WO1999010068A1

WO1999010068A1 - A process and composition for removing fine solid particles from non-aqueous drilling mud

Info

Publication number: WO1999010068A1
Application number: PCT/US1998/014470
Authority: WO
Inventors: Wangqi Hou; Jayaprakash Soma; Kym B. Arcuri
Original assignee: Delta Omega Technologies, Ltd.
Priority date: 1997-08-23
Filing date: 1998-07-15
Publication date: 1999-03-04
Also published as: CO5031279A1

Abstract

The invention relates to a process for removing fine solid particulate matter from an oil based used drilling mud and a composition of matter therefor. The process involves mixing of the used drilling mud with a treatment agent containing a mixture of glycol ether and glycol mono-ester. The treatment agent also contains an aqueous bisulfite solution and a pH-modifying substance to adjust the pH level between 8 and 10. To improve viscosity of the mixture, a discrete amount of fresh base fluid is added at a ratio of between 1 to 30 in relation to the used drilling mud being treated. The mixture is exposed to elevated temperatures and then transferred to a separation device, such as a centrifuge, to cause separation of fine solids from the remainder of the mixture. The process can also be employed for a removal of excessive amount of emulsified water from drilling mud base fluid. The treatment agent for the water removal process contains a mixture of glycol ether and glycol mono-ester.

Description

A PROCESS OF REMOVING FINE SOLID PARTICLES FROM NON- AQUEOUS DRILLING MUD AND A COMPOSITION OF MATTER

THEREFOR

BACKGROUND OF THE INVENTION

The present invention relates to a well exploration industry, and more particularly, to a process for removing fine solid particles from non-aqueous based drilling fluids for subsequent recycling of an oil based drilling mud. Various drilling mud compositions are used during the process of well exploration to facilitate drilling process. Generally, the drilling muds are designed to perform several functions in a well drilling operation. One of the functions is lubrication of the drill bit to minimize energy consumption and preserve the useful life of the drilling equipment. Another important function is provision of the necessary head pressure to prevent escape of subsurface liquids form the bore hole. A portion of the drilling mud remains in the formation forming a wall filter cake along the bore hole while preventing liquid from the surrounding formation from seeping into and out of the well bore. The formed filter cake facilitates mechanical stability of the drilled well bore. Conventionally, the drilling muds are made up of a mgh density clay materials, low density clay materials, a suspending liquid, which can be water or oil, and other additives to prevent settling of the solids in the drilling mud mixture. The solids typically include a high density material, which can be mineral, for example, barium sulfate, and fine solid clay materials. Asphalt is sometimes added to the mud compound as a finely dispersed powder. Dissolved salts such as calcium carbonate, are often present in a typical drilling mud composition, usually forming a part of an emulsified water in the oil.

The non-aqueous liquid or oil based fluids that are used conventionally in the field include diesel, mineral or synthetic oils. In some cases, an ester compound or other polar hydrocarbon may also be included in the base fluid. The drilling muds are also classified by density, one of the more widely used has a density 10-18 pounds per gallon. A low density clay material comprises approximately 5% of the drilling mud volume, and the amount of high density solids, typically barite, can be 5-20% by volume. In addition to solids, drilling muds contain liquid materials which constitute 70% to 90% by volume of the drilling mud composition. The liquid materials consist of oil and emulsified aqueous phase, or water. The emulsified aqueous phase contains dissolved salts. There are also trace amounts of additives which can be asphalt, viscosity modifiers, emulsifiers and other agents added based on the particular drilling formation. The suspended low density particles and emulsified water preferably contribute to the necessary Theological properties to the drilling mud mixture to keep the heavy solids suspended while maintaining an appropriate yield point and gel properties. Further, the drilling mud must possess the necessary Theological properties; the drilling mud must possess the desired lubrication properties for cooling the drill, performing its function of sweeping the drill cuttings out of the bore hole to the surface, while the drilling mud is recirculated.

In use, the composition of the drilling mud changes as it performs its vital function in drilling applications. The amount of fine solids present in the base fluid increases due to the preferential loss of the oil base through the walls of the bore hole. Additionally, the mud may accumulate additional fines and/or water from the subsurface environment. Continued reuse of the mud in drilling applications eventually leads to unacceptable changes in the solids, water, base fluid, and other constituents.

Once used, the drilling mud cannot be freely disposed back into the environment due to its highly contaminated nature. Conventional disposal methods include landfilling under the appropriate environmental regulations.

Used drilling mud contains a higher solids to liquid mass ratio compared to the feed mud originally used in the beginning of the process. Once the drilling mud achieves an undesirable liquid to solids ratio, it cannot be recycled back into the bore hole without first undergoing a treatment for removing the solids. Typically, a low speed centrifuge, operating at 600-1600 rpm, is used to remove high density solids. The mud is then processed through a high speed centrifuge, operating at 1500-3200 rpm, to remove fine solids. The liquid effluent from the high speed centrifuge is used as the base fluid for preparing fresh feed mud. Eventually, the efficiency of the centrifuge removal process decreases, as the amount of fine particles increases in the base fluid. In that case, various chemical additives are used to restore the Theological properties of the mud and achieve the desired viscosity. However, the addition of the chemical additives is not a perfect solution. The additives are costly and produce undesirable effects if used in high concentrations.

For example, it is sometimes necessary to increase the levels of emulsifying agents to values beyond those typically used in order to offset the impact of excessive levels of fine solids and/or other deviations in the mud composition which affect the desired performance properties. Eventually the high concentrations of emulsifying agent can lead to excessive levels in the amount of emulsified water in the base fluid and the base fluid can no longer be used.

Sometimes, it becomes necessary to dilute the spent drilling mud, after processing it with the centrifuge, with a fresh base fluid. Typically, this step is performed if there are excessive amounts of fine solids after treatment through the high speed centrifuge. Still, this approach has certain drawbacks, as the increased amount of drilling mud should be disposed of in an environmentally safe manner, either through the use in a field or in separation treatment. The high disposal and transportation costs of large quantities of drilling mud reduce the desirability of this approach. Another solution to the treatment of drilling mud containing high concentration of fine solids is to vaporize the base fluid and recover the base fluid oil after condensing the vapor. This approach also has certain disadvantages since the base fluid undergoes chemical changes during the thermal process such as dehydrogenation. Thermal treatment causes cracking, formation of aromatics and other undesirable ringed structures. The increase in the olefin or aromatic content leads to unacceptable decrease in the aniline point which leads to an increase in the dissolution of the asphalt. The increased dissolution of the asphalt leads to a loss in mud performance properties. Poor mud performance properties are encountered when the base fluid contains dissolved asphalt. Various solutions have been offered to the process of fine solids removal from crude petroleum and other petroleum derived products. One of the solutions is suggested in U.S. Patent No. 5,447,638 disclosing a method of flocculating finely divided solid particles which are suspended in non-polar liquids. According to that patent, the flocculates are selected from the group consisting of chemical agents containing cationic quaternary amine functional group, used alone or in combination with sulfates and phosphate esters. Alkylimidazolines are also used. Reference is made to the broad based applications which involve the use of non- polar or surfactant agents to promote the dispersion of the active compound into the non-polar dispersing agents as well as surfactants to aid in the effectiveness of the flocculate. No reference is made to drilling muds.

U.S. Patent No. 4,466,885 discloses a method of removing solids and water from petroleum crudes. According to that patent, an alkalizing agent, such as caustic soda, is added to adjust the pH level to at least 8, after which a destabilizing agent and a coagulating agent are added to break the emulsion in the crude oil. The preferred coagulation agent is filter alum. Destabilizing agents, such as ammonium bisulfite, sodium bisulfide or sodium hydrosulfite are added for destabilizing the oil/water emulsion.

Another solution is offered in U.S. Patent No. 4,539,100 disclosing a method of removing solid particles and water from petroleum crudes using a demulsifier which comprises an anionic surfactant that is soluble in oil, a nonionic surfactant insoluble in water and dispersible in oil, as well as a cationic surfactant that is soluble in water. This patent discloses the fact that many conventional agents used to remove solids are not effective for use with crude petroleum. Additionally, an inorganic additive capable of acting directly on inorganic sulfur present in the petroleum crude is incorporated into the treatment compound. This additive can be alkali metal, alkaline earth metal and ammonium monosulfides and hydrosulfides and agents, typically, ammonium bisulfite and the hydrosulfites of alkali metals and alkaline earth metals that are capable of reacting in the petroleum crude present to form monosulfides and/or hydrosulfides. U.S. patent 4,466,885 discloses the use of ethylene glycol distearate as the non-ionic surfactant to use in the process of removing fine solids from petroleum crudes. Example 1 in U.S. Patent No. 4,466,885 specifically references the use of EMEREST 2355, a non-ionic surfactant consisting of an entylene glycol distearate (manufactured by Emery Industries Ltd., Toronto, Ontario, Canada). The patent claims the use of non-ionic surfactants, such as ethylene glycol distearate, which consists of di-ester functionality in the compound. The patent does not claim the use of a glycol ester, which has a mono-ester functionality. The technology in U.S. Patent No. 4,466,885 focuses on removing both the water and solids contained within petroleum (non-polar) liquids by breaking the water in oil emulsion. This is not a desired objective for the purposes of the present invention since drilling mud base fluids must maintain some emulsified water in oil in order to possess the desired performance application in drilling applications.

While the above patents concentrate on removal of fine particles from crude oil and non-polar liquids, few of them can be successfully implemented in the treatment of drilling muds. Typically, the efforts for treatment of the residual drilling mud involve removal of water by using flocculating agents and then mechanically separating the solids.

One of such methods is described in U.S. Patent No. 4,174,278. European Patent Application No. 85201411.7 discloses a method of using coagulants or flocculants in removal of fine solids from drilling base fluids. No reference is made to the use of bisulfate or surfactants for preferentially removing fine solids from drilling base fluids. The patent essentially extends the technology base of using anionic and cationic agents in drilling muds. The present invention contemplates elimination of drawbacks associated with the prior art and provision of a method for removing fine particulate matter from oil based drilling muds, base fluids and a composition of matter therefor.

SUMMARY OF THE INVENTION It is, therefore, an object of the present invention to provide a process of removing fine solid particles from an oil based drilling mud.

It is another object of the present invention to provide a process for separating fine solid particles from the remainder of the drilling mud composition for a subsequent recycling of the recovered fluids in drilling applications. It is a further object of the present invention to provide a process for separating fine particles from liquid components for subsequent recovery and recycling. It is still a further object of the present invention to provide a composition of matter suitable for use as an effective treatment agent in separating fine particulate matter from base fluids of the drilling muds.

It is a further object of the present invention to provide a process and a composition of matter for removal of undesirable amounts of emulsified water from the base fluid to facilitate restoration of the desired Theological properties for drilling operations.

These and other objects of the present invention are achieved through a provision of a process for removing fine solid particulate matter from an oil based drilling mud. The process comprises the steps of loading used drilling mud containing fine solids into a treatment container, such as a mixing tank. A treatment agent comprising a mixture of glycol ether and glycol mono- ester are added into the treatment container in the amount of 0.2% to 0.9% by volume. The preferred amount is 0.4%-o.6% by volume. Additionally, the treatment agent may comprise a discrete amount of an aqueous sulfite or bisulfite solution and a pH-modifying substance added in the amount sufficient to cause adjustment in the pH level to about 8-10.

When it is desirable to remove the excessive amounts of emulsified water, a treatment agent comprised of a mixture of the glycol ether and glycol mono-ester is added to the treatment container. The aqueous sulfite and/or bisulfite solution and a pH modifying substance can be added, as an optional mixture, when required.

In order to improve viscosity of the drilling mud and the treatment agent mixture, fresh base drilling mud fluid can be added into the mixing tank. The mixture of the used base drilling fluid and the treatment agent is allowed to remain in the mixing tank in order to cause an intimate mixture of the loaded ingredients. The mixture is then exposed to elevated temperatures, for example by passing through a heat exchanger, in order to reduce the viscosity of the mixture. The heated mixture is then transferred to a separation device, for example, a high speed centrifuge, wherein the mixture is processed in order to cause separation, by gravity, of fine solids from the remainder of the mixture. The fine solids are removed from the solids discharge port of the centrifuge, while the remainder of the mixture is reused as a base fluid in preparing new drilling muds. Should an usually high amount of fine solids be present in the used drilling mud, the mixture can be recycled through the mixing tanks, heating step and the centrifuge one or more times in order to bring the amount of fine solids to an acceptable level. In the preferred embodiment, the mixture of the drilling mud and the treatment agent contains about 0.4% -0.6% by volume of the treatment agent. In the preferred embodiment, the mixture is heated to about 150°F and 250°F, the preferred temperature being 180°F - 220°F. In the preferred embodiment, the mass ratio of glycol ether to glycol ester is 0.66 to 3. The aqueous sulfite and/or bisulfite solution is added using any accompanying cation, such as ammonium, sodium, potassium and other cations. The amount of sulfite and/or bisulfite to be added to the base fluid is between 1,000 and 20,000 parts per million based on weight of bisulfite. In the preferred embodiment, the sulfite and/or bisulfite level is between 10,000 and 15,000 ppm. A pH modifying substance, for example sodium hydroxide, is added in the preferred embodiment in the amount of 0.003 to 0.02 weight units per unit weight of the used drilling mud treated.

The process of the present invention and the treatment agent for use therein is particularly adapted for the removal of fine solid particulate matter from oil based drilling mud base fluid, as well as for reducing excessive amounts of emulsified water in the base fluid. BRIEF DESCRIPTION OF THE DRAWINGS

Reference will now be made to the drawings, wherein like parts are designated by like numerals, and wherein Figure 1 is a schematic flow chart of the process of separating fine solid particles from used oil based drilling mud.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT Turning now to the drawing in more detail, numeral 10 designates a system for removing solid particles and excess water from non-aqueous drilling mud based fluids. The system comprises a mixing tank 12, a heat exchanger 14 and a centrifuge 16 connected by suitable pipelines. The system is employed in the process of removing fine particulate matter from base fluids composed of diesel, mineral, or synthetic oils. The process starts with depositing used based fluid to be treated into a mixing tank 12. If necessary, high density solids can be removed by using centrifuges prior to depositing the base fluid into the mixing tank 12.

Since fine particulate matter is usually composed of particles about 4 microns or less in size, effective removal of these solids cannot be accomplished by conventional means using high speed centrifuges. Therefore, the used oil based drilling mud fluid that contains excessive levels of fine solids (typically >5 volume %) needs to be treated by a different method, to which the instant invention is directed.

To decrease the viscosity of the fluid and improve the total amount of fine solids removed under this invention, fresh base fluid is optionally added to the mixing tank 12. The addition of the fresh base fluid is designed to facilitate the solids separation process. The amount of fresh base fluid that needs to be added will greatly depend on the contents of the used base fluid, this amount increasing depending on the liquid losses associated with the recirculation of the drilling mud through the wellbore and the amount of fine solids which are to be removed in a single pass through the treatment process described under this invention. In cases where it is necessary to make up for fluid losses during recirculation of the drilling mud in the wellbore, the addition of fresh base fluid should correspond in this value. For example, if the fluid loss in the base fluid is as high as 13% by volume, the fresh base fluid can be added at a flow rate up to about 4 barrels/hour, assuming that the incoming rate of the base fluid is approximately 30 barrels/hour. The ratio of the fresh base fluid to the used base fluid within the preferred embodiment can be 1 to 30, respectively. The addition of fresh base fluid to the treatment process can be less than the volume corresponding to wellbore losses.

A treatment agent in accordance with the present invention comprises a mixture of glycol ether and glycol mono-ester with a sulfite and/or bisulfite solution, as well as a caustic solution. The mixture of glycol ether and glycol mono-ester is added at a rate of 5.4 gallons per hour which is believed to be an optimum rate of addition given the above rates of flow of the used base fluid.

Glycol ether comprises ethyl, propyl and butyl alkyl groups. Alternatively, propylene and butene groups can be incorporated in the glycol ether. The glycol mono-ester used as a part of the treatment agent in the present invention can be a glycol ester manufactured by Witco Corporation of Greenwich, Connecticut sold under the tradenames WITBREAK DGE-128A and DGE-169. Witbreak DGE- 128A and 169 are oxyalkylated glycol esters used as non ionic surfactants, usually to break the water-in-oil emulsion; these compounds also contain a petroleum solvent, naphthalene and 1, 2-propanediol or 1, 2, 3-propanetriol. The glycol mixture comprises between 40-80% of the glycol ether and between 20- 60% of glycol mono-ester, and the treatment agent containing glycol ether and glycol mono-ester is added in die amount of between about 0.2% to 0.9% by volume, preferably 0.4%-0.6% by volume.

The ratio between the two main constituent materials of the treatment agent will depend on the structure of the base fluid treated in the system of the present invention. In the preferred embodiment, the mixture contains 66% by total weight of dipropylene glycol n-butyl ether and 34% by total weight of glycol mono-ester. It is preferred that the ether to ester mass ratio be in the range of 0.66 to 3. The preferred ether to ester mass ratio is 1 to 2.

If the used base fluid treated in the system of the present invention contains a relatively large amount of water, for example 15% by volume, the ether/ester mass ratio should be approximately 1. However, if the amount of water is less than 15%, it is preferred that the ether/ester mass ratio be as high as 2.5 or 3. The amount of the glycol ether and glycol ester treatment agent used in the present invention is preferred to be between 0.001 to 0.01 volume units per volume unit of used base fluid added into the mixing tank 12. The preferred volume ratio is 0.003 to 0.006. The solids removal efficiency as measured by volume of solids removed per volume of the glycol mixture added decreases at the higher usage rates.

A bisulfite solution is added into the mixing tank at an approximate rate of 72 gallons per hour (based on a used base fluid flow rate of 30 bbl hr) or at other suitable rate, depending on the flow rate of the base fluid. It is preferred that the sulfite and/or bisulfite solution be an aqueous 40% by total weight solution of sodium bisulfite. Preferably, the amount of bisulfite ranges between 1,000 ppm and 20,000 ppm, depending on the molecular weight of bisulfite. The optimum treatment level, with the flow rates of base fluid of 30 barrels per hour should be between 10,000 and 15,000 ppm.

Additionally, a caustic compound, for example sodium hydroxide is added to the tank 12 in order to adjust the pH of the mixture and bring it to the level of 8- 10. In a typical oil based mud treatment process, the amount of the alkalizing agent is in the range of 0.003 - 0.02 weight units per unit weight of the base fluid mud undergoing treatment in the system 10. With a flow rate of 30 barrels per hour of used base fluid, the caustic agent can be added at a rate of 6 gallons per hour. It is preferred to use a 50% by weight solution of sodium hydroxide, although the strength of this ingredient can vary, between 20 - 70% by total weight, depending upon the original flow rate.

The fluid drilling mud is thoroughly mixed with die treatment agent, the mixture of glycol ester and glycol ether, bisulfite solution and a caustic agent to cause an intimate contact of the drilling mud with the treatment chemicals and the fresh base fluid. It is preferred that the mixing be allowed to take place for at least fifteen minutes after all the ingredients are placed in the tank 12. The temperature of fluid in the mixing tank can be an ambient temperature or it can be elevated up to 250°F to increase effectiveness of the process, although preferred embodiment provides for heating up to 180°F -220°F.

After the mixture of the base fluid and the treatment agent is allowed to mix in the tank 12, it is transferred through a pipeline 18 to the high speed centrifuge 16. On its way, the mixture passes through a heat exchanger which can be any conventional systems suitable for heating viscous fluids. For example, an insulated pipe heated with electric or fossil fuel burner can be employed, utilizing hot oil or a glycol-water mixture. In an alternative embodiment, a steam boiler can be used as a source of thermal energy for the heat exchanger 14.

The temperature of the effluent from the heat exchanger is carefully monitored to make sure that the desirable properties of the treatment chemicals, as well as the base fluid are not destroyed during heating. While glycol, by itself, is not a volatile compound, it is still combustible and great care should be exercised in controlling the temperature of the fluid moving between the mixing tank to the centrifuge through the heat exchanger. The temperature of heating is important since it prevents decomposition or denaturing of the constituent components of the mixture, while allowing the fine solids to remain in the suspended state in the liquid which facilitates separation of the fine particulate matter from the liquid ingredients. Preferably the mixture is heated to between about 180°F to 220°F. It is preferred that the heated mixture is not allowed to cool to any substantial degree before it reaches the centrifuge 16, wherein the mixture of the base fluid and the treatment chemical agent is processed at high speed, for example up to 3200 rpm, causing separation of fine solids from the remainder of the base fluid. The separated solids are removed by gravity, from the bottom of the centrifuge 18, at a rate of 2-7 barrels per hour (based on 30 bbl/hr feed rate). The remainder of (or remaining) fresh base fluid is removed from the centrifuge 16 at a rate of 20-38 barrels per hour and can be used as the base for fresh drilling mud. In certain cases, where the used base fluid has an unusually high percentage of fine solids and the desired degree of solids reduction is more than 60% of the initial solids content, for example more than 15% by total weight, it is suggested that the used base fluid be recycled through a pipeline 20 back into the mixing tank 12 for a second cycle of treatment. After the treatment, the treated base fluid is removed through the conduit 22 from the centrifuge 16, with the fine solid particle content being reduced to the desired level with one or more passes through the treatment process.

The present invention is described herein as using glycol ester/glycol ether mixture. However, other mixtures of organic compounds, in which an oxygen atom is interposed between two carbon atoms can serve as a substitution of the glycol ether.

The process of the present invention allows to treat used drilling mud base fluid and receive a relatively high output of substantially solids-free base drilling mud fluid. In order to further facilitate the removal of fine solids, used base fluids, prior to loading into the mixing tank, can be pre-treated to remove larger solid particles, using low-speed centrifuges, vibrating screens and other means available in the industry. It is envisioned, that in such a case the amount of fine solids remaining in the used base fluid can be further minimized.

Under certain conditions, it is highly desirable to reduce the amount of emulsified water that forms a part of the oil base. Such conditions can be caused by a prolonged re-use of the drilling mud base fluid and additions of emulsifying agents necessarily introduced to maintain Theological properties of the drilling muds. Eventually, the drilling mud reused over a number of times will contain excessive amounts of water. This water adversely affects the functionality of the base fluid and must be reduced to an appropriate level to restore the usable properties of the base fluid.

When removal of the excessive amounts of water becomes an object, a mixture of glycol ether and glycol mono-ester is added to the treatment vessel 12. The sulfite/bisulfite solution or pH modifying substance are not required for this process. The mixture of the base fluid and the treatment agent comprised of glycol ether and glycol mono-ester contains between 0.2% to 0.9% by volume to the treatment agent. The preferred amount is 0.4%-0.6% by volume. The drilling mud and the treatment agent are allowed to remain in the mixing vessel for a minimum of fifteen minutes or for such time as to allow an intimate mixing of the base fluid with the treatment agent. The mixture is then transferred to a heat exchanger 14, where it is heated to between 160°F and 180°F. The heated mixture is then processed in a high speed centrifuge 16 in order to separate the undesirable amounts of water from the base fluid. The amount of emulsified water is reduced from 30% by volume to 10% or less.

In some cases the amount of 15% by volume of emulsified water is considered excessive, and the drilling mud will be processed in the system 10 of the present invention according to the method described above.

Many changes and modifications can be made in the system of the present invention without departing from the spirit thereof. We, therefore, pray that our rights to the present invention be limited only by the scope of the appended claims.

Claims

We claim:

1. A process for removing fine solid particulate matter from a non-aqueous used drilling mud, comprising the steps of: loading used drilling mud containing fine solids into a treatment container; loading a treatment agent comprising glycol ether and glycol mono-ester into the treatment container and retaining the drilling mud and the treatment agent in the treatment container for a time sufficient to form an intimate mixture of the drilling mud and die treatment agent; heating the mixture to reduce viscosity of the mixture; and transferring the heated mixture to a separation device to cause separation of fine solids from the mixture.

2. The process of Claim 1, wherein said treatment agent is added in the amount of between 0.2% to 0.9% by volume.

3. The process of Claim 1, wherein said treatment agent is added in the amount of 0.4%-0.6% by volume.

4. The process of Claim 1, wherein the treatment agent further comprises a bisulfite solution and a pH-modifying substance.

5. The process of Claim 4, wherein the pH-modifying substance is added to adjust the pH level to between 8 and 10.

6. The process of Claim 1, wherein the mixture is heated to between 150┬░F and 250┬░F.

7. The process of Claim 1, wherein the glycol ether and glycol mono-ester are added as a premixed compound comprising between about 40% to 80% by total weight of glycol ether and between about 20% to 60% by total weight of glycol mono-ester.

8. The process of Claim 7, wherein a mass ratio of glycol ether to glycol ester is 0.66 to 3.

9. The process of Claim 4, wherein said bisulfite solution is an aqueous solution of bisulfite having a positively charged ion in a molecular structure thereof.

10. The process of Claim 9, wherein said bisulfite solution comprises between 1,000 and 20,000 parts per million of bisulfite weight units.

11. The process of Claim 1, wherein said treatment agent further comprises a sulfite solution having between 1,000 and 20,000 parts per million of sulfite base units.

12. The process of Claim 5, wherein the pH-modifying substance is a caustic compound added in the amount of between about 0.003 to 0.02 weight units per unit weight of the drilling mud loaded in the treatment vessel.

13. The process of Claim 1, wherein said separation device is a centrifuge.

14. The process of Claim 1, further comprising a step of adding a fresh base drilling mud fluid to the treatment vessel to decrease viscosity of the mixture.

15. The process of Claim 14, wherein a ratio of the fresh based drilling mud fluid added to the used drilling mud is at least 1 to 30.

16. The process of Claim 1, wherein the used drilling mud is processed until the fine solids content is reduced to less than 5 volume %.

17. A process of separating fine solid particulate matter from an oil-based used drilling mud, comprising the steps of: loading used drilling mud containing fine solids into a treatment container; loading a treatment agent comprising glycol ether, glycol ester, an aqueous solution of bisulfite, and a pH-modifying substance into the treatment container; allowing the treatment agent to form an intimate mixture with the drilling mud; exposing the mixture to elevated temperatures of between 180┬░F to 220┬░F; and transferring the heated mixture to a separation device to cause separation of fine solids from the mixture to a level of 5% by total weight of base fluid.

18. The process of Claim 17, wherein the pH modifying substance is added to adjust the pH level to between 8 and 10.

19. The process of Claim 17, wherein the glycol ether and the glycol mono- ester are added as a premixed compound with a mass ratio of glycol ether to glycol mono-ester between 0.66 to 3.

20. The process of Claim 17, wherein the pH-modifying substance is sodium hydroxide added in the amount of between about 0.003 to 0.02 weight units per unit weight of the drilling mud loaded into the treatment vessel.

21. The process of Claim 17, wherein said bisulfite solution comprises between 1000 and 20,000 parts per million of bisulfite weight units.

22. The process of Claim 17, further comprising a step of removing separated fine solids from the separation device and transferring a substantially solid-free mixture for recycling as a fresh base drilling mud fluid.

23. A composition for use as an effective treatment agent for separation of fine particulate matter from used oil based drilling mud, comprising a mixture of glycol mono-ester, glycol ether, an aqueous bisulfite solution and a pH-modifying substance.

24. The composition of Claim 23, wherein a mass ratio of glycol ether to glycol mono-ester is about 0.66 to 3.

25. The composition of Claim 23, wherein pH-modifying substance is present in an amount sufficient to adjust the pH value to about 8 to 10.

26. The composition of Claim 23, wherein said bisulfite solution comprises between 1000 and 20,000 parts per million of bisulfite weight units.

27. A process of removing excessive amounts of emulsified water from used drilling mud, comprising the steps of: loading used drilling mud containing an excessive amount of emulsified water into a treatment container; loading a treatment agent comprising glycol ether and glycol mono-ester into the treatment container and retaining drilling mud and the treatment agent mixture in the treatment container for a time sufficient to form an intimate mixture of the drilling mud and the treatment agent; heating the mixture to reduce viscosity of the mixture; and transferring the heated mixture to a separator device to cause separation of solids and emulsified water to bring the amount of emulsified water to less than 10% by volume.

28. The process of Claim 27, wherein the treatment agent is added in the amount of between about 0.2% and 0.9% by volume.

29. The process of Claim 27, wherein the treatment agent is added in the amount of 0.4%-0.6% by volume.

30. The process of Claim 27, wherein die mixture is heated to between 180┬░F and 220┬░F.