Patent Grant
7488704
1. Field of the Invention
The present invention relates to compositions and methods for drilling, cementing and 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.
2. Description of Relevant Art
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.
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.
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 (5th 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.
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.
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.
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.
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.
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 oil:water 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′10/G′200 (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.
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 (Tau0). The “Stress Build Function” is defined as follows:
SBF10 m=(gel strength at 10 minutes−Tau0)/Tau0
Generally, a field mud of the present invention will have an SBF10 m of greater than about 3.8.
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 U.S. patent application Ser. No. 09/929,465, of Jeff Kirsner (co-inventor of the present invention), Kenneth W. Pober and Robert W. Pike, filed Aug. 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 C6 to about C14 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.
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 FACTAN® (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, Tex., U.S.A.
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 Dec. 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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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′10/G′200 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, Tex.
Test 1: Ratio of G′10/G′200.
Table 1 provides data taken with smooth parallel plate geometry. The elastic modulus (G′) was measured using 35 mm parallel plate geometry at a separation of 1 mm on a Haake RS 150 controlled stress rheometer. The applied torque was <1 Pa, inside the linear viscoelastic region for each sample. The elastic modulus was measured after 10 seconds (G′10) and after 200 seconds (G′200), and the ratio of G′10/G′200 is shown in Table 1. All the samples in Table 1 were of drilling fluids having 11.0 pounds per gallon (“ppg” or “lb./gal.”) total density and a base oil: water volume ratio of 70:30.
Similar data were found for an ACCOLADE™ fluid of 14.0 ppg, for which G′10/G′200 was 4.2
Test 2: Yield points.
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 10.0 s−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.
The program for measurement was as follows:
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 (0.03 s−1) was taken as the yield point. All drilling fluids in Table 2 were 11.0 ppg with 70/30 oil/water volume ratio.
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.
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.
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 (Tau0). This measure also effectively normalizes for mud weight as well, since generally higher weight fluids have higher Tau0 values. The “Stress Build Function” is defined as follows:
SBF10 m=(gel strength at 10 minutes−Tau0)/Tau0
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.
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′10/G′200 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.
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 U.S. patent application Ser. No. 09/929,465, of Jeff Kirsner (co-inventor of the present invention), Kenneth W. Pober and Robert W. Pike, filed Aug. 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 C14 fatty acids and alcohols, and are particularly or more preferably disclosed in U.S. Pat. No. Re. 36,066, reissued Jan. 25, 1999 as a reissue of U.S. Pat. No. 5,232,910, assigned to Henkel KgaA of Dusseldorf, Germany, and Baroid Limited of London, England, and in U.S. Pat. No. 5,252,554, issued Oct. 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. Pat. No. 5,106,516, issued Apr. 21, 1992, and U.S. Pat. No. 5,318,954, issued Jun. 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 C12 to about C14 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, Tex. 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.
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 C16 and about 20 to about 50 weight percent C18 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, Tex. Alternatively, other hydrocarbons such as paraffins, mineral oils, glyceride triesters, 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.
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.
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”).
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, Tex. XP-07™ is primarily a C12-16 linear paraffin.
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.
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 CnH2n where n is a number about 5 to about 30.
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.
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.
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, Tex., 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.
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 Dec. 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—(C2H4O)n(C3H6O)m(C4H8O)k—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.
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.
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.
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.
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 (C3H6O—) or butoxy group (C4H8O—). Mixed alkoxides containing all three alkoxide groups—ethylene oxide, propylene oxide, and butylene oxide—are possible for the invention but are not preferred.
Preferably, for use according to this invention, the compound of formula (I) will have a value for m ranging from about 1 to about 10 with k zero or a value for k ranging from about 1 to about 10 with m zero. Most preferably, m will be about 1 to about 10 and k will be zero.
Alternatively, such thinners may be a non-ionic surfactant which is a reaction product of ethylene oxide, propylene oxide and/or butylene oxide with C10-22 carboxylic acids or C10-22 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, Tex., 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.
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, Tex., 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 (methylstyrene/acrylate copolymer particularly suited for providing HPHT filtration control in non-aqueous fluid systems); RHEMOD L™ suspension agent/viscosifier (modified fatty acid); comprising dimeric and trimeric fatty acids); GELTONE® II viscosifier (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.
1Blend of oxidized tall oil and polyaminated fatty acid emulsion stabilizer.
2Polyaminated fatty acid emulsifier.
3Organophilic leonardite filtration control agent.
4Copolymer HTHP filtration control agent for non-aqueous systems.
5Modified fatty acid suspension agent/viscosifier.
6Organophilic clay viscosifier.
7Carboxylic acid suspension agent.
8Ground barium sulfate weighting agent.
9Sulfonate sodium salt wetting agent/thinner.
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
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.
As used in Table 5 “N” and “K” are Power Law model rheology parameters.
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 rpm). 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.
Field Tests
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
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, Tex.), 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, Tex. (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.
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.
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.
Table 10 below and
Environmental Impact Studies
Table 11 and the graph in
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 biodegradability requirements set forth by the United States Environmental Protection Agency.
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.
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.
This application is a continuation of U.S. patent application Ser. No. 10/292,124, filed Nov. 12, 2002, pending, which is a continuation-in-part of Ser. No. 10/175,272, filed Jun. 19, 2002, now U.S. Pat. No. 6,887,832, issued May 3, 2005, which is a continuation-in-part of U.S. patent application Ser. No. 09/929,465, filed Aug. 14, 2001, abandoned, and International Patent Application Nos. PCT/US00/35609 and PCT/US00/35610, both filed Dec. 29, 2000, and having entered national phase in the United States and pending as U.S. patent application Ser. No. 10/432,787 and U.S. patent application Ser. No. 10/432,786 respectively.
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| Number | Date | Country | |
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| Child | 11634008 | US |
| Number | Date | Country | |
|---|---|---|---|
| Parent | 10175272 | Jun 2002 | US |
| Child | 10292124 | US | |
| Parent | 09929465 | Aug 2001 | US |
| Child | 10175272 | US | |
| Parent | PCT/US00/35609 | Dec 2000 | US |
| Child | 09929465 | US | |
| Parent | PCT/US00/35610 | Dec 2000 | US |
| Child | PCT/US00/35609 | US |
