly water soluble salt is fed into a stream of drill cuttings.

[0036] Although highly water soluble salts can destabilize and consolidate solids in drill cuttings, the process can be significantly improved by adding a polymer flocculant. The addition of a water-soluble polymer to the highly water soluble salt can significantly reduce the time for consolidation of solid particles. Hence, in another aspect of the present disclosure, consolidating drill cuttings is implemented by mixing the cuttings with a highly water soluble salt and a water- soluble polymer flocculant to form a consolidated material. The consolidated material and the liquid phase (salt solutions and oil) can be separated from each other by gravity such as sedimentation or more or less immediately such as by physical technics, such as by centrifugation, filtration, electro-filtration, dewatering screws and screens, etc. The separated consolidated material then can be disposed or deposited in a containment stmcture which allows removal of released water from the consolidated material.

[0037] Polymers that are useful in practicing the present disclosure include water soluble flocculating polymers such as a nomomc polyacrylamide, an anionic polyacryl amide (APAM) such as a polyacrylamide-co-acrylic acid, and a cationic polyacrylamide (CP AM), which can contain co-monomers such as acryloxyethyltrimethyl ammonium chloride. methacryloxyethyltrimethyl ammonium chloride, dimethyldiallyammonium chloride (DMDAAC), etc. Other water soluble flocculating polymers useful for practicing the present disclosure include a polyamine, such as a polyamine or quaternized form thereof, e.g., polyacrylamide-co-dimethylaminoethylacrylate in quaternized form, a polyethyleneimine, a polydialiyldimethyl ammonium chloride, a polydicyandiamide, or their copolymers, a polyamide-co-amine, polyelectrolytes such as a sulfonated polystyrenes can also be used. Other water soluble polymers such as polyethylene oxide and its copolymers can also be used. The polymer flocculants can be synthesized in the form of a variety of molecular weights (MW), electric charge types and charge density to suit specific requirements. Advantageously, the flocculating polymer used in practicing processes of the present disclosure do not include use of activated polysaccharides or activated starches, i.e., polysaccharides and starches that have been heat treated, in sufficient amounts to lower the density of the floe to below the density of the process water from which they are separated. Such activated polysaccharides and activated starches when used in sufficiently high dosages tend to form low density floes which rise to the surface of an aqueous composition complicating removal of hydrocarbon and can hinder removal of solids in large scale operations involving high solids content and can also hinder dewatering of consolidated material.

[0038] The amount of polymer(s) used to treat cuttings should preferably be sufficient to flocculate the solids in the cuttings and any added sand. The amount of polymer(s) used to treat cuttings can be characterized as a concentration based on the total weight of the cuttings or as a dosage based on the weight percent of the solids in the cuttings.

[0039] In some embodiments of the present disclosure, the concentration of the one or more polymer floeculant(s) in the treated cuttings has dosage (weight of the flocculant(s) to weight of the solids in the cuttings) of no less than zero and up to about 0,005 wt%, e.g., up to about 0.01 wt% and in some implementations, up to about 0.015 wt%, 0.020 wt%, 0.025 wt%, 0.03 wt%, or 0.04 wt%.

[0040] In addition, the processes of the present disclosure can also include treating drill cuttings with coarse particles, e.g., particles with sizes greater than 44 μιη, such as sand, to increase the solids content. 1 ^

[0041] In yet another embodiment of the process, the addition of a solvent, diluent or fresh oil such as diesel or a synthetic oil together with a highly water soluble salt and, if necessary, a flocculating polymer can result in an improved oil recover}' by helping break the original water in oil emulsions in the drilling muds.

[0042] Treating drill cuttings with at least one highly water soluble salt and optionally with either or both of at least one polymer flocculant and/or sand can be carried out in a number of ways. In certain embodiments, treating the drill cuttings includes combining and/or mixing the various components. In addition, the at least one salt can be added directly to the cuttings either as an undiluted powder or as a solution; the at least one polymer flocculant can be added directly to the cuttings either as an undiluted material or as a solution, and the sand can be added to the cuttings directly or with the salt and/or polymer or solutions thereof. The salt and polymer can be combined in a single solution, with or without sand, and combined with the cuttings. The order of combining the salt, polymer and sand to the cuttings can give equivalent results and optimization of the process will depend on the scale and equipment used in the process.

[0043] However, it tends to be more convenient to use one or more solutions including the one or more highly water soluble salt(s) and the one or more polymer flocculant(s) followed by combining the one or more solutions with the drill cuttings and sand. In certain embodiments, an aqueous solution of one or more highly water soluble salt(s) can be used in the processes of the present disclosure having a concentration of no less than about 0.5 wt% or 1 wt%, e.g., at least about 2 wt%, 3 wt%, 4 wt%, 5 wt , 6 wt%, 7 wt%, 10 wt%, 20 wt%, 30 wt% and even as great as a 40 wt% or as an aqueous salt slurry for use in treating the cuttings. The one or more polymer fiocculant(s) can also be included in the aqueous solution of the salt(s) and can have a concentration of up to about 0.001 wt%, e.g., up to about 0.003 wt%, 0.005 wt%, 0.01 wt%, 0.04 wt%, 0.05 wt %, 0.1 wt¾, 0.2 wt¾, 0.4 wt%, for example,

[0044] Because highly water soluble salts and polymer flocculants that are preferably water soluble are used in the process of the present disclosure, the temperature of the treated cuttings need not be elevated above ambient temperature to practice the process. In certain embodiments, treating the drill cuttings can be carried out at ambient temperature, e.g., no more than about 2 °C to about 5 °C above ambient. In other embodiments, treating drill cuttings can be carried out at a temperature of no more than about 50 °C, e.g., no more than about 40 °C or 30 °C. Advantageously, the processes of the present disclosure can be practiced without addition of a significant amount of an alkali metal hydroxide salt(s), such as lithium, sodium or potassium hydroxide, e.g., less than 0.05 wt% or without any addition of such salts. Such strongly alkali salts tend to require elevated temperatures to be effective.

[0045] In practicing aspects of the present disclosure, solids in drill cuttings can be consolidated by treating the drill cuttings with at least one highly water soluble salt or aqueous solutions thereof which can optionally include at least one polymer flocculant. Treating cuttings in this manner can cause destabilization and consolidation of the solids to form a consolidated material, which can settle under gravity relatively quickly in the drilling fluid. The drilling fluid can then be readily separated from the consolidated material.

[0046] The treated cuttings and/or consolidated material can be further dewatered to further separate the water from the consolidated material and, in some instances, further consolidate the solids. In some embodiments, the consolidated material formed in the treated cuttings can be separated from the drilling fluid by any one or more of decanting, filtering, e.g., eleetrofiltering, cross-flow filtering, gravity draining, vacuuming and other evaporating techniques, etc. or combinations thereof and/or by any one or more of a mechanical dewatering, i .e., applying an external force to the consolidated material, with a device for dewatering consolidated material such as by applying a centrifuge, decanting centrifuge, dewatering screw, hydrocyclone, filter press, pressing device, etc. or combinations thereof.

[0047] Only the preferred embodiment of the present invention and examples of its versatility are shown and described in the present disclosure. It is to be understood that the present invention is capable of use in various other combinations and environments and is capable of changes or modifications within the scope of the inventive concept as expressed herein. Thus, for example, those skilled in the art will recognize, or be able to ascertain, using no more than routine experimentation, numerous equivalents to the specific substances, procedures and arrangements described herein. Such equivalents are considered to be within the scope of this invention, and are covered by the following claims.

Claims

WHAT IS CLAIMED IS:

1. A process of consolidating drill cuttings which includes solids and drilling fluid, the process comprising:

treating the drill cuttings with at least one highly water soluble salt to form a treated cuttings including a consolidated material, and

separating the consolidated material from the drilling fluid.

2. A process of consolidating drill cuttings which includes solids and drilling fluid, the process comprising:

treating the drill cuttings with at least one highly water soluble salt and at least one polymer floccuient to form a treated cuttings including a consolidated material; and

separating the consolidated material the drilling fluid.

3. A process of consolidating drill cuttings which includes solids and drilling fluid, the process comprising:

treating the drill cuttings with at least one highly water soluble salt and coarse particles to form a treated cuttings including a consolidated material, and

separating the consolidated material the drilling fluid.

4. A process of consolidating drill cuttings which includes solids and drilling fluid, the process comprising:

treating the drill cuttings with at least one highly water soluble salt, at least one polymer floccuient and coarse particles to form a treated cuttings including a consolidated material; and separating the consolidated material the drilling fluid.

5. The process of any one of claims 1-4, wherein the drill cuttings contains between about 10 wt% to about 50 wt% solids. ] 5

6. The process of any one of claims 1-5, wherein the cuttings further comprise hydrocarbon and the process further comprises treating the cuttings with a diluent to dilute the hydrocarbon and recovering the diluted hydrocarbon.

7. The process of claim 6, wherein the recovered diluted hydrocarbon directly obtained from the treated cuttings has less than I wt% of fines.

8. The process of any one of claims 1-7, wherein the at least one highly water soluble salt is a non-hydrolyzing salt.

9. The process of any one of claims 1-8, wherein the at least one highly water soluble salt has a solubility in water of greater than 10 g/100 g at 20 °C 0. The process of any one of claims 1-9, wherein the at least one highly water soluble salt has a monovalent cation.

1 1. The process of any one of claims 1-9, wherein the treated cuttings has a salt-cuttings concentration of the at least one highly water soluble salt of at least 0.5 wt%.

12. The process of any one of claims 1-10, wherein the at least one highly water soluble salt is an ammonium based salt.

13. The process of claim 12, wherein the ammonium based salt is selected from ammonium chloride, ammonium bromide, ammonium carbonate, ammonium bicarbonate, ammonium nitrate, or ammonium sulfate, ammonium phosphate, or a combination thereof.

14. The process of any one of claims 2 or 4-13, wherein the at least one polymer flocculent is a polyacrylamide or co-polymer thereof.

15. The process of any one of claims 2 or 4-14, wherein the treated cuttings have a polymer- cuttings concentration of the at least one polymer flocculent of no less than about 0.04 wt%.

16. The process of any one of claims 3-15, wherein the cuttings are treated with sand,

17. The process of any one of claims 1-16, wherein the consolidated material has a solids content of at least 45% by weight.

18. The process of any one of claims 1-17, wherein the drill cuttings includes a water-based drilling fluid and the process further comprises recovering at least a portion of the water-based drilling fluid.

19. The process of claim 18, further comprising recycling at least a portion of the recovered separated water based drilling fluid to treat additional drill cuttings.

20. The process of any one of claims 1-17, wherein the drill cuttings includes an oil-based drilling fluid and the process further comprises recovering at least a portion of the oil-based drilling fluid.

21. The process of any one of claims 1-20, wherein the drill cuttings are treated at ambient temperature

22. The consolidated material obtained from any one of claims 1-21.