CN101068904A - Drilling Fluid Additives and Methods - Google Patents

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 Additives and Methods

technical field

The present invention relates to drilling fluid compositions and methods of providing wellbores.

Background technique

When drilling a wellbore, drilling fluid is typically circulated through the drill pipe, through the drill bit and up to the annulus around the drill pipe to circulate cuttings out of the wellbore and cool the drill bit. The drilling fluid contains components such that the density of the drilling fluid provides a bottomhole pressure approximately equal to or greater than the pore pressure of fluids in the formation through which the wellbore is drilled and also provides no greater than the formation fracture that causes the wellbore to be drilled through. pressure of pressure. Drilling fluids often also contain additives that serve other purposes. For example, drilling fluids often contain solids that will form a filter cake along the wellbore walls to reduce fluid loss from the wellbore into the formation. Desirably, the filter cake has relatively low permeability to reduce fluid loss to the wellbore. This very low permeability filter cake is undesirable when producing hydrocarbons from the formation, particularly for the portion of the wellbore provided in intervals from which hydrocarbons are to be produced. It is therefore preferred to remove the filter cake prior to production of hydrocarbons, for example by circulating an acid composition which decomposes the solids in the filter cake. It is desirable that the filter cake be completely removed, but it is not easy to achieve with the existing methods for removing the filter cake.

Patel et al. in US Patent No. 6,484,821 suggested that primary amines could be used in drilling fluids to inhibit clay swelling. Formations containing large amounts of clay are generally not areas for hydrocarbon production because clay formations are not sufficiently impermeable and porous.

Filtration control additives are proposed by Clapper et al. in US Patent No. 4,735,732. The filtration control additive is useful in invert emulsion drilling fluids and methods of using the drilling fluids. The additives include pyrolysis products obtained by combining finely divided humic acid-containing material with primary amines containing an alkyl group of 10-20 carbon atoms or a phenyl group substituted with an alkyl group having 10 -20 carbon atoms) primary amines are mixed and heated.

Murphey et al. in US Pat. No. 6,143,698 propose a method of removing a filter cake from a subterranean wellbore comprising drilling the wellbore with a drilling fluid containing additives to form a filter cake containing oxidatively degradable components. The oxidatively degradable component is preferably a polysaccharide. When it is desired to remove the filter cake, the filter cake is contacted with clear bromine-containing brine or a bromate generator to degrade the polymer in the filter cake. The brine contains bromide salts and an oxidizing agent capable of delaying the oxidation of bromide to bromine under downhole conditions. In one embodiment, a drilling fluid comprising an amine-substituted starch and an amine-substituted xanthan gum thickener is used. The amine is preferably diethylaminoisopropanol. Alternatively, polymers containing tertiary and quaternary functional groups such as copolymers of polyethyleneimine and ethylene oxide have been proposed. The method relies on the oxidation of the filter cake and does not generate gas to physically lift the filter cake from the wellbore wall.

Card et al. in US Pat. No. 5,979,557 propose a method of restricting formation water inflow during well rotation to maximize polymer recovery following a formation hydraulic fracturing treatment. The method includes the steps of selectively plugging pore structure in the water-bearing zone and not plugging the pore structure of the hydrocarbon zone at the surface of the formation; performing a hydraulic fracturing treatment with a fluid containing polymer; and rotating the well to recover the polymer. Also provided is a method of acidifying a formation, preferably a matrix, having a hydrocarbon zone and a water bearing zone. The method comprises the steps of: selectively plugging the pore structure in the water-bearing zone at the surface of the formation to selectively impede migration of acid into the water-bearing zone; and injecting acid into the formation, wherein the acid is transferred from the water-bearing zone to the hydrocarbon zone as a result of the selective plugging step . When the aqueous zone contains residual amounts of hydrocarbon residues, the method further includes injecting a mutual solvent prior to the selective plugging step. In these methods, the selective plugging step preferably forms a viscous fluid plug in the pore structure of the water-bearing zone at the surface of the formation. The viscous fluid preferably contains at least a viscoelastic surfactant capable of forming worm-like micelles in an aqueous environment, a water-soluble salt for formation stability, and an aqueous carrier fluid.

Contents of the invention

The present invention includes a method of drilling a wellbore comprising the steps of: providing a drilling fluid comprising a primary amine; circulating the drilling fluid while drilling the wellbore, wherein the primary amine is incorporated into a filter deposited on the wellbore wall as the wellbore is drilled. cake; and removing at least a portion of the filter cake after drilling the wellbore by circulating a fluid comprising nitrous acid into the wellbore.

The present invention includes drilling fluids comprising about 0.5-3 wt% nitrogen in the form of primary amines.

The present invention includes 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 with the solid component therein while the hydrocarbon Drilling a wellbore in the production zone, and circulating a drilling fluid comprising an activating component after drilling at least a portion of the wellbore in the production zone, thereby forming gas bubbles in the filter cake and causing the filter cake to at least partially peel off the wellbore wall.

Detailed ways

The drilling fluids of the present invention include components that generate gas when the activating component contacts the solid component. When circulated through the well during the drilling process, this component incorporates itself into the filter cake against and slightly into the wellbore wall. Slight overpressure within the wellbore forces some of the drilling fluid into the formation through which the wellbore is drilled, and solids in the drilling fluid are thereby deposited on the surface of the wellbore and in pore intervals in the formation near the wellbore. As the drilling fluid is passed into the formation, more solids will deposit on the surface of the wellbore and eventually form a filter cake. The filter cake then reduces the loss of drilling fluid by creating a relatively impermeable surface at and near the surface of the wellbore wall. Especially when the formation through which the wellbore is being drilled is a producing interval, it is desirable to remove the surface layer after it has served its purpose of reducing drilling fluid loss while drilling.

To remove filter cake, the drilling fluids of the present invention incorporate components that generate gas when in contact with the activating component. In one embodiment, the gas forming component is a primary amine containing component and the activating component includes nitrous acid. Primary amines can be in solid form so that they become embedded in the filter cake. Primary amines can be incorporated into the solids, for example by grafting onto starch or xanthan gum or other natural or synthetic polymers that are insoluble in the drilling fluid composition. Primary amines may be polymers such as polyvinyl formamide that are hydrolyzed to the amine form. Polyvinyl formamides of this type are available from BASF Corporation under the tradename Lupamin. A low molecular weight form of Lupamin designated Lupamin 1595 or a high molecular weight form designated Lupamin 9095 may be used, for example.

Primary amines can be grafted onto starch, for example by methods other than those proposed by G. Mino and S. Kaizerman in Journal of Polymer Science, Vol. 31, pp. 242-243. As described by Mino and Kaizerman, cerium salts such as nitrates and sulfates are used in this method to form efficient redox systems in the presence of organic reducing agents such as alcohols, thiols, diols, aldehydes or amines. This oxidation-reduction produces cerium ions and transition radical species capable of initiating vinyl polymerization. An exemplary graft polymer of polyacrylamide on polyvinyl alcohol can be prepared as follows: 2.5 ml of a 0.1 M solution of ceric ammonium nitrate in 1 M nitric acid can be added to 5 g of acrylamide and 1 g of polyvinyl alcohol in 97.5 ml of water in the solution. Polymerization can be performed at 20°C in a nitrogen atmosphere. After polymerization, for example 1 hour, the solution can be poured into excess acetone to precipitate crude polymer. The conversion of acrylamide may for example be 93%. Fractional precipitation of crude polymer may indicate that no free polyacrylamide will be present. This step may substitute starch or xanthan gum for polyvinylamide, and may substitute polyvinyl formamide for example for acrylamide to produce primary amine-containing components useful in the practice of this invention. This method can be readily modified to graft primary amines onto other polymers that are insoluble in the drilling fluid compositions of the present invention. Such polymers may, for example, be synthetic or natural polymers.

The primary amine-containing component may be present in the drilling fluid composition, for example, at a concentration of about 0.1-10 wt% nitrogen, and in another embodiment about 0.5-3 wt% nitrogen.

In one embodiment, the primary amine may be added in liquid form, but the solid may offer the advantage of being concentrated in the filter cake and remaining in the filter cake until removal begins upon contact with the nitrous acid composition.

An acid solution for filter cake removal may be formed by combining a sodium nitrite solution with a mineral acid such as hydrochloric acid. Sodium nitrite becomes nitrous acid when combined with acid, and will rapidly convert primary amine functionality to diazo functionality, which further decomposes into olefins and nitrogen. With conventional acid attack, the acid can further break down the filter cake components, but the action of generating nitrogen gas will create permeability in the filter cake, break the filter cake, lift the filter cake from the wellbore wall and greatly strengthen the filter cake removal.

Kornblum and Lffland in Journal of the American Chemical Society, Vol. 71, p. 2137, show that primary amines do not react with nitrous acid at a pH below 3. But the inventors found that it reacts violently with polymers such as Lupamin at a pH of 3 or less. Some embodiments of the present invention may use a nitrous acid solution at a pH such as 4 or less, or alternatively at a pH of 1-3, to remove the filter cake from the wellbore.

The shale hydration inhibitor may be present in sufficient concentration to reduce surface hydration-based swelling and/or osmotic-based swelling of the shale. The precise amount of shale hydration inhibitor present in a particular drilling fluid formulation can be determined by trial and error by testing combinations of drilling fluids and shale formations encountered. Typically, however, shale hydration inhibitors may be used in drilling fluids at a concentration of about 1-18 pounds per barrel (lbs/bbl or ppb) (about 2.852-51.34 g/l), and more preferably about 2-12 lbs/bbl (about 5.704-34.22g/l) concentration of drilling fluid.

In order to increase the density of the drilling fluid, the drilling fluid of some embodiments of the present invention includes a weighting material. The main purpose of this type of weighting material is to increase the density of the drilling fluid to prevent recoil and blowout. Those skilled in the art will know and understand that preventing kickback and blowout is important to the safe daily operation of a drilling rig. A functionally effective amount of weighting material is therefore added to the drilling fluid, the amount largely depending on the nature of the formation being drilled.

Weighting materials suitable for use in formulating drilling fluids of the present invention may generally be selected from any type of weighting material that is solid, in granular form, suspended in solution, dissolved in the aqueous phase as part of the preparation process, or added later during drilling. Preferably, the weighting material is selected from barite, hematite, iron oxide, calcium carbonate, magnesium carbonate, organic and inorganic salts and mixtures and combinations of these compounds and similar such weighting materials that can be used to formulate drilling fluids .

Materials commonly referred to as cementitious materials, diluents and fluid loss control agents are optionally added to the drilling fluid formulation, in addition to the other components previously mentioned. Among these additional materials, each material can be added to the formulation in the concentration required as a function of the drilling conditions. Typical cementitious materials used in water-based drilling fluids are bentonite, sepiolite, clay, attapulgite clay, anionic high molecular weight polymers and biopolymers.

It is also common to add diluents such as lignosulfonates to water-based drilling fluids. Typically lignosulfonates, modified lignosulfonates, polyphosphates and tannins are added. In other embodiments, low molecular weight polyacrylates may also be added as diluents. Thinners are added to drilling fluids in order to reduce flow resistance and control gelling tendency. Other functions performed by diluents include reducing filtration and filter cake thickness, counteracting the effects of salt, minimizing the effect of water on drilling formations, emulsifying oil in water, and stabilizing drilling fluid properties at high temperatures.

A variety of fluid loss control agents may be added to the drilling fluids of some embodiments of the present invention, generally selected from synthetic organic polymers, biopolymers, and mixtures thereof. Fluid loss control agents such as modified lignite, polymers, modified starches and modified celluloses may also be added to the water-based drilling fluid systems of the present invention. In one embodiment, the additives of the present invention can be selected to have low toxicity and compatibility with commonly used anionic drilling fluid additives such as polyanionic carboxymethylcellulose (PAC or CMC), polyacrylates, partially hydrolyzed polyacrylamides ( PHPA), lignosulfonate, xanthan gum, their mixtures, etc.

The drilling fluids of some embodiments of the present invention may also comprise an encapsulating agent, generally selected from synthetic organic, inorganic and biopolymers and mixtures thereof. The role of the encapsulant is to adsorb to the clay particles at multiple points along the chain, thereby binding the particles together and encapsulating the cuttings. These encapsulants help improve cuttings removal with less dispersion of cuttings into the drilling fluid. Encapsulating agents can be anionic, cationic, amphoteric or nonionic 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 enhancers, defoamers, corrosion inhibitors, and loss circulation products. These compounds are known to those of ordinary skill in the art of formulating water-based drilling fluids.

The following examples are included to illustrate 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 be 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 a similar result without departing from the scope of the invention.

The following examples illustrate the feasibility of removing the filter cake by exposing the filter cake to an acid to generate gas when the filter cake contains primary amines.

surface

12ppg PHPA drilling fluid

Fresh water lb 283.50＝283.50 cc (＝0.81 bbl)

Bentonite Clay lb 8.00 3.02 cc

NaCl 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 g/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 (g/cc) g/cc 1.31 1.31

Final Density (ppg) ppg 10.93 10.93

Final Lupamin concentration ppb 9.77 9.77

Filter cakes were made in a laboratory environment from a 12 lb/gal (1.438 kg/l) PHPA drilling fluid system and from a 12 lb/gal (1.438 kg/l) lignosulfonate drilling fluid. The drilling fluid was prepared according to the formula in the table above. A sample of these drilling fluids was prepared with 10 lb/gal (1.198 kg/l) Lupamin 1595 and another sample was prepared with 10 lb/gal (1.198 kg/l) Lupamin 9095. A high temperature fluid loss test was then performed at 150°F to generate a sample filter cake from each drilling fluid. The filter cake was cut in half and a plate was filled with half of the sample, hydrochloric acid solution and sodium nitrite solution containing 5.0 wt% hydrochloric acid and 5.0 wt% sodium nitrite.

The filter cake did not appear porous until the acid solution was added to the filter cake sample. After adding the acid solution, each filter cake was swollen and porous.

Those skilled in the art will appreciate that many modifications and changes may be made to the disclosed embodiments, structures, materials and methods without departing from the spirit and scope thereof. Accordingly, the scope of the appended claims and their functional equivalents should not be limited by the specific embodiments described and illustrated herein, since these are merely exemplary in nature.

Claims (19)

1. drilling fluid, it comprises the nitrogen of the primary amine form of about 0.5-3wt%.

2. the drilling fluid of claim 1, it also comprises the starch of about 1-10wt%.

3. the drilling fluid of claim 2 wherein is grafted on the starch to the small part primary amine.

4. the drilling fluid of claim 2 wherein is grafted on the xanthan gum to the small part primary amine.

5. the drilling fluid of claim 1, wherein primary amine is grafted on the polymkeric substance that is insoluble to this drilling fluid.

6. the drilling fluid of claim 1, wherein this drilling fluid is a water-base drilling fluid.

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

8. the drilling fluid of claim 1, it also comprises wilkinite.

9. the drilling fluid of claim 1, wherein this drilling fluid also comprises sodium-chlor.

10. method that wellhole is provided in hydrocarbon mining area, it may further comprise the steps:

The solid ingredient that will form gas in the time of will being exposed to activating component is mixed drilling fluid;

Make the circulation of drilling fluid that solid ingredient is wherein arranged in hydrocarbon mining area, drill wellhole simultaneously; With

Make the circulation of drilling fluid that comprises activating component after in mining area, being drilled to the small part wellhole, in filter cake, form bubble thus and filter cake to small part is peeled off from borehole wall.

11. the method for claim 10, wherein solid ingredient is a primary amine.

12. the method for claim 11, wherein primary amine is grafted on the starch.

13. the method for claim 11, wherein primary amine is grafted on the xanthan gum.

14. the method for claim 11, wherein primary amine is grafted on the polymkeric substance that is insoluble to drilling fluid.

15. the method for claim 11, wherein activating component is acid.

16. the method for claim 15, wherein activating component also comprises nitrous acid.

17. the method for claim 21, wherein primary amine is a polyvinylamine.

18. the method for claim 10, it is further comprising the steps of: after the probing wellhole and before making the circulation of drilling fluid that comprises activating component filter screen is set in wellhole.

19. the method for claim 10, wherein bubble is a nitrogen bubble.