# Patent

## Title
Thinners for invert emulsions

## Abstract

A method of reducing the viscosity of oil-based drilling fluids and well service fluids at low temperatures and a thinner compound for use in such drilling fluids and well service fluids is disclosed. The method comprises adding to said drilling fluids or well service fluids a thinner having the formula:

R—(C2H4O)n(C3H6O)m(C4H8O)k-H

where R is a saturated or unsaturated, linear or branched alkyl radical having about 8 to about 24 carbon atoms, n is a number ranging from about 1 to about 10, m is a number ranging form about 0 to about 10, and k is a number ranging from about 0 to about 10.

## Background
BACKGROUND OF THE INVENTION
1. Field of the Invention
This invention is generally related to methods and compositions for drilling and servicing wellbores in hydrocarbon bearing subterranean formations. Particularly, this invention is related to oil-based drilling fluid systems comprising water-in-oil invert emulsions, and to thinners that enhance or enable use of such fluids, at temperatures at or below about 50 degrees Fahrenheit (about 10 degrees Centigrade).
2. Description of Relevant Art
A drilling fluid, or “mud” which a drilling fluid is also often called, is a specially designed fluid that is circulated in a wellbore as the wellbore is being drilled to facilitate the drilling operation. The various functions of a drilling fluid include removing drill cuttings from the wellbore, cooling and lubricating the drill bit, aiding in support of the drill pipe and drill bit, and providing a hydrostatic head to maintain the integrity of the wellbore walls and prevent well blowouts. Specific drilling fluid systems are selected to optimize a drilling operation in accordance with the characteristics of a particular geological formation.
A drilling fluid typically comprises water and/or oil or synthetic oil or other synthetic material or synthetic fluid (“synthetic”) as a base fluid, with solids in suspension. A non-aqueous based drilling fluid typically contains oil or synthetic as a continuous phase and may also contain water dispersed in the continuous phase by emulsification so that there is no distinct layer of water in the fluid. Such dispersed water in oil is generally referred to as an invert emulsion or water-in-oil emulsion.
A number of additives may be included in such oil based drilling fluids and invert emulsions to enhance certain properties of the fluid. Such additives may include, for example, emulsifiers, weighting agents, fluid-loss additives or fluid-loss control agents, viscosifiers or viscosity control agents, and alkali. Further general discussion and description of oil-based drilling fluids is provided in P. A. Boyd, et al., New Base Oil Used In Low Toxicity Oil Muds, Journal of Petroleum Technology, pages 137-142 (1985), which is incorporated herein by reference.
An essential criterion for assessing the utility of a fluid as a drilling fluid or as a well service fluid is the fluid's rheological parameters, particularly under drilling and wellbore conditions. For use as a drilling fluid, or as a fluid for servicing a well, the fluid must be capable of maintaining certain viscosities suitable for drilling and circulation in the wellbore. Preferably, a drilling fluid will be sufficiently viscous to be capable of supporting and carrying to the surface of the well drill cuttings without being so viscous as to interfere with the drilling operation. Moreover, a drilling fluid must be sufficiently viscous to be able to suspend barite and other weighting agents. However, increased viscosity can result in problematic sticking of the drill string, and increased circulating pressures can contribute to lost circulation problems.
Thinners may be added to the drilling fluid or drilling mud systems before and in the course of drilling. Anionic surfactants particularly from the group of the fatty alcohol sulfates, the fatty, alcohol ether sulfates and the alkylbenzenesulfonates are examples of such thinners known in the prior art. Although such compounds have been shown to effect thinning of drilling fluids, problems with such prior art thinners may occur when using the drilling muds at low temperatures (temperatures at or below about 50° F. (10° C.)).
At such low temperatures, despite the use of known prior art thinners, oil based drilling fluids typically have high or increased viscosity, which may render the fluids unusable for drilling. After pumping into the wellbore, drilling fluids may undergo heating from the formation, depending on the depth of the wellbore and the temperature of the formation. For example, heating in the range of about 150° to about 250° F. (about 66° to about 121° C.) is not uncommon and subterranean temperatures as high as about 350° F. (about 178° C.), particularly in very deep wellbores, are known. The Arctic region, for example, is known to have very low surface temperatures but very high subterranean temperatures. Even more problematic are deepwater wells (i.e., typically wells below at least about 1500 feet), which subject drilling fluids to chilling from cold waters surrounding the riser as the fluid returns to the surface from the high temperature subterranean formation. Such chilling of oil based drilling fluids typically increases their viscosity while such subterranean heating of oil based drilling fluids typically reduces their viscosity.
Preferably, thinners which reduce the viscosity of drilling fluids at low temperatures will not affect the viscosity of the fluids at high temperatures. That is, in many cases, a thinner is desired that is capable of “selectively” influencing the rheology or particularly reducing the viscosity of oil-based drilling fluids only at lower temperatures, such as may be encountered at the ground surface of the wellbore, or in the riser surrounded by waters above a deepwater offshore well, for example.
Thinners and other additives to drilling fluids, as well as drilling fluids employed in onshore and offshore wells, must commonly meet stringent environmental regulations related to biodegradability and toxicity. Further, drilling fluids and additives to drilling fluids must be able to withstand subterranean conditions that the fluids will typically encounter in a wellbore, such as high temperatures, high pressures, and pH changes.
A need exists for improved rheology-modifying or viscosity reducing additives to oil-based drilling fluids, and particularly to drilling fluids comprising invert (water-in-oil) emulsions, which are expected to be used in or to encounter low temperatures in drilling operations. As used herein, unless indicated otherwise, “low temperatures” shall be understood to mean temperatures at or below about 50° F. (about 10° C.).
SUMMARY OF THE INVENTION
According to the method of the present invention, a compound is added to a water-in-oil or invert emulsion drilling fluid or well service fluid which reduces the viscosity of the drilling fluid or well service fluid at low temperatures or which enables or enhances the ability of the drilling fluid or well service fluid to maintain its viscosity at low temperatures. The compound, which may be generally called a “thinner,” continues to have this effect on a drilling fluid or well service fluid in drilling or servicing wellbores in subterranean formations, particularly hydrocarbon bearing subterranean formations. Further, this compound does not significantly affect the viscosity of the emulsion at high temperatures.
The compound has the following formula:

R—(C2H4O)n(C3H6O)m(C4H8O)k-H

where R is a saturated or unsaturated, linear or branched alkyl radical having about 8 to about 24 carbon atoms, n is a number ranging from about 1 to about 10, m is a number ranging from about 0 to about 10, and k is a number ranging from about 0 to about 10.

The invention also comprises the composition of a water-in-oil or invert emulsion drilling fluid or well service fluid containing this thinner compound.



BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 is a graph comparing yield point of mud systems with and without thinners of the invention tested as reported in Table 2 at different temperatures.
FIG. 2 is a graph comparing yield point of mud systems with and without thinners of the invention tested as reported in Table 3 at different temperatures.
FIG. 3 is a graph comparing yield point of mud systems with and without thinners of the invention tested as reported in Table 4 at different temperatures.
FIG. 4 is a graph comparing yield point of mud systems with and without thinners of the invention tested as reported in Table 5 at different temperatures.
FIG. 5 is a graph comparing yield point of mud systems with and without thinners of the invention tested as reported in Table 6 at different temperatures.
FIG. 6 is a graph comparing yield point of mud systems with and without thinners of the invention tested as reported in Table 7 at different temperatures.
FIG. 7 is a graph comparing yield point of mud systems with and without thinners of the invention tested as reported in Table 8 at different temperatures.
FIG. 8 is a graph comparing yield point of mud systems with and without thinners of the invention tested as reported in Table 9 at different temperatures.



DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS
The present invention provides a method of influencing the rheology, and particularly reducing the viscosity, of drilling fluids or well service fluids comprising invert (water-in-oil) emulsions. The method is particularly applicable to fluids for use in wellbores penetrating hydrocarbon bearing subterranean formations and has particular advantage in applications where the fluids are subjected to low temperatures, as in drilling or in servicing deepwater offshore wells. Such drilling fluids and well service fluids typically comprise a continuous oil phase, water dispersed in the oil phase, solids insoluble in the drilling fluid or well service fluid suspended in the fluid, and various additives. As the term is used herein, “invert emulsion” or “oil-in-water emulsion” is understood to mean the liquid portion of the drilling fluid comprising an emulsion (excluding solids). The term “invert emulsion drilling fluid” means the total sum of what is circulated as a drilling fluid.
In the method of this invention, a composition or compound having the following formula (I) is added to the invert emulsion or oil-based drilling fluid (or well service fluid) to reduce the viscosity of the fluid or to enhance the ability of the fluid to maintain its viscosity or to resist increasing viscosity at low temperatures. The compound may be added to the fluid during initial preparation of the fluid or later as the fluid is being used for drilling or well service purposes in the formation. The quantity added is an effective amount to maintain or effect the desired viscosity of the drilling fluid. For purposes of this invention, an “effective amount” of thinner of formula (I) is preferably from about 0.5 to about 15 pounds per barrel of drilling fluid or mud. A more preferred amount of thinner ranges from about 1 to about 5 pounds per barrel of drilling fluid and a most preferred amount is about 1.5 to about 3 pounds thinner per barrel of drilling fluid.
Formula (I) is:

R—(C2H4O)n(C3H6O)m(C4H8O)k-H  (I)

where R is a saturated or unsaturated, linear or branched, alkyl radical having about 8 to about 24 carbon atoms, n is a number ranging from about 1 to about 10, m is a number ranging from about 0 to about 10, and k is a number ranging from about 0 to about 10. Preferably, R has about 8 to about 18 carbon atoms; more preferably, R has about 12 to about 18 carbon atoms; and most preferably, R has about 12 to about 14 carbon atoms. Also, most preferably, R is saturated and linear.

The compositions or compounds of formula (I) may be prepared by customary techniques of alkoxylation, such as alkoxylating the corresponding fatty alcohols with ethylene oxide and/or propylene oxide or butylene oxide under pressure and in the presence of acidic or alkaline catalysts as is known in the art. Such alkoxylation may take place blockwise, i.e., the fatty alcohol may be reacted first with ethylene oxide, propylene oxide or butylene oxide and subsequently, if desired, with one or more of the other alkylene oxides. Alternatively, such alkoxylation may be conducted randomly, in which any desired mixture of ethylene oxide, propylene oxide and/or butylene oxide is reacted with the fatty alcohol.
In formula (I), the subscripts n and m respectively represent the number of ethylene oxide (EO) and propylene oxide (PO) molecules or groups in one molecule of the alkoxylated fatty alcohol. The subscript k indicates the number of butylene oxide (BO) molecules or groups. The subscripts n, m, and k need not be integers, since they indicate in each case statistical averages of the alkoxylation. Included without limitation are those compounds of the formula (I) whose ethoxy, propoxy, and/or butoxy group distribution is very narrow, such as for example, “narrow range ethoxylates” also called “NREs” by those skilled in the art.
To accomplish the purposes of this invention, the compound of formula (I) must contain at least one ethoxy group. Preferably, the compound of formula I will also contain at least one propoxy group (C3H6O—) or butoxy group (C4H8O—). Mixed alkoxides containing all three alkoxide groups—ethylene oxide, propylene oxide, and butylene oxide—are possible for the invention but are not preferred.
Preferably, for use according to this invention, the compound of formula (I) will have a value for m ranging from about 1 to about 10 with k zero or a value for k ranging from about 1 to about 10 with m zero. Most preferably, m will be about 1 to about 10 and k will be zero.
Other preferred compounds for use in the invention having the formula (I) above will have n ranging from about 1 to about 6, m ranging from about 1 to about 6, and k zero. Still other preferred compounds for use in the invention having the formula (I) above will have n ranging from about 2 to about 5, and m being about 3 or about 4 with k zero. It is particularly advantageous to establish the distribution of ethylene oxide and propylene oxide groups in the compounds of formula (I) in an ethylene oxide to propylene oxide ratio of about 1:1 to about 2:1, or even more preferably, about 2:1.5.
Additional preferred compounds for use in the invention having formula (I) above will have alkyl radicals containing about 12 to about 18 carbon atoms, or more preferably about 12 to about 14 carbon atoms, with subscripts n and m each having values of about 4 or about 5.
Used as thinners according to the method of the invention, the compounds of formula (I) reduce the viscosity or lower the yield point of the drilling fluid to which they are added. These thinners are particularly effective at low temperatures, i.e., temperatures at or below about 50° F. (about 10° C.) and most particularly effective at temperatures at or below about 40° F. (about 4° C.). The lower limit of effectiveness for these thinners is about 14° F. (about −10° C.). The thinners do not significantly influence or affect the rheology of drilling fluids at high temperatures, particularly temperatures ranging from about 100 to about 250° F. or more.
The compounds of formula (I) are biodegradable and are of little or no toxicity. They are expected to be capable of meeting increasingly stringent environmental regulations affecting the oil and gas industry worldwide.
Example drilling fluids comprising invert (water-in-oil) emulsions of particular use in the method of the invention generally have an oil phase comprising diesel oil, paraffin oil and/or mineral oil, or a synthetic oil. Alternatively, other carrier fluids may be used such as carboxylic esters, alcohols, ethers, internal olefins, alphaolefins (IO and/or AO), and polyalphaolefins (PAO), which may be branched or unbranched but are preferably linear and preferably ecologically acceptable (non-polluting oils). Preferably, the oils or carrier fluids used for the oil phase of the drilling fluid will be comprised of compounds which are flowable and pumpable at temperatures above about 32° F. (about 0° C.) or at least as low as about 40° F. (about 5° C.) as well as at higher temperatures. For example, compounds selected from one or more of the following groups or classes below are believed particularly suitable to comprise the oil phase of drilling fluids used in the present invention:

    
    
        (a) most preferably, carboxylic esters of the formula:

R′—COO—R′′  (II)

        where R′ is a saturated or unsaturated, linear or branched, alkyl radical having about 5 to about 23 carbon atoms and R′′ is an alkyl radical, branched or unbranched, saturated or unsaturated, having about 1 to about 22 carbon atoms;
        (b) also preferably, linear or branched olefins having about 8 to about 30 carbon atoms;
        (c) water-insoluble symmetric or asymmetric ethers of monohydric alcohols of natural or synthetic origin, said alcohols containing about 1 to about 24 carbon atoms;
        (d) water-insoluble alcohols of the formula:

R′′′—OH  (III)

        where R′′′ is a saturated, unsaturated, linear or branched alkyl radical having about 8 to about 24 carbon atoms; and
        (e) carbonic diesters.
    
    


Such suitable oils are taught further, for example, in: European Patent Applications 0 374 671, 0 374,672, 0 382 070, and 0 386 638 of Cognis; European Laid-Open Specification 0 765 368 of Cognis (linear olefins); European Application 0 472 557 (water insoluble symmetric or asymmetric ethers of monohydric alcohols of natural or synthetic origin containing about 1 to about 24 carbon atoms); European Application 0 532 570 (carbonic diesters). Carboxylic esters of formula (II) above are preferred for the oil phase of drilling fluids used in this invention and particularly preferred are the esters described in European Laid-Open Specification EP 0 374 672 and EP 0 386 636.
In a preferred embodiment of this invention, compounds of formula (I) are added to drilling fluids comprising invert emulsions having an oil phase comprising esters of formula (II) where the radical R′ in formula (II) is an alkyl radical having about 5 to about 21 carbon atoms (or more preferably about 5 to about 17 carbon atoms or most preferably about 11 to about 17 carbon atoms). Particularly suitable alcohols for making such esters are branched or unbranched alcohols with about 1 to about 8 carbon atoms, for example, methanol, isopropanol, isobutanol, and 2-ethylhexanol. Alcohols having about 12 to about 18 carbon atoms may alternatively be preferred for making other esters suitable for the invention.
For example, additional preferred esters for the oil phase of drilling fluids used in the invention include, without limitation: saturated C12-C14 fatty acid esters and unsaturated C16-C18 fatty acids (with isopropyl-, isobutyl- or 2-ethylhexanol as the alcohol component); 2-ethylhexyl octanoate; acetic acid esters, especially acetates of C16-C18 fatty alcohols; branched carboxylic esters disclosed in WO 99/33932 of Chevron or EP 0 642 561 of Exxon; alpha olefin mixtures disclosed in EP 0 765 368 A1 of Cognis and Halliburton; and blends of these various esters.
The oil phase of the emulsions of the drilling fluids used in the invention is preferably comprised of at least about 50% by volume of one or more preferred compounds (a)-(e) above. More preferably, such preferred compounds comprise about 60% to about 80% by volume of said oil phase, and most preferably, such preferred compounds comprise about 100% of the oil phase.
Water is preferably present in the liquid phase of the drilling fluids used in the invention, and preferably in amounts not less than about 0.5% by volume (excluding solids in the liquid phase). In a preferred embodiment of this invention, thinners of formula (I) are added to drilling fluids comprising invert emulsions containing about 15 to about 35% by volume water and more preferably 20% by volume water and about 80% by volume oil phase. To compensate for the osmotic gradient between the drilling mud and the formation or connate water, water in drilling fluids used in the present invention typically includes fractions of electrolytes, such as calcium salts and/or sodium salts. CaCl2 in particular is frequently used, although other salts from the group of alkali metals and/or alkaline earth metals are also suitable, with potassium acetates and formates being common examples.
Preferred drilling fluids used in this invention have the following rheology: plastic viscosity (PV) in the range of about 10 to about 60 cP, and preferably in the range of about 15 to about 40 cP, and yield point (YP) in the range of about 5 to about 40 lb/100 ft2, and preferably in the range of about 10 to about 25 lb/100 ft2, at about 122° F. (about 50° C.). At lower temperatures, i.e., at or below about 40° F. (about 4° C.), the YP should not exceed about 75 lb/100 ft2, and should preferably be in the range of about 10 to about 65 lb/100 ft2, more preferably about 15 to about 45 lb/100 ft2, and most preferably less than about 35 lb/100 ft2. A preferred practicable lower limit for YP for drilling fluids used in this invention is about 5 lb/100 ft2.
Methods for determining these parameters of PV and YP are well known to those skilled in the art. An example reference is “Manual of Drilling Fluids Technology”, particularly the chapter on Mud Testing, available from Baroid Drilling Fluids, Inc., in Houston, Tex. (USA), incorporated herein by reference.
The solids content (not including low gravity solids), or the amount of weighting agents, in drilling fluids used in this invention is preferably about 0 to about 500 lb/bbl, and most preferably about 150 to about 350 lb/bbl. The mud weight, i.e., the density of the drilling fluids, is preferably in the range of about 8 to about 18 lb/gal. and more preferably about 9 to about 15 lb/gal. Such solids, or weighting agents, which serve to increase the density of the drilling fluids, may be any solids known to those skilled in the art as useful for such purpose, but will preferably be inert or environmentally friendly.
Drilling fluids used in this invention may optionally also contain other additives known to those skilled in the art, such as fluid-loss control additives and emulsifiers. Alkali may also be used, preferably lime (calcium hydroxide or calcium oxide), to bind or react with acidic gases (such as CO2 and H2S) encountered during drilling in the formation. Such alkali, or an alkali reserve, is known to prevent hydrolysis by acidic gases of generally acid-labile esters of the drilling fluid. Preferred quantities of free lime in the drilling fluids range from about 1 to about 10 lbs/bbl, and more preferably about 1 to about 4 lbs/bbl, although lower ranges such as less than about 2 lbs/bbl are preferred for certain esters that tend to hydrolyze in the presence of alkaline compounds as will be known to those skilled in the art. Other suitable agents as an alternative to lime may also be used to adjust and/or stabilize invert emulsions of the drilling fluids with respect to acids. An example of such alternative agents is a protonated amine, as described in U.S. Pat. No. 5,977,031.
Further optional additives that may be present in the drilling fluids used in this invention include electrolytes, such as calcium chloride, organophilic bentonite and organophilic lignite. Glycols and/or glycerol may also be added. Still further, dispersion aids, corrosion inhibitors and/or defoamers may be used. These and other suitable auxiliaries and additives are used in amounts known to those skilled in the art depending on the conditions of the particular wellbore and subterranean formation.
Although the invention has primarily been described in the context of a method of using compounds of formula (I) as thinners for drilling fluids at low temperatures, the compounds of formula (I) may also be effective as thinners for well service fluids such as spotting fluids or workover fluids at low temperatures.
Further description and use of the invention is shown by the following examples:
EXAMPLES
To show the effect of the invention, the following experiments were conducted. In each case an invert emulsion drilling mud system of the following general composition was prepared:

















Ester
bbl
0.496



Water
bbl
0.233



Emulsifier
lb
6.0



Organophilic bentonite
lb
1.0



Organophilic lignite
lb
5.0



Alkali reserve (lime)
lb
1.5



CaCl2 × 2 H2O
lb
27.2



Barite
lb
314.0



Dispersing auxiliary
lb
0.5



Thinner
lb/bbl
2.0










The oil phase (A) used was a 2-ethylhexyl octanoate as disclosed in EP 0 386 636. The emulsifier used was the product EZ MUL NTE (Baroid Drilling Fluids Inc., Houston, Tex.). The oil/water ratio was 70/30 in each case. Measurements were carried out on a system without thinner (C1), and with a C12/14 fatty alcohol sulfate +2 EO, sodium salt (C2), with a C12 ether sulfate, sodium salt (C3) and with an oleic acid sulfonate disodium salt (C4), respectively, as prior art thinners, and comparison was made with these thinners and with compounds of formula (I) in accordance with the invention. The formula (I) compounds used for this purpose were as follows:

    
    
        E1 C12/C14 fatty alcohol containing 2 EO and 4 PO
        E2 C12/C14 fatty alcohol containing 5 EO and 4 PO
        E3 C12/C18 fatty alcohol containing 5 EO and 4 PO
        E4 C12/C14 fatty alcohol containing 6 EO and 4 PO
    
    


The invert muds were prepared in a conventional manner and subsequently, at 40° F. and 122° F., the rheological characteristics of plastic viscosity (PV) and yield point (YP) and the gel strength after 10 seconds and 10 minutes using a Fann SR12 rheometer (from Fann) were determined.
Measurements E5, E6 and E7 were carried out using the thinners E1, E2 and E4, but in contrast to the details above, 45 lb of solids (rev dust, i.e., filter ash) were also added to each of the muds, in order to demonstrate the advantageous action of the compounds of formula (I) used in accordance with the invention in the case of high solids loading of the emulsions. In these cases, the measurements were taken only after 16 hours of aging at 150° F. The thinner was not added to the muds E5 to E7 until after aging.
The results of the measurements are given in Tables 1a and 1b below.
























TABLE 1a







C1
C1
C2
C2
C3
C3
C4
C4
E1
E1
E2
E2
E3
E3
E4
E4
































Temp.
40
122
40
122
40
122
40
122
40
122
40
122
40
122
40
122


° F.


PV
94
28
105
30
n.m.
33
91
24
93
31
87
28
94
28
83
29


(cP)


YP
68
29
71
35
n.m.
62
69
20
70
41
34
33
62
41
30
30


lb/100 ft2


Gels
27/29
12/13
24/29
15/15
n.m.
26/31
25/25
6/7
25/28
17/19
11/13
14/16
20/24
17/18
8/11
13/14


10′′/10′





n.m: not measurable













TABLE 1b







Measurements with addition of 45 lb rev dust
















C1
C1
E5
E5
E6
E6
E7
E7



















Temperature
40
122
40
122
40
122
40
122


° F.


PV
94
28
107
37
108
40
106
37


(cP)


YP
68
29
37
23
72
42
46
30


lb/100 ft2


Gels
27/29
12/13
12/14
7/9
26/30
14/18
17/19
12/14


10′′/10′









The data, especially for the yield point (YP), clearly indicate the advantageous thinning effect of the compounds of formula (I) used in the method and in the emulsions of the invention, especially at low temperatures, in comparison to the prior art. The higher plastic viscosity for E5 to E7 is attributable to the higher proportion of solids in the mud systems.
Further experiments may be seen in Tables 2 to 9. In these cases, the yield point (YP) of the systems tested was investigated at different temperatures and depicted as a graph. This illustrates particularly well the advantageous influence of the compounds of formula (I) on the rheology at low temperatures (40° F., 4° C.) without any marked influence at high temperatures (120° F., 50° C.). The measurements were carried out using a Fann 35 viscometer (from Fann). The tables also indicate the dial readings at different speeds of rotation per minute (rpm).
In Tables 2 to 9:


    
    
        PETROFREE LV® (is 2-ethylhexyl octanoate (from Cognis, Germany)
        PETROFREE LE® is linear alpha-olefin (from Cognis, Germany)
        PETROFREE® is C8-14 fatty acid 2-ethylhexyl ester (from Cognis, Germany)
        GELTONE II® is organophilic bentonite (from Baroid, Houston, Tex.)
        Thinner E1 is Formula I C12/C14 fatty alcohol of the invention containing 2 EO and 4 PO
        Thinner E2 is Formula I C12/C14 fatty alcohol of the invention containing 5 EO and 4PO
    
    










TABLE 2







Mud system
PETROFREE LV


Mud weight, lb/gal
14.0


Oil/water ratio
70/30


Contaminant
Drill solids










E2, lb/bbl
0
3
5













Temperature, ° F.
40
120
40
120
40
120


Plastic viscosity, cP
118
40
113
34
107
35


Yield point, lb/100 ft2
38
14
25
14
19
13


10 sec gel, lb/100 ft2
16
6
10
6
6
6


10 min gel, lb/100 ft2
22
11
13
8
9
8







Fann 35 dial readings













600 rpm
274
94
251
82
233
83


300 rpm
156
54
138
48
126
48


200 rpm
114
40
97
35
88
35


100 rpm
70
25
56
22
49
22


 6 rpm
17
6
10
7
7
6


 3 rpm
14
5
7
6
5
5




















TABLE 3









Mud system
PETROFREE




Mud weight, lb/gal
14.0



Oil/water ratio
75/25



Contaminant
Excess GELTONE II













E2, lb/bbl
0

3














Temperature, ° F.
40
120
40
120



Plastic viscosity, cP
180
51
126
50



Yield point, lb/100 ft2
230
152
19
125



10 sec gel, lb/100 ft2
108
64
10
50



10 min gel, lb/100 ft2
110
66
13
52







Fann 35 dial readings













600 rpm
590
254
271
225



300 rpm
410
203
145
175



200 rpm
336
179
103
149



100 rpm
248
146
59
119



 6 rpm
112
79
10
62



 3 rpm
100
70
8
58





















TABLE 4









Mud system
PETROFREE LV




Mud weight, lb/gal
16.0



Oil/water ratio
80/20



Contaminant
Drill solids













E2, lb/bbl
0

3














Temperature, ° F.
40
120
40
120



Plastic viscosity, cP
152
51
142
40



Yield point, lb/100 ft2
62
27
40
19



10 sec gel, lb/100 ft2
22
10
18
10



10 min gel, lb/100 ft2
48
26
22
12







Fann 35 dial readings













600 rpm
366
129
324
99



300 rpm
214
78
182
59



200 rpm
158
59
130
45



100 rpm
98
38
78
30



 6 rpm
24
11
16
10



 3 rpm
20
9
12
9





















TABLE 5









Mud system
PETROFREE




Mud weight, lb/gal
11.0



Oil/water ratio
70/30



Contaminant
Excess GELTONE II













E2, lb/bbl
0

3














Temperature, ° F.
40
120
40
120



Plastic viscosity, cP
132
31
88
29



Yield point, lb/100 ft2
54
53
37
53



10 sec gel, lb/100 ft2
33
23
13
26



10 min gel, lb/100 ft2
38
27
17
30







Fann 35 dial readings













600 rpm
318
115
213
111



300 rpm
186
84
125
82



200 rpm
139
71
90
70



100 rpm
91
54
56
55



 6 rpm
35
25
15
28



 3 rpm
32
21
13
25





















TABLE 6









Mud system
PETROFREE




Mud weight, lb/gal
11.0



Oil/water ratio
70/30



Contaminant
Drill solids













E2, lb/bbl
0

3














Temperature, ° F.
40
120
40
120



Plastic viscosity, cP
110
34
113
34



Yield point, lb/100 ft2
90
47
73
44



10 sec gel, lb/100 ft2
38
21
27
20



10 min gel, lb/100 ft2
44
24
30
22







Fann 35 dial readings













600 rpm
310
115
299
112



300 rpm
200
81
186
78



200 rpm
157
67
142
64



100 rpm
110
50
95
48



 6 rpm
42
23
31
22



 3 rpm
38
21
27
19





















TABLE 7









Mud system
PETROFREE LE




Mud weight, lb/gal
16.4













E2, lb/bbl
0

3














Temperature, ° F.
40
120
40
120



Plastic viscosity, cP
173
40
107
43



Yield point, lb/100 ft2
21
9
18
7



10 sec gel, lb/100 ft2
16
8
11
8



10 min gel, lb/100 ft2
19
11
15
11







Fann 35 dial readings













600 rpm
367
89
232
93



300 rpm
194
49
125
50



200 rpm
135
35
88
37



100 rpm
74
22
50
22



 6 rpm
12
5
9
6



 3 rpm
10
4
7
5





















TABLE 8









Mud system
PETROFREE LE




Mud weight, lb/gal
11.6













E2, lb/bbl
0

3














Temperature, ° F.
40
120
40
120



Plastic viscosity, cP
80
31
56
32



Yield point, lb/100 ft2
25
18
27
16



10 sec gel, lb/100 ft2
12
8
17
9



10 min gel, lb/100 ft2
20
11
23
11







Fann 35 dial readings













600 rpm
185
80
139
80



300 rpm
105
49
83
48



200 rpm
77
37
63
37



100 rpm
46
24
43
24



 6 rpm
11
7
14
8



 3 rpm
9
6
13
7





















TABLE 9









Mud system
PETROFREE LV




Mud weight, lb/gal
14.0



Oil/water ratio
70/30



Contaminant
Drill solids













E1, lb/bbl
0

3














Temperature, ° F.
40
120
40
120



Plastic viscosity, cP
118
40
113
35



Yield point, lb/100 ft2
38
14
41
16



10 sec gel, lb/100 ft2
16
6
16
9



10 min gel, lb/100 ft2
22
11
20
11







Fann 35 dial readings













600 rpm
274
94
267
86



300 rpm
156
54
154
51



200 rpm
114
40
114
39



100 rpm
70
25
71
26



 6 rpm
17
6
18
8



 3 rpm
14
5
14
8










The foregoing description of the invention is intended to be a description of preferred embodiments. Various changes in the details of the described composition and method can be made without departing from the intended scope of this invention as defined by the appended claims.

## Claims

1. A method of influencing the rheology of a drilling fluid or well service fluid comprising an invert emulsion, said method comprising adding to said drilling fluid or well service fluid a compound having the formula:


R—(C2H4O)n(C3H6O)m(C4H8—O)k—H


where R is a saturated or unsaturated, linear or branched alkyl radical having about 8 to about 24 carbon atoms, n is a number ranging from about 1 to about 10, m is a number ranging from about 1 to about 10, and k is a number ranging from about 0 about 10, such that the ratio of n to m ranges from about 1:1 to about 2:1, and wherein said compound reduces the viscosity and/or lowers the yield point of the drilling fluid or well service fluid at temperatures at or below about 50° F., and wherein the compound is added i) during drilling or ii) when the drilling fluid or well service fluid is circulating in a subterranean formation.

2. The method of claim 1 wherein in said formula, k is zero and the ratio of n to m is about 2:1.5.

3. The method of claim 1 wherein in said formula, n is a number ranging from about 1 to about 6, m is a number ranging front about 1 to about 6, and k is zero.

4. The method of claim 1 wherein said invert emulsion to which said compound has been added comprises a continuous oil phase comprising compounds or compositions flowable and pumpable at temperatures at least as low as about 40 degrees Fahrenheit.

5. The method of claim 4 wherein said oil phase comprises synthetic compounds or compositions selected from the group consisting of: (a) carboxylic esters of the formula: R′—COO —R′′ where R′ is a saturated or unsaturated, linear or branched, alkyl radical having about 1 to about 23 carbon atoms and R′′ is an alkyl radical, branched or unbranched, saturated or unsaturated, having about 1 to about 23 carbon atoms; (b) linear or branched olefins having about 8 to about 30 carbon atoms; (c) water-insoluble symmetric or asymmetric ethers of monohydric alcohols of natural or synthetic origin, said alcohols containing about 1 to about 24 carbon atoms; (d) water-insoluble alcohols of the formula: R′′′—OH where R′′′ is a saturated, unsaturated, linear or branched alkyl radical having about 8 to 24 carbon atoms; and (e) carbonic diesters.

6. The method of claim 1 wherein said compound is added to said drilling fluid or well service fluid in an amount of about 0.5 to about 1 pound per barrel of said drilling fluid or well service fluid.

7. The method of claim 1 wherein said compound is added to said drilling fluid or well service fluid in quantities ranging from about 0.5 pounds to about 15.0 pounds of said compound per barrel of said drilling fluid or well service fluid.

8. The method of claim 1 wherein said compound does not significantly affect the viscosity of said fluid at temperatures ranging from about 100° F. to about 250° F.

9. The method of claim 1 wherein said compound is also added to said fluid when said fluid is prepared.

10. The method of claim 1 wherein said compound is added to said fluid while said fluid is circulating in a wellbore.

11. The method of claim 1 wherein, in said formula, R has about 12 to about 18 carbon atoms, n and m each have values of about 4 or about 5 and k is zero.

12. The method of claim 1 wherein said compound reduces the viscosity of the drilling fluid at 50° F.

13. The method of claim 1 wherein said compound reduces the viscosity of the drilling fluid at temperatures below 50° F.

14. The method of claim 1 wherein said compound lowers the yield point of the drilling fluid at 50° F.

15. The method of claim 1 wherein said compound lowers the yield point of the drilling fluid at temperatures below 50° F.

16. A method of reducing the viscosity of an invert emulsion drilling fluid or well service fluid at temperatures less than about 50° F. without significantly affecting the viscosity of the fluid at temperatures in the range of about 100° F. to about 250° F., said method comprising adding to said fluid an effective amount of thinner compound having the formula:


R—(C2H4O)n(C3H6O)m(C4H8O)k—H


where R is a saturated or unsaturated, linear or branched alkyl radical having about 8 to about 24 carbon atoms, n is a number ranging from about 1 to about 10, m is a number ranging from about 1 to about 10, such that the ratio of n to m ranges from about 1:1 to about 2:1 and k is a number about 0 and the viscosity of the fluid is reduced at temperatures less than about 50° F. without significantly being affected at temperatures in the range of about 100° F. to about 250° F.; and wherein the oil phase of the invert emulsion is synthetic, comprising about 50% to about 100% compounds or compositions selected from the group consisting of: (a) carboxylic esters of the formula: R′—COO—R′′ where R′ is a saturated or unsaturated, linear or branched, alkyl radical having about 1 to about 23 carbon atoms and R′′ is an alkyl radical, branched or unbranched, saturated or unsaturated, having about 1 to about 23 carbon atoms; (b) linear or branched olefins having about 8 to about 30 carbon atoms; (c) wafer-insoluble symmetric or asymmetric ethers of monohydric alcohols of natural or synthetic origin, said alcohols containing about 1 to about 24 carbon atoms; (d) water-insoluble alcohols of the formula: R′′′—OH where R′′′ is a saturated, unsaturated, linear or branched alkyl radical having about 8 to about 24 carbon atoms; and (e) carbonic diesters, wherein said thinner compound is added i) during drilling or ii) when the fluid is circulating in a subterranean formation.

17. The method of claim 16 further comprising circulating said fluid in a wellbore and adding said compound to said fluid during said circulation.

18. The method of claim l6 further comprising preparing said fluid and wherein the compound is also added.

19. The method of claim 16 wherein in the first formula n and m have a ratio of 2:1.5.

20. The method of claim 16 wherein, after the thinner compound has been added, the fluid has a yield point in the range of about 5 to about 45 lb/100ft2 at about 40° F.