THERMALLY STABLE OIL-BASE DRILLING FLUID

Abstract: An oil-base drilling fluid capable of being held at temperatures in excess of 400 DEG F while maintaining its yield point comprises (i) oil, (ii) a surfactant, (iii) an organophilic clay, (iv) a polymeric fluid loss control agent selected from the group consisting of polystyrene, polybutadiene, polyethylene, polypropylene, polybutylene, polyisoprene, natural rubber, butyl rubber, polymers consisting of at least two monomers selected from the group consisting of styrene, butadiene, isoprene, and vinyl carboxylic acid, and mixtures thereof, and (v) a sulfonated elastomer polymeric viscosifier.

Description: THERMALLY STABLE OIL-BASE DRILLING FLUID BACKGROUND OF THE INVENTION The present invention relates to oil-base drilling fluids and systems and processes for drilling a borehole in a subterranean formation. Oil-base drilling muds and techniques for drilling boreholes in subterranean formations to recover hydrocarbons (e.g., oil and gas) are well known to those skilled in the art. While tripping a drillstring, running logs, performing fishing operations, or conducting other procedures during a drilling operation, the drilling fluid or mud in the borehole remains stagnant and its temperature can reach, and remain at, the bottomhole temperature for several days. SUMMARY OF THE INVENTION According to one aspect of the invention, there is provided an oil-base drilling fluid comprising oil, a surfactant, a fluid loss control agent, and a viscosifier, characterized in that the fluid loss control agent is selected from the group consisting of polystyrene, polybutadiene, polyethylene, polypropylene, polybutylene, polyisoprene, natural rubber, butyl rubber, polymers consisting of at least two monomers selected from the group consisting of styrene, butadiene, isoprene, and vinyl carboxylic acid, and mixtures thereof and the viscosifier is a sulfonated elastomer polymer. According to another aspect of the invention, there is provided an oil-base drilling fluid weighing about 7.5 to about 20 pounds per gallon and comprising: (a) about 25 to about 85 volume percent oil based on the total volume of the fluid; (b) about 1 to about 20 pounds per barrel (ppb) surfactant; (c) up to about 45 volume percent water based on the total volume of the fluid; (d) up to about 600 ppb weighting agent; (e) about 0.5 to about 30 ppb organophilic clay; (f) up to about 30 ppb auxiliary fluid loss control agent; (g) about 3 to about 12 ppb polymeric fluid loss control agent selected from the group consisting of polystyrene, polybutadiene, polyethylene, polypropylene, polybutylene, polyisoprene, natural rubber, butyl rubber, polymers consisting of at least two monomers selected from the group consisting of styrene, butadiene, isoprene, and vinyl carboxylic acid, and mixtures thereof; (h) about 0.02 to about 2 weight percent sulfonated elastomer polymeric viscosifier; (i) up to about 60 ppb shale inhibiting salt; and (j) up to about 30 ppb lime. According to a further aspect of the invention, there is provided a drilling system comprising: (a) at least one subterranean formation; (b) a borehole penetrating a portion of at least one of the subterranean formations; (c) a drill bit suspended in the borehole; and (d) a drilling fluid located in the borehole and proximate the drill bit, wherein the drilling fluid is the oil-base drilling fluid, as described above. According to a still further aspect of the invention, there is provided a method for drilling a borehole in a subterranean formation, the method comprising the steps of: (a) rotating a drill bit at the bottom of the borehole and (b) introducing a drilling fluid into the borehole (i) to pick up drill cuttings and (ii) to carry at least a portion of the drilling cuttings out of the borehole, wherein the drilling fluid is the oil-base drilling fluid, as described above. Organophilic clays used in oil-base drilling fluids have been observed to degrade when the drilling fluid is maintained at bottomhole temperatures exceeding 400° F. This degradation lowers the yield point of the drilling fluid— rendering the drilling fluid incapable of suspending solids and resulting in expensive drilling problems such as weighting agent sagging, mud density variations, solids settling, stuck drillpipe, poor hole cleaning, excessive fluid loss to the formation, and poor cement jobs. The present invention provides an oil-base drilling fluid capable of being held at temperatures in excess of 400° F while maintaining its yield point. The oil-base fluid comprises (i) oil, (ii) a surfactant, (iii) an organophilic clay, (iv) a polymeric fluid loss control agent selected from the group consisting of polystyrene, polybutadiene, polyethylene, polypropylene, polybutylene, polyisoprene, natural rubber, butyl rubber, polymers consisting of at least two monomers selected from the group consisting of styrene, butadiene, isoprene, and vinyl carboxylic acid, and mixtures thereof, and (v) a sulfonated elastomer polymeric viscosifier. In addition, a drilling system and a method for drilling a borehole are also provided by the invention. The drilling system comprises (a) at least one subterranean formation, (b) a borehole penetrating a portion of at least one of the subterranean formations, (c) a drill bit suspended in the borehole, and (d) the above drilling fluid located in the borehole and proximate the drill bit. Regarding the method for drilling a borehole of the present invention, this method comprises the steps of (a) rotating a drill bit at the bottom of the borehole and (b) introducing the aforesaid drilling fluid into the borehole (i) to pick up drill cuttings and (ii) to carry at least a portion of the drill cuttings out of the borehole. DESCRIPTION OF THE DRAWINGS The improved heat aged performance characteristics and other features, aspects, and advantages of the present invention will become better understood with reference to the following description, appended claims, and accompanying drawings where: Figure 1 is a graph depicting the plastic viscosity as a function of aging time at about 400" F of three commercially available drilling fluids alleged by their suppliers to possess good thermal stability. Figure 2 is a graph depicting the yield point as a function of aging time at about 400° F of the three commercially available drilling fluids shown in Figure 1. Figure 3 is a graph depicting the high temperature- high pressure fluid (HTHP) loss as a function of aging time at about 400° F of the three commercially available drilling fluids shown in Figure 1. Figure 4 is a graph depicting the top oil separation as a function of aging time at about 400° F of the three commercially available drilling fluids shown in Figure 1. Figure 5 is a graph depicting the plastic viscosity as a function of aging time at about 400° F of an exemplary drilling fluid of the present invention and another two commercially available drilling fluids alleged by their suppliers to possess better thermal stability than the drilling fluids depicted in Figures 1-4. Figure 6 is a graph depicting the yield point as a function of aging time at about 400° F of the exemplary drilling fluid of the present invention and the other two commercially available drilling fluids shown in Figure 5. Figure 7 is a graph depicting the HTHP loss as a function of aging time at about 400° F of the exemplary drilling fluid of the present invention and the other two commercially available drilling fluids shown in Figure 5. Figure 8 is a graph depicting the top oil separation as a function of aging time at about 400° F of the exemplary drilling fluid of the present invention and the other two commercially available drilling fluids shown in Figure 5. DETAILED DESCRIPTION OF THE INVENTION Without being bound by the theory of its operation, it is believed that the oil-based drilling fluid of the present invention maintains it yield point upon aging at temperatures greater than about 400° F by, among other things, the unique combination of three ingredients, namely, a thermally stable organophilic clay, a polymeric fluid loss control agent, and a sulfonated elastomeric polymeric viscosifier. Exemplary thermally stable organophilic clays include, but are not necessarily limited to, hectorite and bentonite, with hectorite being the more preferred. The organophilic clays can be employed either individually or in combina io . Illustrative polymeric fluid loss control agents include, but are not limited to, polystyrene, polybutadiene, polyethylene, polypropylene, polybutylene, polyisoprene, natural rubber, butyl rubber, polymers consisting of at least two monomers selected from the group consisting of styrene, butadiene, isoprene, and vinyl carboxylic acid. Individual or mixtures of polymeric fluid loss control agents can be used in the oil base drilling fluid of this invention. Exemplary polymeric fluid loss control agents are described in SPE 13560 (1985) , this article being incorporated herein in its entirety by reference. The preferred polymeric fluid loss control agents are styrene-butadiene copolymers. Characteristics of exemplary styrene-butadiene copolymers are listed in the following Table I: TABLE I Union Oil Company of California Product Number Characteristic 76RES4176 Styrene/- Butadiene Ratio 50/50 Surfactant Type Anionic Tg, °C -22 pH 9.0 All the styrene/butadiene copolymers described in above Table I also contain about 1 to about 3 weight percent copolymerized carboxylic acid (e.g. , itaconic acid and acrylic acid) . The sulfonated elastomer polymeric viscosifier is preferably a neutralized sulfonated elastomer polymer having about 5 to about 100 millie uivalents of sulfonate groups per 100 grams of sulfonated polymer. More preferably, the neutralized sulfonated elastomer polymer has about 5 to about 50 milliequivalents, and most preferably about 5 to about 30 milliequivalents, of sulfonate groups per 100 grams of sulfonated polymer. Preferably, the sulfonated elastomer polymeric viscosifier is derived from an elastomer polymer selected from the group consisting of ethylene-propylene-diene monomer (EPDM) terpolymers, copolymers of isoprene and styrene sulfonate salt, copolymers of chloroprene and styrene sulfonate salt, copolymers of isoprene and butadiene, copolymers of styrene and styrene sulfonate salt, copolymers of butadiene and styrene sulfonate salt, copolymers of butadiene and styrene, terpolymers of isoprene, styrene, and styrene sulfonate salt, terpolymers of butadiene, styrene, and styrene sulfonate salt, butyl rubber, partially hydrogenated polyisoprenes, partiallyhydrogenated polybutylene, partially hydrogenated natural rubber, partially hydrogenated buna rubber, partially hydrogenated polybutadienes, and Neoprene. Methods for obtaining and characteristics of sulfonated elastomer polymers are known to those skilled in the art. See, for example, U.S. Patent 4,447,338, U.S. Patent 4,425,462, U.S. Patent 4,153,588, U.S. Patent 4,007,149, U.S. Patent 3,912,683, andU.K. Patent Application 2,212,192, these documents being incorporated in their entirety by reference. Typically, the oil-base drilling fluid of the present invention contains the ingredients and properties set forth in the following Table II: TABLE II Ingredient Oil, volume % a Surfactant (active) , pounds per barrel (ppb) b ' 9 Water, volume % a Weighting agent, ppb Organophilic clay, ppb 0.5-30 1-10 Auxiliary fluid loss control agent, ppb Up to 30 2-15 Polymeric fluid loss control agent, ppb c 3-12 5-10 Sulfonated elastomer polymeric viscosifier, ppb d Shale inhibiting salt, ppb Lime, ppb e Property Density, ppg a. Volume percent is based on the total volume of the drilling fluid. b. As used in the specification and claims, the term "surfactant" means a substance that, when present at low concentration in a system, has the property of adsorbing onto the surfaces or interfaces of the system and of altering to a marked degree the surface or interfacial free energies of those surfaces (or interfaces) . As used in the foregoing definition of surfactant, the term "interface" indicates a boundary between any two immiscible phases and the term "surface" denotes an interface where one phase is a gas, usually air. Exemplary ingredients referred to as surfactants by those skilled in the art include emulsifiers and oil wetting agents. c. The polymeric fluid loss control agent is preferably present in the drilling fluid in a concentration of about 6 to about 9 ppb. d. The sulfonated elastomer polymeric viscosifier is preferably present in the drilling fluid in a concentration of about 0.1 to about 1 ppb. e. As used in the specification and claims, the term "lime" means quicklime (CaO) , quicklime precursors, and hydrated quicklime (e.g., slaked lime (Ca(OH) E )). f. ppg denotes pounds per gallon. g. The parts per barrel (ppb) is based upon the final composition of the drilling fluid. The volumetric ratio of oil to water in the drilling fluid of the present invention ranges from about 100:0 to about 50:50. Preferably, the weight ratio of the polymeric fluid loss control agent to the sulfonated elastomer polymeric viscosifier is about 1.5:1 to about 50:1, more preferably about 3:1 to about 20:1, and most preferably about 5:1 to about 10:1. Oils, surfactants, weighting agents, and shale inhibiting salts typically used in oil-base drilling fluids are suitable for use in the present invention. For example, exemplary oils, surfactants, and weighting agents are described in U.S. Patent 4,447,338 and U.S. Patent 4,425,462, these patents having previously been incorporated herein in their entireties by reference. Typical shale inhibiting salts are alkali metal and alkaline-earth metal salts. Calcium chloride and sodium chloride are the preferred shale inhibiting salts. As used in the specification and claims, the term "auxiliary fluid loss control agents" means particles (other than the polymeric fluid loss control agent discussed above) having a size only slightly smaller than that of the pore openings in the formation. The auxiliary fluid loss control agent is used to form a filter cake on the surface of a wellbore to reduce the loss of drilling fluid solids and liquids to the formation. Exemplary auxiliary fluid loss control agents include, but are not limited to, sulfonated asphaltenes, asphaltenes, lignite, and gilsonite. The softening point of the auxiliary fluid loss control agent is as high as possible, preferably at least about 300° F, and more preferably at least about 350° F. Due to its high softening point, gilsonite is the most preferred auxiliary fluid loss control agent. Commercially available gilsonite has a softening point within the range of about 290° to about 400° F. The drilling fluid is preferably prepared by mixing the constituent ingredients in the following order: (a) oil, (b) organophilic clay, (c) surfactant, (d) lime, (e) an aqueous solution comprising water and the shale inhibiting salt, (f) auxiliary fluid loss control agent, (g) weighting agent, (h) polymeric fluid loss control agent, and (i) sulfonated elastomer polymeric viscosifier. The preferred plastic viscosity, yield point, high temperature-high pressure (HTHP) fluid loss, and top oil separation ranges for the drilling mud of the present invention are set forth in the following Table III. TABLE III Preferred Range Plastic Viscosity, cp about 25 to about 48 Yield Point, lb/lOOsqft about 10 to about 32 HTHP Fluid Loss, ml about 1 to about 23 Top Oil Separation, ml less than about 25 EXAMPLES The following examples (which are intended to illustrate and not limit the invention, the invention being defined by the claims) compare various properties of an exemplary drilling fluid within the scope of the present invention (Example 1) with commercially available drilling fluids (Comparative Examples 2-7) . In addition, Examples 8-11 demonstrate that different styrene/butadiene copolymers are suitable for use in the drilling fluids of this invention. The effect of varying sulfonated elastomer polymeric viscosifier and polymeric fluid loss control agent concentrations on the properties of drilling fluids is shown in Examples 12-18. EXAMPLE 1 An exemplary oil-base drilling fluid or mud (about 5 lab barrels, each lab barrel containing about 350 ml) within the scope of the present invention was formulated as shown in the following Table IV. The ingredients were sequentially added in the order set forth in Table IV. After the addition of each ingredient, the resulting composition was mixed for the indicated mixing time prior to adding a subsequent ingredient to the composition. TABLE IV Component Mentor 26 brand oil Inventone 38H brand amine-treated hectorite Versamul I brand primary emulsifier Versacoat I brand oil wetting agent Versawet I brand surfactant Lime (Ca(OH) 2 ) Brine solution Water CaCl 2 Versatrol brand gilsonite Barite HT brand polymeric fluid loss control agent Tek Mud 1949 brand sulfonated elastomer polymeric viscosifier a. N/A denoted not applicable. b. The amine-treated hectorite was slowly added to the oil. One sample was used to check the initial rheological properties. Samples to be aged were tested in duplicate, i.e., two samples were aged for about 24 hours and another two samples were aged for about 72 hours. The age-tested samples were placed into aging bombs in the presence of about 100 psi nitrogen and rolled at about 400° F. After aging, the amount of top oil separation was measured and the consistency of the drilling fluid noted. The age-tested samples were then remixed and their rheological properties checked. Both the initial and age-tested rheological properties were measured at about 150° F. The results are set forth below in Table V, with the plastic viscosity (PV) , yield point (YP) , high temperature-high pressure (HTHP) fluid loss, and top oil separation being plotted in Figures 5-8, respectively. Top oil separation, ml 9 16 18 a. E.S. denotes electrical stability and was measured according to the procedure described in Recommended Practice - Standard Procedure for Field Testing Drilling Fluids, Recommended Practice 13B (RP 13B) , Twelfth Edition, September 1, 1988, American Petroleum Institute, Washington, DC (hereinafter referred to as "API"), page 28. b. Dial readings were obtained using a 115-volt motor driven viscometer described in API, pages 7-9, sections 2.4 to 2.5. c. Gel strength for 10 seconds and 10 minutes was determined in accordance with the procedure discussed in API, page 9, section 2.5, paragraphs f and g, respectively. d. PV was determined in accordance with the procedure and calculations discussed in API, page 9, sections 2.5 to 2.6. e. YP was determined in accordance with the procedure and calculations discussed in API, page 9, sections 2.5 to 2.6. f. HTHP was determined in accordance with the procedure discussed in API, page 12, section 3.5. g. Top oil separation was determined by decanting and measuring the oil layer above the solids in the age-tested drilling fluid present in aging bomb. COMPARATIVE EXAMPLES 2-7 In comparative Examples 2-7, six different high temperature service company drilling fluids (about 5 lab barrels each) were prepared using recipes and mixing procedures supplied by the service companies. One sample of each of the different drilling fluids was used to check the initial rheological properties. Each aged sample was tested in duplicate, i.e., two samples of each different drilling fluid were aged for about 24 hours and another two samples were aged for about 72 hours. The age-tested samples were placed into aging bombs in the presence of about 100 psi nitrogen and rolled at about 400° F. After aging, the amount of top oil separation was measured and the consistency of the drilling fluid noted. The age-tested samples were then remixed and their rheological properties checked. Both the initial and age-tested rheological properties were measured at about 150° F. The results are set forth below in Tables VI to XI, with the PV, YP, HTHP fluid loss, and top oil separation data for Examples 2-4 being respectively plotted in Figures 1-4 and the PV, YP, HTHP fluid loss, and top oil separation data for Examples 5-7 being plotted in Figures 5-8, respectively. TABLE VI MILPARK INVERT EMULSION DRILLING FLUID #1 Component Mentor 26 brand oil Carbo-Tec brand high temperature emulsifier Carbo-Mul brand emulsifier and wetting agent Quick lime Brine solution Water CaCl 2 Carbo-Gel brand hectorite-based organophilic clay Tek Mud 1949 brand sulfonated elastomer polymeric viscosifier Carbo Trol HT brand polymeric fluid loss control agent Barite a. N/A denoted not applicable. MILPARK INVERT EMULSION DRILLING FLUID #1 Gel Strength 0 , TABLE VI (continued) 10 sec/ 10 min 10/2 2/5 4/2 PV, cp d 20 36 44 . 5 YP, lbs/100sqft e 5 13 8 . 5 HTHP fluid loss , ml f 4.4 25.5 110 Top oil separation, ml 9 55 a.-g. See Table V, footnotes. TABLE VII MILPARK INVERT EMULSION DRILLING FLUID #2 Component Mentor 26 brand oil Carbo-Tec brand high temperature emulsifier Carbo-Mul brand emulsifier and wetting agent Quick lime Brine solution Water CaCl 2 Carbo-Gel brand hectorite-based organophilic clay 2 ppb Tek Mud 1949 brand sulfonated elastomer polymeric viscosifier PE-0140 brand latex polymer Carbo Trol HT brand polymeric fluid loss control agent Barite a. N/A denoted not applicable. TABLE VII (continued) Top oil separation, ml 9 30 68 r a.-g. See Table V, footnotes. h. Drilling mud was severely caked in the bottom of the agi g bomb. TABLE VIII M-I INVERT EMULSION DRILLING FLUID Mixing Time, minutes N/A a 30 TABLE VIII (continued) oil wetting agent Versawet I brand surfactant Lime (Ca(OH) 2 ) Brine solution Water CaCl 2 Versatrol brand gilsonite HT brand polymeric fluid loss control agent Barite a. N/A denoted not applicable. M-I INVERT EMULSION DRILLING FLUID Gel Strength 0 , 10 sec/10 min 10/6 PV, cp d 26 YP, lbs/100sqft e 15 HTHP fluid loss, ml f 18 Top oil separation, ml 9 32 40 a.-g. See Table V, footnotes. TABLE IX TABLE IX (continued) BARIOD INVERT EMULSION DRILLING FLUID #1 After Hot Rolling At 400° F 24 Hours 72 Hours 327 258 105 126 62 76 47 57 29 34 5 4 4 3 4/24 17/3 43 50 19 25.5 3.4 8 Top oil separation, ml 9 16 a.-g. See Table V, footnotes. TABLE X continued Top oil separation, ml 9 a.-g. See Table V, footnotes. TABLE XI IDF INVERT EMULSION DRILLING FLUID Mixing Time, Component Quantity minutes Mentor 26 brand oil 0.55 bbl N/A 3 Interdrill Emul brand oil mud emulsifier 3 ppb Interdrill Fl brand fluid loss reducer and secondary emulsifier 7 ppb Interdrill OW brand oil wetting agent 1 ppb Interdrill ESX brand high temperature emulsion/- contamination stabilizer Lime Vistone HT brand organophilic clay Brine solution Water CaCl 2 Trudrill S brand asphaltene fluid loss control agent Barite a. N/A denoted not applicable. TABLE XI (continued) IDF INVERT EMULSION DRILLING FLUID After Hot Rolling At 400° F Top oil separation, ml 9 a.-g. See Table V, footnotes. A comparison of the results depicted in Figures 1-8 graphically indicates that the only drilling mud possessing satisfactory initial and aged plastic viscosity, yield point, HTHP fluid loss loss, and top oil separation characteristics is the exemplary drilling fluid within the scope of the present invention. EXAMPLES 8-11 EXEMPLARY DRILLING FLUIDS CONTAINING DIFFERENT STYRENE/BUTADIENE POLYMERS Using the different styrene/butadiene polymers set forth above in Table I, exemplary oil-base drilling fluids (about 5 lab barrels each) within the scope of the present invention were formulated as shown in the following Table XII: TABLE XII MixingTime, Component Ouantity minutes Mentor 26 brand oil 205 ml (0.586 bbl) N/A a Inventone 38H brand amine-treated hectorite 3 ppb 30 L Versamul I brand primary emulsifier 4 ppb Versacoat I brand oil wetting agent 5 ppb 10 Versawet I brand surfactant 3 ppb Lime (Ca(OH) 2 ) 10 ppb 10 Brine solution 30 Water 51.5 ml (0.147 bbl) CaCl 2 26.3 ppb Versatrol brand gilsonite 10 ppb 15 Barite 269 ppb 20 Styrene/Butadiene polymer 6 ppb 10 Tek Mud 1949 brand sulfonated elastomer polymeric viscosifier 1 ppb 35 a. N/A denoted not applicable. b. The amine-treated hectorite was slowly added to the oil. One sample of each drilling fluid was used to check the initial rheological properties. Samples to be aged for about 72 hours were tested in duplicate, while only one sample was used for those to be age-tested for about 24 hours. The age-tested samples were placed into 8 aging bombs in the presence of about 100 psi nitrogen and rolled at about 400° F. After aging, the amount of top oil separation was measured and the consistency of the drilling fluid noted. The age- tested samples were then remixed and their rheological properties checked. Both the initial and age-tested rheological properties were measured at about 150° F. The results are set forth below in Table XIII. TABLE XIII Gel Strength 0 , 10 sec/10 min 21/32 12/22 6/12 PV, cp d 40 50 54 YP, lbs/100sqft e 30 32 18 HTHP fluid loss, ml 6 18 11 Top oil separation, ml ε 25 24 Top oil separation, ml 9 28 27 TABLE XIII (continued) C. 76RES4106 After Hot Rolling At 400° F Initial 24 Hours 72 Hours 367 307 106 85 63 49 50 37 33 24 11 7 10 6 10/20 6/17 43 36 20 13 44 36 Top oil separation, ml 9 23 25 TABLE XIII (continued) D. 76RES4470 After Hot Rolling At 400' 24 Hours 72 Hours 318 277 102 106 58 58 42 43 27 25 6 5 5 4 5/10 4/10 44 48 14 10 10 20 Top oil separation, ml 9 13 21 a.-g. SeeTableV,footnotes. The data listed in above Table XIII indicate that each of the four different styrene/butadiene polymers listed in Table I yields a drilling fluid having overall satisfactory characteristics for use at elevated temperatures when formulated in accordance with the present invention. EXAMPLES 12-18 EFFECT OF VARYING SULFONATED ELASTOMER POLYMERIC VISCOSIFIER AND POLYMERIC FLUID LOSS CONTROL AGENT CONCENTRATIONS Seven exemplary oil-base drilling fluids (about 5 lab barrels each) were formulated using varying sulfonated elastomer polymeric viscosifier and polymeric fluid loss control agent concentrations as shown in the following Table XIV: TABLE XIV Mixing Time, Component Ouantity minutes Mentor 26 brand oil 205 ml (0.586 bbl) N/A 3 Inventone 38H brand amine-treated hectorite 3 ppb 30 c Versamul I brand primary emulsifier 4 ppb Versacoat I brand oil wetting agent Versawet I brand surfactant Lime (Ca(0H) 2 ) Brine solution Water CaCl 2 Versatrol brand gilsonite Barite HT brand polymeric fluid loss control agent varied 10 Tek Mud 1949 brand sulfonated elastomer polymeric viscosifier varied 35 a. N/A denoted not applicable. b. The amine-treated hectorite was slowly added to the oil One sample was used to check the initial rheological properties and either single or duplicate samples were used to check the rheological properties after being aged for about 72 hours. Each age-tested sample was placed into an aging bomb in the presence of about 100 psi nitrogen and rolled at about 400° F. After aging, the amount of top oil separation was measured and the consistency of the drilling fluid noted. The age-tested samples were then remixed and their rheological properties checked. Both the initial and age-tested rheological properties were measured at about 150° F. The results are noted below in Table XV. TABLE XV HT Polymer, ppb Tek Mud, ppb TABLE XV continued 32 TABLE XV (continued) Gel Strength 0 , 10 sec/10 min 9/18 1/1 17/18 2/5 27/37 17/28 PV, cp d 21 31 32 37 58 56 YP, lbs/100sqft e 18 -1 23 8 34 37 HTHP fluid loss, ml f 2.4 1.6 1.4 73 Top oil separation, ml 9 N/A h 34 19 TABLE XV continued 38/50 165/225 48/96 111 132 TV 1' 51 486 TV 1 6.7 2.4 10 Top oil separation, ml 9 17 a.-g. See Table V, footnotes. h. N/A denotes not available. i. TV denotes too viscous to obtain. The data in above Table XV indicate that, for the concentrations ranges tested, best results were obtained when the drilling fluid of the present invention contained a polymeric fluid loss control agent concentration of about 6 ppb and a sulfonated elastomer polymeric viscosifier concentration of about 0.5 to about 1 ppb. Field observations indicate that lower concentrations of the polymeric fluid loss control agent and sulfonated elastomer polymeric viscosifier can be employed to give very acceptable results. This observation is believed to be due to the presence in the drilling fluid of ine particle size materials that originate in the subterranean formation but do not separate from drilling fluid when the drilling fluid is processed to remove drill cuttings. Although the present invention has been described in detail with reference to some preferred versions, other versions are possible. Therefore, the spirit and scope of the appended claims should not necessarily be limited to the description of the preferred versions contained herein.

Claims: C L A I S 1. An oil-base drilling fluid comprising oil, a surfactant, a fluid loss control agent, and a viscosifier, characterized in that the fluid loss control agent is selected from the group consisting of polystyrene, polybutadiene, polyethylene, polypropylene, polybutylene, polyisoprene, natural rubber, butyl rubber, polymers consisting of at least two monomers selected from the group consisting of styrene, butadiene, isoprene, and vinyl carboxylic acid, and mixtures thereof and the viscosifier is a sulfonated elastomer polymer. 2. The oil-base drilling fluid of claim 1 wherein the sulfonated elastomer polymer is a neutralized sulfonated elastomer polymer having about 5 to about 100 milliequivalents of sulfonate groups per 100 grams of sulfonated polymer. 3. The oil-base drilling fluid of claim 1 wherein the sulfonated elastomer polymer is derived from an elastomer polymer selected from the group consisting of ethylene- propylene-diene monomer (EPDM) terpolymers, copolymers of isoprene and styrene sulfonate salt, copolymers of chloroprene and styrene sulfonate salt, copolymers of isoprene and butadiene, copolymers of styrene and styrene sulfonate salt, copolymers of butadiene and styrene sulfonate salt, copolymers of butadiene and styrene, terpolymers of isoprene, styrene, and styrene sulfonate salt, terpolymers of butadiene, styrene, and styrene sulfonate salt, butyl rubber, partially hydrogenated polyisoprenes, partially hydrogenated polybutylene, partiallyhydrogenated natural rubber, partially hydrogenated buna rubber, partially hydrogenated polybutadienes, and Neoprene. 4. The oil-base drilling fluid of claim 1 wherein the fluid loss control agent is a styrene-butadiene copolymer. 5. The oil-base drilling fluid of claim 1 comprising about 3 to about 12 pounds per barrel (ppb) of the fluid loss control agent and about 0.02 to about 2 ppb of the sulfonated elastomer polymer. 6. The oil-base drilling fluid of claim 1 comprising about 5 to about 10 pounds per barrel (ppb) of the fluid loss control agent and about 0.5 to about 1.5 ppb of the sulfonated elastomer polymer. 7. The oil-base drilling fluid of claim 6 comprising about 6 to about 9 ppb of the fluid loss control agent. 8. The oil-base drilling fluid of claim 1 wherein the weight ratio of (a) the fluid loss control agent to (b) the sulfonated elastomer polymer is about 1.5:1 to about 50:1. 9. The oil-base drilling fluid of claim 1 wherein the weight ratio of (a) the fluid loss control agent to (b) the sulfonated elastomer polymer is about 3:1 to about 20:1. 10. The oil-base drilling fluid of claim 1 wherein the weight ratio of (a) the fluid loss control agent to (b) the sulfonated elastomer polymer is about 5:1 to about 10:1. 11. The oil-base drilling fluid of claim 1 further comprising water. 12. The oil-base drilling fluid of claim 1 further comprising lime. 13. The oil-base drilling fluid of claim 1 further comprising a weighting agent. 14. The oil-base drilling fluid of claim 1 further comprising a shale inhibiting salt. 15. An oil-base drilling fluid weighing about 7.5 to about 20 pounds per gallon and comprising: (a) about 25 to about 85 volume percent oil based on the total volume of the fluid; (b) about 1 to about 20 pounds per barrel (ppb) surfactant; (c) up to about 45 volume percent water based on the total volume of the fluid; (d) up to about 600 ppb weighting agent; (e) about 0.5 to about 30 ppb organophilic clay; (f) up to about 30 ppb auxiliary fluid loss control agent; (g) about 3 to about 12 ppb polymeric fluid loss control agent selected from the group consisting of polystyrene, polybutadiene, polyethylene, polypropylene, polybutylene, polyisoprene, natural rubber, butyl rubber, polymers consisting of at least two monomers selected from the group consisting of styrene, butadiene, isoprene, and vinyl carboxylic acid, and mixtures thereof; (h) about 0.02 to about 2 weight percent sulfonated elastomer polymeric viscosifier; (i) up to about 60 ppb shale inhibiting salt; and (j) up to about 30 ppb lime. 16. The oil-base drilling fluid of claim 15 weighing about 9 to about 16 pounds per gallon and comprising: (a) about 50 to about 60 volume percent oil based on the total volume of the fluid; (b) about 1 to about 10 ppb surfactant; (c) about 10 to about 20 volume percent water based on the total volume of the fluid; (d) about 150 to about 400 ppb weighting agent; (e) about 1 to about 10 ppb organophilic clay; (f) about 2 to about 15 ppb auxiliary fluid control agent; (g) about 5 to about 10 ppb polymeric fluid control agent; (h) about 0.5 to about 1.5 weight percent sulfonated elastomer polymeric viscosifier; (i) about 20 to about 30 ppb shale inhibiting salt; and (j) about 1 to about 10 ppb lime. 17. The oil-base drilling fluid of claim 15 wherein the auxiliary fluid control loss agent is selected form the group consisting of amine-treated lignite, gilsonite, asphaltics, and mixtures thereof. 18. A drilling system comprising: (a) at least one subterranean formation; (b) a borehole penetrating a portion of at least one of the subterranean formations; (c) a drill bit suspended in the borehole; and (d) a drilling fluid located in the borehole and proximate the drill bit, wherein the drilling fluid is the oil-base drilling fluid of claim 1. 19. A drilling system comprising: (a) at least one subterranean formation; (b) a borehole penetrating a portion of at least one of the subterranean formations; (c) a drill bit suspended in the borehole; and (d) a drilling fluid located in the borehole and proximate the drill bit, wherein the drilling fluid is the oil-base drilling fluid of claim 15. 20. A method for drilling a borehole in a subterranean formation, the method comprising the steps of: (a) rotating a drill bit at the bottom of the borehole and (b) introducing a drilling fluid into the borehole (i) to pick up drill cuttings and (ii) to carry at least a portion of the drilling cuttings out of the borehole, wherein the drilling fluid is the oil-base drilling fluid of claim 1. 21. A method for drilling a borehole in a subterranean formation, the method comprising the steps of: (a) rotating a drill bit at the bottom of the borehole and (b) introducing a drilling fluid into the borehole (i) to pick up drill cuttings and (ii) to carry at least a portion of the drilling cuttings out of the borehole, wherein the drilling fluid is the oil-base drilling fluid of claim 15.

Inventors: SPADA LONNIE T, STEINWAND PAUL J, VAN SLYKE DONALD C, SPADA, LONNIE, T., STEINWAND, PAUL, J., VAN SLYKE, DONALD, C.
Applicants: UNION OIL CO, UNION OIL COMPANY OF CALIFORNIA
Application year: 1992
Main classification: C09K7
IPC codes: C09K8