Classifications

• • C—CHEMISTRY; METALLURGY
  • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
  • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
  • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
  • C09K8/02—Well-drilling compositions
  • C09K8/32—Non-aqueous well-drilling compositions, e.g. oil-based
  • C09K8/36—Water-in-oil emulsions

Definitions

• 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 methods for improving the rheology of invert emulsion drilling fluids, particularly at high temperatures, and to compositions for low mud weight, invert emulsion drilling fluids, with good stability and high performance properties.
• 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.
• the fluid should be sufficiently viscous to suspend barite and drilled cuttings and to carry the cuttings to the well surface. However, the fluid should not be so viscous as to interfere with the drilling operation.
• Oil based muds are normally used to drill swelling or sloughing shales, salt, gypsum, anhydrite and 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.
• An oil-based invert emulsion-based drilling fluid may commonly comprise between about 50:50 to about 95:5 by volume oil phase to water phase.
• Such oil-based muds used in drilling typically comprise: a base oil 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.
• additives commonly included organophilic clays and organophilic lignites. See H.C.H.
• the term "clay- free” means a drilling fluid made without addition of any organophilic clays or organophilic lignites to the drilling fluid composition.
• such "clay-free” drilling fluids may acquire clays and/or lignites from the formation or from mixing with recycled fluids containing clays and/or lignites.
• contamination of "clay-free” drilling fluids is preferably avoided and organophilic clays and organophilic lignites should not be deliberately added to "clay-free” drilling fluids during drilling.
• 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, and "clay- free” invert emulsion-based muds, particularly those capable of "fragile gel" behavior as described in U.S. Patent Nos. 7,462,580 and 7,488,704 to Kirsner, et al., are becoming increasingly popular.
• Clay-free invert emulsion drilling fluids like INNOVERT® drilling fluid available from Halliburton Energy Services, Inc., in Duncan, Oklahoma and Houston, Texas, for example, have been shown to yield high performance in drilling, with "fragile gel” strengths and rheology leading to lower equivalent circulating density (ECDs) and improved rate of penetration ROP.
• ECDs equivalent circulating density
• a limiting factor in drilling a particular portion of a well is the mud weight
• a particularly critical drilling scenario is one that combines deepwater and shallow overburden, as is typical of ultra deepwater fields in Brazil. This scenario is characterized by high pore fluid pressure, low effective stresses, low fracturing gradients and narrow mud weight windows.
• inert solids may improve the rheology, but result in a decreased rate of penetration during drilling and loss of or decline in other benefits seen with a clay free system.
• inert solids include for example, fine sized calcium carbonate, and the term as used herein is not meant to be understood to include or refer to drill cuttings.
• Low mud weight or reduced density clay-free oil based invert emulsion drilling fluids also may show a decline in the desired "fragile gel” strength characteristic of clay-free invert emulsion drilling fluids.
• Fraile gel strength generally refers to the ability of the drilling fluid to both suspend drill cuttings at rest and show a lack of a pressure spike upon resumption of drilling.
• the present invention provides oil-based invert emulsion drilling fluids with improved rheology without the addition of inert solids, and at temperatures ranging from about 100°F to about 375°F or higher.
• the present invention also provides improved methods of drilling wellbores in subterranean formations employing oil-based invert emulsion muds or drilling fluids having low mud weight.
• 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 invert emulsion drilling fluid of the present invention comprises an oikwater ratio preferably in the range of 50:50 to 95:5 and preferably employs a natural oil, such as for example without limitation diesel oil or mineral oil, or a synthetic base, as the oil phase and water comprising calcium chloride as the aqueous phase.
• a natural oil such as for example without limitation diesel oil or mineral oil, or a synthetic base
• the rheology modifier or additive for rheology stability is a hydrophobic amine additive, having the following general structure:
• R represents a hydrophobic or partially hydrophobic group with carbon atoms from 16 - 54 which can be straight chained or branched and can be aliphatic, cycloaliphatic and aryl aliphatic;
• N is a primary, secondary or tertiary amine wherein the Rl and R2 groups may be the same or different and are selected from the group consisting of a hydrogen group, alkyl group, cyano alkyl group, amino alkyl group, amino aryl group, hydroxyl alkyl group or a derivative thereof; alternatively the Rl and R2 can be a carbonyl group, carbonate group, alkoxy group, hydroxyl group or a derivative thereof;
• X comprises a hydrophilic group such as an amine which can be primary, secondary or tertiary with substituents being a hydrogen group, alkyl group, cyano alkyl group, amino alkyl group, amino aryl group, hydroxyl alkyl group or a derivative thereof; alternative
• a preferred commercially available C36 dimer diamine contains C18 fatty monoamine and C54 fatty trimer triamine which are obtained during the commercial production of the dimer diamine.
• quantities of such hydrophobic amine ranging from about 1 ppb to about 6 ppb are preferred and are effective even when the mud weight is low, that is, is in the range of about 9 to about 12 ppg.
• the invert emulsion drilling fluid of the present invention comprising the hydrophobic amine additive has increased LSYP, YP, and 10 minute Gel Strength but similar or lower PV, relative to the drilling fluid without the hydrophobic amine additive.
• LSYP Low Shear Yield Point
• YP Yield Point
• 10 minute Gel Strength limits the increase in the Plastic Viscosity (PV) to about 60% or less, relative to the drilling fluid not having the hydrophobic amine additive, when measured at 120°F.
• HPHT High Pressure High Temperature
• the invert emulsion drilling fluid of the present invention comprising the hydrophobic amine additive has increased LSYP, YP, and 10 minute Gel Strength but similar or lower PV, relative to the drilling fluid without the hydrophobic amine additive.
• Such a lower PV seen with the invert emulsion drilling fluid of the invention is believed to help minimize the amount of density increase caused by pumping of the fluid.
• Invert emulsion drilling fluids of the invention may also demonstrate "fragile
• Figure 1 is a bar graph comparing the plastic viscosity, yield point and low shear yield point of example 9 ppg drilling fluid formulations of the invention having various concentrations of a hydrophobic amine rheology modifier, with a formulation without that additive.
• Figure 2a is a graph comparing, at high temperature and pressure, the low shear yield point of an example drilling fluid formulation of the invention having 3 ppb hydrophobic amine rheology modifier, with a base or control fluid not containing a hydrophobic amine rheology modifier.
• Figure 2b is a graph comparing, at high temperature and pressure, the yield point of an example drilling fluid formulation of the invention having 3 ppb hydrophobic amine rheology modifier, with a base or control fluid not containing a hydrophobic amine rheology modifier.
• Figure 2c is a graph comparing, at high temperature and pressure, the plastic viscosity of an example drilling fluid of the invention having 3 ppb hydrophobic amine rheology modifier, with a base or control fluid not containing a hydrophobic amine rheology modifier.
• Figure 3 is a graph showing the effect of a hydrophobic amine rheology modifier on an example drilling fluid of the invention not containing any inert solids additive.
• Figure 4 is bar graph comparing rheological characteristics of example drilling fluids of the invention having different mineral oil bases.
• Figure 5 is a bar graph comparing the rheology of an example 12 ppg drilling fluid of the invention with a base or control drilling fluid not having a hydrophobic amine rheology modifier, after hot rolling for 16 hours at 350°F.
• Figure 6 is a graph showing fragile gel behavior of an example 9 ppg drilling fluid of the invention compared to the behavior of a 9 ppg drilling fluid not having a hydrophobic amine rheology modifier.
• Figure 7a is a graph showing fragile gel behavior of an example drilling fluid of the invention having a mud weight of 16 ppg.
• Figure 7b is a graph showing fragile gel behavior of an example drilling fluid of the invention having a mud weight of 18 ppg
• the present invention provides an oil-based, invert emulsion drilling fluid with improved performance in the field at mud weights in the range of about 9 ppg to about 18 ppg, and a method of drilling employing that drilling fluid.
• the oil base may be a natural oil such as for example diesel oil, or a synthetic base such as, for example, ACCOLADE® base comprising esters or ENCORE® base comprising isomerized olefins, both available from Halliburton Energy Services, Inc., in Houston, Texas and Duncan, Oklahoma.
• a mineral oil may even be successfully used as the oil base in the present invention, even though in the prior art some difficulties have been experienced in obtaining desirable rheological properties with mineral oils under certain conditions such as low mud weights, that is, mud weights ranging from about 9 to about 12 ppg, and particularly at high temperatures (greater than 225 °F).
• Mineral oils particularly suitable for use in the invention are selected from the group consisting of n-paraffins, iso-paraffins, cyclic alkanes, branched alkanes, and mixtures thereof.
• An aqueous solution containing a water activity lowering compound, composition or material comprises 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 such as for example glycerol or sugar known in the art may alternatively or additionally be used.
• Such other salts may include for example sodium chloride, sodium bromide, calcium bromide and formate salts.
• Water preferably comprises less than 50%, or as much as about 50%, of the drilling fluid and the oikwater ratio preferably ranges from about 50:50 to about 95:5.
• Drilling fluids of the present invention uniquely include a hydrophobic amine additive as a rheology modifier, as will be discussed further below. Further, the drilling fluids of, or for use in, the present invention, have added to them or mixed with their invert emulsion oil base, other fluids or materials needed to comprise complete drilling fluids.
• Such other materials optionally may include, for example: additives to reduce or control low temperature rheology or to provide thinning, for example, additives having the trade names COLDTROL®, ATC®, and OMC2TM; additives for enhancing viscosity, for example, an additive having the trade name RHEMOD LTM (modified fatty acid); additives for providing temporary increased viscosity for shipping (transport to the well site) and for use in sweeps, for example, an additive having the trade name TEMPERUSTM (modified fatty acid); additives for filtration control, for example, additives having the trade names ADAPTA® and BDF-366; an emulsifier activator, such as, for example, lime; additives for high temperature high pressure control (HTHP) and emulsion stability, for example, an additive having the trade name FACTANTTM (highly concentrated tall oil derivative); and additives for emulsification, for example, an additive having the trade name EZ MUL® NT (polyaminated fatty acid).
• a preferred commercially available drilling fluid system for use in the invention is the INNOVERT® drilling fluid system, having a paraffin/mineral oil base, available from Baroid, a Halliburton Company, in Houston, Texas and Duncan, Oklahoma.
• the INNOVERT® drilling fluid system typically comprises the following additives, in addition to the paraffin/mineral oil base and brine, for use as an invert emulsion drilling fluid: RHEMODTM L modified fatty acid suspension and viscosifying agent, BDF-366TM or ADAPTATM copolymer for HPHT filtration control, particularly for use at high temperatures, and EZ MUL® NT polyaminated fatty acid emulsifier/oil wetting agent, also particularly for use at high temperatures.
• TAU-MODTM amorphous/fibrous material as a viscosifier and suspension agent.
• TAU-MODTM material is optional.
• Invert emulsion drilling fluids of the present invention comprising the hydrophobic amine additive, maintain acceptable and even preferred rheology measurements at low mud weights and do not experience a decreased rate of penetration (and with clay-free invert emulsion drilling fluids, also do not experience a decline in desired fragile gel strength) when in use in drilling even at high temperatures and pressures.
• the invert emulsion drilling fluids of the present invention comprising the hydrophobic amine additive, has increased LSYP, YP, and 10 minute Gel Strength but similar or lower PV relative to the drilling fluid without the hydrophobic amine additive.
• Preferred commercially available hydrophobic amines suitable for use in the present invention include without limitation VERSAMINE® 552 hydrogenated fatty C36 dimer diamine, and VERSAMINE® 551 fatty C36 dimer diamine, both available from Cognis Corporation (functional products) of Monheim, Germany and Cincinnati, Ohio and PRIAMINETM 1073 and PRIAMINETM1074 fatty C36 dimer diamine, both available from Croda Internationale Pic of Goole East Yorkshire, United Kingdom and New Castle, Delaware.
• an amount of such dimer diamine in the range of about 1 pound per barrel (ppb) to about 3 ppb is sufficient for purposes of the invention.
• These fatty dimer diamines are prepared commercially from fatty dimer diacids which have been produced from dimerisation of vegetable oleic acid or tall oil fatty acid by thermal or acid catalyzed methods.
• C36 dimer acids This material is a mixture of monocyclic dicarboxylic acid, acyclic dicarboxylic acid and bicyclic dicarboxylic acid along with small quantities of trimeric triacids. These diacids are converted into diamines via the reaction scheme given below:
• diamines are further converted into compounds that fall under the scope of hydrophobic amine additives.
• These diamines are converted into cyanoethyl derivatives via cyanoethylation with acrylonitrile; these cyanoethyl derivatives are further reduced into aminopropyl amines via reduction as shown in the reaction scheme II below, as taught in United States Patent No. 4,250,045, issued February 10, 1981 to Coupland, et al.
• Dicyanoethylated dimer diamine is available commercially as Kemamine DC 3680 and 3695 and di N-aminopropylated dimer diamine is available commercially as Kemamine DD 3680 and 3695 from Chemtura Corporation USA.
• Different structures of the dimeric hydrophobic amine additives are given below:
• the Plastic Viscosity (PV), Yield Point (YP), Yield Stress (Tau zero) and Low Shear Yield Point (LSYP) of the invert emulsion drilling fluid were determined on a direct- indicating rheometer, a FANN 35 rheometer, powered by an electric motor.
• the rheometer consists of two concentric cylinders, the inner cylinder is called a bob, while the outer cylinder is called a rotor sleeve.
• the drilling fluid sample is placed in a thermostatically controlled cup and the temperature of the fluid is adjusted to 120 (+ 2) °F.
• the drilling fluid in the thermostatically controlled cup is then placed in the annular space between the two concentric cylinders of the FANN 35.
• the outer cylinder or rotor sleeve is driven at a constant rotational velocity.
• the rotation of the rotor sleeve in the fluid produces a torque on the inner cylinder or bob.
• a torsion spring restrains the movement of the bob, and a dial attached to the bob indicates displacement of the bob.
• the dial readings are measured at different rotor sleeve speeds of 3, 6, 100, 200, 300 and 600 revolutions per minute (rpm).
• Yield Point is defined as the value obtained from the Bingham- Plastic rheological model when extrapolated to a shear rate of zero. It may be calculated using 300 rpm and 600 rpm shear rate readings as noted above on a standard oilfield rheometer, such as a FANN 35 or a FANN 75 rheometer.
• Yield Stress or Tau zero is the stress that must be applied to a material to make it begin to flow (or yield), and may commonly be calculated from rheometer readings measured at rates of 3, 6, 100, 200, 300 and 600 rpm. The extrapolation may be performed by applying a least-squares fit or curve fit to the Herchel-Bulkley rheological model.
• a more convenient means of estimating the Yield Stress is by calculating the Low-Shear Yield Point (LSYP) by the formula shown below in Equation 2 except with the 6 rpm and 3 rpm readings substituted for the 600-rpm and 300- rpm readings, respectively.
• Plastic Viscosity (PV) is obtained from the Bingham-Plastic rheological model and represents the viscosity of a fluid when extrapolated to infinite shear rate. The PV is obtained from the 600 rpm and the 300 rpm readings as given below in Equation 1.
• a low PV may indicate that a fluid is capable of being used in rapid drilling because, among other things, the fluid has low viscosity upon exiting the drill bit and has an increased flow rate.
• a high PV may be caused by a viscous base fluid, excess colloidal solids, or both.
• the PV and YP are calculated by the following set of equations:
• Samples of 9 ppg INNOVERT® invert emulsion drilling fluid containing 3 ppb C36 dimer diamine were evaluated further with a FANN 75 rheometer using simulated down hole conditions, and particularly testing high temperature and high pressure rheology.
• the FANN 75 rheometer measures similarly as the FANN 35 rheometer but can measure rheology under high temperature and pressure.
• the compositions of these samples are set forth in Table 2(a) below and the results of these tests are graphed in Figures 2(a), 2(b) and 2(c). Before testing, the samples were hot rolled at 325°F.
• Formulation sample 5 in Table 2(a) was a "control," the drilling fluid without a dimer diamine (hydrophobic amine) additive.
• the data for these figures is provided in Table 2(b) (control formulation sample 5) and Table 2(c) (invention formulation sample 6) below.
• Tables 2(b) and 2(c) show that the addition of the hydrophobic amine additive increased the YP and LSYP of the invert emulsion drilling fluid, but maintained similar or lower PV relative to the control (formulation 5), under High Pressure High Temperature (HPHT) conditions.
• HPHT High Pressure High Temperature
• Invert emulsion drilling fluids of the present invention were also prepared and laboratory tested with other commercially available mineral oil invert emulsion bases, particularly EDC 99-DW mineral oil base, available from Total in Paris, France, ESCAID®- 110 mineral oil base, available from ExxonMobil, in Houston, Texas, and XP-07 mineral oil base, available from Petrochem Carless in Wynnewood, Oklahoma and the United Kingdom. More particularly, these samples had the formulations set forth in Table 4 below. Each formulation had a mud weight of 9 ppg and an oil: water ratio of 60:40. After hot rolling at 250°F for 16 hours, the sample rheologies were evaluated with a FANN 35 rheomoter at 120°F. Test data are shown in Table 4 and these results are graphed in Figure 4, showing the invention to be effective with a variety of commercially available mineral oil invert emulsion drilling fluid bases.
• EDC 99-DW mineral oil base available from Total in Paris, France
• ESCAID®- 110 mineral oil base available
• INNOVERT® invert emulsion drilling fluid having an oil:water ratio of 70:30
• C36 dimer diamine Formulation 12
• Table 5 The formulation of the samples tested and the test results are set forth in Table 5 below.
• Figure 6 provides a graph showing the favorable characteristic "fragile gel"
• Figures 7a and 7b provide graphs showing "fragile gel” behavior of example clay-free drilling fluids of the invention having mud weights of 16 and 18 ppg, respectively. These graphs show that even at high mud weight and higher hot roll temperatures, a clay-free invert emulsion drilling fluid with the hydrophobic amine additive of the present invention demonstrates "fragile gel” behavior.
• Table 6 also shows another advantage of the invention— that HPHT fluid losses of high mud weight drilling fluids with a hydrophobic amine additive of the invention are lower than otherwise comparable drilling fluids without the hydrophobic amine additive. In addition, the HPHT filtrate of these fluids without the hydrophobic amine additive showed an undesirable presence of a solid mass.
• a drilling fluid of the invention may be employed in drilling operations.
• 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).
• the fluid is weighted as appropriate for the formation pressures and thinned as appropriate for the formation temperatures.
• the fluids of the invention afford real-time monitoring and rapid adjustment of the fluid to accommodate changes in such subterranean formation conditions.
• 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.

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• 2012
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