CA2587997A1

CA2587997A1 - Drilling fluid additive and method

Info

Publication number: CA2587997A1
Application number: CA002587997A
Authority: CA
Inventors: Leonard Michael Haberman
Original assignee: Individual
Current assignee: Shell Canada Ltd
Priority date: 2004-12-02
Filing date: 2005-11-30
Publication date: 2006-06-08
Also published as: GB2435177A; AU2005312035A1; BRPI0516640A; US20060137878A1; CN101068904A; GB0710206D0; WO2006060388A3; WO2006060388A2

Abstract

A method is provided for drilling a wellbore including the steps of: providing a drilling mud comprising a primary amine; circulating the drilling mud while the wellbore is being drilled wherein the primary amine is incorporated into a filter cake deposited on the wellbore wall as the wellbore is being drilled;
and removing at least a portion of the filter cake after the wellbore is drilled by circulating fluid into the wellbore a composition comprising nitrous acid. The invention also includes the drilling fluid containing a solid component that generates gas from within the filter cake upon contact with a component that causes the solid component to generate gas. In some embodiments, the solid component is a primary amine grafted to a polymer that is not soluble in the drilling fluid composition such as a starch.

Description

DRILLING FLUID ADDITIVE AND METHOD

Field of Invention The present invention relates to a drilling fluid composition and a method to provide a wellbore.
Background As wellbores are drilled, drilling fluids are typically circulated through a drill pipe, through the drill bit, and up an annulus around the drill pipe in order to circulate drilling cuttings out of the wellbore and to cool the drill bit. This drilling fluid contains components that result in the density of the drilling fluid being a density that provides a bottom hole pressure that is about equal to or greater than the pore pressure of fluids in the formation through which the wellbore is being drilled, and also provide a pressure that is not greater than a pressure that causes the formation through which the wellbore is being drilled to fracture. Drilling fluids also typically contain additives that serve other functions. For example, drilling fluids often contain solids that will form a filter cake along the wall of the wellbore in order to reduce fluid losses from the wellbore into the formation. This filter cake desirably has a relatively low permeability in order to reduce the loss of fluids from the wellbore. Particularly for the portion of a wellbore that is being provided in an interval from which hydrocarbons are to be produced, this very low permeability filter cake is undesirable when it is time to produce hydrocarbons from the formation. Prior to production of hydrocarbons, the filter cakes are therefore preferably removed by, for example, circulation of an acid composition that will break down the solids within the filter cake. Complete removal of the filter cakes is desirable, but not readily achievable with current methods for removal of the filter cakes.
Primary amines are suggested by Patel et al. in US patent no. 6,484,821, to be useful in drilling fluids for the purpose of inhibiting swelling of clays.
Formations containing a significant amount of clay would normally not be hydrocarbon production zones because of the impermeability and lack of porosity of the clay formations.
A filtration control additive is suggested by Clapper et al. in US patent no 4,735,732. This filtration control additive is for use in inverted emulsion drilling fluids, and methods of using the fluids. The additive includes a pyrolyzed product obtained by intermixing and heating finely divided humic acid-containing material and a primary amine having an alkyl radical of 10 to 20 carbon atoms or a primary amine having one alkyl-substituted phenyl radical, the alkyl radical having 10 to 20 carbon atoms.
Murphey et al., in US patent 6,143,698, suggests a method for removing filtercake from a subterranean borehole that includes drilling the borehole with a drilling fluid that includes additives to form a filtercake having an oxidation-degradable component. The oxidation-degradable component is preferably a polysaccharide. When it is desired to remove the filtercake, the filtercake is contacted with a clear brine containing bromine or bromate generating agents to degrade the polymers within the filtercake. The brine contains bromide salts and an oxidant capable of delayed oxidation of the bromide to bromine at downhole conditions. In one embodiment, a drilling fluid is used that includes an amine-substituted starch and an amine-substituted xanthan thickening agent.
The amine is preferably a diethylaminoisopropanol. Alternatively, a polymer containing tertiary and quaternary functional groups such as a copolymer of polyethylenimine and ethylene oxide is suggested. The method relies on oxidation of the filter cake and not generation of gas to physically lift the filter cake from the wall of the wellbore.
Card et al., in US patent 5,979,557, suggests a method for limiting the inflow of formation water during a well turn around to maximize polymer recovery after a hydraulic fracturing treatment of a formation. The method includes a step for selectively blocking the pore structure in a water-bearing zone and not blocking the pore structure of a hydrocarbon zone at the formation face; performing a hydraulic fracturing treatment using a fluid having a polymer; and turning the well around to recover the polymer. There is also provided a method of acidizing, preferably matrix acidizing, a formation having a hydrocarbon zone and a water-bearing zone. The method includes a step for selectively blocking the pore structure in the water-bearing zone at the formation face to selectively retard migration of acid into the water-bearing zone; and injecting acid into the formation, wherein the acid is diverted from the water-bearing zone to the hydrocarbon zone as a result of the selective blocking step. When the water-bearing zone contains a residual amount of hydrocarbon residues, the method further includes injecting a mutual solvent prior to the step for selectively blocking. In these methods, the step for selectively blocking preferably forms a plug of a viscous fluid in the pore structure of the water-bearing zone at the formation face.
The viscous fluid preferably has at least a viscoelastic surfactant capable of forming a

2 worm-like micelle in an aqueous environment, a water-soluble salt to effect formation stability, and an aqueous carrier fluid.
Summarv of the Invention The present inventions include a method for drilling a wellbore comprising the steps of providing a drilling mud comprising a primary amine, circulating the drilling mud while the wellbore is being drilled wherein the primary amine is incorporated into a filter cake deposited on the wellbore wall as the wellbore is being drilled, and removing at least a portion of the filter cake after the wellbore is drilled by circulating fluid into the wellbore comprising nitrous acid.
The present inventions include a drilling fluid comprising between about 0.5 and about 3 percent by weight of nitrogen in the form of a primary amine.
The present inventions include a method of providing a wellbore in a hydrocarbon production zone comprising the steps of incorporating into a drilling fluid a solid component that forms a gas when exposed to an activating component, circulating the drilling fluid while drilling the wellbore in the hydrocarbon production zone whereby the solid component, and circulating a drilling fluid comprising the activating component after at least a portion of the wellbore within the production zone is drilled, and there by forming gas bubbles within the filter cake and causing the filter cake to at least partially release from a wall of the wellbore.
Detailed Description The drilling fluid of the present invention includes a component that generates a gas when an activating component is contacted with the solid component. Upon circulation through a well during a drilling process, the component incorporates itself in a filtercake against and slightly into the wall of the wellbore. A slight overpressure within the wellbore forces some drilling fluid into the fonnation through which the wellbore is being drilled, and solids within the drilling fluid are thereby deposited on the surface of the wellbore and within pore spaces near the wellbore within the formation. As drilling fluid passes into the formation, more solids will deposit on the surface of the wellbore, and a filter cake will eventually form. The filter cake then reduces loss of drilling fluids by creating a relatively impermeable skin on the surface and near the surface of the wall of the wellbore.
Particularly when the formation through which the wellbore is being drilled is a production

3 interval, it is desirable for this skin to be removed after it has served its purpose of reducing loses of drilling fluid while drilling.
In order to remove the filter cake, the drilling fluid of the present invention incorporates a component that generates a gas upon contact with an activating component.
In one embodiment, the component that forms a gas is a primary amine-containing component, and the activating component includes nitrous acid. The primary amine may be in the form of a solid so that it will be embedded within the filter cake.
A primary amine can, for example, be incorporated into a solid by grafting onto a starch or a xanthan gum, or another natural or synthetic polymer that is not soluble in the drilling fluid composition. The primary amine could be a polymer such as a polyvinylformamide that has been hydrolyzed to the amine form. Such a polyvinylformamide is available from BASF Corporation under the trade name Lupamin. Either a low molecular weight version of Lupamin designated as Lupamin 1595 or a high molecular weight version designated as Lupamin 9095, for example, may be useful.
The primary amine may be grafted to a starch, for example, but methods suggested by G. Mino and S. Kaizerman in Journal of Polymer Science, Vol. 31, pages 242-243. As described by Mino and Kaizerman, in this method ceric salts, such as nitrate and sulfates, are used to form effective redox systems in the presence of organic reducing agents such as, for example, alcohols, thiols, glycols, aldehydes, or amines. The oxidation-reduction produces cerous ions and transient free radical species capable of initiating vinyl polymerization. An exemplary graft polymer of polyacrylamide on polyvinyl alcohol may be prepared as follows: 2.5 ml. of a 0.1 M solution of ceric ammonium nitrate in 1 M nitric acid could be added to a solution of 5 g. acrylamide and 1. g. polyvinyl alcohol in 97.5 ml.
water. Polymerization may be carried out in an atmosphere of nitrogen at 20 C. After polymerization, for example one hour, the solution could be poured into an excess of acetone to precipitate the gross polymer. A conversion of acrylamide may be, for example, 93%. Fractional precipitation of the gross polymer could show that no free polyacrylamide would be present. This procedure may be used with starch or zanthan gum instead of the polyvinyl amide and the acrylamide could be replaced with, for example, a polyvinylformamide to produce a primary amine containing component useful in the practice of the present invention. This method may be easily modified to provide grafting of primary amines onto other polymers that are not soluble in the drilling fluid composition

4 of the present invention. Such polymers may be, for example, synthetic or natural polymers.
The primary amine-containing component may be present in the drilling fluid composition in a concentration of, for example, about 0.1 to about 10 percent by weight nitrogen, and in another embodiment, from about 0.5 to about 3 percent by weight nitrogen in the drilling fluid composition.
In one embodiment, the primary amine may be applied in a liquid form, but a solid may offer an advantage of concentrating in the filter cake and remaining in the filter cake until removal was initiated by contact with the nitrous acid composition.
An acid solution used to remove the filter cake may be formed by combining a solution of sodium nitrite with a mineral acid such as hydrochloric acid. The sodium nitrite, when combined with the acid, becomes nitrous acid, and will rapidly convert the primary amine functional groups to diazo functional groups, which further decompose to olefin and nitrogen gas. The acid may further decompose the filter cake components by normal acid attack, but the action of generation of the nitrogen gas will have created permeability within the filter cake, breaking up the filter cake, and lifting the filter cake from the wellbore wall, and greatly enhance removal of the filter cake.
Komblum and Lffland, in Journal of the American Chemical Society, Vol. 71, page 2137, say that primary amines do not react with nitrous acid at a pH below 3.
But the present inventors have found that a reaction with polymers such as Lupamin react vigorously at a pH of 3 or less. Some embodiments of the present invention may utilize a nitrous acid solution having a pH of, for example, 4 or less, or alternatively, 1 to 3, to remove the filter cake from the wellbore.
A shale hydration inhibition agent may be present in sufficient concentration to reduce either or both the surface hydration based swelling and/or the osmotic based swelling of the shale. The exact amount of the shale hydration inhibition agent present in a particular drilling fluid formulation may be determined by a trial and error method of testing the combination of drilling fluid and shale formation encountered.
Generally however, the shale hydration inhibition agent may be used in drilling fluids in a concentration from about 1 to about 18 pounds per barrel (lbs/bbl or ppb) (about 2.852 to about 51.34 gm/1) and more preferably in a concentration from about 2 to about 12 pounds per barrel (about 5.704 to about 34.22 gm/1) of drilling fluid.

5 The drilling fluids of the some embodiments of the present invention include a weight material in order to increase the density of the fluid. The primary purpose for such weighting material is to increase the density of the drilling fluid so as to prevent kickbacks and blow-outs. One of skill in the art should know and understand that the prevention of kickbacks and blow-outs is important to the safe day-to-day operations of a drilling rig.
Thus the weight material is added to the drilling fluid in a functionally effective amount largely dependent on the nature of the formation being drilled.
Weight materials suitable for use in the formulation of the drilling fluids of the present invention may be generally selected from any type of weighting materials be it in solid, particulate form, suspended in solution, dissolved in the aqueous phase as part of the preparation process or added afterward during drilling. It is preferred that the weight material be selected from the group including barite, hematite, iron oxide, calcium carbonate, magnesium carbonate, organic and inorganic salts, and mixtures and combinations of these compounds and similar such weight materials that may be utilized in the formulation of drilling fluids.
In addition to the other components previously noted, materials generically referred to as gelling materials, thinners, and fluid loss control agents, are optionally added to drilling fluid formulations. Of these additional materials, each may be added to the formulation in a concentration as functionally required by drilling conditions. Typical gelling materials used in aqueous based drilling fluids are bentonite, sepiolite, clay, attapulgite clay, anionic high-molecular weight polymer and biopolymers.
Thinners such as lignosulfonates are also often added to water-base drilling fluids.
Typically lignosulfonates, modified lignosulfonates, polyphosphates and tannins are added.
In other embodiments, low molecular weight polyacrylates can also be added as thinners.
Thinners are added to a drilling fluid to reduce flow resistance and control gelation tendencies. Other functions performed by thinners include reducing filtration and filter cake thickness, counteracting the effects of salts, minimizing the effects of water on the formations drilled, emulsifying oil in water, and stabilizing mud properties at elevated temperatures.
A variety of fluid loss control agents may be added to the drilling fluids of come embodiments of the present invention that are generally selected from a group consisting of synthetic organic polymers, biopolymers, and mixtures thereof. The fluid loss control

6 agents such as modified lignite, polymers, modified starches and modified celluloses may also be added to the water base drilling fluid system of this invention. In one embodiment the additives of the invention may be selected to have low toxicity and to be compatible with common anionic drilling fluid additives such as polyanionic carboxymethylcellulose (PAC or CMC), polyacrylates, partially-hydrolyzed polyacrylamides (PHPA), lignosulfonates, xanthan gum, mixtures of these and the like.
The drilling fluid of some embodiments of the present invention may further contain an encapsulating agent generally selected from the group consisting of synthetic organic, inorganic and bio-polymers and mixtures thereof. The role of the encapsulating agent is to absorb at multiple points along the chain onto the clay particles, thus binding the particles together and encapsulating the cuttings. These encapsulating agents help improve the removal of cuttings with less dispersion of the cuttings into the drilling fluids. The encapsulating agents may be anioic, cationic, amphoteric, or non-ionic in nature.
Other additives that may be present in the drilling fluids of some embodiments of the present invention include products such as lubricants, penetration rate enhancers, defoamers, corrosion inhibitors and loss circulation products. Such compounds should be known to one of ordinary skill in the art of formulating aqueous based drilling fluids.
The following examples are included to demonstrate preferred embodiments of the invention. It should be appreciated by those of skill in the art that the techniques disclosed in the examples which follow represent techniques discovered by the inventors to function well in the practice of the invention, and thus can be considered to constitute preferred modes for its practice. However, those of skill in the art should, in light of the present disclosure, appreciate that many changes can be made in the specific embodiments which are disclosed and still obtain a like or similar result without departing from the scope of the invention.
The following examples demonstrate the feasibility of removing a filter cake by generation of gasses by exposure of the filter cake to acids when the filter cake contains a primary amine.

7

8 PCT/US2005/043127 TABLE
12 ppg PHPA Mud Freshwater lb 283.50 = 283.50 cc (= 0.81 bbl) Bentonite lb 8.00 3.02 cc NaCI lb 73.00 cc PAC-L lb 0.75 0.47 cc DEXTRID LT lb 4.00 2.67 cc EZ-MUD DP lb 0.75 0.94 cc BARAZAN-D PLUS lb 0.35 0.22 cc Barite lb 118.00 27.90 cc Rev-Dust lb 20.00 8.51 cc Total: lb 508.35 385.80 cc Density gm/cc 1.32 1.32 Density ppg 10.98 10.98 Lupamin lb 10.00 9.26 Total: lb 518.35 395.06 cc Final Density (gm/cc) gm/cc 1.31 1.31 Final Density (ppg) ppg 10.93 10.93 Final Lupamin Concentration ppb 9.77 9.77 A filter cake was created in a lab environment from a 12 pound per gallon (1.438 kgm/l) PHPA drilling mud system and from a 12 pound per gallon (1.438 kgm/1) lignosulfonate drilling mud. The mud was prepared according to the formulation of the table above. Samples of these muds were prepared with 10 pounds per gallon (1.198kgm/1) of Lupamin 1595 and another sample was prepared with 10 pounds per gallon (1.198 kgm/1) of Lupamin 9095. A high temperature fluid loss experiment was then performed at 150 degrees F to generate sample filter cakes from each of the muds. The filter cakes were cut in half, and to a dish with one of the half samples, a solution of hydrochloric acid and sodium nitrite solutions with 5.0 percent by weight hydrochloric acid and 5.0 percent by weight sodium nitrite.
Prior to addition of the acid solutions to the filter cake samples, the filter cakes appeared to not be porous. After addition of the acid solutions, each of the filter cakes was expanded and porous.

Those of skill in the art will appreciate that many modifications and variations are possible in terms of the disclosed embodiments, configurations, materials, and methods without departing from their spirit and scope. Accordingly, the scope of the claims appended hereafter and their functional equivalents should not be limited by particular embodiments described and illustrated herein, as these are merely exemplary in nature.

9

Claims

1. A drilling fluid comprising between about 0.5 and about 3 percent by weight of nitrogen in the form of a primary amine.

2. The drilling fluid of claim 1 further comprising between about 1 and about percent by weight of a starch.

3. The drilling fluid of claim 2 wherein at least a portion of the primary amine is grafted onto the starch.

4. The drilling fluid of claim 2 wherein at least a portion of the primary amine is grafted onto xanthan gum.

The drilling fluid of claim 1 wherein the primary amine is grafted to a polymer that is not soluble in the drilling fluid.

6. The drilling fluid of claim 1 wherein the drilling fluid is a water based drilling fluid.

7. The drilling fluid of claim 1 wherein the primary amine is an aliphatic amine.

8. The drilling fluid of claim 1 further comprising a bentonite clay.

9. The drilling fluid of claim 1 wherein the drilling fluid further comprises sodium chloride.

10. A method of providing a wellbore in a hydrocarbon production zone comprising the steps of:
incorporating into a drilling fluid a solid component that forms a gas when exposed to an activating component;
circulating the drilling fluid while drilling the wellbore in the hydrocarbon production zone whereby the solid component; and circulating a drilling fluid comprising the activating component after at least a portion of the wellbore within the production zone is drilled, and there by forming gas bubbles within the filter cake and causing the filter cake to at least partially release from a wall of the wellbore.

11. The method of claim 10 wherein the solid component is a primary amine.

12. The method of claim 11 wherein the primary amine is grafted onto a starch.

13. The method of claim 11 wherein the primary amine is grafted onto a xanthan gum.

14. The method of claim 11 wherein the primary amine is grafted onto a polymer that is not soluble in the drilling fluid.

15. The method of claim 11 wherein the activating component is an acid.

16. The method of claim 15 wherein the activation component further comprises nitrous acid.

17.The method of claim 21 wherein the primary amine is a polyvinyl amine.

18. The method of claim 10 further comprising the step of placing a screen in the wellbore after the wellbore is drilled and prior to circulating the drilling fluid comprising the activating component.

19. The method of claim 10 wherein the gas bubbles are nitrogen gas bubbles.