WO2004044087A1

WO2004044087A1 - Invert drilling fluids and methods of drilling boreholes

Info

Publication number: WO2004044087A1
Application number: PCT/GB2003/004887
Authority: WO
Inventors: Jeff Kirsner; Don Siems; Kimberly Burrows-Lawson; David Carbajal; Ian Robb; Dale E. Jamison
Original assignee: Halliburton Energy Services, Inc; Wain, Christopher, Paul
Priority date: 2002-11-12
Filing date: 2003-11-12
Publication date: 2004-05-27
Also published as: US20070078060A1; US20070078061A1; US7547663B2; US7488704B2; US7534743B2; US7462580B2; US20070078062A1; US20070082822A1; US20030144153A1; US7456135B2; AU2003283554A1

Abstract

Methods for drilling, running casing in, and/or cementing a borehole in a subterranean formation without significant loss of drilling fluid are disclosed, as well as compositions for use in such methods. The methods employ drilling fluids comprising fragile gels or having fragile gel behavior and providing superior oil mud rheology and overall performance. The fluids are especially advantageous for use in offshore wells because the fluids exhibit minimal differences between downhole equivalent circulating densities and surface densities notwithstanding differences in drillign or penetration rates. When an ester and isomerized olefin blend is used for the base of the fluids, the fluids make environmentally acceptable and regulatory compliant invert emulsion drilling fluids.

Description

INVERT DRILLING FLUIDS AND METHODS OF DRILLING BOREHOLES

[0001] This invention relates to invert drilling fluids and methods of drilling boreholes.

[0002] More particularly, the present invention relates to compositions and methods for drilling, cementing and(- — — 1 casing boreholes in subterranean formations, particularly hydrocarbon bearing formations. More particularly, the present invention relates to oil or synthetic fluid based drilling fluids and fluids comprising invert emulsions, such as fluids using esters for example, which combine high ecological compatibility with good stability and performance properties.

[0003] A drilling fluid or mud is a specially designed fluid that is circulated through 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.

[0004] Oil or synthetic fluid-based muds are normally used to drill swelling or sloughing shales, salt, gypsum, anhydrite or other evaporate formations, hydrogen sulfide-containing formations, and hot (greater than about 300 degrees Fahrenheit ("° F") holes, but may be used in other holes penetrating a subterranean formation as well. Unless indicated otherwise, the terms "oil mud" or "oil-based mud or drilling fluid" shall be understood to include synthetic oils or other synthetic fluids as well as natural or traditional oils, and such oils shall be understood to comprise invert emulsions.

[0005] Oil-based muds used in drilling typically comprise: a base oil (or synthetic fluid) comprising the external phase of an invert emulsion; a saline, aqueous solution (typically a solution comprising about 30% calcium chloride) comprising the internal phase of the invert emulsion; emulsifiers at the interface of the internal and external phases; and other agents or additives for suspension, weight or density, oil-wetting, fluid loss or filtration control, and rheology control. Such additives commonly include organophilic clays and organophilic lignites. See H.C.H. Darley and George R. Gray, Composition and Properties of Drilling and Completion Fluids 66-67, 561-562 (5^th ed. 1988). An oil-based or invert emulsion-based drilling fluid may commonly comprise between about 50:50 to about 95:5 by volume oil phase to water phase. An all oil mud simply comprises 100% liquid phase oil by volume; that is, there is no aqueous internal phase.

[0006] Invert emulsion-based muds or drilling fluids (also called invert drilling muds or invert muds or fluids) comprise a key segment of the drilling fluids industry. However, increasingly invert emulsion-based drilling fluids have been subjected to greater environmental restrictions and performance and cost demands. There is consequently an increasing need and industry-wide interest in new drilling fluids that provide improved performance while still affording environmental and economical acceptance.

[0007] The present invention provides improved methods of drilling wellbores in subterranean formations employing oil-based muds, or more particularly, invert emulsion-based muds or drilling fluids. As used herein, the term "drilling" or "drilling wellbores" shall be understood in the broader sense of drilling operations, which include running casing and cementing as well as drilling, unless specifically indicated otherwise. The present invention also provides invert emulsion based drilling fluids for use in the methods of the invention to effect the advantages of the invention.

[0008] The methods of the invention comprise using a drilling fluid that is not dependent on organophilic clays (also called "organo-clays") to obtain suspension of drill cuttings or other solids. Rather, the drilling fluid comprises a synergistic combination of an invert emulsion base, thinners. and/or other additives that form a "fragile gel" or show "fragile gel" behavior when used in drilling. The fragile gel structure of the drilling fluid is believed to provide or enable suspension of drill cuttings and other solids.

[0009] The fragile gel drilling fluids of the invention, for use in the methods of the invention, are characterized by their performance. When drilling is stopped while using a fluid of the invention, and consequently when the stresses or forces associated with drilling are substantially reduced or removed, the drilling fluid acts as a gel, suspending/continuing to suspend drill cuttings and other solids (such as for example weighting materials) for delivery to the well surface. Nevertheless, when drilling is resumed, the fluid is flowable, acting like a liquid, with no appreciable or noticeable pressure spike as observed by pressure-while-drilling (PWD) equipment or instruments. During drilling, the fluids of the invention generally maintain consistently low values for the difference in their surface density and their equivalent density downhole (ECDs) and show significantly reduced loss when compared to other drilling fluids used in that formation or under comparable conditions. "Sag" problems do not tend to occur with the fluids when drilling deviated wells. The phenomenon of "sag," or "barite sag" is discussed below. Also, the fluids respond quickly to the addition of thinners, with thinning of the fluids occurring soon after the thinners are added, without need for multiple circulations of the fluids with the thinners additive or additives in the wellbore to show the effect of the addition of the thinners. The fluids of the invention also yield flatter profiles between cold water and downhole rheologies, making the fluids advantageous for use in offshore wells. That is, the fluids may be thinned at cold temperatures without causing the fluids to be comparably thinned at higher temperatures.

[0010] Laboratory tests may be used to generally identify or distinguish a drilling fluid of the invention. These tests measure elastic modulus and yield point and are generally conducted on laboratory-made fluids having an oikwater ratio of about 70:30. Generally, a fluid of the present invention at these laboratory conditions/specifications will have an elastic modulus ratio of G'ιo G'₂oo (as defined herein) greater than about 2. Furthermore, a fluid of the present invention at these laboratory conditions/specifications will have a yield point (measured as described herein) of less than about 3 Pa.

[0011] Another test, useful for distinguishing a drilling fluid of the invention using field mud samples, is a performance measure called "Stress Build Function." This measure is an indication of the fragile gel structure building tendencies that are effectively normalized for the initial yield stress (TauO). The "Stress Build Function" is defined as follows: SBF 1 Om = (gel strength at 10 minutes - TauO)/ TauO Generally, a field mud of the present invention will have an SBF 10m of greater than about 3.8. [0012] Although the invention is characterized primarily as identifying characteristics or features of an invert emulsion drilling fluid that yield superior performance for use in drilling, certain example compositions also provide significant benefits in terms of environmental acceptance or regulatory compliance. An example of a suitable base is a blend of esters with isomerized or internal olefins ("the ester blend") as described in United States Patent Application Serial No. 09/929,465, of Jeff Kirsner (co-inventor of the present invention), Kenneth W. Pober and Robert W. Pike, filed August 14, 2001, entitled "Blends of Esters with Isomerized Olefins and Other Hydrocarbons as Base Oils for Invert Emulsion Oil Muds, the entire disclosure of which is incorporated herein by reference. The esters in the blend may be any quantity, but preferably should comprise at least about 10 weight percent to about 99 weight percent of the blend and the olefins should preferably comprise about 1 weight percent to about 99 weight percent of the blend. The esters of the blend are preferably comprised of fatty acids and alcohols and most preferably about Cβ to about C*₄ fatty acids and 2-ethyl hexanol. Esters made in ways other than with fatty acids and alcohols, for example, esters made from olefins combined with either fatty acids or alcohols, could also be effective.

[0013] Further, such environmentally acceptable examples of invert emulsion drilling fluids have added to or mixed with them other fluids or materials needed to comprise a complete drilling fluid. Such materials may include, for example: additives to reduce or control temperature rheology or to provide thinning, for example, additives having the tradenames COLDTROL®, ATC®, and OMC2™; additives for enhancing viscosity, for example, an additive having the tradename RHEMOD L™; additives for providing temporary increased viscosity for shipping (transport to the well site) and for use in sweeps, for example, an additive having the tradename TEMPERUS™ (modified fatty acid); additives for filtration control, for example, additives having the tradename ADAPTA®; additives for high temperature high pressure control (HTHP) and emulsion stability, for example, additives having the tradename FACTANT™ (highly concentrated tall oil derivative); and additives for emulsification, for example, additives having the tradename LE SUPERMUL™ (polyaminated fatty acid). All of the aforementioned trademarked products are available from Halliburton Energy Services, Inc. in Houston, Texas, U.S.A.

[0014] Thinners disclosed in International Patent Application Nos. PCT/US00/35609 and PCT/US00/35610 of Halliburton Energy Services, Inc., Cognis Deutschland GmbH & Co KG., Heinz Muller, Jeff Kirsner (co-inventor of the present invention) and Kimberly Burrows (co- inventor of the present invention), both filed December 29, 2000 and entitled "Thinners for Invert Emulsions," and both disclosures of which are incorporated entirely herein by reference, are particularly useful in the present invention for effecting "selective thinning" of the fluid of the present invention; that is thinning at lower temperatures without rendering the fluid too thin at higher temperatures.

[0015] However, as previously noted, preferably no organophilic clays are added to the drilling fluid for use in the invention. Any characterization of the drilling fluid herein as "clayless" shall be understood to mean lacking organophilic clays. Although omission of organophilic clays is a radical departure from traditional teachings respecting preparation of drilling fluids, this omission of organophilic clays in preferred embodiments of the present invention allows the drilling fluid to have greater tolerance to drill solids (i.e., the properties of the fluid are not believed to be readily altered by the drill solids or cuttings) and is believed (without limiting the invention by theory) to contribute to the fluid's superior properties in use as a drilling fluid.

Reference is now made to the accompanying drawings, in which:

[0016] Figures 1(a), 1(b) and 1(c) provide three graphs showing field data comparing fluid losses incurred during drilling, running casing and cementing with a prior art isomerized olefin fluid and with a fluid of the present invention. Figure 1(a) shows the total downhole losses;

Figure 1(b) shows the barrels lost per barrel of hole drilled; and Figure 1(c) shows the barrels lost per foot.

[0017] Figure 2 is a graph comparing fluid loss incurred running casing and cementing in seven boreholes at various depths, where the fluid used in the first three holes was a prior art isomerized olefin fluid and the fluid used in the last four holes was a fluid of the present invention.

[0018] Figure 3 is a graph indicating "fragile gel" formation in fluids of the present invention and their response when disrupted compared to some prior art isomerized olefin fluids.

[0019] Figure 4 is a graph comparing the relaxation rates of various prior art drilling fluids and fluids of the present invention.

[0020] Figure 5(a) is a graph comparing the differences in well surface density and the equivalent circulating density for a prior art isomerized olefin fluid and for a fluid of the invention in two comparable wells. Figure 5(b) shows the rate of penetration in the wells at the time the density measurements for Figure 5(a) were being taken.

[0021] Figure 6 is a graph comparing the differences in well surface density and the equivalent circulating density for a fluid of the invention with a flowrate of 704 to 811 gallons per minute in a 12 ! inch borehole drilled from 9,192 ft to 13,510 ft in deep water and including rate of penetration.

[0022] Figure 7 is a graph comparing the differences in well surface density and the equivalent circulating density for a fluid of the invention with a flowrate of 158 to 174 gallons per minute in a 6 ' _ inch borehole drilled from 12,306 ft to 13,992 ft and including rate of penetration.

[0023] Figure 8 is a graph comparing the differences in well surface density and the equivalent circulating density for a fluid of the invention at varying drilling rates from 4,672 ft to 12,250 ft, and a flowrate of 522 to 586 gallons per minute in a 9 7/8" borehole.

[0024] Figure 9(a) is a bar graph comparing the yield point of two densities of a^' fluid of the invention at standard testing temperatures of 40° F and 120° F. Figures 9(b) and (c) are graphs of the FANN® 35 instrument dial readings for these same two densities of a fluid of the invention over a range of shear rates at standard testing temperatures of 40° F and 120° F. .

[0025] Figure 10 is a graph comparing the viscosity of various known invert emulsion bases for drilling fluids with the invert emulsion base for a drilling fluid of the present invention.

[0026] Figure 1 1 is a graph showing the Stress Build Function for several prior art field muds compared to the Stress Build Function for a field sample of a fluid of the present invention.

[0027] Figure 12 is a graph showing bioassay results for a 96-hour sediment toxicity test with

Leptocheirus plumulosus, comparing a reference internal olefin to laboratory and field mud samples of the ACCOLADE™ system.

[0028] The present invention provides an invert drilling fluid that meets environmental constraints and provides improved performance in the field. The fluid does not rely on organophilic clays to obtain suspension of barite or drill cuttings, in contrast to other fluids used commercially today. Some of the other characteristics that further distinguish the fluid of the present invention from prior art invert fluids are: (1) lack of noticeable or significant pressure spikes (as detected for example with pressure-while-drilling or PWD equipment or instruments) when resuming pumping after a period of rest during drilling; (2) rapid incorporation of additives while pumping; (3) little or no sag of barite or other solids, including drill cuttings; (4) reduction in fluid losses during drilling; and (5) low ECDs. These characteristics will be further explained and discussed below.

[0029] The distinctive characteristics of the fluid of the present invention are believed to be due to a synergistic combination of base oils comprising the fluid. Without limiting the invention by theory, the combination is believed to have the effect of forming a "fragile gel." A "gel" may be defined a number of ways. One definition indicates that a "gel" is a generally colloidal suspension or a mixture of microscopic water particles (and any hydrophilic additives) approximately uniformly dispersed through the oil (and any hydrophobic additives), such that the fluid or gel has a generally homogeneous gelatinous consistency. Another definition states that a "gel" is a colloid in a more solid form than a "sol" and defines a "sol" as a fluid colloidal system, especially one in which the continuous phase is a liquid. Still another definition provides that a "gel" is a colloid in which the disperse phase has combined with the continuous phase to produce a viscous jelly-like product. Generally, a gel has a structure that is continually building. If the yield stress of a fluid increases over time, the fluid has gelled. "Yield stress" is the stress required to be exerted to initiate deformation.

[0030] A "fragile gel" as used herein is a "gel" that is easily disrupted or thinned, and that liquifies or becomes less gel-like and more liquid-like under stress, such as caused by moving the fluid, but which quickly returns to a gel or gel-like state when the movement or other stress is alleviated or removed, such as when circulation of the fluid is stopped, as for example when drilling is stopped. The "fragileness" of the "fragile gels" of the present invention contributes to the unique and surprising behavior and advantages of the present invention. The gels are so "fragile" that it is believed that they may be disrupted by a mere pressure wave or a compression wave during drilling. They break instantaneously when disturbed, reversing from a gel back into a liquid form with minimum pressure, force and time and with less pressure, force and time than known to be required to convert prior art fluids from a gel-like state into a flowable state. [0031] In contrast, conventional drilling fluids, using clays to achieve suspension of solids (such as barite and drill cuttings) are believed to have linked or interlinked clay particles providing structure. That is, organo-clays, which are typically formed from montmorillonite treated with a di-alkyl cationic surfactant, swell in non-polar organic solvents, forming open aggregates. This structure, combined with the volume occupied by water droplets is believed to be the main suspending mechanism for barite and other inorganic materials in conventional invert drilling fluids. Mixing additives into the oil/clay suspended system is slower than mixing additives into drilling fluids of the invention.

[0032] The drilling fluids of the invention respond quickly to the addition of thinners, with thinning of the fluids occurring soon after the thinners are added, without need for multiple circulations of the fluids with the thinners additive or additives in the wellbore to show the effect of the addition of the thinners. This characteristic provides the drilling operator with the ability to control the fluid rheology "on-the-fly" and "on-command" from the wellbore surface, facilitating control of fluid rheological properties real time. Also, once returned to the surface, the thinner can be used to help separate the solids or drill cuttings from the drilling fluid. This same drilling fluid, after its base fluid has been replenished with requisite additives for fragile gel behavior, can be recycled back into the well for additional drilling. This ability for recycling provides another important advantage of the invention with respect to minimizing disposal costs and environmental issues related to fluid disposal.

[0033] The drilling fluids of the invention also yield flatter profiles between cold water and downhole rheologies, making the fluids advantageous for use in deep water wells. That is, the fluids may be thinned at cold temperatures without causing the fluids to be comparably thinned at higher temperatures. As used herein, the terms "deep water" with respect to wells and "higher" and "lower" with respect to temperature are relative terms understood by one skilled in the art of the oil and gas industry. However, generally, as used herein, "deep water wells" refers to any wells at water depths greater than about 1500 feet deep, "higher temperatures" means temperatures over about 120° F and "lower temperatures" means temperatures at about 40° F to about 60° F. Rheology of a drilling fluid is typically measured at about 120° F or about 150° F. [0034] Another distinctive and advantageous characteristic or feature of the drilling fluids of the invention is that sag does not occur or does not significantly occur when the fluids are used in drilling deviated wells. Suspensions of solids in non-vertical columns are known to settle faster than suspensions in vertical ones, due to the "Boycott effect." This effect is driven by gravity and impeded by fluid rheology, particularly non-Newtonian and time dependent rheology. Manifestation of the Boycott effect in a drilling fluid is known as "sag." Sag may also be described as a "significant" variation in mud density (> 0.5 to 1 pound per gallon ) along the mud column, which is the result of settling of the weighting agent or weight material and other solids in the drilling fluid. Sag can result in formation of a bed of the weighting agent on the low side of the wellbore, and stuck pipe, among other things. In some cases, sag can be very problematic to the drilling operation and in extreme cases may cause hole abandonment. [0035] The fragile gel nature of the invention also contributes to the reduced loss of drilling fluid observed in the field when using the fluid and to the relatively low "ECDs" obtained with the fluid. The difference in a drilling fluid's measured surface density at the well head and the drilling fluid's equivalent circulating density downhole (as typically measured during drilling by downhole pressure-while-drilling (PWD) equipment) is often called "ECD" in the industry. Low "ECDs", that is, a minimal difference in surface and downhole equivalent circulating densities, is critical in drilling deep water wells and other wells where the differences in subterranean formation pore pressures and fracture gradients are small.

[0036] Three tests may be used to distinguish drilling fluids of the invention from clay- suspended, (i.e., traditional) fluids. Two of these tests are conducted with laboratory prepared fluids and the third test is conducted with samples of field muds — fluids that have already been used in the field. The two tests with laboratory fluids concern measurement of elastic modulus and yield point and apply to lab-made fluids having a volume ratio of 70/30 oil/water. Generally, drilling fluids of the present invention at these laboratory conditions/specifications will have an elastic modulus ratio of G'ι₀/G'₂₀o greater than about 2 and a yield point less than about 3 Pa. These tests are discussed further below using an example drilling fluid of the invention. The example drilling fluid, tradename ACCOLADE™, is available from Halliburton Energy Services, Inc. in Houston, Texas. Test 1: Ratio of G'ι₀/G'₂oo •

[0037] Table 1 provides data taken with smooth parallel plate geometry. The elastic modulus (G') was measured using 35mm parallel plate geometry at a separation of 1mm on a Haake RS 150 controlled stress rheometer. The applied torque was < lPa, inside the linear viscoelastic region for each sample. The elastic modulus was measured after 10 seconds (G' IO) and after 200 seconds (G'₂₀o), and the ratio of G'_!0/G'₂oo is shown in Table 1. All the samples in Table 1 were of drilling fluids having 1 1.0 pounds per gallon ("ppg" or "lb ./gal.") total density and a base oil: water volume ratio of 70:30.

TABLE 1

Ratios of G'i₀/G'₂oo for various drilling fluids 1 1.0 ppg Oil: water of 70:30

Similar data were found for an ACCOLADE™ fluid of 14.0 ppg, for which G' ιo/G'₂₀o was 4.2 Test 2: Yield points.

[0038] The drilling fluids of the invention have an unusually low yield point, measured at low shear rate. The yield point in this test is the torque required to just start a system moving from rest. This point is selected for the measurement because low shear rates remove inertial effects from the measurement and are thus a truer measure of the yield point than measurements taken at other points. The Haake RS 150 rheometer measured the yield point (τ in units of Pascals, Pa) as the shear rate increased through 0.03, 0.1, 1.0, 3.0 and 10.0s^"1. It was found that τ increased with shear rate, and the value at 0.03 s^"1 was taken as the true yield point. [0039] The program for measurement was as follows: a) steady shear at 10s^"1 for 30 seconds; b) zero shear for 600 seconds; c) steady shear at 0.03s^"1 for 60 seconds- take the highest torque reading; d) zero shear for 600 seconds; e) steady shear at 0.1 s^"1 for 60 seconds- take the highest torque reading; f) zero shear for 600 seconds; g) steady shear at 1.0 s^"1 for 60 seconds - take the highest torque reading; h) zero shear for 600 seconds; i) steady shear at 3.0s^"1 for 60 seconds- take the highest torque reading; j) zero shear for 600 seconds; and k) steady shear at 10 s^"1 for 60 seconds - take the highest torque reading. [0040] The measuring geometry was a 3 mm diameter stainless steel serrated plate, made by Haake with 26 serrations per inch, each serration 0.02 inches deep. As expected the maximum value of the torque to start shearing, as shown in Table 2, increased with shear rate and the value at the lowest shear rate (0.03s^'1) was taken as the yield point. All drilling fluids in Table 2 were 11.0 ppg with 70/30 oil/water volume ratio.

TABLE 2 Maximum torque (Pa) at increasing shear rates

[0041] While the ACCOLADE™ fluid or system (example drilling fluid of the invention) was comprised of a mixture of the two tradename PETROFREE® esters and the tradename PETROFREE® SF base oil tested separately, the yield point of the example drilling fluid of the invention was lower than the yield point of any of those individual components or their average. The ACCOLADE™ system's low yield point (1.6 Pa) is a reflection of the "fragile" nature of the ACCOLADE™ system of the invention and contributes to the excellent properties of that fluid of the invention. Further, these test results show a synergistic combination of the base oils to give this low yield point.

[0042] Field-based fluids (as opposed to laboratory fluids or muds) may yield varying results in the tests above because of the presence of other fluids, subterranean formation conditions, etc. Generally, experience has shown that the fluids of the invention often tend to yield better results in the field than in the lab. Some field test data will be presented and discussed further below. Test 3: Stress Build Function.

[0043] A test for distinguishing a drilling fluid of the invention using field mud samples is a performance measure called "Stress Build Function." This measure is an indication of the structure building tendencies that are effectively normalized for the initial yield stress (TauO). This measure also effectively normalizes for mud weight as well, since generally higher weight fluids have higher TauO values. The "Stress Build Function" is defined as follows:

SBF10m = (gel strength at 10 minutes - TauO)/ TauO Figure 11 shows data comparing the Stress Build Function for various field samples of prior art fluids with the Stress Build Function for a field sample of an example fluid of the present invention, ACCOLADE™ system. The prior art fluids included PETROFREE® SF and a prior art internal olefin fluid. All of this data was taken at 120° F using a FANN® 35, a standard six speed oilfield rheometer. Generally, a field mud of the present invention will have an SBF 10m of greater than about 3.8. Field muds having a SBFlOm as low as about 3.0, however, can provide some advantages of the invention.

[0044] While some organo-clay may enter the fluids in the field, for example due to mixing of recycled fluids with the fluids of the invention, the fluids of the invention are tolerant of such clay in quantities less than about 3 pounds per barrel, as demonstrated by the test data shown in Table 3 below. The fluids of the invention, however, behave more like traditional drilling fluids when quantities greater than about 3 pounds per barrel of organo-clays are present. GELTONE® II additive used in the test is a common organo-clay. ___ TABLE 3

Effects of Addition of Organo-Clays to ACCOLADE™ System

[0045] Any drilling fluid that can be formulated to provide "fragile gel" behavior is believed to have the benefits of the present invention. Any drilling fluid that can be formulated to have an elastic modulus ratio of G'ιo/G'₂_o greater than about 2 and/or a yield point measured as described above less than about 3 Pa is believed to have the benefits of the present invention. [0046] While the invert emulsion drilling fluids of the present invention have an invert emulsion base, this base is not limited to a single formulation. Test data discussed herein for an example formulation of an invert emulsion drilling fluid of the invention is for a drilling fluid comprising a blend of one or more esters and one or more isomerized or internal olefins ("ester blend") such as described in United States Patent Application Serial No. 09/929,465, of Jeff Kirsner (co- inventor of the present invention), Kenneth W. Pober and Robert W. Pike, filed August 14, 2001, entitled "Blends of Esters with Isomerized Olefins and Other Hydrocarbons as Base Oils for Invert Emulsion Oil Muds," the entire disclosure of which is incorporated herein by reference. In such blend, preferably the esters will comprise at least about 10 weight percent of the blend and may comprise up to about 99 weight percent of the blend, although the esters may be used in any quantity. Preferred esters for blending are comprised of about C₆ to about C_]4 fatty acids and alcohols, and are particularly or more preferably disclosed in U.S. Patent No. Re. 36,066, reissued January 25, 1999 as a reissue of U.S. Patent No. 5,232,910, assigned to Henkel KgaA of Dusseldorf, Germany, and Baroid Limited of London, England, and in U.S. Patent No. 5,252,554, issued October 12, 1993, and assigned to Henkel Kommanditgesellschaft auf Aktien of Dusseldorf, Germany and Baroid Limited of Aberdeen, Scotland, each disclosure of which is incorporated in its entirety herein by reference. Esters disclosed in U.S. Patent No. 5,106,516, issued April 21, 1992, and U.S. Patent No. 5,318,954, issued June 7, 1984, both assigned to Henkel Kommanditgesellschaft auf Aktien, of Dusseldorf, Germany, each disclosure of which is incorporated in its entirety herein by reference, may also (or alternatively) be used. The most preferred esters for use in the invention are comprised of about Cι₂ to about C^* fatty acids and 2-ethyl hexanol or about C₈ fatty acids and 2-ethyl hexanol. These most preferred esters are available commercially under tradenames PETROFREE® and PETROFREE® LV, respectively, from Halliburton Energy Services, Inc. in Houston, Texas. Although esters made with fatty acids and alcohols are preferred, esters made other ways, such as from combining olefins with either fatty acids or alcohols, may also be effective.

[0047] Isomerized or internal olefins for blending with the esters for an ester blend may be any such olefins, straight chain, branched, or cyclic, preferably having about 10 to about 30 carbon atoms. Isomerized, or internal, olefins having about 40 to about 70 weight percent

and about 20 to about 50 weight percent C-g are especially preferred. An example of an isomerized olefin for use in an ester blend in the invention that is commercially available is SF BASE™ fluid, available from Halliburton Energy Services, Inc. in Houston, Texas. Alternatively, other hydrocarbons such as paraffins, mineral oils, glyceride tri esters, or combinations thereof may be substituted for or added to the olefins in the ester blend. Such other hydrocarbons may comprise from about 1 weight percent to about 99 weight percent of such blend.

[0048] Invert emulsion drilling fluids may be prepared comprising SF BASE™ fluid without the ester, however, such fluids are not believed to provide the superior properties of fluids of the invention with the ester. Field data discussed below has demonstrated that the fluids of the invention are superior to prior art isomerized olefin based drilling fluids, and the fluids of the invention have properties especially advantageous in subterranean wells drilled in deep water. Moreover, the principles of the methods of the invention may be used with invert emulsion drilling fluids that form fragile gels or yield fragile gel behavior, provide low ECDs, and have (or seem to have) viscoelasticity that may not be comprised of an ester blend. One example of such a fluid may comprise a polar solvent instead of an ester blend. Diesel oil may be substituted for the ester provided that it is blended with a fluid that maintains the viscosity of that blend near the viscosity of preferred ester blends of the invention such as the ACCOLADE™ system. For example, a polyalphaolefin (PAO), which may be branched or unbranched but is preferably linear and preferably ecologically acceptable (non-polluting oil) blended with diesel oil demonstrates some advantages of the invention at viscosities approximating those of an

ACCOLADE™ fluid.

[0049] Other examples of possible suitable invert emulsion bases for the drilling fluids of the present invention include isomerized olefins blended with other hydrocarbons such as linear alpha olefins, paraffins, or naphthenes, or combinations thereof ("hydrocarbon blends").

[0050] Paraffins for use in blends comprising invert emulsions for drilling fluids for the present invention may be linear, branched, poly-branched, cyclic, or isoparaffins, preferably having about 10 to about 30 carbon atoms. When blended with esters or other hydrocarbons such as isomerized olefins, linear alpha olefins, or naphthenes in the invention, the paraffins should comprise at least about 1 weight percent to about 99 weight percent of the blend, but preferably less than about 50 weight percent. An example of a commercially available paraffin suited for blends useful in the invention is called tradename XP-07™ product, available from Halliburton

Energy Services, Inc. in Houston, Texas. XP-07™ is primarily a C*₂.ι₆ linear paraffin.

[0051] Examples of glyceride triesters for ester/hydrocarbon blends useful in blends comprising invert emulsions for drilling fluids for the present invention may include without limitation materials such as rapeseed oil, olive oil, canola oil, castor oil, coconut oil, corn oil, cottonseed oil, lard oil, linseed oil, neatsfoot oil, palm oil, peanut oil, perilla oil, rice bran oil, safflower oil, sardine oil, sesame oil, soybean oil, and sunflower oil.

[0052] Naphthenes or napthenic hydrocarbons for use in blends comprising invert emulsions for drilling fluids for the present invention may be any saturated, cycloparaffinic compound, composition or material with a chemical formula of C_nH_2n where n is a number about 5 to about

30. [0053] In still another embodiment, a hydrocarbon blend might be blended with an ester blend to comprise an invert emulsion base for a drilling fluid of the present invention. [0054] The exact proportions of the components comprising an ester blend (or other blend or base for an invert emulsion) for use in the present invention will vary depending on drilling requirements (and characteristics needed for the blend or base to meet those requirements), supply and availability of the components, cost of the components, and characteristics of the blend or base necessary to meet environmental regulations or environmental acceptance. The manufacture of the various components of the ester blend (or other invert emulsion base) is understood by one skilled in the art.

[0055] Further, the invert emulsion drilling fluids of the invention or for use in the present invention have added to them or mixed with their invert emulsion base, other fluids or materials needed to comprise complete drilling fluids. Such materials may include, for example: additives to reduce or control temperature rheology or to provide thinning, for example, additives having the tradenames COLDTROL®, ATC®, and OMC2™; additives for enhancing viscosity, for example, an additive having the tradename RHEMOD L™; additives for providing temporary increased viscosity for shipping (transport to the well site) and for use in sweeps, for example, an additive having the tradename TEMPERUS™ (modified fatty acid); additives for filtration control, for example, an additive having the tradename ADAPTA®; additives for high temperature high pressure control (HTHP) and emulsion stability, for example, an additive having the tradename FACTANT™ (highly concentrated tall oil derivative); and additives for emulsification, for example, an additive having the tradename LE SUPERMUL™ (polyaminated fatty acid). All of the aforementioned trademarked products are available from Halliburton Energy Services, Inc. in Houston, Texas, U.S.A. Additionally, the fluids comprise an aqueous solution containing a water activity lowering compound, composition or material, comprising the internal phase of the invert emulsion. Such solution is preferably a saline solution comprising calcium chloride (typically about 25% to about 30%, depending on the subterranean formation water salinity or activity), although other salts or water activity lowering materials known in the art may alternatively or additionally be used.

[0056] Figure 10 compares the viscosity of a base fluid for comprising a drilling fluid of the present invention with known base fluids of some prior art invert emulsion drilling fluids. The base fluid for the drilling fluid of the present invention is one of the thickest or most viscous. Yet, when comprising a drilling fluid of the invention, the drilling fluid has low ECDs, provides good suspension of drill cuttings, satisfactory particle plugging and minimal fluid loss in use. Such surprising advantages of the drilling fluids of the invention are believed to be facilitated in part by a synergy or compatibility of the base fluid with appropriate thinners for the fluid. [0057] Thinners disclosed in International Patent Application Nos. PCT/USOO/35609 and PCT USOO/35610 of Halliburton Energy Services, Inc., Cognis Deutschland GmbH & Co KG., Heinz Muller, Jeff Kirsner (co-inventor of the present invention) and Kimberly Burrows (co- inventor of the present invention), both filed December 29, 2000 and entitled "Thinners for Invert Emulsions," and both disclosures of which are incorporated entirely herein by reference, are particularly useful in the present invention for effecting such "selective thinning" of the fluid of the present invention; that is thinning at lower temperatures without rendering the fluid too thin at higher temperatures. Such thinners may have the following general formula: R- (C₂H₄0)_n(C₃H₆θ)_m(C H₈θ) -H ("formula 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.

[0058] The thinner may be added to the drilling fluid during initial preparation of the fluid or later as the fluid is being used for drilling or well service purposes in the subterranean formation. The quantity of thinner added is an effective amount to maintain or effect the desired viscosity of the drilling fluid. For purposes of this invention, the thinner of formula (I) is preferably from about 0.5 to about 15 pounds per barrel of drilling fluid. 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.

[0059] 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 case any desired mixture of ethylene oxide, propylene oxide and/or butylene oxide is reacted with the fatty alcohol.

[0060] 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 formula (I) whose ethoxy, propoxy, and/or butoxy group distribution is very narrow, for example, "narrow range ethoxylates" also called "NREs" by those skilled in the art.

[0061] The compound of formula (I) should contain at least one ethoxy group. Preferably, the compound of formula I will also contain at least one propoxy group (C₃H₆0-) or butoxy group (C₄H₈0~). Mixed alkoxides containing all three alkoxide groups — ethylene oxide, propylene oxide, and butylene oxide — are possible for the invention but are not preferred. [0062] 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. [0063] Alternatively, such thinners may be a non-ionic surfactant which is a reaction product of ethylene oxide, propylene oxide and/or butylene oxide with C-₀-₂₂ carboxylic acids or Cι_0-22 carboxylic acid derivatives containing at least one double bond in position 9/10 and/or 13/14. These thinners may be used alone (without other thinners) or may be used in combination with a formula (I) thinner or with one or more commercially available thinners, including for example, products having the tradenames COLDTROL® (alcohol derivative), OMC2™ (oligomeric fatty acid), and ATC® (modified fatty acid ester), which themselves may be used alone as well as in combination, and are available from Halliburton Energy Services, Inc. in Houston, Texas, U.S.A. Blends of thinners such as the OMC2™, COLDTROL®, and ATC® thinners can be more effective in fluids of the invention than a single one of these thinners.

[0064] The formulations of the fluids of the invention, and also the formulations of the prior art isomerized olefin based drilling fluids, used in drilling the boreholes cited in the field data below, vary with the particular requirements of the subterranean formation. Table 4 below, however, provides example formulations and properties for these two types of fluids discussed in the field data below. All trademarked products in Table 4 are available from Halliburton Energy Services, Inc. in Houston, Texas, including: LE MUL™ emulsion stabilizer (a blend of oxidized tall oil and polyaminated fatty acid); LE SUPERMUL™ emulsifier (polyaminated fatty acid); DURATONE® HT filtration control agent (organophilic leonardite); ADAPTA® filtration control agent (copolymer particularly suited for providing HPHT filtration control in non- aqueous fluid systems); RHEMOD L™ suspension agent/viscosifier (modified fatty acid); GELTONE® II viscosifϊer (organophilic clay); VIS-PLUS® suspension agent (carboxylic acid); BAROID® weighting agent (ground barium sulfate); and DEEP -TREAT® wetting agent/thinner (sulfonate sodium salt). In determining the properties in Table 4, samples of the fluids were sheared in a Silverson commercial blender at 7,000 rpm for 10 minutes, rolled at 150 ° F for 16 hours, and stirred for 10 minutes. Measurements were taken with the fluids at 120 ° F, except where indicated otherwise.

TABLE 4

Example Formulations

en o oxi ze ta o an po yam nate a y ac emu s on sta zer.

Polyaminated fatty acid emulsifier.

Organophilic leonardite filtration control agent.

Copolymer HTHP filtration control agent for non-aqueous systems.

Modified fatty acid suspension agent/viscosifier.

Organophilic clay viscosifier.

Carboxylic acid suspension agent.

Ground barium sulfate weighting agent.

Sulfonate sodium salt wetting agent/thinner. TABLE 4 — continued B. Properties

[0065] The invert emulsion drilling fluids of the present invention preferably do not have any organophilic clays added to them. The fluids of the invention do not need organophilic clays or organophilic lignites to provide their needed viscosity, suspension characteristics, or filtration control to carry drill cuttings to the well surface. Moreover, the lack of appreciable amounts of organophilic clays and organophilic lignites in the fluids is believed to enhance the tolerance of the fluids to the drill cuttings. That is, the lack of appreciable amounts of organophilic clays and organophilic lignites in the fluids of the invention is believed to enable the fluids to suspend and carry drill cuttings without significant change in the fluids' rheological properties.

Experimental

[0066] The present invention provides a drilling fluid with a relatively flat rheological profile.

Table 5 provides example rheological data for a drilling fluid of the invention comprising 14.6 ppg of a tradename ACCOLADE™ system.

TABLE 5

ACCOLADE™ System Downhole Properties

FANN® 75 Rheology

14.6 ppg ACCOLADE™ System

As used in Table 5, "N" and "K" are Power Law model rheology parameters. [0067] Figures 9(b) and (c) compare the effect of temperature on pressures observed with two different fluid weights (12.1 and 12.4 ppg) when applying six different and increasing shear rates (3, 6, 100, 200, 300, and 600 φm). Two common testing temperatures were used~40° F and 120° F. The change in temperature and fluid weight resulted in minimal change in fluid behavior. Figure 9(a) compares the yield point of two different weight formulations (12.1 ppg and 12.4 ppg) of a fluid of the present invention at two different temperatures (40° F and 120° F). The yield point is unexpectedly lower at 40° F than at 120° F. Prior art oil-based fluids typically have lower yield points at higher temperatures, as traditional or prior art oils tend to thin or have reduced viscosity as temperatures increase. In contrast, the fluids of the invention can be thinned at lower temperatures without significantly affecting the viscosity of the fluids at higher temperatures. This feature or characteristic of the invention is a further indicator that the invention will provide good performance as a drilling fluid and will provide low ECDs. Moreover, this characteristic indicates the ability of the fluid to maintain viscosity at higher temperatures. The preferred temperature range for use of an ACCOLADE™ system extends from about 40° F to about 350° F. The preferred mud weight for an ACCOLADE™ system extends from about 9 ppg to about 17 ppg.

Field Tests

[0068] The present invention has been tested in the field and the field data demonstrates the advantageous performance of the fluid compositions of the invention and the methods of using them. As illustrated in Figures 1(a), (b), (c), and 2, the present invention provides an invert emulsion drilling fluid that may be used in drilling boreholes or wellbores in subterranean formations, and in other drilling operations in such formations (such as in casing and cementing wells), without significant loss of drilling fluid when compared to drilling operations with prior art fluids.

[0069] Figures 1(a), (b), and (c) show three graphs comparing the actual fluid loss experienced in drilling 10 wells in the same subterranean formation. In nine of the wells, an isomerized olefin based fluid (in this case, tradename PETROFREE® SF available from Halliburton Energy Services, Inc. in Houston, Texas), viewed as an industry "standard" for full compliance with current environmental regulations, was used. In one well, a tradename ACCOLADE™ system, a fluid having the features or characteristics of the invention and commercially available from Halliburton Energy Services, Inc. in Houston, Texas (and also fully complying with current environmental regulations) was used. The hole drilled with an ACCOLADE™ system was 12.25 inches in diameter. The holes drilled with the "standard" tradename PETROFREE® SF fluid were about 12 inches in diameter with the exception of two sidetrack holes that were about 8.5 inches in diameter. Figure 1(a) shows the total number of barrels of fluid lost in drilling, running, casing and cementing the holes. Figure 1(b) shows the total number of barrels of fluid lost per barrel of hole drilled. Figure 1(c) shows the total number of barrels of fluid lost per foot of well drilled, cased or cemented. For each of these wells graphed in these Figures 1(a), (b) and (c), the drilling fluid lost when using a fluid of the invention was remarkably lower than when using the prior art fluid.

[0070] Figure 2 compares the loss of fluid with the two drilling fluids in running casing and cementing at different well depths in the same subterranean formation. The prior art isomerized olefin based fluid was used in the first three wells shown on the bar chart and a fluid of the present invention was used in the next four wells shown on the bar chart. Again, the reduction in loss of fluid when using the fluid of the present invention was remarkable. [0071] The significant reduction in fluid loss seen with the present invention is believed to be due at least in substantial part to the "fragile gel" behavior of the fluid of the present invention and to the chemical structure of the fluid that contributes to, causes, or results in that fragile gel behavior. According to the present invention, fluids having fragile gel behavior provide significant reduction in fluid losses during drilling (and casing and cementing) operations when compared to fluid losses incurred with other drilling fluids that do not have fragile gel behavior. Thus, according to the methods of the invention, drilling fluid loss may be reduced by employing a drilling fluid in drilling operations that is formulated to comprise fragile gels or to exhibit fragile gel behavior. As used herein, the term "drilling operations" shall mean drilling, running casing and/or cementing unless indicated otherwise.

[0072] Figure 3 represents in graphical form data indicating gel formation in samples of two different weight (12.65 and 15.6 ppg) ACCOLADE® fluids of the present invention and two comparably weighted (12.1 and 15.6 ppg) prior art invert emulsion fluids (tradename PETROFREE® SF) at 120° F. When the fluids are at rest or static (as when drilling has stopped in the wellbore), the curves are flat or relatively flat (see area at about 50-65 minutes elapsed time for example). When shear stress is resumed (as in drilling), the curves move up straight vertically or generally vertically (see area at about 68 to about 80 elapsed minutes for example), with the height of the curve being proportional to the amount of gel formed — the higher the curve the more gel built up. The curves then fall down and level out or begin to level out, with the faster rate at which the horizontal line forms (and the closer the horizontal line approximates true horizontal) indicating the lesser resistance of the fluid to the stress and the lower the pressure required to move the fluid. [0073] Figure 3 indicates superior response and performance by the drilling fluids of the present invention. Not only do the fluids of the present invention appear to build up more "gel" when at rest, which enables the fluids of the invention to better maintain weight materials and drill cuttings in suspension when at rest — a time prior art fluids are more likely to have difficulty suspending such solid materials — but the fluids of the present invention nevertheless suφrisingly provide less resistance to the sheer, which will result in lower ECDs as discussed further herein. [0074] Figure 4 provides data further showing the gel or gel-like behavior of the fluids of the present invention. Figure 4 is a graph of the relaxation rates of various drilling fluids, including fluids of the present invention and prior art isomerized olefin based fluids. In the test, conducted at 120° F, the fluids are exposed to stress and then the stress is removed. The time required for the fluids to relax or to return to their pre-stressed state is recorded. The curves for the fluids of the invention seem to level out over time whereas the prior art fluids continue to decline. The leveling out of the curves are believed to indicate that the fluids are returning to a true gel or gellike structure.

[0075] The significant reduction in fluid loss seen with the present invention can be due in substantial part to the viscoelasticity of the fluids of the present invention. Such viscoelasticity, along with the fragile gel behavior, is believed to enable the fluids of the invention to minimize the difference in its density at the surface and its equivalent circulating density downhole. [0076] Table 10 below and Figure 5(a) showing the Table 10 data in graph form illustrate the consistently stable and relatively minimal difference in equivalent circulating density and actual fluid weight or well surface density for the fluids of the invention. This minimal difference is further illustrated in Figure 5(a) and in Table 10 by showing the equivalent circulating density downhole for a commercially available isomerized olefin drilling fluid in comparison to a drilling fluid of the present invention. Both fluids had the same well surface density. The difference in equivalent circulating density and well surface density for the prior art fluid however was consistently greater than such difference for the fluid of the invention. Figure 5(b) provides the rates of penetration or drilling rates at the time the measurements graphed in Figure 5(a) were made. Figure 5(b) indicates that the fluid of the invention provided its superior performance — low — ECDs at suφrisingly faster drilling rates, making its performance even more impressive, as faster drilling rates tend to increase ECDs with prior art fluids.

TABLE 10 Comparison of Equivalent Circulating Densities

[0077] Figure 6 graphs the equivalent circulating density of an ACCOLADE™ system, as measured downhole during drilling of a 12 !4 inch borehole from 9,192 feet to 13,510 feet in deepwater (4,900 feet), pumping at 704 to 811 gallons per minute, and compares it to the fluid's surface density. Rate of penetration ("ROP")(or drilling rate) is also shown. This data further shows the consistently low and stable ECDs for the fluid, notwithstanding differences in the drilling rate and consequently the differences in stresses on the fluid.

[0078] Figure 7 similarly graphs the equivalent circulating density of an ACCOLADE™ system, as measured downhole during drilling of a 6 Vz inch borehole from 12,306 feet to 13,992 feet, pumping at 158 to 174 gallons per minute in deepwater, and compares it to the fluid's surface density. Rate of penetration (or drilling rate) is also shown. Despite the relatively erratic drilling rate for this well, the ECDs for the drilling fluid were minimal, consistent, and stable. Comparing Figure 7 to Figure 6 shows that despite the narrower borehole in Figure 7 (6 V_ inches compared to the 12 14 inch borehole for which data is shown in Figure 6), which would provide greater stress on the fluid, the fluid performance is effectively the same.

[0079] Figure 8 graphs the equivalent circulating density of an ACCOLADE™ system, as measured downhole during drilling of a 9 7/8 inch borehole from 4,672 feet to 12,250 feet in deepwater, pumping at 522 to 585 gallons per minute, and compares it to the surface density of the fluid and the rate of penetration ("ROP") (or drilling rate). The drilling fluid provided low, consistent ECDs even at the higher drilling rates. Environmental Impact Studies

[0080] Table 11 and the graph in Figure 12 summarize results of an environmental impact 10- day Leptocheirus test. TABLE 11

Synthetic Based Fluids Bioassay

Using 960Hour Sediment Toxicity Test

With Leptocheirus plumulosus

As used in Table 11, the abbreviation "IO" refers to the reference isomerized olefin cited in the test, and the abbreviation "SBM" refers to a "synthetic based mud." "SBM" is used in Table 11 to help distinguish laboratory formulations prepared for testing from field mud samples collected for testing (although the field muds also have a synthetic base). The data shows that the ACCOLADE™ samples provided enhanced compatibility with Leptocheirus, exceeding the minimum required by government regulations. The test was conducted according to the ASTM E 1367-99 Standard Guide for Conducting 10-day Static Sediment Toxicity Tests with Marine and Estuarine Amphipods, ASTM, 1997 (2000). The method of the test is also described in EPA Region 6. Final NPEDS General Permit for New and Existing Sources and New Discharges in the Offshore Subcategory of the Outer Continental Shelf of the Gulf of Mexico (GMG 290000); Appendix A, Method for Conducting a Sediment Toxicity Test with Leptocheirus plumulosus and Non-Aqueous Fluids or Synthetic Based Drilling Fluids (Effective February, 2002). Further, the ACCOLADE™ samples were found to meet and exceed the biodegradabihty requirements set forth by the United States Environmental Protection Agency.

[0081] As indicated above, the advantages of the methods of the invention may be obtained by employing a drilling fluid of the invention in drilling operations. The drilling operations — whether drilling a vertical or directional or horizontal borehole, conducting a sweep, or running casing and cementing — may be conducted as known to those skilled in the art with other drilling fluids. That is, a drilling fluid of the invention is prepared or obtained and circulated through a wellbore as the wellbore is being drilled (or swept or cemented and cased) to facilitate the drilling operation. The drilling fluid removes drill cuttings from the wellbore, cools and lubricates the drill bit, aids in support of the drill pipe and drill bit, and provides a hydrostatic head to maintain the integrity of the wellbore walls and prevent well blowouts. The specific formulation of the drilling fluid in accordance with the present invention is optimized for the particular drilling operation and for the particular subterranean formation characteristics and conditions (such as temperatures). For example, the fluid is weighted as appropriate for the formation pressures and thinned as appropriate for the formation temperatures. As noted previously, the fluids of the invention afford real-time monitoring and rapid adjustment of the fluid to accommodate changes in such subterranean formation conditions. Further, the fluids of the invention may be recycled during a drilling operation such that fluids circulated in a wellbore may be recirculated in the wellbore after returning to the surface for removal of drill cuttings for example. The drilling fluid of the invention may even be selected for use in a drilling operation to reduce loss of drilling mud during the drilling operation and/or to comply with environmental regulations governing drilling operations in a particular subterranean formation. [0082] The foregoing description of the invention is intended to be a description of preferred embodiments. Various changes in the details of the described fluids and methods of use can be made without departing from the intended scope of this invention as defined by the appended claims.

Claims

What is claimed is:

1. A method of drilling a wellbore in a subterranean formation comprising employing an invert emulsion based fragile gel drilling fluid wherein laboratory formulations weighing about 11.0 ppg have an elastic modulus ratio of G'*o/G'₂oo greater than about 2, a yield point less than about 3 Pa, or both.

2. A method according to claim 1 wherein said laboratory formulations have an oil:water ratio of about 70:30.

3. A method according to claim 1 or 2 wherein said yield point is measured at low shear rate.

4. A method according to claim 1, 2 or 3 wherein said drilling fluid demonstrates lower yield point at lower temperatures than at higher temperatures.

5. A method according to claim 4 wherein said higher temperatures are temperatures over about 120°F and said lower temperatures range from about 40°F to about 60°F.

6. A method according to claim 1, 2, 3, 4 or 5 wherein field samples of said drilling fluid have a Stress Build Function greater than about 3.8.

7. A method according to any preceding claim wherein said drilling fluid is substantially free of organophilic clay.

8. A method according to any preceding claim wherein said drilling fluid provides suspension of at least one of the materials in the group consisting of weighting agents and drill cuttings.

9. A method according to any one of claims 1 to 6 wherein said drilling fluid comprises less than about 3 pounds per barrel of organophilic clay.

10. A method according to any preceding claim wherein said drilling is conducted without significant loss of drilling fluid.

11. A method according to any preceding claim said drilling fluid does not require organophilic clays to provide filtration control.

12. A method according to any preceding claim wherein said drilling fluid has viscoelasticity.

13. A method according to any preceding claim wherein said drilling fluid has at least one property selected from the group consisting of fragile gel behavior, no appreciable pressure spike upon resumed drilling, low difference in surface and downhole equivalent circulating densities, no significant sag, and generally flat rheology between higher and lower temperatures.

14. A method according to claim 13 wherein said drilling fluid utilizes a base oil, an emulsifier, and a filtration control agent to provide the drilling fluid with said at least one said property.

15. A method according to claim 13 or 14 wherein pressure-while-drilling equipment is used for detecting any pressure spike upon resumed drilling.

16. A method according to claim 13, 14 or 15 wherein the equivalent circulating density of said drilling fluid approximates the surface density of said drilling fluid.

17. A method according to claim 13, 14 or 15 wherein said difference in surface and downhole equivalent circulating densities is less than about 0.5.

18. A method according to claim 13, 14 or 15 wherein said drilling fluid demonstrates lower differences in surface and downhole equivalent circulating densities at faster drilling rates.

19. A method according to claim 13, 14 or 15 wherein said drilling is at different rates and said drilling fluid maintains a lowdifference in surface and downhole equivalent circulating densities over said different drilling rates.

20. A method according to claim 13, 14 or 15 wherein said drilling is at different rates and said drilling fluid maintains saidgenerally flat rheology oyer said different drilling rates.

21. A method according to claim 13, 14 or 15 wherein said rheology is not significantly changed by contact of said drilling fluid with drill cuttings.

22. A method according to claim 21 further comprising removing said drill cuttings from said drilling fluid and recycling said drilling fluid.

23. A method according to claim 22 farther comprising using thinner in separating drill cuttings from the drilling fluid outside said subterranean formation and replenishing said base oil, emulsifier and filtration control agent in said drilling fluid as needed to provide fragile gel behavior prior to said recycling, wherein said recycling comprises further using said drilling fluid in drilling.

24. A method according to any preceding claim wherein said invert emulsion has a continuous base comprised of at least one component selected from one of the groups consisting of:

(i) esters prepared from fatty acids and alcohols, esters prepared from olefins and fatty acids or alcohols;

(ii) olefins comprising linear alpha olefins, isomerized olefins having a straight chain, olefins having a branched structure, isomerized olefins having a cyclic structure; olefin hydrocarbons;

(iii) paraffin hydrocarbons comprising linear paraffins, branched paraffins, poly- branched paraffins, cyclic paraffins, isoparaffins;

(iv) mineral oil hydrocarbons;

(v) glyceride triesters comprising rapeseed oil, olive oil, canola oil, castor oil, coconut oil, corn oil, cottonseed oil, lard oil, linseed oil, neatsfoot oil, palm oil, peanut oil, perilla oil, rice bran oil, safflower oil, sardine oil, sesame oil, soybean oil, sunflower oil:

(vi) naphthenic hydrocarbons; and

(vii) combinations thereof.

25. A method according to claim 24 wherein said base comprises a blend of esters with isomerized or internal olefins.

26. A method according to claim 25 wherein said esters comprise at least about 10 wt % to about 99 wt % of said blend.

27. A method according to claim 25 wherein said olefins comprise about 1 wt % to about 99 weight percent of said blend.

28. A method according to claim 27 wherein said olefins have about 40 wt % to about 70 wt % Ci₆ and about 20 wt % to about 50 wt % C₁₈.

29. A method according to claim 24, 25, 26, 27 or 28 wherein said esters comprise about C₆ to about C₁ fatty acids and 2-ethyl hexanol.

30. A method according to any one of claims 24 to 29 wherein said straight-chain, branched, and cyclic olefins each have about 10 to about 30 carbon atoms.

31. A method according to any one of claims 24 to 30 wherein the internal phase of said invert emulsion comprises an aqueous solution containing a water activity lowering material.

32. A method according to claim 31 wherein said aqueous solutionis saline.

33. A method according to claim 31 wherein said water activity lowering material is calcium chloride.

34. A method according to claim 1 wherein said drilling fluid comprises a blend of esters with other hydrocarbons selected from the group consisting of paraffins, mineral oils, glyceride triesters, and combinations thereof.

35. A method according to claim 34 wherein said other hydrocarbons comprise from about 1 wt % to about 99 wt % of said blend.

36. A method according to any preceding claim wherem said drilling fluid is ester-free.

37. A method according to any preceding claim wherein said drilling fluid comprises a polar solvent.

38. A method according to any preceding claim wherein said drilling fluid comprises diesel oil.

39. A method according to any preceding claim wherein said drilling fluid further comprises a polyalphaolefin.

40. A method according to any preceding claim wherein said drilling fluid comprises isomerized olefins blended with other hydrocarbons selected from the group consisting of linear alpha olefins, paraffins, naphthenes, and combinations thereof.

41. A method according to any preceding claim wherein said drilling fluid comprises paraffin hydrocarbons having about 10 to about 30 carbon atoms.

42. A method according to any preceding claim wherein said drilling fluid comprises paraffins blended with mineral oils or glyceride triesters.

43. A method according to any preceding claim wherein said drilling fluid comprises napthenes selected from the group consisting of saturated, cycloparaffinic compounds, compositions and materials having a chemical formula of C_nH_2n, wherein n is a number about 5 to about 30.

44. A method according to any preceding claim wherein said drilling fluid comprises at least one additive selected from the group consisting of thinners, rheology control agents, viscosifiers, filtration control agents, emulsion stabilizers, HTHP additives, emulsifiers and weighting agents.

45. A method according to claim 44 wherein said drilling fluid incoφorates said additive or additives quickly.

46. A method according to claim 44 or 45 further comprising real time monitoring of the rheological properties of said drilling fluid during said drilling and adjusting said properties with addition of at least one of said additives.

47. A method according to claim 46 wherein weighting agents are added to said fluid to adjust for increased formation pressure.

48. A method according to claim 46 wherein at least one thinner is added to said fluid to adjust for change in formation temperature.

49. A method according to any one of claims 44 to 48 wherein said drilling fluid can be thinned at lower temperatures without significantly affecting the viscosity of the fluid at higher temperatures.

50. A method according to any one of claims 44 to 49 wherein one of said thinners has the formula:

R-(C₂H₄O)_n(C₃H₆O)_m(C₄H₈0)_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.

51. A method according to claim 50 wherein said alkyl radical has about 8 to about 18 carbon atoms.

52. A method according to claim 50 wherein said alkyl radical has about 12 to about 18 carbon atoms.

53. A method according to claim 50 wherein said alkyl radical has about 12 to about 14 carbon atoms.

54. A method according to any one of claims 50 to 53 wherein said alkyl radical is saturated and linear.

55. A method according to any one of claims 50 to 54 wherein said thinner contains at least one propoxy group.

56. A method according to any one of claims 50 to 55 wherein said flrinner contains at least one butoxy group.

57. A method according to any one of claims 44 to 56 wherein one of said thinners is a non- ionic surfactant.

58. A method according to any one of claims 44 to 57 wherein one of said thinners comprises a blend of thinners, at least one of which is selected from the group consisting of thinners derived from alcohols, thinners containing oligomeric fatty acids, and thinneis containing modified fatty acid esters.

59. A method according to any preceding claim wherein said drilling fluid maintains its viscosity at higher temperatures.

60. A method according to any preceding claim wherein said drilling fluid facilitates control of fluid rheological properties in real time.

61. A method according to any preceding claim wherein the differences in the pore pressures and fracture gradients of said formation are small.

62. A method according to any preceding claim wherein said drilling fluid meets or exceeds the minimum requirements for environmental compatibility as tested in a 10-day Liptocheirus test.

63. A method according to any preceding claim wherein said drilling fluid meets or exceeds biodegradability requirements of the United States Environmental Protection Agency.

64. A method according to any preceding claim wherein said drilling is offshore.

65. A method according to any preceding claim wherein said drilling is of a deviated well.

66. A method according to any preceding claim wherein said drilling comprises at least one of the steps consisting of boring a wellbore in said subterranean formation: completing said wellbore: and producing fluids from said wellbore.

67. A method according to claim 66 wherein said completing said wellbore comprises cementing or running casing in said wellbore.

68. A method of drilling in a subterranean formation comprising providing a drilling fluid that provides a generally flat rheology between higher and lower temperatures.

69. A method according to claim 68 wherein said higher temperatures are temperatures over about 120°F and said lower temperatures range from about 40°F to about 60°F.

70. A method according to claim 68 or 69 wherein said drilling fluid demonstrates lower yield point at said lower temperatures than at said higher temperatures.

71. A method according to claim 70 wherein said yield point is measured at low shear rate.

72. A method according to claim 68, 69, 70 or 71 wherein field samples of said drilling fluid have a Stress Build Function greater than about 3.8.

73. A method according to claim 68, 69, 70, 71 or 72 wherein said drilling fluid is substantially free of organophilic clay.

74. A method according to any one of claims 68 to 73 wherein said drilling fluid provides suspension of at least one of the materials in the group consisting of weighting agents and drill cutting^.

75. A method according to any one of claims 68 to 72 wherein said drilling fluid comprises less than about 3 pounds per barrel of organophilic clay.

76. A method according to any one of claims 68 to 75 wherein said drilling is conducted without significant loss of drilling fluid.

77. A method according to any one of claims 68 to 76 wherein said drilling fluid does not require organophilic clays to provide filtration control.

78. A method according to any one of claims 68 to 77 wherein said drilling fluid has viscoelasticity.

79. A method according to any one of claims 68 to 78 wherein said drilling fluid has at least one property selected from the group consisting of fragile gel behavior, no appreciable pressure spike upon resumed drilling, low difference in surface and downhole equivalent circulating densities, and no significant sag.

80. A method according to claim 79 wherein said drilling fluid utilizes abase oil, an emulsifier, and a filtration control agent to provide the drilling fluid with said at least one said property.

81. A method according to claim 79 or 80 wherein pressure-while-drilling equipment is used for detecting any pressure spike upon resumed drilling.

82. A method according to claim 79, 80 or 81 wherein the equivalent circulating density of said drilling fluid approximates the surface density of said drilling fluid.

83. A method according to claim 79, 80, 81 or 82 wherein said difference in surface and downhole equivalent circulating densities is less than about 0.5.

84. A method according to claim 79, 80, 81, 81 or 82 wherein said drilling fluid demonstrates lower differences in surface and downhole equivalent circulating densities at faster drilling rates.

85. A method according to any one of claims 79 to 84 wherein said drilling is at different rates and said drilling fluid maintains a low difference in surface and downhole equivalent circulating densities over said different drilling rates.

86. A method according to any one of claims 68 to 78 wherein said drilling is at different rates and said drilling fluid maintains said generally flat rheology over said different drilling rates.

87. A method according to claim 86 wherein said riieology is not significantly changed by contact of said drilling fluid with drill cuttings.

88. A method according to claim 86 or 87 further comprising removing said drill cuttings from said drilling fluid and recycling said drilling fluid.

89. A method according to claim 88 further comprising using thinner in separating drill cuttings from the drilling fluid outside said subterranean formation and said recycling comprises further using said drilling fluid in drilling.

90. A method according to any one of claims 68 to 89 wherein said drilling fluid comprises an invert emulsion having a continuous base comprised of at least one component selected from one of the groups consisting of:

(i) esters prepared from fatty acids and alcohols, esters prepared from olefins and fatty acids or alcohols: (ii) olefins comprising linear alpha olefins, isomerized olefins having a straight chain, olefins having a branched structure, isomerized olefins having a cyclic structure; olefin hydrocarbons;

(iv) mineral oil hydrocarbons;

(v) glyceride triesters comprising rapeseed oil, olive oil, canola oil, castor oil, coconut oil, com oil, cottonseed oil, lard oil, linseed oil, neatsfoot oil, palm oil, peanut oil, perilla oil, rice bran oil, safflower oil, sardine oil, sesame oil, soybean oil, sunflower oil:

(vi) naphthenic hydrocarbons; and

(vii) combinations thereof.

91. A method according to claim 90 wherein said base comprises a blend of esters with isomerized or internal olefins.

92. A method according to claim 91 wherein said esters comprise at least about 10 wt % to about 99 wt % of said blend.

93. A method according to claim 91 wherein said olefins comprise about 1 wt % to about 99 weight percent of said blend.

94. A method according to claim 90, 91 , 92 or 93 wherein said esters comprise about C₆ to about C₁ fatty acids and 2-ethyl hexanol.

95. A method according to claim 90, 91 , 92, 93 or 94 wherein said straight-chain, branched, and cyclic olefins each have about 10 to about 30 carbon atoms.

96. A method according to any one of claims 90 to 95 wherein said olefins have about 40 wt % to about 70 wt % Cι₆ and about 20 wt % to about 50 wt % C-g.

97. A method according to claim 90 wherein said base comprises a blend of esters with other hydrocarbons selected from the group consisting of paraffins, mineral oils, glyceride triesters, and combinations thereof.

98. A method according to claim 97 wherein said other hydrocarbons comprise from about 1 wt % to about 99 wt % of said blend

99. A method according to any one of claims 90 to 98 wherein said paraffin hydrocarbons have about 10 to about 30 carbon atoms.

100. A method according to any one of claims 90 to 99 wherein the internal phase of said invert emulsion comprises an aqueous solution containing a water activity lowering material.

101. A method according to claim 100 wherein said aqueous solution is saline.

102. A method according to claim 100 wherein said water activity lowering material is calcium chloride.

103. A method according to any one of claims 68 to 102 wherein said drilling fluid is ester- free.

104. A method according to any one of claims 68 to 103 wherein said drilling fluid comprises a polar solvent.

105. A method according to any one of claims 68 to 104 wherein said drilling fluid comprises diesel oiL

106. A method according to claim 105 wherein said drilling fluid further comprises a polyalphaolefin.

107. A method according to any one of claims 68 to 89 wherein said drilling fluid comprises isomerized olefins blended with other hydrocarbons selected from the group consisting of linear alpha olefins, paraffins, naphthenes, and combinations thereof.

108. A method according to any one of claims 68 to 89 wherein said drilling fluid comprises paraffins blended with other hydrocarbons.

109. A method according to any one of claims 68 to 89 wherein said drilling fluid comprises napthenes selected from the group consisting of saturated, cycloparaffinic compounds, compositions and materials having a chemical formula of C_nH_2n wherein n is a number about 5 to about 30.

110. A method according to any one of claims 68 to 109 wherein said drilling fluid comprises at least one additive selected from the group consisting of thinners, rheology control agents, viscosifiers, filtration control agents, emulsion stabilizers, HTHP additives, emulsifiers and weighting agents.

111. A method according to claim 110 wherein said drilling fluid incoφorates said additive or additives quickly.

112. A method according to claim 110 further comprising real time monitoring of the rheological properties of said drilling fluid during said drilling and adjusting said properties with addition of at least one of said additives.

113. A method according to claim 110, 111 or 112 wherein weighting agents are added to said fluid to adjust fir increased formation pressure.

114. A method according to claim 110, 111, 112 or 113 wherein at least one thinner is added to said fluid to adjust for change in formation temperature.

115. A method according to any one of claims 68 to 114 wherein said drilling fluid can be thinned at said lower temperatures without significantly affecting the viscosity of the fluid at said higher temperatures.

116. A method according to claim 115 wherein said thinning is facilitated by adding to said drilling fluid 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 from about 0 to about 10, and k is a number ranging from about 0 to about 10.

117. A method according to claim 116 wherein said alkyl radical has about 8 to about 18 carbon atoms.

118. A method according to claim 116 wherein said alkyl radical has about 12 to about 14 carbon atoms.

119. A method according to claim 116, 117 or 118 wherem said alkyl radical is saturated and linear.

120. A method according to a claim 116, 117, 118 or 119 wherein said thinner contains at least one propoxy group.

121. A method according to claim 116, 117, 118, 119 or 120 wherein said thinner contains at least one butoxy group.

122. A method according to any one of claims 110 to 121 wherein said thinner is a non-ionic surfactant.

123. A method according to any one of claims 110 to 122 wherein one said thinner comprises a blend of thinners, at least one of which is selected from the group consisting of thinners derived from alcohols, thinners containing oligomeric fatty acids, and thinneis containing modified fatty acid esters.

124. A method according to any one of claims 68 to 123 wherein said drilling fluid maintains its viscosity at higher temperatures.

125. A method according to any one of claims 68 to 124 wherein said drilling fluid facilitates control of fluid rheological properties in realtime.

126. A method according to any one of claims 68 to 125 wherein the differences in the pore pressures and fracture gradients of said formation are small.

127. A method according to any one of claims 68 to 126 wherein said drilling fluid meets or exceeds the minimum requirements for environmental compatibility as tested in a 10-day Liptocheirus test.

128. A method according to any one of claims 68 to 127 wherein said drilling fluid meets or exceeds biodegradability requirements of the United States Environmental Protection Agency.

129. A method according to any one of claims 68 to 128 wherein said drilling is offshore.

130. A method according to any one of claims 68 to 129 wherein said drilling is of a deviated well.

131. A method according to any one of claims 68 to 130 wherein said drilling comprises at least one of the steps consisting of boring a wellbore in said subteiranean formation; completing said wellbore; and producing fluids from said wellboie.

132. A method according to claim 131 wherein said completing said wellbore comprises cementing or running casing in said wellbore.

133. A method of drilling in a subterranean formation comprising providing a substantially organophilic clay-free invert emulsion drilling fluid having at least one property selected from the group consisting of fragile gel behavior, no appreciable pressure spikes upon resumed drilling, low difference in surface and downhole equivalent circulating densities, no significant sag, and generally flat rheology between higher and lower temperatures.

134. A method according to claim 133 wherein said drilling fluid demonstrates lower yield point at lower temperatures than at higher temperatures.

135. A method according to claim 134 wherein said yield point is measured at low shear rate.

136. A method according to claim 133, 134 or 135 wherein said higher temperatures are temperatures over about 120°F and said lower temperatures range from about 40°F to about 60°F.

137. A method according to claim 133, 134, 135 or 136 wherein field samples of said drilling fluid have a Stress Build Function greater than about 3.8.

138. A method according to claim 133, 134, 135, 136 or 137 wherein said drilling fluid provides suspension of at least one material in the group consisting of weighting agents and drill cuttings.

139. A method according to any one of claims 133 to 138 wherein said drilling fluid comprises less than about 3 pounds per barrel of organophilic clay.

140. A method according to any one of claims 133 to 139 wherein said drilling is conducted without significant loss of drilling fluid.

141. A method according to any one of claims 133 to 140 wherein said drilling fluid provides filtration control.

1 2. A method according to any one of claims 133 to 141 wherein said drilling fluid has .viscoelasticity.

143. A method according to any one of claims 133 to 142 wherein said drilling fluid utilizes a base oil, an emulsifier, and a filtration control agent to provide the drilling fluid with said at least one property.

144. A method according to any one of claims 133 to 143 wherein pressure- while-drilling equipment is used fcr detecting any pressure spike upon resumed drilling.

145. A method according to any one of claims 133 to 144 wherein the equivalent circulating density of said drilling fluid approximates the surface density of said drilling fluid.

146. A method according to any one of claims 133 to 145 wherein said difference in surface and downhole equivalent circulating densities is less than about 0.5.

147. A method according to any one of claims 133 to 146 wherein said drilling fluid demonstrates lower differences in surface and downhole equivalent circulating densities at faster drilling rates.

148. A method according to any one of claims 133 to 147 wherein said drilling is at different rates and said drilling fluid maintains alow difference in surface and downhole equivalent circulating densities over said different drilling rates.

149. A method according to any one of claims 133 to 148 wherein said drilling is at different rates and said drilling fluid maintains said generally flat rheology over said different drilling rates.

150. A method according to any one of claims 133 to 149 wherein said rheology is not significantly changed by contact of said drilling fluid with drill cuttings.

151. A method according to claim 150 further comprising removing said drill cuttings from said drilling fluid and recycling said drilling fluid.

152. A method according to claim 151 further comprising using thinner in separating drill cuttings from the drilling fluid outside said subterranean formation and replenishing said base oil, emulsifier, and filtration control agent in said drilling fluid as needed to provide fragile gel behavior prior to said recycling, wherein said recycling comprises further using said drilling fluid in drilling.

153. A method according to any one of claims 133 to 152 wherein said invert emulsion has a continuous base comprised of at least one component selected from one of the groups consisting of:

(iii) paraffin hydrocarbons comprising linear paraffins, branched paraffins, poly-branched paraffins, cyclic paraffins, isoparaffins;

(iv) mineral oil hydrocarbons;

(v) glyceride triesters comprising rapeseed oil, olive oil, canola oil, castor oil. coconut oil, corn oil, cottonseed oil, lard oil, linseed oil, neatsfoot oil, palm oil, peanut oil, perilla oil, rice bran oil, safflower oil, sardine oil, sesame oil, soybean oil, sunflower oil;

(vi) naphthenic hydrocarbons; and ,

(vii) combinations thereof.

154. A method according to claim 153 wherein said base comprises a blend of esters with isomerized or internal olefins.

155. A method according to claim 154 wherem said esters comprise at least about 10 wt % to about 99 wt % of said blend.

156. A method according to claim 154 wherein said olefins comprise about 1 wt % to about 99 weight percent of said blend.

157. A method according to claim 153 or 154 wherein said esters comprise about C₆to about C₁₄ fatty acids and 2-ethyl hexanol.

158. A method according to claim 153, 154 or 155 wherein said straight-chain, branched, and cyclic olefins each have about 10 to about 30 carbon atoms.

159. A method according to claim 158 wherein said olefins have about 40 wt % to about 70 wt % Ciβ and about 20 wt % to about 50 wt % C₁₈.

160. A method according to claim 153 wherein said base comprises a blend of esters with other hydrocarbons selected from the group consisting of paraffins, mineral oils, glyceride triesters, and combinations theieof.

161. A method according to claim 160 wherein said other hydrocarbons comprise from about 1 wt % to about 99 wt % of said blend.

162. A method according to claim 153 wherein said base is ester-free.

163. A method according to any one of claims 153 to 162 wherein said base comprises a polar solvent.

164. A method according to any one of claims 153 to 163 wherein said base comprises diesel oil.

165. A method according to claim 164 wherein said base further comprises a olyalphaolefin.

166. A method according to claim 153 wherein said base comprises isomerized olefins blended with other hydrocarbons selected from the group consisting of linear alpha olefins, paraffins, naphthenes, and combinations thereof.

167. A method according to any one of claims 153 to 166 wherein said paraffin hydrocarbons have about 10 to about 30 carbon atoms.

168. A method according to any one of claims 133 to 167 wherein said drilling fluid comprises paraffins blended with other hydrocarbons.

169. A method according to claim 153 wherein said base comprises napthenes selected from the group consisting of saturated, cycloparaffinic compounds, compositions and materials having a chemical formula of C_nH_2n, wherein n is a number about 5 to about 30.

170. A method according to any one of claims 153 to 169 wherein the internal phase of said invert emulsion comprises an aqueous solution containing a water activity lowering material.

171. A method according to claim 170 wherein said aqueous solution is saline.

172. A method according to claim 170 wherein said water activity lowering material is calcium chloride.

173. A method according to any one of claims 133 to 172 wherein said drilling fluid comprises at least one additive selected from the group consisting of thinners, rheology control agents, viscosifiers, filtration control agents, emulsion stabilizers, HTHP additives, emulsifiers and weighting agents.

174. A method according to claim 173 wherein said drilling fluid incoφorates said additive or additives quickly.

175. A method according to claim 173 or 174 further comprising real time monitoring of the rheological properties of said drilling fluid during said drilling and adjusting said properties with addition of at least one of said additives.

176. A method according to claim 175 wherein weighting agents are added to said fluid to adjust for increased formation pressure.

1 7. A method according to claim 175 wherein at least one thinner is added to said fluid to adjust for change in formation temperature.

178. A method according to any one of claims 133 to 177 wherein said drilling fluid can be thinned at lower temperatures without significantly affecting the viscosity of the fluid at higher temperatures.

179. A method according to claim 173 wherein one said thinner has the formula:

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.

180. A method according to claim 179 wherein said alkyl radical has about 8 to about 18 carbon atoms.

181. A method according to claim 179 wherein said alkyl radical has about 12 to about 18 carbon atoms.

182. A method according to claim 179 wherein said alkyl radical has about 12 to about 14 carbon atoms.

183. A method according to claim 179, 180, 181 or 182 wherein said alkyl radical is saturated and linear.

184. A method according to claim 179, 180, 181, 182 or 183 wherein said thinner contains at least one propoxy group.

185. A method according to any one of claims 179 to 184 wherein said thinner contains at least one butoxy group

186. A method according to claim 179 wherein said thinner is a non-ionic surfactant.

187. A method according to claim 173 wherein said thinner comprises a blend of thinners, at least one of which is selected from the group consisting of thinners derived from alcohols, thinners containing oligomeric fatty acids, and thinners containing modified fatty acid esters.

188. A method according to any one of claims 133 to 187 wherein said drilling fluid maintains its viscosity at higher temperatures.

189. A method according to any one of claims 133 to 188 wherein said drilling fluid facilitates control of fluid rheological properties in real time.

190. A method according to any one of claims 133 to 189 wherein the differences in the pore pressures and fracture gradients of said formation are small.

191. A method according to any one of claims 133 to 190 wherein said drilling fluid meets or exceeds the minimum requirements for environmental compatibility as tested in a 10-day Liptocheirus test.

192. A method according to any one of claims 133 to 191 wherein said drilling fluid meets or exceeds biodegradability requirements of the United States Environmental Protection Agency.

193. A method according to any one of claims 133 to 192 wherein said drilling is offshore.

194. A method according to any one of claims 133 to 193 wherein said drilling is of a deviated well.

195. A method according to any one of claims 133 to 194 wherein said drilling comprises at least one of the steps consisting of boring a wellbore in said subterranean formation completing said wellbore: and producing fluids from said wellbore.

196. A method according to claim 195 wherein said completing said wellbore comprises cementing or running casing in said wellbore.

197. A method of drilling in a subterranean formation comprising using a drilling fluid that utilizes abase oil, an emulsifier, and a filtration control agent to provide the drilling fluid with at least oneproperty selected from the group consisting of fragile gel behavior, no appreciable pressure spikes upon resumed drilling, low difference in surface and downhole equivalent circulating densities, no significant sag, and generally flat rheology between higher and lower temperatures.

198. A method according to claim 197 wherein said yield point is measured at low shear rate.

199. A method according to claim 197 or 198 wherein said drilling fluid demonstrates lower yield point at lower temperatures than at higher temperatures.

200. A method according to claim 199 wherein said higher temperatures are temperatures over about 120°F and said lower temperatures range from about 40°F to about 60°F.

201. A method according to claim 197, 198, 199 or 200 wherein field samples of said drilling fluid have a Stress Build Function greater than about 3.8.

202. A method according to claim 197, 198, 199, 200 or 201 wherein said drilling fluid is substantially free of organophilic clay.

203. A method according to claim 202 wherein said drilling fluid provides suspension of at least one of the materials in the group consisting of weighting agents and drill cuttings.

204. A method according to claim 197, 198, 199, 200 or 201 wherein said drilling fluid comprises less than about 3 pounds per barrel of organophilic clay.

205. A method according to any one of claims 197 to 204 wherein said drilling is conducted without significant loss of drilling fluid.

206. A method according to any one of claims 197 to 205 wherein said drilling fluid does not require organophilic clays to provide filtration control.

207. A method according to any one of claims 197 to 206 wherein said drilling fluid has viscoelasticity.

208. A method according to any one of claims 197 to 207 wherein pressure- while-drilling equipment is used for detecting any pressure spike upon resumed drilling.

209. A method according to any one of claims 197 to 208 wherein the equivalent circulating density of said drilling fluid approximates the surface density of said drilling fluid.

210. A method according to any one of claims 197 to 209 wherein said difference in surface and downhole equivalent circulating densities is less than about 0.5.

211. A method according to any one of claims 197 to 210 wherein said drilling fluid demonstrates lower differences in surface and downhole equivalent circulating densities at faster drilling rates.

212. A method according to any one of claims 197 to 211 wherein said drilling is at different rates and said drilling fluid maintains a low difference in surface and downhole equivalent circulating densities over said different drilling rates.

213. A method according to any one of claims 197 to 212 wherein said drilling is at different rates and said drilling fluid maintains said generally flat rheology over said different drilling rates.

214. A method according to any one of claims 197 to 213 wherein said rheology is not significantly changed by contact of said drilling fluid with drill cutting.

215. A method according to claim 214 further comprising removing said drill cuttings from said drilling fluid and recycling said drilling fluid.

216. A method according to claim 214 or 215 further comprising using thinner in separating drill cutting from the drilling fluid outside said subterranean formation and replenishing said base oil, emulsifier, and filtration control in said drilling fluid as needed to provide fragile gel behavior prior to said recycling, wherein said recycling comprises further using said drilling fluid in drilling.

217. A method according to any one of claims 197 to 216 wherein said base oil is comprised of at least one component selected from one of the groups consisting of:

(iii) paraffin hydrocarbons comprising linear paraffins, branched paraffins, poly- branched paraffins, cyclic paraffins, isoparaffins; (iv) mineral oil hydrocarbons:

(v) glyceride triesters comprising rapeseed oil, olive oil, canola oil, castor oil, coconut oil, com oil, cottonseed oil, lard oil, linseed oil, neatsfoot oil, palm oil, peanut oil, perilla oil, rice bran oil, safflower oil, sardine oil, sesame oil, soybean oil, sunflower oil;

(vi) naphthenic hydrocarbons; and

(vii) combinations thereof.

218. A method according to claim 217 wherein said base comprises a blend of esters with isomerized or internal olefins.

219. A method according to claim 218 wherein said esters comprise at least about 10 wt % to about 99 wt % of said blend.

220. A method according to claim 218 wherein said olefins comprise about 1 wt % to about 99 weight percent of said blend.

221. A method according to claim 217, 218, 219 or 220 wherein said esters comprise about C₆ to about C₁ fatty acids and 2-ethyl hexanol.

222. A method according to claim 217, 218, 219, 220 or 221 wherein said straight-chain, branched, and cyclic olefins each have about 10 to about 30 carbon atoms.

223. A method according to any one of claims 218 to 222 wherein said olefins have about 40 wt % to about 70 wt % C₁₆ and about 20 wt % to about 50 wt % C₁₈.

224. A method according to claim 217 wherein said base oil comprises a blend of esters with other hydrocarbons selected from the group consisting of paraffins, mineral oils, glyceride triesters, and combinations thereof.

225. A method according to claim 224 wherein said other hydrocarbons comprise from about 1 wt % to about 99 wt % of said blend

226. A method according to any one of claims 197 to 225 wherein said base oil is ester-free.

227. A method according to any one of claims 197 to 226 wherein said base oil comprises a polar solvent.

228. A method according to any one of claims 197 to 227 wherein said base oil comprises diesel oil.

229. A method according to claim 228 wherein said base oil further comprises a polyalphaolefin.

230. A method according to any one of claims 197 to 217 wherein said base oil comprises isomerized olefins blended with other hydrocarbons selected from the group consisting of linear alpha olefins, paraffins, naththenes, and combinations thereof.

231. A method according to claim 230 wherein said paraffins have about 10 to about 30 carbon atoms.

232. A method according to any one of claims 197 to 217 wherein said drilling fluid comprises paraffins having about 10 to about 30 carbon atoms blended with esters or other hydrocarbons.

233. A method according to any one of claims 197 to 217 wherein said base oil comprises napthenes selected from the group consisting of saturated, cycloparaffinic compounds, compositions and materials having a chemical formula of C_nH_2n, wherein n is a number about 5 to about 30.

234. A method according to any one of claims 197 to 233 wherein said drilling fluid comprises at least one additive selected from the group consisting of thinners, rheology control agents, viscosifiers, filtration control agents, emulsion stabilizers, HTHP additives, emulsifiers and weighting agents.

235. A method according to claim 234 wherein said drilling fluid incoφorates said additive or additives quickly.

236. A method according to claim 234 or 235 further comprising real time monitoring of the rheological properties of said drilling fluid during said drilling and adjusting said properties with addition of at least one of said additives.

237. A method according to claim 234, 235 or 236 wherein weighting agents are added to said fluid to adjust £>r increased formation pressure.

238. A method according to claim 234, 235, 236 or 237 wherein at least one thinner is added to said fluid to adjust for change in formation temperature.

239. A method according to any one of claims 197 to 238 wherein said drilling fluid can be thinned at lower temperatures without significantly affecting the viscosity of the fluid at higher temperatures.

240. A method according to claim 238 wherein said thinner has the formula: R-(C₂H₄O)_n(C₃H₆0)_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.

241. A method according to claim 240 wherein said alkyl radical has about 8 to about 18 carbon atoms.

242. A method according to claim 240 wherein said alkyl radical has about 12 to about 18 carbon atoms.

243. A method according to claim 240 wherein said alkyl radical has about 12 to about 14 carbon atoms.

244. A method according to claim 240, 241, 242 or 243 wherein said alkyl radical is saturated and linear.

245. A method according to claim 240, 241, 242, 243 or 244 wherein said thinner contains at least one propoxy group.

246. A method according to any one of claims 240 to 245 wherein said thinner contains at least one butoxy group.

247. A method according to any one of claims 240 to 246 wherein said thinner is a non-ionic surfactant.

248. A method according to any one of claims 240 to 247 wherein said thinner comprises a blend of thinners, at least one of which is selected from the group consisting of thinners derived from alcohols, thinners containing oligomeric fatty acids, and thinneis containing modified fatty acid esters.

249. A method according to any one of claims 197 to 248 wherein said drilling fluid maintains its viscosity at higher temperatures.

250. A method according to any one of claims 197 to 249 wherein said drilling fluid facilitates control of fluid rheological properties in realtime.

251. A method according to any one of claims 197 to 250 wherein the differences in the pore pressures and fracture gradients of said formation are small.

252. A method according to any one of claims 197 to 251 wherein said drilling fluid meets or exceeds the minimum requirements for environmental compatibility as tested in a 10-day Liptocheirus test.

253. A method according to any one of claims 197 to 252 wherein said drilling fluid meets or exceeds biodegradability requirements of the United States Environmental Protection Agency.

254. A method according to any one of claims 197 to 253 wherein said drilling is offshore.

255. A method according to any one of claims 197 to 254 wherein said drilling is of a deviated well.

256. A method according to any one of claims 197 to 255 wherein said drilling comprises at least one of the steps consisting of boring a wellbore in said subterranean formation; completing said wellbore; and producing fluids from said wellbore.

257. A method according to claim 256 wherein said completing said wellbore comprises cementing or nxnning casing in said wellbore.