Reusable high performance water based drilling fluids

Information

  • Patent Grant
  • 10669468
  • Patent Number
    10,669,468
  • Date Filed
    Friday, October 3, 2014
    10 years ago
  • Date Issued
    Tuesday, June 2, 2020
    4 years ago
Abstract
Compositions emulate oil based fluids include an aqueous phase and an organic internal phase, which creates an osmotic membrane within the aqueous continuous phase. The osmotic membrane allows hydration-dehydration mechanisms to be in place and control interactions between formation and fluid, where the non-aqueous phase is composed of glycerols, polyglycerols, poly hydroxyl alcohols, monosaccharide derivatives, polysaccharide derivatives, or mixtures and combinations thereof, while the aqueous phase contains additives that impart different inhibiting mechanisms to the overall composition, where the additives include, without limitation, amphoteric polymers, potassium and/or sodium salts up to saturation and/or acrylamides.
Description
BACKGROUND OF THE INVENTION

1. Field of the Invention


Embodiments of this invention relates to reusable high performance water based drilling fluids.


In particular, embodiments of this invention relates to reusable high performance water based drilling fluids, where the fluids include a water based continuous aqueous phase and discontinuous non-aqueous phase, where the aqueous phase is a brine and the non-aqueous phase is composed of glycerols, polyglycerols, poly hydroxyl alcohols, poly hydroxyl alcohols, monosaccharide derivatives, polysaccharide derivatives, or mixtures and combinations thereof.


2. Description of the Related Art


Oil based drilling fluids have historically been the preferred choice for exploration and development of drilling projects. These fluids are often reused from well to well and guarantee among other things: reasonable costs, good inhibiting properties, and good lubricity properties. Against these advantages, there are several disadvantages including high environmental impact such as spillage risks, significant cuttings disposal costs and location remedial costs. These fluids also entail logistics issues in moving large volumes of organic base fluids and salts, increased costs on solids control equipments and an undesirable dependency on the type of organic base fluids chosen for a given project.


Many principles have been addressed to control shale hydration due to drilling fluids used in the oil industry. Some of these control technologies include the use of lime and gypsum calcic fluids, salts dissolved in the aqueous phase up to saturation, silicate fluids, shale encapsulating polymers, amines, amphoteric polymers, inverted emulsion fluids, pore pressure transmission blocking mechanisms, glycol based fluids and many intermediate combinations of the above. Most fluids are based on one principle and often fail to address geological conditions and environmental regulation.


Historically, water based fluids have been a one interval disposable volume. Thus, there is a need in the art for reusable high performance water based drilling fluids.


SUMMARY OF THE INVENTION

Embodiments of the present invention provide different inhibition mechanisms to cope with reactive formations such as a formation including swellable clays. The present compositions emulate oil based fluids by having an organic internal phase, which creates an osmotic membrane. The osmotic membrane allows hydration-dehydration mechanisms to be in place and control interactions between the formation and the fluid. The non-aqueous phase, on the inhibition side, comprises or is composed of glycerols, polyglycerols, poly hydroxyl alcohols, monosaccharide derivatives, polysaccharide derivatives, or mixtures and combinations thereof, while the aqueous phase contains ingredients to impart different inhibiting mechanisms to the overall composition, where the ingredients and/or mechanisms include, without limitation, amphoteric polymers, potassium and/or sodium salts of up to saturation and/or polyacrylamides. In certain embodiments, the compositions may also include silicates. The compositions of this invention allow the drilled cuttings to travel up the annular gap, avoiding dissolution. Also fluid dilution is minimized. Pore pressure transmission blocking mechanisms are present in the fluids enhancing well stability and widening the pressure window between hydrostatic pressure and fracture gradient. The fluids have low environmental impact, which will save on solids control equipment requirements and will minimize disposal and remedial costs.


Embodiments of the present invention also provide methods for making or preparing compositions of this invention.


Embodiments of the present invention also provide methods for drilling a borehole comprising circulating, e.g., in the borehole, a composition of the present invention.


Embodiments of the present invention also provider reusable high performance water based drilling fluids and other reusable high performance water based downhole fluids having low toxicity and reduced environmental impact. This reduces operating costs by improving material logistics and providing high drilling performance to operators.







DETAILED DESCRIPTION OF THE INVENTION

The inventors have found that a reusable high performance water based fluids may be formulated having a full range of densities. The reusable high performance water based fluids include a continuous aqueous phase and a discontinuous organic or non-aqueous phase forming an osmotic membrane. The aqueous phase comprises a brine having certain controlled properties and the non-aqueous phase comprises glycerols, polyglycerols, poly hydroxyl alcohols, monosaccharide derivatives, polysaccharide derivatives, or mixtures and combinations thereof. The term reusable, in the context of oil-based drilling muds or fluids, means that when a particular drilling job is finished or completed, the mud or drilling fluid may be stored in tanks until it is needed for drilling another well. The fluids of this invention remain complete, high performance water based drilling fluids that may be used over and over again for drilling. The drilling fluids of this invention, therefore, are capable of being used from job to job, with make-up fluid volume being added as needed and drilling fluid treatments made to the drilling fluids of this invention to maintain, modify, and/or alter desired fluid properties.


The inventors have found that by using a storage facility nearby the location in between jobs, the water based fluid may be rendered reusable. The present fluids will reduce liability for environmental integrated projects.


The inventors have also found that reusable high performance water based fluids may be formulated having density over a wide density range. In certain embodiments, the density of the fluids ranges between about 8.6 ppg and one 20 ppg and the fluids may be formulated for both low, moderate, and high temperature applications. In certain embodiments, the density of the fluids is between about 8.6 ppg and 18 ppg. In other embodiments, the density of the fluids is between about 8.6 ppg and 16 ppg. In other embodiments, the density of the fluids is between about 8.6 ppg and 14 ppg. In other embodiments, the density of the fluids is between about 8.6 ppg and 12 ppg. In other embodiments, the density of the fluids is between about 8.6 ppg and 10 ppg. The term “ppg” will be herein understood to mean “pounds per gallon”.


Multi-functional additives have been developed that improve drilling fluid lubricity as well as a penetration rate and improve inhibiting properties of reactive shale. The new additives have been used at various volume % (vol. %) concentrations, based on the total fluid composition, e.g., drilling fluid composition, in formulations having varying densities. In certain embodiments, the concentration is at least 5% by volume. In certain embodiments, the concentration is at least 10% by volume. In certain embodiments, the concentration is at least 16% by volume. In certain embodiments, the concentration is at least 18% by volume. In certain embodiments, the concentration is up to 20% by volume.


In certain embodiments, the compositions include from about 51 wt. % to about 95 wt. % of the aqueous phase and from about 5 wt. % to about 49 wt. % of the non-aqueous phase. In other embodiments, the compositions include from about 55 wt. % to about 95 wt. % of the aqueous phase and from about 5 wt. % to and about 45 wt. % of the non-aqueous phase. In other embodiments, the compositions include from about 60 wt. % to about 95 wt. % of the aqueous phase and from about 5 wt. % to and about 40 wt. % of the non-aqueous phase. In other embodiments, the compositions include from about 65 wt. % to about 95 wt. % of the aqueous phase and from about 5 wt. % to and about 35 wt. % of the non-aqueous phase. In other embodiments, the compositions include from about 75 wt. % to about 95 wt. % of the aqueous phase and from about 5 wt. % to about 25 wt. % of the non-aqueous phase.


Embodiments of this invention broadly relate to reusable fluid compositions including (a) an aqueous continuous phase including an additive composition to change certain properties of the aqueous continuous phase, where the additive composition comprises amphoteric polymers, salts up to saturation, polyacrylamides, and mixtures or combinations thereof, and (b) an organic internal phase including glycerols, polyglycerols, poly hydroxyl alcohols, monosaccharide derivatives, polysaccharide derivatives, or mixtures and combinations thereof, where the organic internal phase forms an osmotic membrane within the continuous aqueous phase and where the osmotic membrane allows hydration-dehydration mechanisms to be in place and control interactions between formation and fluid. In other embodiments, the additive composition includes hydratable polymers. In other embodiments, the additive composition includes a humalite product, high molecular weight xanthan gum and/or a complex mixture of natural polysaccharides, high-quality, low-viscosity, sodium salt of carboxymethyl celluloses, polyanionic cellulose, glycol-based anti-foaming agents, white calcium carbonate, barium sulfate mineral, and/or shale inhibitor. Humalite may be described as a natural derivative from sub-bituminous coal, containing substances such as humic acid, fulvic acid and/or humin. In other embodiments, the compositions have a density between about 8.6 ppg and about 20 ppg. In other embodiments, the compositions have a density between about 8.6 ppg and about 18 ppg. In other embodiments, the aqueous phase is present in an amount between about 51 wt. % and about 95 wt. % and the non-aqueous phase is present in an amount between about 5 wt. % and about 49 wt. %. In other embodiments, the aqueous phase is present in an amount between about 55 wt. % and about 95 wt. % and the non-aqueous phase is present in an amount between about 5 wt. % and about 45 wt. %. In other embodiments, the aqueous phase is present in an amount between about 65 wt. % and about 95 wt. % and the non-aqueous phase is present in an amount between about 5 wt. % and about 35 wt. %. In other embodiments, the aqueous phase comprises a brine. In other embodiments, the brine comprises a fresh water brine formed by adding the salts to fresh water.


Embodiments of this invention broadly relates to reusable drilling fluid compositions including (a) an aqueous continuous phase including an additive composition to change certain properties of the aqueous continuous phase, where the additive composition includes amphoteric polymers, salts up to saturation, polyacrylamides, or mixtures and combinations thereof, and (b) an organic internal phase including glycerols, polyglycerols, poly hydroxyl alcohols, monosaccharide derivatives, polysaccharide derivatives, or mixtures and combinations thereof, where the organic internal phase creates an osmotic membrane within the continuous aqueous phase and where the osmotic membrane allows hydration-dehydration mechanisms to be in place and control interactions between formation and fluid. In certain embodiments, the compositions have a density between about 8.6 ppg and about 20 ppg. In other embodiments, the compositions have a density between about 8.6 ppg and about 18 ppg. In other embodiments, the aqueous phase is present in an amount between about 51 wt. % and about 95 wt. % and the non-aqueous phase is present in an amount between about 5 wt. % and about 49 wt. %. In other embodiments, the aqueous phase is present in an amount between about 55 wt. % and about 95 wt. % and the non-aqueous phase is present in an amount between about 5 wt. % and about 45 wt. %. In other embodiments, the aqueous phase is present in an amount between about 65 wt. % and about 95 wt. % and the non-aqueous phase is present in an amount between about 5 wt. % and about 35 wt. %. In other embodiments, the aqueous phase comprises a brine. In other embodiments, the brine comprises a fresh water brine formed by adding the salts to fresh water.


Embodiments of this invention broadly relates to methods for drilling a borehole including the step of (a) while drilling, circulating a fluid composition of this invention. The fluid composition comprises (a) an aqueous continuous phase including an additive composition to change certain properties of the aqueous continuous phase, where the additive composition comprises amphoteric polymers, salts up to saturation, polyacrylamides or mixtures and combinations thereof, and (b) an organic internal phase including glycerols, polyglycerols, poly hydroxyl alcohols, monosaccharide derivatives, polysaccharide derivatives, or mixtures and combinations thereof, where the organic internal phase creates an osmotic membrane within the continuous aqueous phase, where the osmotic membrane allows hydration-dehydration mechanisms to be in place and control interactions between formation and fluid and where the drilling fluid composition is reusable and the fluid has improved lubricity and improved cutting lift properties. In certain embodiments, the compositions have a density between about 8.6 ppg and about 20 ppg. In other embodiments, the compositions have a density between about 8.6 ppg and about 18 ppg. In other embodiments, the aqueous phase is present in an amount between about 51 wt. % and about 95 wt. % and the non-aqueous phase is present in an amount between about 5 wt. % and about 49 wt. %. In other embodiments, the aqueous phase is present in an amount between about 55 wt. % and about 95 wt. % and the non-aqueous phase is present in an amount between about 5 wt. % and about 45 wt. %. In other embodiments, the aqueous phase is present in an amount between about 65 wt. % and about 95 wt. % and the non-aqueous phase is present in an amount between about 5 wt. % and about 35 wt. %. In other embodiments, the aqueous phase comprises a brine. In other embodiments, the brine comprises a fresh water brine formed by adding the salts to fresh water.


Suitable Reagents

Suitable non-aqueous phase compositions include, without limitation, polyglycerol blends. Exemplary examples include a specific commercial mixture of mono, di, and triglycerins or a polyglycerol blend such as Oxi-Cure products from Cargill, Incorporated including Oxi-Cure 500 bearing CAS#25618-55-7 with synonymous products including glycerol homopolymers, glycerol polymers, polyglycerols, and/or 1,2,3-propanetriol homopolymers. One polyglycerol blend used in the compositions of the present invention had the following specification:


















Structure
HO(CH2CH(OH)CH2O)nH



Structure
HO(CH2CH(CH2OH)O)nH



Mol. Formula
HO(C3H6O2)nH



Test
Specification



Appearance
Pale yellow sticky liquid



Water
≤1%



Viscosity
~41 Pa · s (dynamic)



Assay (glpc)













Triglycerol
from 35 wt. % to 55 wt. %




Diglycerol
from 15 wt. % to 30 wt. %




Tetraglycerol
from 10 wt. % to 25 wt. %




Pentaglycerol
less than or equal to (≤) 10 wt. %




Higher oligomers
less than or equal to (≤) 5 wt. %










RI, ηD20°C.
1.491 @ 25° C.



Heavy metals
less than (<) 10 ppm



As
less than (<) 3 ppm



Chloride
less than (<) 0.1%










Suitable aqueous phase compositions include, without limitation, sodium brines, potassium brines, calcium brines, other brines, or mixtures and combinations thereof. The brines are made by adding sodium, potassium, and/or calcium salts to water up to saturation. Exemplary examples of sodium, potassium, and/or calcium salts include NaCl, KCl, CaCl2, and/or equivalent sodium, potassium and/or calcium salts.


Suitable polyols, monosaccharides, and/or polysaccharides include, without limitation, six carbon sugars and their derivatives (e.g., allose, altrose, glucose, mannose, gulose, idose, galactose, talose, and cyclic hemiacetals or other derivatives), sorbitol, sorbitan, agar, agarose, alginic acid, alguronic acid, alpha glucan, amylopectin, amylose, arabinoxylan, beta-glucan, biocell collagen, callose, capsulan, carrageenan, cellodextrin, cellulin, cellulose, chitin, chitin nanofibril, chitosan, chrysolaminarin, curdlan, cyclodextrin, deae-sepharose, dextran, dextrin, exopolysaccharide, alpha-cyclodextrin, ficoll, fructan, fucoidan, galactoglucomannan, galactomannan, gellan gum, glucan, glucomannan, glucuronoxylan, glycocalyx, glycogen, hemicellulose, homopolysaccharide, hypromellose, icodextrin, inulin, kefiran, laminarin, lentinan, levan polysaccharide, lichenin, matrixdb, mixed-linkage glucan, mucilage, natural gum, oxidized cellulose, paramylon, pectic acid, pectin, pentastarch, pleuran, polydextrose, polysaccharide peptide, porphyran, pullulan, schizophyllan, selective relaxant binding agent, sepharose, sinistrin, sizofiran, sugammadex, unhydrolysable glucose polymers, welan gum, xanthan gum, xylan, xyloglucan, zymosan or mixtures or combinations thereof.


Suitable hydratable polymers that may be used in embodiments of the invention include any of the hydratable polysaccharides which are capable of forming a gel in the presence of a crosslinking agent. For instance, suitable hydratable polysaccharides include, but are not limited to, xanthan gums, galactomannan gums, glucomannan gums, guars, derived guars, and cellulose derivatives. Specific examples are guar gum, guar gum derivatives, locust bean gum, Karaya gum, carboxymethyl cellulose, carboxymethyl hydroxyethyl cellulose, and hydroxyethyl cellulose. Exemplary examples include, but are not limited to, guar gums, hydroxypropyl guar, carboxymethyl hydroxypropyl guar, carboxymethyl guar, and carboxymethyl hydroxyethyl cellulose. Suitable hydratable polymers may also include synthetic polymers, such as polyvinyl alcohol, polyacrylamides, poly-2-amino-2-methyl propane sulfonic acid, and various other synthetic polymers and copolymers. The hydratable polymer may be present in the fluid in concentrations ranging from about 0.10% to about 5.0% by weight of the aqueous fluid. A preferred range for the hydratable polymer is about 0.20% to about 0.80% by weight.


Suitable amphoteric polymers include, without limitation, branched and/or cross-linked associative amphoteric polymers. The usable branching agents (cross-linking agents) are N-methylol acrylamide, methylene bis acrylamide, allyl ethers of sucrose, diacrylates, divinyls and all other multifunction compounds which can cause branching. One could also use one of the known branching agents for diallylated compounds such as methyl triallyl ammonium chloride, triallylamine, tetraallyl ammonium chloride, tetra allyl oxyethane, tetra allyl ethylene diamine and, more generally, all polyallylated compounds. It is also possible to make post-cross-linked polymers, for example by amidation reaction, esterification reaction, gamma ray treatment, etc.


An example of an amphoteric polymer is described in U.S. Pat. No. 7,700,702 B2. An example of such amphoteric polymer may comprise at least one acrylamide-derived cationic monomer containing a hydrophobic chain and with the general formula:

R1,R2C═CR3CONR4QN+R5R6R7X

where: R1, R2, R3, R4, R5, and R6 are independently, a hydrogen or an alkyl chain containing 1 to 4, carbons, Q is an alkyl chain containing 1 to 8 carbons, R7 is an alkyl or arylalkyl chain containing 8 to 30 carbons, X is a halide selected from the group including bromide, chloride, iodide, fluoride or a counterion with a negative charge;


between 1 and 99.9 mole % of at least one anionic monomer, and


between 1 and 99 mole % at least one non-ionic hydrosoluble monomer.


The anionic monomers can be selected from a wide group. These monomers may present acrylic, vinyl, maleic, fumaric or allyl functionalities and may contain a carboxy, phosphonate, sulfonate or other group with an anionic charge, or the ammonium salt or alkaline-earth metal salt or alkaline metal salt corresponding to such a monomer. Examples of suitable monomers include acrylic acid, methacrylic acid, itaconic acid, crotonic acid, maleic acid, fumaric acid and strong-acid monomers, for example with a sulfonic or phosphonic acid-type function such as 2-acrylamido-2-methylpropane sulfonic acid, vinylsulfonic acid, vinylphosphonic acid, allylsulfonic acid, allylphosphonic acid, styrene sulfonic acid and their water-soluble salts of an alkali metal, alkaline-earth metal and ammonium.


The at least one non-ionic hydrosoluble monomer can be selected from the group including water-soluble vinyl monomers. In certain embodiments, the monomers belonging to this category are advantageously selected from the group including acrylamide and methacrylamide, N-isopropylacrylamide, N,N-dimethylacrylamide and N-methylolacrylamide. N-vinylformamide, N-vinyl acetamide, N-vinylpyridine and/or N-vinylpyrrolidone can also be used. Acrylamide may be the preferred non-ionic monomer.


Other amphoteric polymers include polymers having between 0.005 and 10 mole % hydrophobic cationic monomers, between 5 and 90 mole % of at least one anionic monomer, advantageously acrylic acid and/or methacrylic acid and/or 2-acrylamido-2-methylpropane sulfonic acid and their salts; and between 5 and 90 mole % of at least one hydrosoluble non-ionic monomer, advantageously acrylamide and/or methacrylamide and/or N-isopropylacrylamide and/or N,N-dimethylacrylamide and/or N-vinylformamide and/or N-vinyl acetamide and/or N-vinylpyrrolidone. Other polymers contain between 0.01 and 5 mole % of hydrophobic monomers and between 10 and 60 mole % of an anionic monomer and between 35 and 90 mole % of a non-ionic monomer. Other polymers contain between 0.02 and 2 mole % of hydrophobic monomers and between 10 and 50 mole % of an anionic monomer: acrylic acid, methacrylic acid and/or 2-acrylamido-2-methylpropane sulfonic acid and their salts, and between 48 and 90 mole % of a non-ionic monomer: acrylamide and/or methacrylamide and/or N-isopropylacrylamide and/or N,N-dimethylacrylamide and/or N-vinylformamide and/or N-vinyl acetamide and/or N-vinylpyrrolidone. Other polymers include acrylamide-derived hydrophobic cationic monomers preferred for the invention are N-acrylamidopropyl-N,N-dimethyl-N-dodecyl ammonium chloride (DMAPA Cl(C12)), N-methacrylamidopropyl-N,N-dimethyl-N-dodecyl ammonium chloride (DMAPMA Cl(C12)), N-acrylamidopropyl-N,N-dimethyl-N-dodecyl ammonium bromide (DMAPA Br(C12)), N-methacrylamidopropyl-N,N-dimethyl-N-dodecyl ammonium bromide (DMAPMA Br(C12)), N-acrylamidopropyl-N,N-dimethyl-N-octadecyl ammonium chloride (DMAPA Cl(C18)), N-methacrylamidopropyl-N,N-dimethyl-N-octadecyl ammonium chloride (DMAPMA Cl(C18)), N-acrylamidopropyl-N,N-dimethyl-N-octadecyl ammonium bromide (DMAPA Br(C18)), N-methacrylamidopropyl-N,N-dimethyl-N-octadecyl ammonium bromide (DMAPMA Br(C18)).


Suitable silicates that may be used in the fluids of this invention include, without limitation, hydrated or anhydrous silicate minerals with a layered structure and include, for example, alumino-silicate clays such as kaolins including hallyosite, smectites including montmorillonite, illite, and the like. Exemplary silicates include those marketed under the tradename CLOISITE® marketed by Southern Clay Additives, Inc. In an embodiment, silicates are exfoliated to separate individual sheets, or are non-exfoliated. Other silicates of similar structure can also be included such as, for example, talc, micas including muscovite, phlogopite, or phengite, or the like.


EXPERIMENTS OF THE INVENTION
Example 1

This example illustrates the preparation of reusable high performance water based drilling fluid having a density of 10 ppg.


18.0 wt. % of sorbitol powder was dissolved in 23.3 wt. % deionized water. The resulting aqueous solution was then mixed into 56.7 wt. % of a polyglycerol blend such as Oxi-Cure 500 and mixing was continued until fluid was completely blended. To this fluid, 2.0 wt. % of a 50 wt. % KOH solution (1.0% equivalent KOH) was added. The KOH was added to the 13.1 wt. % NaCl brine, then pre-solubilize the 10 ppb HUMALITE in the aqueous mixture. The resulting polyglycerol blend was used successfully at a 14% concentration level in 10 ppg and 12 ppg formulations of a 13.1% by weight NaCl water-base system. The initial pH was 12.34 at 72.2° F. The pH after 30 days was 11.22 at 71.0° F. The pH after 71 days was 9.84 at 71.0° F.


The neat composition of Example 1 was a viscous liquid and had a brownish amber color, a specific gravity between 1.23 and 1.28, a density in pounds per gallon (ppg) between 10.26 ppg and 10.68 ppg, a flash point >392° F. (>200° C.), a pH between 9.5 and 10.5, mild odor, and freeze point <−36.4° F. (<−38° C.).









TABLE 1







Composition of the Example 1










FORMULATION
SP. GR.
GRAMS
WT. %











Aqueous Component
86.0












13.1 wt. % NaCl brine,
1.09
297.52




ppb






KOH, ppb
2.06
1.50




WRD-6003, ppb
1.30
10.00




Wel-Zan D, ppb
1.55
0.60




Wel-Pac LV, ppb
1.60
4.00




Wel-Defoam G, ppb

2 drops




ExCAL CW 325 ppb
2.70
20.00




Barite, ppb
4.20
10.70




KCl, ppb
1.98
14.00




Wel-Hib NPH, ppb
1.07
8.00









Non-Aqueous Component
14.0












Polyglycerol blend*
1.26
53.81



Total Weight (g)


419.53



Total Volume (cc)


350.00



WBM Weight (ppg)


10.00



SG


1.199





WRD-6003 is a humalite product available from Canadian Humalite International Inc.


Wel-Zan ™ D - high molecular weight xanthan gum, a complex mixture of natureal polysaccharides available from Weatherford.


Wel-Pac ™ LV - high-quality, low-viscosity, sodium salt of carboxymethyl cellulose-commonly referred to as polyanionic cellulose available from Weatherford.


Wel-Defoam ™ G - a glycol-based anti-foaming agent formulated for use in polymer systems available from Weatherford.


ExCal - white calcium carbonate 325 mesh available SpecialChem


Barite - barium sulfate mineral


Wel-Hib NPH a shale inhibitor available from Weatherford.


Polyglycerol blend* was Oxi-cure 500 from Cargill, Inc.













TABLE 2







Example 1 Selected Properties









Property
OFI#
Cell #






Rheology at 120° F.




Before Hot Rolling
After Hot Rolling at 250° F.


600 rmp
98
92


300 rmp
61
59


200 rmp
47
45


100 rmp
29
28


 6 rmp
4
5


 3 rmp
3
4


10″ Second Gel
2
4


10′ Minute Gel
3
5


PV, cp
37
33


YP, lb/100 ft2
24
26


API Fluid Loss, mL

2.5


HTHP Fluid Loss at

13.6


250° F., mL




pH
10.8 @ 68.5° F.
9.25 @ 70.8° F.


Mud Weight, ppg
10.09
10.01


Specific Gravity
1.21
1.20









Example 1 had a pH:13.17 @ 68.8° F., a specific gravity of 1.24, and a brownish amber color. The freezing point of the composition was supposed to be −38° F. When the sample was left in the chiller for 24 hours at −38° F., the sample was very thick with very slow flow fluid, but was not frozen. When the sample was left for 48 hours at −38° F., the sample was still was very thick with very slow flow, but still not frozen. After sitting at room temperature for about 7 minutes to 8 minutes after being left in the chiller for 48 hours, the sample was back to flowing the same as the 0° F. After the sample was in the chiller for 24 hours at 0° F., the sample was normal. After the sample was in the chiller for 24 hours at −20° F., the sample was very thick and very slow flow.


Example 2

This example illustrates reusable high performance water based fluid having a density of 12.80 ppg. This fluid was prepared in accord with the preparation method of Example 1.









TABLE 4







Composition of the Example 2










FORMULATION
SP. GR.
GRAMS
WT. %











Aqueous Component
86.0












13.1 wt. % NaCl brine,
1.09
272.40




ppb






KOH, ppb
2.06
1.00




WRD-6003, ppb
1.30
10.00




Wel-Zan D, ppb
1.55
0.75




Wel-Pac LV, ppb
1.60
3.25




Wel-Defoam G

2 drops




ExCAL CW 325 ppb
2.70
20.00




Barite, ppb
4.20
125.50




KCl, ppb
1.98
14.00




Wel-Hib NPH, ppb
1.07
8.00









Non-Aqueous Component
14.0












Polyglycerol blend*
1.26
48.48



Weight (g)


503.38



Volume (cc)


350.00



Mud Weight (ppg)


12.00



Specific Gravity


1.438





WRD-6003 is a humalite product available from Canadian Humalite International Inc.


Wel-Zan ™ D - high molecular weight xanthan gum, a complex mixture of natureal polysaccharides available from Weatherford.


Wel-Pac ™ LV - high-quality, low-viscosity, sodium salt of carboxymethyl cellulose-commonly referred to as polyanionic cellulose available from Weatherford.


Wel-Defoam ™ G - a glycol-based anti-foaming agent formulated for use in polymer systems available from Weatherford.


ExCal - white calcium carbonate 325 mesh available SpecialChem


Barite - barium sulfate mineral


Wel-Hib NPH a shale inhibitor available from Weatherford.


Polyglycerol blend* was Oxi-cure 500 from Cargill, Inc.













TABLE 5







Example 2 Selected Properties









Properties
OFI#
Cell #






Rheology at 120° F.




Before Hot Rolling
After Hot Rolling at 250° F.


600 rmp
146  
141


300 rmp
98  
94


200 rmp
81  
74


100 rmp
51  
48


 6 rmp
7 
10


 3 rmp
6 
7


10″ second Gel
6 
8


10′ minute Gel
7 
10


PV, cp
48  
47


YP, lb/100 ft2
50  
47


API Fluid Loss, mL
#3  
1.9


HTHP Fluid Loss at

15.2


250° F., mL




pH
10.03 @ 74° F.
8.45 @ 72° F.


Mud Weight (ppg)
 12.18
12.01


Specific Gravity
 1.46
1.44









All references cited herein are incorporated by reference. Although the invention has been disclosed with reference to its preferred embodiments, from reading this description those of skill in the art may appreciate changes and modification that may be made which do not depart from the scope and spirit of the invention as described above and claimed hereafter.

Claims
  • 1. A reusable fluid composition comprising: an aqueous continuous phase comprising an additive composition to change certain properties of the aqueous continuous phase, the additive composition comprising an amphoteric polymer, a polyacrylamide, or a combination thereof; andan organic internal phase comprising a glycerol, a polyglycerol, a poly hydroxyl alcohol, a monosaccharide derivative, a polysaccharide derivative, or a combination thereof, wherein the organic internal phase creates an osmotic membrane within the aqueous continuous phase, and wherein the osmotic membrane allows hydration-dehydration mechanisms to be in place and control interactions between formation and fluid.
  • 2. The fluid composition of claim 1, wherein the fluid composition has a density between about 8.6 ppg and about 20 ppg, the aqueous continuous phase is present in an amount between about 51 wt.% and about 95 wt.%, and the organic internal phase is present in an amount between about 5 wt.% and about 49 wt.%.
  • 3. The fluid composition of claim 2, wherein the fluid composition has a density between about 8.6 ppg and about 16 ppg, the aqueous continuous phase is present in an amount between about 55 wt.% and about 95 wt.%, and the organic internal phase is present in an amount between about 5 wt.% and about 45 wt.%.
  • 4. The fluid composition of claim 3, wherein the fluid composition has a density between about 8.6 ppg and about 14 ppg, the aqueous continuous phase is present in an amount between about 65 wt.% and about 95 wt.%, and the organic internal phase is present in an amount between about 5 wt.% and about 35 wt.%.
  • 5. The fluid composition of claim 1, wherein the aqueous continuous phase further comprises a brine, the brine comprises a salt, and the salt comprises a sodium salt, a potassium salt, a calcium salt, or a combination thereof.
  • 6. The fluid composition of claim 5, wherein the brine comprises a fresh water brine and wherein the salt comprises NaCl, KCl, CaCl2, and/or equivalent sodium, potassium and/or calcium salts.
  • 7. A reusable drilling fluid composition comprising: an aqueous continuous phase comprising an additive composition to change certain properties of the aqueous continuous phase, the additive composition comprising a salt up to saturation and at least one of an amphoteric polymer or a polyacrylamide; andan organic internal phase, which creates an osmotic membrane within the aqueous continuous phase, wherein the osmotic membrane allows hydration-dehydration mechanisms to be in place and control interactions between formation and fluid, and wherein the organic internal phase comprises a glycerol, a polyglycerol, a poly hydroxyl alcohol, a monosaccharide derivative, a polysaccharide derivative, or a combination thereof.
  • 8. The fluid composition of claim 7, wherein the fluid composition has a density between about 8.6 ppg and about 20 ppg, the aqueous continuous phase is present in an amount between about 51 wt.% and about 95 wt.%, and the organic internal phase is present in an amount between about 5 wt.% and about 49 wt.%.
  • 9. The fluid composition of claim 8, wherein the fluid composition has a density between about 8.6 ppg and about 16 ppg, the aqueous continuous phase is present in an amount between about 55 wt.% and about 95 wt.%, and the organic internal phase is present in an amount between about 5 wt.% and about 45 wt.%.
  • 10. The fluid composition of claim 9, wherein the fluid composition has a density between about 8.6 ppg and about 14 ppg, the aqueous continuous phase is present in an amount between about 65 wt.% and about 95 wt.%, and the organic internal phase is present in an amount between about 5 wt.% and about 35 wt.%.
  • 11. The fluid composition of claim 7, wherein the aqueous continuous phase further comprises a brine, the brine comprises a salt, and the salt comprises a sodium salt, a potassium salt, a calcium salt, or a combination thereof.
  • 12. The fluid composition of claim 11, wherein the brine comprises a fresh water brine and wherein the salt comprises NaCl, KCl, CaCl2, and/or equivalent sodium, potassium and/or calcium salts.
  • 13. A reusable fluid composition comprising: an aqueous continuous phase comprising an additive composition to change certain properties of the aqueous continuous phase, the additive composition comprising a salt up to saturation, a hydratable polymer, and an amphoteric polymer; andan organic internal phase comprising a glycerol, a polyglycerol, a poly hydroxyl alcohol, a monosaccharide derivative, a polysaccharide derivative, or a combination thereof, wherein the organic internal phase creates an osmotic membrane within the aqueous continuous phase, and wherein the osmotic membrane allows hydration-dehydration mechanisms to be in place and control interactions between formation and fluid.
  • 14. The fluid composition of claim 13, wherein the salt is a potassium salt, a sodium salt, or a combination thereof.
  • 15. The fluid composition of claim 13, wherein the fluid composition has a density between about 8.6 ppg and about 20 ppg, the aqueous continuous phase is present in an amount between about 51 wt.% and about 95 wt.%, and the organic internal phase is present in an amount between about 5 wt.% and about 49 wt.%.
  • 16. The fluid composition of claim 13, wherein the fluid composition has a density between about 8.6 ppg and about 16 ppg, the aqueous continuous phase is present in an amount between about 55 wt.% and about 95 wt.%, and the organic internal phase is present in an amount between about 5 wt.% and about 45 wt.%.
  • 17. The fluid composition of claim 13, wherein the fluid composition has a density between about 8.6 ppg and about 14 ppg, the aqueous continuous phase is present in an amount between about 65 wt.% and about 95 wt.%, and the organic internal phase is present in an amount between about 5 wt.% and about 35 wt.%.
Parent Case Info

This application claims the benefit of and provisional priority to U.S. Application Ser. No. 61/888,325 filed Oct. 8, 2013.

US Referenced Citations (253)
Number Name Date Kind
2196042 Timpson Apr 1940 A
2390153 Kern Dec 1945 A
2805958 Bueche et al. Jul 1959 A
3059909 Wise Oct 1962 A
3163219 Wyant et al. Dec 1964 A
3301723 Chrisp Jan 1967 A
3301848 Halleck Jan 1967 A
3303896 Tillotson et al. Feb 1967 A
3317430 Priestley et al. May 1967 A
3565176 Wittenwyler Feb 1971 A
3856921 Shrier et al. Dec 1974 A
3888312 Tiner et al. Jun 1975 A
3933205 Kiel Jan 1976 A
3937283 Blauer et al. Feb 1976 A
3960736 Free et al. Jun 1976 A
3965982 Medlin Jun 1976 A
3990978 Hill Nov 1976 A
4007792 Meister Feb 1977 A
4052159 Fuerst et al. Oct 1977 A
4067389 Savins Jan 1978 A
4108782 Thompon Aug 1978 A
4112050 Sartori et al. Sep 1978 A
4112051 Sartori et al. Sep 1978 A
4112052 Sartori et al. Sep 1978 A
4113631 Thompson Sep 1978 A
4378845 Medlin et al. Apr 1983 A
4385935 Skyeldal May 1983 A
4461716 Barbarin et al. Jul 1984 A
4479041 Fenwick et al. Oct 1984 A
4506734 Nolte Mar 1985 A
4514309 Wadhwa Apr 1985 A
4541935 Constien et al. Sep 1985 A
4549608 Stowe et al. Oct 1985 A
4561985 Glass, Jr. Dec 1985 A
4623021 Stowe Nov 1986 A
4654266 Kachnik Mar 1987 A
4657081 Hodge Apr 1987 A
4660643 Perkins Apr 1987 A
4683068 Kucera Jul 1987 A
4686052 Baranet et al. Aug 1987 A
4695389 Kubala Sep 1987 A
4705113 Perkins Nov 1987 A
4714115 Uhri Dec 1987 A
4718490 Uhri Jan 1988 A
4724905 Uhri Feb 1988 A
4725372 Teot et al. Feb 1988 A
4739834 Peiffer et al. Apr 1988 A
4741401 Walles et al. May 1988 A
4748011 Baize May 1988 A
4779680 Sydansk Oct 1988 A
4780220 Peterson Oct 1988 A
4795574 Syrinek et al. Jan 1989 A
4817717 Jennings, Jr. et al. Apr 1989 A
4830106 Uhri May 1989 A
4846277 Khalil et al. Jul 1989 A
4848468 Hazlett et al. Jul 1989 A
4852650 Jennings, Jr. et al. Aug 1989 A
4869322 Vogt, Jr. et al. Sep 1989 A
4892147 Jennings, Jr. et al. Jan 1990 A
4926940 Stromswold May 1990 A
4938286 Jennings, Jr. Jul 1990 A
4978512 Dillon Dec 1990 A
5005645 Jennings, Jr. et al. Apr 1991 A
5024276 Borchardt Jun 1991 A
5067556 Fudono et al. Nov 1991 A
5074359 Schmidt Dec 1991 A
5074991 Weers Dec 1991 A
5076373 Hale et al. Dec 1991 A
5082579 Dawson Jan 1992 A
5106518 Cooney et al. Apr 1992 A
5110486 Manalastas et al. May 1992 A
5169411 Weers Dec 1992 A
5224546 Smith et al. Jul 1993 A
5228510 Jennings, Jr. et al. Jul 1993 A
5246073 Sandiford et al. Sep 1993 A
5259455 Nimerick et al. Nov 1993 A
5330005 Card et al. Jul 1994 A
5342530 Aften et al. Aug 1994 A
5347004 Rivers et al. Sep 1994 A
5363919 Jennings, Jr. Nov 1994 A
5465792 Dawson et al. Jan 1995 A
5402846 Jennings, Jr. et al. Apr 1995 A
5411091 Jennings, Jr. May 1995 A
5424284 Patel et al. Jun 1995 A
5439055 Card et al. Aug 1995 A
5462721 Pounds et al. Oct 1995 A
5472049 Chaffe et al. Dec 1995 A
5482116 El-Rabaa et al. Jan 1996 A
5488083 Kinsey, III et al. Jan 1996 A
5497831 Hainey et al. Mar 1996 A
5501275 Card et al. Mar 1996 A
5539044 Dindi et al. Jul 1996 A
5551516 Norman et al. Sep 1996 A
5624886 Dawson et al. Apr 1997 A
5635458 Lee et al. Jun 1997 A
5649596 Jones et al. Jul 1997 A
5669447 Walker et al. Sep 1997 A
5674377 Sullivan, III et al. Oct 1997 A
5686396 Hale et al. Nov 1997 A
5688478 Pounds et al. Nov 1997 A
5693837 Smith et al. Dec 1997 A
5711396 Joerg et al. Jan 1998 A
5722490 Ebinger Mar 1998 A
5744024 Sullivan, III et al. Apr 1998 A
5755286 Ebinger May 1998 A
5775425 Weaver et al. Jul 1998 A
5787986 Weaver et al. Aug 1998 A
5806597 Tjon-Joe-Pin et al. Sep 1998 A
5807812 Smith et al. Sep 1998 A
5833000 Weaver et al. Nov 1998 A
5853048 Weaver et al. Dec 1998 A
5871049 Weaver et al. Feb 1999 A
5877127 Card et al. Mar 1999 A
5908073 Nguyen et al. Jun 1999 A
5908814 Patel et al. Jun 1999 A
5964295 Brown et al. Oct 1999 A
5979557 Card et al. Nov 1999 A
5980845 Cherry Nov 1999 A
6001887 Keup et al. Dec 1999 A
6016871 Burts, Jr. Jan 2000 A
6035936 Whalen Mar 2000 A
6047772 Weaver et al. Apr 2000 A
6054417 Graham et al. Apr 2000 A
6059034 Rickards et al. May 2000 A
6060436 Synder et al. May 2000 A
6063972 Duncum et al. May 2000 A
6069118 Hinkel et al. May 2000 A
6123394 Jeffrey Sep 2000 A
6133205 Jones Oct 2000 A
6147034 Jones et al. Nov 2000 A
6162449 Maier et al. Dec 2000 A
6162766 Muir et al. Dec 2000 A
6169058 Le et al. Jan 2001 B1
6228812 Dawson et al. May 2001 B1
6247543 Patel et al. Jun 2001 B1
6267938 Warrender et al. Jul 2001 B1
6283212 Hinkel et al. Sep 2001 B1
6291405 Lee et al. Sep 2001 B1
6330916 Rickards et al. Dec 2001 B1
6725931 Nguyen et al. Apr 2004 B2
6756345 Pakulski et al. Jun 2004 B2
6793018 Dawson et al. Sep 2004 B2
6832650 Nguyen et al. Dec 2004 B2
6875728 Gupta et al. Apr 2005 B2
7055628 Grainger et al. Jun 2006 B2
7186353 Novak Mar 2007 B2
7268100 Kippie et al. Sep 2007 B2
7350579 Gatlin et al. Apr 2008 B2
7392847 Gatlin et al. Jul 2008 B2
7517447 Gatlin Apr 2009 B2
7565933 Kippie et al. Jul 2009 B2
7566686 Kippie et al. Jul 2009 B2
7700702 Gaillard et al. Apr 2010 B2
7712535 Venditto et al. May 2010 B2
7767628 Kippie et al. Aug 2010 B2
7829510 Gatlin et al. Nov 2010 B2
7886824 Kakadjian et al. Feb 2011 B2
7915203 Falana et al. Mar 2011 B2
7932214 Zamora et al. Apr 2011 B2
7942201 Ekstrand et al. May 2011 B2
7956017 Galtin et al. Jun 2011 B2
7956217 Falana et al. Jun 2011 B2
7971659 Gatlin et al. Jul 2011 B2
7989404 Kakadjian et al. Aug 2011 B2
7992653 Zamora et al. Aug 2011 B2
8011431 van Petegem et al. Sep 2011 B2
8028755 Darnell et al. Oct 2011 B2
8034750 Thompson et al. Oct 2011 B2
8084401 Lukocs et al. Dec 2011 B2
8093431 Falana et al. Jan 2012 B2
8097567 Wilson, Jr. Jan 2012 B2
8141661 Kakadjian et al. Mar 2012 B2
8158562 Wilson, Jr. et al. Apr 2012 B2
8172952 Wanner et al. May 2012 B2
8220546 Kakadjian et al. Jul 2012 B2
8258339 Falana et al. Sep 2012 B2
8273693 Schwartz Sep 2012 B2
8287640 Zamora et al. Oct 2012 B2
8362298 Falana et al. Jan 2013 B2
8466094 Kakadjian et al. Jun 2013 B2
8475585 Zamora et al. Jul 2013 B2
8507412 Lukocs et al. Aug 2013 B2
8507413 Wilson, Jr. Aug 2013 B2
8524639 Falana et al. Sep 2013 B2
8530394 Gatlin et al. Oct 2013 B2
8563481 Gatlin et al. Oct 2013 B2
8714283 Gatlin et al. May 2014 B2
8728989 Kakadjian et al. May 2014 B2
8772203 Schwartz Jul 2014 B2
8794325 Willberg Aug 2014 B2
8835364 Thompson et al. Sep 2014 B2
8841240 Kakadjian et al. Sep 2014 B2
8846585 Falana et al. Sep 2014 B2
8851174 Zamora et al. Oct 2014 B2
8871694 Zamora et al. Oct 2014 B2
8899328 Zamora et al. Dec 2014 B2
8932996 Falana et al. Jan 2015 B2
8944164 Veldman et al. Feb 2015 B2
8946130 Zamora et al. Feb 2015 B2
8950493 van Petegem et al. Feb 2015 B2
20020049256 Bergeron, Jr. Apr 2002 A1
20020165308 Kinniard et al. Nov 2002 A1
20030176293 Schilling Sep 2003 A1
20030220204 Baran, Jr. et al. Nov 2003 A1
20050045330 Nguyen et al. Mar 2005 A1
20050092489 Welton et al. May 2005 A1
20050137114 Gatlin et al. Jun 2005 A1
20100252262 Ekstrand et al. Oct 2010 A1
20100305010 Falana et al. Dec 2010 A1
20100311620 Kakadjian et al. Dec 2010 A1
20110001083 Falana et al. Jan 2011 A1
20110011645 Muller Jan 2011 A1
20110177982 Ekstrand et al. Jul 2011 A1
20110240131 Parker Oct 2011 A1
20120061086 Willberg Mar 2012 A1
20120071367 Falana et al. Mar 2012 A1
20120073813 Zamora et al. Mar 2012 A1
20120097893 Wanner et al. Apr 2012 A1
20120273206 Zamora et al. Nov 2012 A1
20120279727 Kakadjian et al. Nov 2012 A1
20120295820 Falana et al. Nov 2012 A1
20120302468 Falana et al. Nov 2012 A1
20120325329 Schwartz Dec 2012 A1
20130081820 Falana et al. Apr 2013 A1
20130096038 Kim et al. Apr 2013 A1
20130130947 Brannon May 2013 A1
20130175477 Falana et al. Jul 2013 A1
20130270012 Kakadjian et al. Oct 2013 A1
20130274151 Kakadjian et al. Oct 2013 A1
20130312977 Lembcke et al. Nov 2013 A1
20130331301 Falana et al. Dec 2013 A1
20140087977 Kim et al. Mar 2014 A1
20140128294 Gatlin et al. May 2014 A1
20140128308 Levey et al. May 2014 A1
20140166285 Santra et al. Jun 2014 A1
20140262287 Treybig et al. Sep 2014 A1
20140262319 Treybig et al. Sep 2014 A1
20140303048 Kakadjian et al. Oct 2014 A1
20140315763 Kakadjian et al. Oct 2014 A1
20140318793 van Petergem et al. Oct 2014 A1
20140318795 Thompson, Sr. et al. Oct 2014 A1
20140323360 Comarin et al. Oct 2014 A1
20140323361 Livanec Oct 2014 A1
20140323362 Falana et al. Oct 2014 A1
20150007989 Tan et al. Jan 2015 A1
20150011440 Zamora et al. Jan 2015 A1
20150051311 Zamora et al. Feb 2015 A1
20150068747 Hwang et al. Mar 2015 A1
20150072901 Samuel et al. Mar 2015 A1
20150087561 Falana et al. Mar 2015 A1
20150087562 Falana et al. Mar 2015 A1
20150203742 Reddy Jul 2015 A1
20160145487 Alam May 2016 A1
Foreign Referenced Citations (12)
Number Date Country
2125513 Jan 1995 CA
4027300 May 1992 DE
775376 Oct 1954 GB
1073338 Jun 1967 GB
2216574 Oct 1989 GB
10001461 Jun 1988 JP
08151422 Nov 1996 JP
10110115 Apr 1998 JP
2005194148 Jul 2005 JP
WO 9856497 Dec 1998 WO
WO2000043465 Jul 2000 WO
WO 2009141308 Nov 2009 WO
Non-Patent Literature Citations (1)
Entry
PCT ISR WO, Application for PCT/IB2014/065110,dated Feb. 13, 2015.
Related Publications (1)
Number Date Country
20150096808 A1 Apr 2015 US
Provisional Applications (1)
Number Date Country
61888325 Oct 2013 US