CA1210928A

CA1210928A - Process for removing contaminates from a well fluid and well system

Info

Publication number: CA1210928A
Application number: CA000432910A
Authority: CA
Inventors: Arnold M. Singer; John E. Oliver, Jr.
Original assignee: Individual
Current assignee: Individual
Priority date: 1982-09-20
Filing date: 1983-07-21
Publication date: 1986-09-09
Also published as: ES535576A0; DK425283A; MX162741A; NO832978L; ES525710A0; GB2127394B; ES8603354A1; NO170102C; GB2127394A; DK425283D0; GB8323084D0; NO170102B; ES8502757A1

Abstract

ABSTRACT

An improved process for removing solid contaminates from a high density, salt-type aqueous drilling/completion packer fluid prior to its introduction into the well bore and for removing contaminates such as drilling mud and fluids from the well system prior to the introduction of brine to maintain the brine in a solids free state. To remove the solid contaminants, small effective amount of an alcohol and a surfactant are added to the brine. After the solid contaminates agglomerate, the solids are separated, leaving the brine in a substantially solids-free state.
To remove the contaminates from the well system, treated water is prepared with a surfactant and alcohol admixed in clean water. Without interrupting circulation, the treated water displaces the fluids and drilling mud within the well system. Circulation of the treated water continues until substantially all of the contaminates are carried in the circulated treated water.
The treated water may be preceded or followed by another fluid which assists in removing the contaminates. The solids-free brine is introduced into the well system to displace the treated water without exposure to the contaminates.

Description

BACKGROUND OF THE INVENTION

Field of the Invention The invention relates to the use of high density brines in wellbores, and it more particularly relates to the removal of contamina~es from a well system and from a high density brine prior to use of the brine in the well system.

Descri tion of the Prior Art P
Well fluids such as aqueous brine solutions of high density are used in well systems employed in the production of petroleum. The term well fluid as used herein, is intended to designate liquids which are water continuous and which liquids may contain fresh water, sea water, or brine and varying in amounts of dissolved solutes such as salts, corrosion inhibitors and gases.
These solutions have been used as both drilling, completion and packer fluids especially in deep wells subject to high formation gas pressures at elevated temperatures. These fluids can be formed of the sodium, calcium, zinc salts with chloride, bromide and potassium.
These aqueous fluids may include corrosion inhibitors and other salts such as soda ash. The density of these salt type well fluids depends on the particular salt, or mixture of salts, and their concentration in the aqueous well fluid. Usually, these salt type well fluids have a density in the range of between about 8 and 19 pounds per gallon.
The salt type well fluid should be solids-free in its use as a well fluid. If there are solids in a packer or completion fluid, they can cause serious injury to a producing formation by plugging cf the pore spaces therein or even of the perforations and channels provided to induce fluid flows between the formation and well 1~ 9'~3 bore. If there are solids in a packer fluid, the solids will precipitate with time upon the packer. As a result, these solid deposits make it difficult to disconnect the tubing from the packer with a resultant costly well workover.
The high density brine can be prepared at the wellsite by dissolving the prescribed amount of salt into the aqueous phase, which phase is principally fresh or sea water but it can include various inhibitors for preventing pitting, corrosion, etc. The mixture is circulated or agitated in the surface mud system equipment until there are no undissolved salt solids.
Naturally, the problems of adding salts to be dissolved in the aqueous well fluid became progressively more severe as the densi~y increases, both in time, manpower and equipment requirements.
At present, vendors will deliver to the wellsite the prepared high density brine of a desired density and com-bination of selected ingredients. It is desired that these well fluids are clean and free of solids. The delivery of brine usually requires several changes in containers. For example, the brine is moved from the vendor ~anks to the truck transport, offshore supply boat and into the rig mud system~ In most circumstances, the brine becomes contaminated by undesired solids, including residual water wetted solids and/or oil based drilling mud t weighting agents such as barite, rust, salt, silt and sand, ferrous and ferric precipitives, and other undissolved materials. Contaminating liquids such as mud bases, lubricants and diesel fuel can also be present in the mud system and become entrained in the brine.
Usually, these contaminating liquids are occluded or absorbed on the undissolved solids.
If the amount of solids in the brine were small in amount, the rig equipment may be used for their removal 9~

usually in a stepwise flow pattern through cartridge filters. However, the costs of manpower and rig time in filtering the brine is e~tremely expensive (e. g., $100,000 per each work shift) unless the solids are (1) less than .01% by weight of the well fluid, (2) granular, and (3) not gelatinous as is usually the case with HEC, polymer or bentonite mud contamination.
Contamination of brine by drilling mud components is most common since the brine is usually handled at the rigs in parts of the mud system. The mud system usually suffers contamination during washing of the cased well bore to remove residual mud and cement solids immediately prior to the introduction of the high density salt-type completion/packer brines. Only a small amount of the wash liquid needs to be combined with the brine so that its solids content becomes excessive. Then, the brine must be treated to remove these solids. Any residual solids must be less than 5 microns in maximum dimension otherwise they cause formation plugging.
As mentioned, the use of cartridge, leaf or bed type filters is impractical on other than very low solid contents in the brine. Further, rig time in equipment and manpower is restricted and available only for critical operations, namely optimum drilling of the well bore. As a result, brines with large solids contamina-tion must be either discarded or returned to some facility for purification. Since the brine is very expensive (e.g., $300-$900 per barrel) it cannot be dis-carded. Furthermore, the brines must be carefully handled so as not to be spilled or wasted because environment injury occurs from strong aqueous brines.
It has also been a practice to clean the rig's mud system of residual drilling mud prior to the introduction of the brine, by various washing and manual clean-up techniques in an attempt to reduce the degree of g;~8 filtration required. For example, offshore rigs use jet streams of sea water and crewpersons with scrapers, brooms, etc. to attempt to remo~e residual drilling mud constituents. This technique for cleaning thoroughly the rig's mud system is very hazardous (slippery, wet, caustic and cramped work areas) and burdensomely expen-sive in labor costs. In addition, the cleaned mud system yet has residual drilling mud which hides in crevices, - but that is entrained in the high density brine which passes therethrough. During the cleaning of the mud systemr the rig must be shut down for between 5 and 13 hours on the average. The costs of cleaning ranges from about $3000 to $8000 per hour. Thus, avoiding this cleaning procedure would save rig down time in the amount of $40,000.
As a practical result, present day rig practices, especially offshore, require full stream filtration (usually in cartridge filters) of the brine so that solid levels less than 0.2% or less are desired immediately before the brine is sent into the well bore.
Even though the brine can be made solids-free at the rig, it is also necessary to clean the well system of drilling fluid, mud solids or other contaminates, before introduction of the brine into it so as to maintain the brine in a solids-free state during use, as hereinabove discussed. One of the main problem areas in removing drilling fluid and mud is from the wellbore equipment which includes the tubing or well pipe and the annulus between it and the casing or surrounding wellbore.
Many chemical washes have been proposed and used to remove drilling fluid and mud from the wellbore equipment prior to introduction of the solids-free brine. For example, circulating chemical washes using water with surfactants, viscosifiers and gel agents, chemical aids such as sodium tetraphosphate, weighting agents such as ~3f, `

1~ 92~3 barite have been used under turbulent flow conditions for achieving effective mud and fluid removal from the wellbore equipment. In some cases, the chemical washes are used as aqueous spacers for increased drilling fluid removal much in the same manner as used to displace drilling fluid prior to a cement slurry used in well cementing operations.
Usually, the chemical washes were designed for turbulent or laminar flow with aqueous phases of fresh and salt water continuous, and for plug flow using gelled water-based phases. The gelled water phase or plug was sufficiently viscous to attempt to reduce settling of drilling fluid from it, especially solids. If oil based drilling fluid was being displaced, diesel oil and an emulsifier are added to increase removal of the drilling fluid and its mud cake. Some chemical washes combined turbulent and plug flow aqueous phases to enhance the displacements of drilling fluid and mud from the wellbore equipment, especially prior to cementing operations or introduction of completion brine. These chemical washes were used, in some opera~ions, in a single pass travel through the wellbore equipment for removing the drilling fluid so as to save rig time.
A process has been developed for removing the contaminating solids from high density, salt-type (brine) aqueous drilling, completion and packer fluids before their placement into a well bore and for removing substantially all of the drilling fluids and mud, including solids such as barite, bentonite, cement, oil materials, as well as other contaminates from the well system prior to entry therein of the solids-fre~ comple-tion and packer brine to prevent recontamination of the brine. As a result, the brine remains substantially free of solids during use in the well system. The overall rig down time and brine cleanup time to practice the present 12~928 process is substantially reduced. Especially larger rig downtime savings are achieved in deep offshore wells with high angles of directional wellbores (e.g. 70 degrees).

SUMMARY OF THE INVENTION

The invention in a broad aspect pertains to a process for eliminating contaminates from a well system prior to introduction of solids-free completion and packer well fluids, the steps comprising displacing contaminates from the well system by circulating treated water therein to displace a major portion of the contaminates from the well system, and the treated water prepared by the addition of an effective amount of a surfactant and alcohol to clean water and subjecting the treated water to agitation and shear mixing, and following the treated water, circulating therein a solids-free well fluid for displacing or carrying the treated water from the well system.

The invention also comprehends a process for eliminating drilling mud fluid from a well system prior to introduction of solids-free completion and packer brines, the steps comprising displacing fluid from the well system by circulating therein in laminar flow at least one plug of aqueous spacer containing a viscosifier to produce a non-Newtonian fluid that is circulated in a gel state for displacing and carrying a major portion of fluid being displaced from the well system, circulating at turbulent flow conditions, a treated water through the well system to displace therefrom fluid from the well system, and the tre~ted water prepared as a Newtonian fluid from the addition of an effective amount of surfactant and alcohol to clean water and subjecting the treated water to agitation and shear mixing. The aqueous spacer plug passes with the treated water from the well system without substantial mixing of the aqueous spacer plug and treatecl water into the following solids-free brine circulated into the well system and solids-free brine is circulated into the well system.

A still further aspect of the invention comprehends a process for eliminating drilling mud fluid from a well system prior to introduction of solids-free completion and packer brines, the steps comprising displacing fluid from the well system by circulating therein in laminar flow a plug of an aqueous spacer containing a viscosifier to produce a non-Newtonian fluid that is circulated in a gel state for displacing and carrying a major portion of the drilling fluid from the well system, immediately following the aqueous spacer plug, circulating at turbulent flow conditions, a treated water through the well system to displace therefrom the aqueous spacer plug carrying drilling fluid with the treated water removing and carrying drilling fluid from the well system, and the treated water prepared as a Newtonian fluid from the addition of an effective amount of surfactant and alcohol to clean water and subjecting the treated water to agitation and shear mixing, immediately following the treated water, circulating therein in laminar flow a plug of an aqueous spacer containing a viscosifier to produce a non-Newtonian fluid that is circulated in a gel state for displacing or carrying the treated water from the well system, and displacing the aqueous spacer plug of the immediately preceding step from the well system by circulating therein of solids-free brine.

The invention still further comprehends a process for . .

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eliminat.ing drilling mud solids and oil from a well system prior to introduction of solids-free completion and packer brines, the steps comprising displacing drilling mud from the well system by circulation therein of clean water until a major po.rtion of the drilling mud is removed from the well system and carried in the clean water, preparing a treated water with the addition of an effective amount of surfactant and alcohol to clean water and subjecting the treated water to agitation and shear mixing in the surface equipment on the well system, circulating the treated water through both the surface equipment and the wellbore equipment of the well system to displace therefrom the clean water carrying drilling mud and circulating the treated water in the well system in which completion and packer brines are to be carried until substantially all of the drilling mud is suspended in the circulated treated water, displacing from the well system to a suitable disposal region, with solids-free clean water, the treated water carrying the drilling mud without interruption of circulation through the well system, and displacing the solids-free clean water from the previous step with solids-free completion and packer brine in the parts of the well system receiving the brine from a source exterior of the well system.

Still another aspect of the invention pertains to a process for producing a solids-free aqueous fluid contaminated with solids selected from the group consisting of rust, sand and drilling mud, the steps comprising (a) introducing in small effective amounts an aliphatic alcohol and a surface active l'Zl~g'~

chemical aid into the fluid, and (b) separating the agglomerated solids from the fluid before it is utilized in a solids free state, wherein the surface active chemical aid in step (a) includes a surfactant having a molecular weight in the range of about 150 to about 500 with predominant hydrophobic characteristics and the surfactant is selected from a group consisting of aliphatic amines, amides and aliphatic oxide constituents having an alkyl group with between 8 and 18 carbon atoms, and wherein the aliphatic alcohol in step (a) employs an aliphatic alcohol with between 5 and 8 carbon atoms. The process is not limited to mud pits or the like but is applicable wherever it is desired to produce solids free aqueous fluid contaminated with solids.
DESCRIPTION OF THE DRAWINGS
The Figure is~ a sch-ematic flow diagram illustrative of the drilling mud equipment on a well system which includes apparatus for preparing solids free brine prior to its introduction into a wellbore and for cireulating treated water through the well system prior to introduction of the brine.
DESCRIPTION OF THE PREFERRED EM~ODIMENT
Referring to the drawing, there is shown in sehematie a well system 11 which includes surface equipment 12 and wellbore equipment 13 forming a part of the drilling mud system which may be found on offshore oil-well rigs. Also, the well system 11 can include a filtration unit 14 which assists in removing solids so as to provide a high density brine in a low solids content, e.g. 0.2% or less by weight. The well system 11 can include other apparatus, or apparatus in a different arrangement and yet be used to practice the present improved process.
For example, the surface equipment can include mud pumps 16 to circulate drilling mud through the well bore equipment 13, and the circulating loop from this equipment can have a shale/desander/desilter shaker 17, a mud pit 18 with power driven mixers 19 and a suction mud pi~ ~1. The mud pit 18 and suction pit 21 can be conventional metal vessels such as used offshore.
The mud pit 18 may contain inlets 22, 23 and 24 for the addition of various well materials such as solids contaminated brine, chemicals and clean or sea water.
The terminology clean or sea water are meant to designate water that may be fresh or salty as from the ocean but with relatively low solids content, e.g., less than 200 p.p.m.
In usual practice, the surface equipment 12 will be used to receive the brine from a source, such as barge or marine vessel transport, and to treat the brine to a solids-free condition for placement into the wellbore equipment 13.
The solids contaminated well fluid is placed into a suitable container (not shown) which can be exposed to air or sealed as is desired. A mixer (not shown) is provided in the container so that the materials used in the present process can be thoroughly mixed with the well fluid. The mixer can be either an impeller type or a centrifugal reciprocating loop type. In addition, the container is provided with a suitable mechanism (not shown) to remove the agglomerated solids from the liquid phase. For example, the mechanism can be a rotary sweeper to remove the solids over an inclined discharge ramp such as used in air flotation cells. Alternatively, the container can be provided with adjustable liquid draw off pipes so that the solids-free well fluid can be decanted away from the removed solids. If desired, ~he container can be provided with both the sweeper or decanter mechanism for separating the solids and the liquid phases. Usually, the container can be operated at the ambient temperatures at which the well fluid is secured.

1 2 ~ 8 The well fluid is assumed to be heavily loaded with solids which may be sand, formation particles and debris, oil, pipe dope, rust insoluble carbonates, mud fluids and solids such as barite, emulsifier, thinners, cement and other solid materials in various combinations and amounts that can be found in the well circulation system.
As the first step of this process, it is preferred to admix with the well fluid a small effective amount of the aliphatic alcohol. The amount of the alcohol is usually not required above about 2% volume. Usually, good results are obtained using alcohol amounts above about 0.5% by volume. In most well fluids, the alcohol can be used in the amount of 0.5% by volume and larger amounts, such as 1.0% by volume, do not seem ~o appreciably increase the described solid removal results.
Usually, the solids removal results decrease when the amount of the alcohol is decreased simultaneously below the 0.5% by volume level.
After the alcohol is thoroughly distributed in the well fluid, the next step of this process is to admix the surface active chemical aid. The amount of the chemical aid is usually not required above about 2% volume. Good results are obtained by using chemical aid amounts above about 0.5% by volume. In most well fluids, the chemical aid can be used in the amount of 0.5% by volume and larger amounts, such as 1.0% by volume, do not seem to appreciably increase the desired solid removal results.
Usually, the solids removal results decrease when the amount of the chemical aid is decreased substantially below the 0.5% by volume level. Large amounts (e.g., above 3% by volume) of the chemical aid increases the amount of well fluid trapped in the removed solids. The chemical aid, and particularly the surfactant, appears to change the surface tension of the boundary film surrounding the negatively charged solid particles, and ~z~S92~
especially the bentonite constituents from drilling muds.
This effect provided by the chemical aid is primarily the agglomeration of the solids mass from the well fluid.
It has been found that the minimum effective amounts of the alcohol and surface active chemical aid depends upon their activity feature and the particular solids in the well fluid. Thus, this minimum effective amount is empirical and there does not seem to be a de~erminable relationship in these amounts between a particular alcohol and a certain surface active chemical aid from the groups hereinafter defined.
After the alcohol and chemical aid are distributed within the well fluid, it is allowed to rest in the quiescent state. The solids are removed from the liquid phase by agglomeration into a gel-like soft mass which may float at the surface or settle to the container bottom depending upon the density of the agglomerated mass of solids. These solids remain stable in this agglomerated mass for substantial periods of time (e.g., a week~ but can be redispersed if the well fluid is subject to remixing operations. The mass of solids are moved from the liquid phase by the sweeper or decanting or both in some instances where part of the solid mass floats, and another part of the mass sinks to the container bottom.
Generally, if the alcohol is added first to the well fluid and then followed by the chemical aid, an immediate clearing of the liquid phase occurs upon termination of the mixing opera~ions. Addition of the chemical aid before or with the alcohol, sometimes requires a long quiescent condition for clearing solids from the liquid phase. The solids clearing time is usually completed within minutes.
In either event, once the liquid phase has cleared, and the agglom~rated mass of solids removed from it, the resultant well fluid is substantially solids-free especially of particle sizes grea~er than 5 microns in ma~imum dimension.
The alcohol is 2-ethyl hexanol which is also known as 2 ethyl hexyl alcohol and octyl alcohol. The chemical abstract service name is l-hexanol, 2-ethyl. This alcohol can be obtained from sources of specialty solvents, and its slow evaporation rate and solvency make it useful in the present process. It has low water solubility and low surface tension properties which are an advantage in readily separating from the brine being cleaned of solids.
A good source for the alcohol is the suppliers to the producers of plasticizers for vinyl resins.
Obviously, the alcohol does not need to be of chemical purity but usually will be 99.0% by volume of pure alcohol with slight amounts of organic acids and aldehydes that do not interfere in this process.
The 2-ethyl hexanol can be obtained commercially and it has a relative~y high COC flash point of 183F, with a specific gravity of about 0.83 at 77F.
The surface active chemical aid includes a surfactant, and usually includes a carrier solvent such as a small amount of an aromatic hydrocarbon, corrosion and pitting inhibitor, and other additives desired to be added to the aqueous well fluid. The surfactant should have a molecular weight in the range of about 150 to about 500 with predominant hydrophobic characteristics.
The surfactant is selected from the group comprising aliphatic amines, amides and aliphatic amide o~ides wherein the amine and amide oxide have an alkyl group with between 8 and 18 carbon atoms.
Preferably, the surfactant is the amide reaction product of a fatty monobasic acid and a secondary or tertiary amine. More particularly, the fatty acid can be given the formula CnH2n+lCOOH wherein n is an integer between 12 and 18. The fatty acid can be selected from the group of oleic and diemirized oleic~ linoleic, palmit oleic, palmitic, myristic, myrestoleic and stearic acids.
The oleic acid amide products give good results.
The secondary and tertiary amines are selected from normal aliphatic amines that react with the fatty monobasic acids to form fatty amides that are generally used as nonionic emulsifiers. Good results are obtained when these amines are selected from the group consisting o~ diethanol and triethanol amines and mixtures thereof.
One surfactant giving excellent results with 2-ethyl hexano~ is a product of Witco Inc., and available under the trademark Witcamide 1017 (surfactant). This product is reported to be the amide (salt) reaction product of oleic acid, and diethanol and triethanol amines. It has a specific gravity of 1.0 (same as water) is amber with a PMCC flash point above 200F, and it is a product not hazardous under current Department of Labor definitions.
The operation theory of the alcohol and surface active chemical aid in the present process could not be determined within certainty from information presently available. It is believed that the alcohol serves to destabilize the dispersed solids by disrupting their electrophretic charges, and then the surfactant acts to gather the solids, and assembled oily materials, into a loose solids system that can be removed by careful liquid/solids phase separation techniques which do not impose shear or mixing en~rgy during solids removal. For example, the liquid phase may be decanted from the solids. Alternatively, the solids can be removed gently by a sweeper such as used in air f]otation cells.
It is preferred that the alcohol be added first and thoroughly admixed into the aqueous well fluid before the addition of the surface active chemical aid. However, with certain alcohol and surface active chemical aid combinations, these materials can be added together and good solids removal results can be produced in this process. At this time, there is no known guideline to aid in selecting these materials for use together in the well fluid so as to produce the same level of good results as provided by the separate but successive addition of the alcohol and then the surface active chemical aid. Likewise, with certain ingredients, the surface active chemical aid can be admixed first with the well fluid, and then the alcohol is added with good solids removal by this process. At this time, there is no known guideline to aid in selecting which surface active chemical aid and alcohol will provide in this additional arrangement the desired good solids removal from well fluid. Unless the alcohol is first mixed into the well fluid and then followed by adding the surface active chemical aid, some experimentation will be required to determine which of these materials can be added together or in reverse order, and yet produce the desired good solids removal by the present process.
In general, the present process can be used to remove solids from all salt type of aqueous well fluids.
Usually, the presence of corrosion inhibitors 9 antipitting compounds, etc. will not create any problems in solids removal. Some of the materials used in preparing drilling muds can interfere in the process, as by requiring increased amounts of alcohol, surface active chemical aid, or in extending separation of the solids from the liquid phase. These interfering materials can be removed before practicing the present process steps.
For example, the well fluid may have an appreciable amount of polyelectrolytes or polymers such as cellulose based organlc fluid loss agents (e.g., ~EC). In these cases, the polymer can be removed by early treatment of C~Z8 the well fluid with a strong oxidant such as hydrogen peroxide before practicing the process on the well fluid.
An inlet 35 to the pump 26 can be used to introduce the solids free brine into the filtration unit 14. The filtration unit is interconnected by valving and flow lines to the suction pit 21 and mud pumps 16 so that the brine can be moved by a centrifugal pump 26 through a filter 27 ~e.g., cartridge type) into a brine suction pit or vessel 28. Then, the mud pumps 16 can introduce the brine into the wellbore. The filtration unit provides additional solids removal capability to the process, but may be omitted when su~ficient contaminates are eliminated by the alcohol and surface active agent.
The wellbore equipment 13 can include the wellhead, casing, tubing, packers, valving and other well associated apparatus, such as the blow-out preventers and surface mud lines, etc.
Several disposal lines 29-32, with auxillary control valves are included in the well system 11 so that fluid from either the surface equipment 12 or the iltration unit 14 can be discharged to a suitable disposal in a pollution free and environmentally safe region.
Prior to introduction of the solids-free brine into the well system 11, the well system must be cleaned of drilling mud and fluid, both as to solids and oil material and other contaminates. For this purpose, in one embodiment of the invention, the drilling mud and fluids are displaced from the wel~ system by circulating therethrough a suitable volume of a spacer fluid constituting clean water introduced into the mud pit 19 from inlet 24. The clean water is circulated by the mud pumps 16. A major portion of the drilling mud is removed from the well system and carried in the clean water, which water can be discharged through one or more of the discharge lines to a suitable disposal region.

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At this time, a treated water is prepared, preferably in the mudpit 18, by adding together clean or sea water, a surfactant and an alcohol. The treated water is subjected to agitatlon and shear mixing by the mixer 19 while it is continuously circulated through the well system in both the surface and wellbore equipment.
The treated water displaces the now contaminated water from the well system via one of the discharge lines 29-32. Importantly, the treated water is circulated through those parts of the well system in which the brine is to be carried. The treated water is circulated in the well system 11 until substantially all of the residuary drilling mud and fluid are suspended therein.
Usually, the treated water is comprised in a chemical water ratio of 4 drums (55 gallons (U.S.) each) ad-~ixed with each 500 ~arrels (42 g~llons (U.S.) each) circul-ated in the well system. Each drum is comprised of a 50/50 composition of the surfactant and alcohol. As a result, the treated water has a concentration by volume each of about ~.8~ of surfactant and alcohol. In most situations, the concentration of the chemicals need not be greater than 1% and a 0.5% concentration works well.
The alcohol can be an aliphatic alcohol with between 5 and 8 carbon atoms and the surfactant is a surface active chemical aid with a molecular weight in the range of about 150 to about 500 with predominately hydrophobic characteristics. The surfactant is selected from the group comprising aliphatic amines, amides and aliphatic amine oxides whPrein the amine and amide have an alkyl group with between 8 and 18 carbon atoms. The surfactant can be an amide, such as ~he amide reaction product of oleic acid and diethanol and triethanol amine previously described.
The alcohol and surfactant can be selected and administered as hereinabove described for the steps ~ Z ~ 9 2 ~

relating to removing the contaminates from the high density brine, however, in the preferred embodiment, the alcohol is 2-ethyl hexanol and the surface active chemical aid is bis hydroxy ethyl cetyl amine and each chemical is used in the amount of 0.5% volume of the clean/sea water used in preparing the treated water.
Other alcohols that work well include pentanol, n-hexanol and octanol.
Various amines can be used in this process. For example, the alkynol amines which are available under the Acquiness trademark can be used, such as Acquiness MA401A. It is understood that this amine is principally bis hydroxy ethyl cetyl amine.
Other examples of amines usable in this invention are coco amine, octylamine, dioctylamine, decylamine and dodecylamine. Cocoamine may be generally represented by the formula CH (CH )loCH2~NH2 and it is prepared from monoethenoid fatty acids derived from coconuts. The "coco" group C12H25 is not a group containing a specific number of carbon atoms, but is a number of individual groups containing different numbers of carbon atoms.
However, the C12H25 group is in greater amount than any other group.
The cocoamine may be a condensation product, i.e.
oxalkylated cocoamine such as ethoxylated cocoamine with between 2 and 15 mols of ethylene oxide. More particularly, the condensation product is formed by subjecting cocoamine to a condensation with a plurality of mols of ethylene oxide in a manner well known in the art. In general, the condensation product of a mol of cocoamine with between 2 and 15 mols of ethylene oxide may be employed with good results. Preferably, the condensation product is formed by condensing 10 mols of ethlene oxide per mol of cocoamine. ~xpressed on the basis of molecular weight, the ethoxylated cocoamine may 9~2~

have an average molecular weight between 285 and 860, but preferably, has an average molec:ular weight of about 645.
The circulating treated water removes substantially all of the residual drilling mud (both solids and oils) and other contaminates from the well system. The drilling mud and fluids are carried in an agglomeration resembling gel-like soft masses of solids in a relatively stable suspension. The treated water effects a scrupulous cleaning of the well system and removes residual drilling mud, fluid and other contaminates in the flow lines, shaker, pits, valving, pumps and other components of ~he well system. As a result, this equip-ment, both on the surface and in the wellbore, retain no significant amounts of these contaminates. Stated in an-other manner, all of the remaining contaminates from the earlier clean water circulation step are now suspended in the treated water being circulated in the equipment 12 and 13. No extensive manual cleaning by rig workpersons is required. The unique treated water is removed from the equipment and carries the residual drilling mud in suspension.
While the treated water is yet being circulated within the well system, it is displaced via disposal lines 29-32 to a suitable non-polluting and safe disposal region. The displacing fluid is solids-free clean water added through inlet 24. After the well system is filled volumetrically with the solids-free clean water, the solids-free brine previously prepared as hereinabove described can be arranged for introduction into the wellbore.
Using the mud pump 16, the solids-free brine is moved from the pit 28 into the wellbore equipment (e.g., tubing, casing annulus and wellhead apparatus) and it volumetrically displaces the solids-free clean water through the disposal line 32. The well system is now ~ 2 ~

ready for subsequent activities once the downhole wellbore equipment is filled with the solids free brine.
It is preferred that the wellpipe or drillpipe, as the case may be, is reciprocated and rotated in the wellbore during circulation of the treated water. The pipe in deviated wells can be reciprocated about 30 feet with periodic rotation and this movement function accelerates removal of the drilling mud from the pipe and wellbore and its suspension in the treated water.
lo In some cases, an improved cleaning result is obtained if the alcohol and surfactant are added in two parts to clean water for producing the treated water.
For example, one half of the chemicals are added after circulation has been underway for thirty minutes, or when the wellpipe is to be reciprocated and rotated in the wellbore.
The use of circulating clean and treated waters in the well system is of advantage since only small amounts of the waters are required. It has been found that the volumes of clean water, treated water and solids-free waters used in this process are in the range of 250 to 1000 bbls. This feature is important in water scarce areas.
In an alternative embodiment of this invention, aqueous spacer plugs can be used before, after (or bo~h) the treated water as the spacer fluid in place of the clean water. The primary purposes of the preceding aqueous spacer are to ~1) reduce gravity mixing of the treated water with either the drilling fluid or solids-free brine, (2) retain and transport well fluid solids such as drilling mud, silt, sand, oil, barite, ferrous and ferric precipitates and other undissolved solids from the well bore equipment, similar to the clean water utilized in the previously described embodiment.
The primary purpose of the following aqueous spacer is to lZ~9Z~

reduce gravity mixing between the treated water and brine.
Usually, the present process removes drilling fluid from the well bore very efficiently so that only the first portion of the circulating brine (e.g., 100 bbls) has any solid contamination.
An aqueous spacer is prepared which contains a viscosifier to produce a non-newtonion fluid that can be circulated in laminar flow in the wellbore equipment.
For example, a small amount (e.g., 50 bbls) of fresh or salt water is placed into the pit 18 and a viscosifier is added that produces a gelled state for this mixture. For example, viscosifiers used in drilling mud products are suitable such as Polybrine, Polymix, Cellosize, Duovis (trademar~s) sold commercially by Magcobar Division of Dresser Industries, Inc. For oil based drilling fluids, this group has available a diesel viscosifier under the trademark Oilfaze which can be used in conjunction with diesel fuel or selected crude oils, clays such bentone, emulsifiers and weighting agents (e.g., barite). The viscosifier is added to the aqueous phase in amounts sufficient to produce the gelled state and to maintain this state under laminar flow conditions at the linear flow velocity where the following treated water moves at such velocity under turbulent flow. Generally, the gelled aqueous spacer operates at a Reynolds number of about 100 wherein the treated water is at a Reynolds number of about 2000.
Stated in a different manner, at a certain linear flow velocity, the gelled aqueous spacer flows below or at the maximum velocity for plug (laminar) flow while the aqueous spacer flows at or above the minimum critical velocity to achieve turbulent flow in the wellbore equipment.

~!~

lZ~9~3 There are many suitable viscosifiers available from mud product suppliers, and they can be substituted for the specific tradename products heretofore recited.
These products have known rhealogical properties and a gelled aqueous phase can be prepared with the desired non-newtonion state.
In many cases, it i5 preferred that a weighting agent be also included in the gelled aqueous phase. For example, barite may be added to increase the phase weight up to 20 pounds per gallon. Other viscosifiers such as Bentone, A~tapulgite, or as~estos fibers can be used with good results. These materials also enhance the action of the gelled aqueous spacer to act as a mechanical swab to not only displace the drilling fluid and mud from the wellbore equipment, but also may remove mud cake deposited on the walls of the well pipe, casing or wellbore.
Although the gelled spacer fluid acts as a true plug or mechanical swab, well effects cause it to be "strung out" in its passage through the wellbore equipment. For example, 50 barrels of the plug may be introduced into the wellbore equipment, but is may require an outflow of twice this volume because of the entrained drilling fluid, etc. intermingled within it.
If the drilling fluid is oil based, and especially as an inverted emulsion (water-in-oil), the gelled aqueous spacer preferably includes a liquid blend of emulsifiers, wetting agents, lubricants, gellants and other additives such as organophyllic ciay~ HEC polymers, starch, polyanionic cellulose, guar gum etc., which additives quickly form a stable inverted emulsion fluid when mi~ed with diesel fuel and water under moderate shear level mixing. For example, the aqueous spacer of inverted oil type can be formed of water and organ-ophyllic clay. The spacer prepares the mud coated pipe ~LZ:~9~

and the oil based drilling fluid for effective displacement from wellbore equipment by the following treated water slug.
The aqueous spacer is moved from the pit 18 and suction pit 21 and forced by the pumps 16 into the wellbore equipment 13. In deep wells, the aqueous spacer is introduced into the well pipe (tubing or drill pipe) and displaces drilling fluid upwardly from the annulus to the shale shaker 17 9 or other suitable disposal as by disposal line 32. However, in other applications, the aqueous spacer can be intrcduced downwardly through the annulus and forces the drilling fluid upwardly through the wellpipe. In either event, the aqueous spacer is in a gelled state forming a discrete plug that acts as a me-chanical swab in displacing the drilling fluid before it.
The linear velocity of the aqueous spacer plug being displaced through the wellbore equipment depends upon the hole diameter or annulus size and usually ranges between 80 and 200 feet per minute to maintain the laminar flow condition for the non-newtonion aqueous spacer which has flow conditions Reynolds Number of about 100.
The treated water is circulated into the wellbore equipment usually immediately following a gelled aqueous spacer. The treated water volumetrically displaces the plug of aqueous spacer and also provides a unique cleaning function in removing residual drilling fluid and other solids such as rust, ferrous and ferric precipitates, sand, silt, oil and other undissolved materials from the wellbore equipment.
The treated water is prepared9 preferably in the mud pit 18, by adding toge~her clean (fresh or sea) water, surfactant and an alcohol. The treated water is subjected to agitation and shear mixing by the mixer 19.
The amount of treated water depends on the capacity and strength of the wellbore equipment 13, the formation lZl~'92~

pressure, and the physical condition of the well, (i.e., open high pressure perforations, or liner tops that wil]
not allow reduction in hydrostatic head~ and may be prepared in an amount, for example, of 25-1000 barrels.
Usually, the treated water is comprised in a chemical-to-water ratio of 4 drums (55 gallons (U.S.)each) admixed with each 500 barrels(42 gallons (u~S.) each) of water added in the pit 18. Each drum is comprised of a 50/50 composition of the surfactant and alcohol. As a result, the treated water has a concentration by volume each of about 1.0% of surfactant and alcohol. In most situations, the concentration of the chemicals need not be greater than 2%, and a 1% concentration usually works well. If desired, other materials can be added that assist the treated water performance, such as sand, wal-nut shells, etc. The alcohol and surfactant can be selected according to the previous embodiment hereinabove described.
The treated water is moved from the pits 18 and 21 and forced by the mud pumps 16 into the wellbore equipment immediately behind the plug of gelled aqueous spacer. The flow of the treated water drives this plug before it, which plug volumetrically displaces the drilling fluid from the wellbore equipment 13. Besides its function as a displacing fluid, the treated water removes residual drilling fluid and its mud cake from the wall surfaces when pumped under turbulent flow con-ditions.
The treated water has a Reynolds number of about 2000 and turbulent flow conditions are obtained in the wellbore equipment at linear flow velocities between about 80 and about 200 feet per minute. The turbulent flow condition is meant to include true turbulence above the critical velocity for the treated water and also the condition at the upper limits of linear flow which are lZ,~.~.r9;2'~
essentially in the effect the same as turbulent flow in cleaning results relative to the drilling fluid. Thus, the treated water and the plug of gelled aqueous spacer can be moved at a range of flow velocities where the treated water is in turbulent flow and the plug moves at linear flow conditions.
As in the previous embodiment, the treated water removes substantially all of the residual drilling fluid (both mud, solids and oils) from the well system. The drilling fluid is carried in an agglomeration resembling gel-like soft masses of solids in a relatively stable suspension. The treated water effects a scrupulous cleaning of the wellbore equipment and removes residual drilling fluid and mud in the wellbore equipment and no significant amounts of drilling fluid constituents escape its cleaning action. Stated in another manner, all of the remaining drilling fluid and mud from the earlier displacement by the gelled aqueous spacer is now sus-pended in the treated water. No cleaning by rig workpersons is required using swabs, etc. in the wellbore equipment. The unique treated water is removed from the equipment and carries the residual contaminates in suspension.
While the treated water is yet being circulated within the wellbore equipment, it is displaced via disposal line 29-32 to a suitable non-polluting and safe disposal region. It can also be treated in the shale shaker, if desired. The treated water is followed immediately by a second plug of gelled aqueous spacer which can be the same composition and volume as the previously described spacer. However, the second plug can have a different gelled aqueous spacer composition if desired.
In some operations, the second plug can be made more compatible for volumetric displacement of the treated 1 2 ~ 8 water by the subsequently introduced solids-free brine.
For this purpose, the viscosifier is preferably a high molecular weight polymer used in clear brine systems, such as hydroxyethyl cellulose (HEC~. A fluid-loss control agent can also be added. For example, the blend of HEC and fluid-loss control agent can be supplied by the tradename produce Polybrine, a product of Macobar Division of Dresser Industries. In any event, the viscosifier and other additives must be operable at the temperature conditions in the wellbore equipment so as to function properly as the plug of gelled aqueous spacer.
The second plug of gelled aqueous spacer is introduced into the wellbore equipment 13 by the mud pump and immediately followed by the solids-free ~rine previously prepared as hereinabove described using the mud pump 16, the solids-free brine is moved from the pit 28 into the wellbore equipment and it volumetrically displaces the first plug of gelled aqueous spacer, the treated water, and the second plug of gelled aqueous spacer through the disposal line 32. The brine enters a clean well system free of drilling fluid, solids or other contaminates. The brine is pumped into the wellbore equipment at the same linear flow velocity as the treated water so that the plugs of gelled aqueous spacer move at laminar flow conditions while the treated water flows at substantially turbulent flow condi~ions. Preferably, there is no interruption of circulation of these fluids but momentary stoppages of flowing can be tolerated since the plugs of gelled aqueous spacers minimize cross contamination between the drilling fluid, treated water and brine being volumetrically displaced through the wellbore equipment.
The well system is now ready for subsequent activities once the wellbore equipment 13 is filled with the solids free brine.

1 2 ~ 8 In an actual field test on an oil-based mud, the present process was used to complete a well with solids-free brine. The following data define this process:
(1) well depth 17,500 feet with 7 inch casing and 3~ drill pipe with a drill pipe volume of 128 barrels, an annular volume of 378 barrels and a total volume of 506 barrels;

(2) first plug of gelled aqueous spacer was 47 barrPls of 8.7% by volume of Bariod EZ Spot in clear water weighted with barite to 14.5 pounds per gallon;

(3) the treated water was 575 barrels of sea water containing 1.74% by volume of 50/50 ratio of 2 ethylhexanol and bis hydroxy ethyl cetyl amine;

(4) the second plug of gelled aqueous spacer was 10 barrels of 0.01% by weight of HEC in clear water;

(5) the following brine was 10 pounds per gallon of solids-free calcium chloride solu~ion.
The first plug was introduced into the drill pipe followed by the treated water with a maximum annular flow velocity of 136 feet per minute. Then, the second plug was introduced and followed by the brine at an annular flow velocity of 375 feet per minute. The well equipment was displaced within about 2~ hours.
Although about 10 barrels of a 14~ pound per gallon Invermul drilling mud was inadvertently introduced ahead of the second plug, the final portions of the treated water were clear as originally introduced. The well equipment was free of solids so that the brine remained solids free and thereinafter producing the one-pass cleansing process described herein.
The initial portions of the treated water displaced from the well equipment brought up tons of dirt and 9Zt3 several hundred pounds of cement even though circulation was interrupted several times during the process. It is estimated that 12 hours of rig time was saved by using this process instead of earlier chemical washing procedures and the well equipment was made substantially free of solids before introduction of the brine.
In another field test, in well bore equipment, a 15.5 pound per gallon Invermul oil based mud was displaced at a reverse flow of about four barrels per minute. A first spacer plug was introduced onto the drilling mud, which spacer was 20 barrels formed of 2 drums of Baroid "F.asy Spot" emulsifier and diesel oil and weighted to 15.5 pounds per gallon. A second spacer plug followed the first spacer, and was used in an amount of 15 barrels. The second spacer was sea water containing 50 pounds per barrel of "Nut Plug" (ground walnut shells) with one-half drum of a 50/50 mixture of surfactant and alcohol as used in the treated water of the previous example. Yet a third spacer plug was used following the second spacer plug. This third spacer was 40 barrels of a high viscosity (120 Saybolt) mixture of HEC polymer with 100 pounds per barrel of "frac" sand. Then, the treated water slug in amount of lO barrels was introduced and immediately followed by the solids-free brine. This treated water was used in amount of 10 barrels formed of fresh water containing one-half drum of the surfactant and alcohol of the previous example.
About 25 barrels of the brine first circulated through the well bore equipment was diluted and therefore discarded. The balance of the brine was made solids-free by filtration for about 90 minutes in circulation within a filter system.
A storm interrupted the above process for 24 hours.
It was noted that the "Nut Plug" floated to the top of , 9~

the second spacer. However, when circula~ion was again practiced, the treated water slug performed as expected.
In other field tests, the present process uses only the first spacer plug and the treated water slug before the circulation of solids-free brine through the well bore equipment for good removal of the drilling mud. Where oil-based muds are present, it is preferred that the first spacer plug contain, or be preceded by a few barrels of an organic based solvent which may contain water-in-oil emulsifier.
The use of the treated water and agueous spacer plugs in the well system is of advantage since only small amounts of water are required. It has been found that the volumes of treated water and gelled aqueous spacers used in this process are in the range of 100 to 1000 bbls and are generally lower in volume than a comparable volume as practiced in the first embodiment (i.e. using clean water instead of the spacer plugs).
This feature is important in water scarce areas and from a waste disposal viewpoint.

9~

SUPPLEMENTARY DISCLOSURE
It has previously been noted that the alcohol may be an alipha-tic alcohol with between 5 and 8 carbon atoms. The alcohol can also be an alcohol having between 8 and 14 carbon atoms, usually the alcohols used will be in the ranye of between 6 and 12 carbon atoms. The lower alcohols (e.g. hexanol and 2-ethyl hexanol) give good resul-~s in producing floating oil and clear water phases with an agglomeration of solids. The intermediate alcohols with between 9 and 11 carbon atoms (e.g.
n-nonyl and unidecyleric alcohols) also produce an agglomeration of sludge solids from the oil and clear water phases. With the alcohols between 11 and 14 carbon atoms however, some experimentation may be required because their physical states can be waxy solids depending on the operating temperature of the liquid phase. For example, the alcohols, l-dodecanol,

6-dodecanol and l-tridecanol have melting points, respectively, of 24C, 30C and 28C. Alcohols with above 15 carbon atoms, such as l-pentadecanol have elevated melting points (e.g. 43C) such that they usually are solids in the liquid phase ambient at operating temperatures (e.g. 25C) and may fail to properly agglomerate the sludge solids.
From the foregoing disclosure andsupplementary disclosure, it will be apparent that there has been described a process for removing contaminates from a high density salt type completion and packer brine and for removing drilling mud and fluids and other contaminates from a well system prior to the introduction of the solids free brine. Various changes and alterations may be made in the practice of this process by those skilled in the art without departing from the spirit of the invention. It is intended that such changes be included within the scope of the appended claims. The present description is intended to be illustrative and not limitative of the present invention.

~5~,* ~

Claims

The embodiments of the invention in which an exclusive property or privilege is claimed are defined as follows:

1. A process for eliminating contaminates from a well system prior to introduction of solids-free completion and packer well fluids, the steps comprising:
(a) displacing contaminates from the well system by circulating treated water therein to displace a major portion of the contaminates from the well system, and the treated water prepared by the addition of an effective amount of a surfactant and alcohol to clean water and subjecting the treated water to agitation and shear mixing; and (b) following the displacing step, circulating therein a solids-free well fluid for displacing or carrying the treated water from the well system.

2. The process of claim 1 specifically directed to removing contaminates from the well bore portion of the well system.

3. The process of claim 2, including the further steps of:
(a) displacing contaminates from the well system by circulation therein of a spacer fluid introduced prior to said treated water until a major portion of the contaminates are removed from the well system and carried in said spacer fluid, said spacer fluid being displaced from the well system by the treated water;
(b) displacing from the well system to a suitable disposal region, the treated water carrying the contaminates with said spacer fluid, said spacer fluid being introduced before the solids-free well fluid without interruption of circulation through the well system; and (c) displacing the spacer fluid from step (b) with the solids-free well fluid in the parts of the well system receiving the well fluid from a source exterior of the well system.

4. The process of claim 2, wherein a second spacer fluid is introduced after said treated water but prior to the solids-free well fluid without interruption of circulation through the well system.

5. The process of claim 4, wherein either of the first or second spacer fluids are selected from a group consisting essentially of clean water, a brine, or a mixture of the two.

6. The process of claim 5, wherein said surfactant has a molecular weight in the range from about 150 to about 500 with predominately hydrophobic characteristics, and said surfactant is selected from the group comprising aliphatic amines, amides and aliphatic amine oxides wherein the amine, amide and amine oxide constituents have an alkyl group with between 8 and 18 carbon atoms, and said alcohol is an aliphatic alcohol with between 5 and 8 carbon atoms.

7. The process of claim 5, wherein in the well bore equipment, the well pipe is reciprocated within the well bore with periodic rotation to assist in suspending drilling mud in the circulating treated water.

8. The process of claim 5, wherein the alcohol is added first to the clean water and then the surfactant to produce the treated water before the well pipe is reciprocated and rotated.

9. The process of claim 5, wherein the surfactant and alcohol are each added in a volume of less than about 1 percent to the clean water for producing the treated water.

10. The process of claim 5, wherein the surfactant is selected from the group consisting essentially of bis hydroxy ethyl cetyl amine and the amide reaction product of oleic acid and diethanol and triethanol amines, and the alcohol is selected from the group consisting essentially of n-hexanol and 2-ethyl hexanol.

11. The process of claim 3, wherein the spacer fluid is aqueous spacer containing a viscosifier to produce a non-newtonion fluid that is circulated as a slug in a gel state in laminar flow and the treated water is prepared as a newtonion fluid circulated at turbulent flow conditions through the well system.

12. The process of claim 11, further including the step of circulating in laminar flow immediately after the treated water a second slug of an aqueous spacer containing a viscosifier to produce a non-newtonion fluid in a gel state for carrying the treated water from the well system without substantial mixing of the aqueous spacer or treated water into the following solids-free well fluid.

13. The process of claim 11, wherein the aqueous spacers are formed of clean water containing a viscosifier polymer.

14. The process of claim 11, wherein the surfactant and alcohol are added each in a volume of less than 1 percent to the clean water for producing the treated water and the plug volume of the aqueous spacers are a magnitude less than the volume of treated water circulated in the well system.

15. The process of claim 11, wherein the surfactant has a molecular weight in the range from about 150 to about 500 with predominately hydrophobic characteristics, and the surfactant is selected from the group comprising aliphatic amines, amides and aliphatic amine oxides with the amine, amide and amine oxide constituents having between 8 and 18 carbon atoms, and the alcohol is an aliphatic alcohol with between 5 and 8 carbon atoms.

16. The process of claim 11, wherein the surfactant is selected from the group consisting essentially of bis hydroxy ethyl cetyl amine and the amide reaction product of oleic acid and diethanol and triethanol amines, and the alcohol is selected from the group consisting essentially of n-hexanol and 2-ethyl hexanol.

17. The process of claim 11, wherein a hydrocarbon such as an organic based solvent is included in the aqueous spacer preceding the treated water when the drilling fluid includes inverted emulsion (water-in-oil) residues such as mud cake.

18. The process of claim 11, wherein the aqueous spacer contains a weighting agent.

19. The process of claim 1 wherein the contaminants include drilling mud fluid and the solids free completion and packer well fluids are brines, the treated water being prepared as a Newtonian fluid and circulated at turbulent flow conditions, and wherein an inverted gel spacer of bentone, water and a hydrocarbon is introduced before the treated water when the drilling fluid includes inverted emulsion (water-in-oil) resides such as mud cake.

20. The process of claim 1 wherein the contaminants include drilling mud fluid and the solids-free completion and packer well fluids are brines, the treated water being prepared as a Newtonian fluid and circulated at turbulent flow conditions, the surfactant having a molecular weight in the range from about 150 to about 500 with predominantly hydrophobic characteristics, and the surfactant being selected from the group comprising aliphatic amines, amides and aliphatic amine oxides with the amine and amide constituents having between 8 and 18 carbon atoms, and the alcohol being an aliphatic alcohol with between 5 and 8 carbon atoms.

21. The process of claims 19 and 20 wherein the surfactant is bis hydroxy ethyl cetyl amine and the alcohol is 2 ethyl hexanol.

22. A process for eliminating drilling mud fluid from a well system prior to introduction of solids-free completion and packer brines, the steps comprising:
(a) displacing fluid from the well system by circulating therein in laminar flow at least one plug of aqueous spacer containing a viscosifier to produce a non-Newtonian fluid that is circulated in a gel state for displacing and carrying a major portion of fluid being displaced from the well system;

(b) circulating at turbulent flow conditions, a treated water through the well system to displace therefrom fluid from the well system, and the treated water prepared as a Newtonian fluid from the addition of an effective amount of surfactant and alcohol to clean water and subjecting the treated water to agitation and shear mixing;
(c) the aqueous spacer plug passing with the treated water from the well system without substantial mixing of the aqueous spacer plug and treated water into the following solids-free brine circulated into the well system; and (d) circulating solids-free brine into the well system.

23. A process for eliminating drilling mud fluid from a well system prior to introduction of solids-free completion and packer brines, the steps comprising:
(a) displacing fluid from the well system by circulating therein in laminar flow a plug of an aqueous spacer containing a viscosifier to produce a non-Newtonian fluid that is circulated in a gel state for displacing and carrying a major portion of the drilling fluid from the well system;
(b) immediately following the displacing step, circulating at turbulent flow conditions, a treated water through the well system to displace therefrom the aqueous spacer plug carrying drilling fluid with the treated water removing and carrying drilling fluid from the well system, and the treated water prepared as a Newtonian fluid from the addition of an effective amount of surfactant and alcohol to clean water and subjecting the treated water to agitation and shear mixing;
(c) immediately following the treated water circulation step, circulating therein in laminar flow a plug of an aqueous spacer containing a viscosifier to produce a non-Newtonian fluid that is circulated in a gel state for displacing or carrying the treated water from the well system; and (d) displacing the aqueous spacer plug of step (c) from the well system by circulating therein of solids-free brine.

24. The process of claim 22 or 23 wherein the aqueous spacer in step (a) contains a weighting agent.

25. The process of claim 23 wherein the surfactant and alcohol are added each in a volume of less than 1 percent to the clean water for producing the treated water and the plug volumes of the aqueous spacers are a magnitude less than the volume of treated water circulated in the well system.

26. The process of claim 22 or 23 wherein the surfactant has a molecular weight in the range from about 150 to about 500 with predominantly hydrophobic characteristics, and the surfactant is selected from the group comprising aliphatic amines, amides and aliphatic amine oxides with the amine, amide, and amine oxide constituents having between 8 and 18 carbon atoms, and the alcohol is an aliphatic alcohol with between 5 and 8 carbon atoms.

27. The process of claim 22 or 23 wherein the surfactant is bis hydroxy ethyl cetyl amine and the alcohol is 2 ethyl hexanol.

28. The process of claim 23 wherein the volumetric ratios in barrels of the aqueous spacer plug of step (a) to the treated water to the aqueous spacer plug of step (c) is about 50/500/10 for a well system having a volumetric capacity of about 500 barrels.

29. The process of claim 23 wherein the aqueous spacer plug of step (c) is formed of clean water containing a viscosifier polymer.

30. The process of claim 29 wherein the viscosifier polymer is hydroxyethylcellulose (H.E.C.).

31. The process of claim 23 wherein the aqueous spacer plugs and treated water are circulated in the well system at linear flow velocity between 100 and 150 feet per minute.

32. The process of claim 31 wherein the linear flow velocity is about 136 feet per minute.

33. The process of claim 23 wherein a hydrocarbon such as diesel oil is included in the aqueous spacer of step (a) when the drilling fluid includes inverted emulsion (water-in-oil) residues such as mud cake.

34. The process of claim 1 specifically directed to removing contaminates from the surface equipment portion of the well system.

35. The process of claim 34 including the further steps of:
(a) displacing the contaminates from the surface equipment associated with the well system by circulation therein of a spacer fluid introduced prior to said treated water until a major portion of the contaminates are removed from the surface equipment and carried in said spacer fluids, said spacer fluid being displaced from the surface equipment by the treated water;
(b) displacing from the surface equipment to a suitable disposal region, the treated water carrying the contaminates with said spacer fluid before the solids-free well fluid without interruption of circulation through the surface equipment; and (c) displacing the spacer fluid from step (b) with the solids-free well fluid.

36. The process of claim 35, wherein said surfactant has a molecular weight in the range of about 100 to about 500 with predominantly hydrophobic characteristics, said surfactant selected from the group comprising aliphatic amines, amides and aliphatic amine oxides wherein the amine, amide and amine oxide constituents have an alkyl group with between 8 and 18 carbon atoms, and said alcohol is an aliphatic alcohol with between 5 and 8 carbon atoms.

37. The process of Claim 35, wherein the surfactant and alcohol are each added in a volume of less than about 1% to the clean water for producing the treated water.

38. The process of Claim 35 or 37, wherein the surfactant is selected from the group consisting essentially of bis hydroxy ethyl cetyl amine and the amide reaction product of oleic acid and diethanol and triethanol amines and the alcohol selected from the group consisting essentially of n-hexanol and 2-ethyl hexanol.

39. The process of Claim 35, 36 or 37 wherein the spacer fluid is an aqueous spacer containing a viscosifier to produce a non-Newtonian fluid that is circulated as a slug in a gel state in laminar flow and the treated water is prepared as a Newtonian fluid circulated at turbulent flow conditions through the surface equipment.

40. A process for eliminating drilling mud solids and oil from a well system prior to introduction of solids-free completion and packer brines, the steps comprising:

(a) displacing drilling mud from the well system by circulation therein of clean water until a major portion of the drilling mud is removed from the well system and carried in the clean water;
(b) preparing a treated water with the addition of an effective amount of surfactant and alcohol to clean water and subjecting the treated water to agitation and shear mixing in the surface equipment on the well system;
(c) circulating the treated water through both the surface equipment and the wellbore equipment of the well system to displace therefrom the clean water carrying drilling mud and circulating the treated water in the well system in which completion and packer brines are to be carried until substantially all of the drilling mud is suspended in the circulated treated water;
(d) displacing from the well system to a suitable disposal region, with solids-free clean water, the treated water carrying the drilling mud without interruption of circulation through the well system; and (e) displacing the clean water from step (d) with solids-free completion and packer brine in the parts of the well system receiving the brine from a source exterior of the well system.

41. The process of claim 40 wherein said surfactant has a molecular weight in the range from about 150 to about 500 with predominately hydrophobic characteristics, and said surfactant selected from the group comprising aliphatic amines, amides and aliphatic amine oxides wherein the amine, amide, and amine oxide constituents have an alkyl group with between 8 and 18 carbon atoms, and said alcohol is an aliphatic alcohol with between 5 and 8 carbon atoms.

42. The process of claim 40 or 41 wherein the clean water can be sea water or fresh water relatively free of solids.

43. The process of claim 40 or 41 wherein in the wellbore equipment, the treated water is circulated through both well pipe and annulus in the wellbore and including any blow-out preventers, stand pipes and other devices associated with the wellbore equipment.

44. The process of claim 40 or 41 wherein in the surface equipment, the treated water is circulated through the surface equipment including pumps, hoppers, valving, mud cleaners, shale shakers.

45. The process of claim 40 wherein in the wellbore equipment, the wellpipe is reciprocated within the wellbore with periodic rotation to assist in suspending drilling mud in the circulating treated water.

46. The process of claim 45 wherein a first part of the surfactant and alcohol are added to the clean water to produce the treated water before the well pipe is reciprocated and rotated, and thereafter the remaining part of the surfactant and alcohol are added to the clean water thereby forming the ultimate treated water circulated through the well system.

47. The process of claim 40 or 41 wherein the surfactant and alcohol are added each in a volume of less than about 1 percent to the clean water for producing the treated water.

48. The process of claim 40 or 41 wherein the surfactant is bis hydroxy ethyl cetyl amine and the alcohol is hexanol.

49. In a process for producing a solids free aqueous fluid contaminated with solids selected from the group consisting of rust, sand and drilling mud, the steps comprising:
(a) introducing in small effective amounts an aliphatic alcohol and a surface active chemical aid into the fluid; and (b) separating the agglomerated solids from the fluid before it is utilized in a solids free state;
wherein the surface active chemical aid in step (a) includes a surfactant having a molecular weight in the range of about 150 to about 500 with predominant hydrophobic characteristics and the surfactant is selected from a group consisting of aliphatic amines, amides and aliphatic amine oxides with the amine, amide and amine oxide constituents having an alkyl group with between 8 and 18 carbon atoms, and wherein the aliphatic alcohol in step (a) employs an aliphatic alcohol with between 5 and 8 carbon atoms.

50. The process of claim 49 wherein the aliphatic alcohol is selected from the group consisting of n-hexanol and 2-ethyl hexanol.

51. The process of claim 49 wherein the aliphatic alcohol is 2-ethyl hexanol.

52. The process of claim 49, 50 or 51, wherein the aqueous fluid is a well fluid of a high density type having one or more of the sodium, calcium or zinc salts with chloride and bromide, and mixtures thereof and the agglomerated solids are separated from the fluid before introduction into a well bore in a solids free state.

53. The process of claim 49, 50 or 51, wherein the surfactant is the amide reaction product of an amine selected from the group consisting of diethanolamine, triethanolamine and mixtures thereof with an organic fatty mono basic acid of the general formula CnH2n+lCOOH wherein n is an integer between 12 and 18.

54. The process of claim 50 or 51, wherein the alcohol and surfactant are used in a 50/50 mixture by volume.

55. The process of claim 49, 50 or 51 wherein the aqueous fluid is of the high density type having one or more of the sodium, calcium or zinc salts with chloride and bromide and mixtures thereof.

56. The process of claim 49 wherein the surfactant is the amide reaction product of an amine selected from the group consisting of diethanolamine, triethanolamine and mixtures thereof with an organic fatty mono basic acid of the general formula CnH2n+lCOOH wherein n is an integer between 12 and 18, wherein the alcohol and surfactant are used in a 50/50 mixture by volume, and wherein the aqueous fluid is of the high density type having one or more of the sodium, calcium or zinc salts with chloride and bromide and mixtures thereof.

57. The process of claim 56 wherein the aliphatic alcohol is selected from the group consisting of n-hexanol and 2-ethyl hexanol.

CLAIMS SUPPORTED BY THE SUPPLEMENTARY DISCLOSURE

58. The process of claim 5, 11 or 19, wherein said surfactant has a molecular weight in the range from about 150 to about 500 with predominately hydrophobic characteristics, and said surfactant is selected from the group comprising aliphatic amines, amides and aliphatic amine oxides wherein the amine, amide and amine oxide constituents have an alkyl group with between 8 and 18 carbon atoms, and said alcohol is an aliphatic alcohol with between 5 and 14 carbon atoms.

59. The process of claim 22, 23 or 25, wherein said surfactant has a molecular weight in the range from about 150 to about 500 with predominately hydrophobic characteristics, and said surfactant is selected from the group comprising aliphatic amines, amides and aliphatic amine oxides wherein the amine, amide and amine oxide constituents have an alkyl group with between 8 and 18 carbon atoms, and said alcohol is an aliphatic alcohol with between 5 and 14 carbon atoms.

60. The process of claim 36 or 41, wherein said surfactant has a molecular weight in the range from about 150 to about 500 with predominately hydrophobic characteristics, and said surfactant is selected from the group comprising aliphatic amines, amides and aliphatic amine oxides wherein the amine, amide and amine oxide constituents have an alkyl group with between 8 and 18 carbon atoms, and said alcohol is an aliphatic alcohol with between 5 and 14 carbon atoms.

61. The process of claim 11 or 19, wherein the surfactant is selected from the group consisting essentially of bis hydroxy ethyl cetyl amine and the amide reaction product of oleic acid and diethanol and triethanol amines, and the alcohol is selected from the group consisting essentially of n-hexanol and 2-ethyl hexanol, n-nonyl, unidecyleric, l-dodecanol, 6-dodecanol and l-tridecanol.

62. The process of claim 22, 23 or 35, wherein the surfactant is selected from the group consisting essentially of bis hydroxy ethyl cetyl amine and the amide reaction product of oleic acid and diethanol and triethanol amines, and the alcohol is selected from the group consisting essentially of n-hexanol, 2-ethyl hexanol, n-nonyl, unidecyleric, l-dodecanol, 6-dodecanol and l-tridecanol.

63. The process of claim 36 or 41, wherein the surfactant is selected from the group consisting essentially of bis hydroxy ethyl cetyl amine and the amide reaction product of oleic acid and diethanol and triethanol amines, and the alcohol is selected from the group consisting essentially of n-hexanol and 2-ethyl hexanol, n-nonyl, unidecyleric, l-dodecanol, 6-dodecanol and l-tridecanol.

64. In a process for producing a solids free aqueous fluid contaminated with solids selected from the group consisting of rust, sand and drilling mud, the steps comprising:
(a) introducing in small effective amounts an aliphatic alcohol and a surface active chemical aid into the fluid; and (b) separating the agglomerated solids from the fluid before it is utilized in a solids free state;
wherein the surface active chemical aid in step (a) includes a surfactant having a molecular weight in the range of about 150 to about 500 with predominant hydrophobic characteristics and the surfactant is selected from a group consisting of aliphatic amines, amides and aliphatic amine oxides with the amine, amide and amine oxide constituents having an alkyl group with between 8 and 18 carbon atoms, and wherein the aliphatic alcohol in step (a) employs an aliphatic alcohol with between 5 and 14 carbon atoms.

65. The process of claim 64 wherein the alcohol is selected from the group consisting of n-hexanol and 2-ethyl hexanol, n-nonyl, unidecyleric, l-dodecanol, 6-dodecanol and 1-tridecanol.

66. The process of claim 64 or 65, wherein the surfactant is the amide reaction product of an amine selected from the group consisting of diethanolamine, triethanolamine and mixtures thereof with an organic fatty mono basic acid of the general formula CnH2n+1COOH wherein n is an integer between 12 and 18.

67. The process of claim 64 or 65, wherein the alcohol and surfactant are used in a 50/50 mixture by volume.

68. The process of claim 64 or 65 wherein the surfactant is the amide reaction product of an amine selected from the group consisting of diethanolamine, triethanolamine and mixtures thereof with an organic fatty mono basic acid of the general formula CnH2n+1COOH wherein n is an integer between 12 and 18, wherein the alcohol and surfactant are used in a 50/50 mixture by volume, and wherein the aqueous fluid is of the high density type having one or more of the sodium, calcium or zinc salts with chloride and bromide and mixtures thereof.