WO2014078069A1

WO2014078069A1 - Sealant for non aqueous drilling fluid channel in wellbore

Info

Publication number: WO2014078069A1
Application number: PCT/US2013/067183
Authority: WO
Inventors: Michael Cowan
Original assignee: Apache Corporation
Priority date: 2012-11-19
Filing date: 2013-10-29
Publication date: 2014-05-22

Abstract

A method for sealing a conduit in a wellbore drilled through subsurface formations wherein the wellbore has been drilled using a non-aqueous base drilling fluid includes mixing cementing material with the drilling fluid. The material is selected to react with aqueous phase components of the drilling fluid to form a solid sealing material. The mixed cementing material into an annular space between the conduit and a wall of the wellbore.

Description

SEALANT FOR NON AQUEOUS DRILLING FLUID CHANNEL IN

WELLBORE

Background

[0001] This disclosure relates generally to the field of sealing liners, pipes or casings within wellbores drilled through subsurface formations. More specifically, this disclosure relates to compositions for sealing such pipes, particularly when the wellbore is drilled with non-aqueous, water based drilling fluid.

[0002] Isolation between exposed formations in a wellbore drilled through such subsurface formations requires substantially complete displacement of the drilling fluids used to drill the wellbore with a cement slurry in the annular space ("annulus") between casing, pipe or liner and the wall of the wellbore. Effective, complete displacement of drilling fluid by cement slurries involves a complex, multi-variant fluid mechanics design process. Centralization of the casing is one of the important variables affecting displacement efficiency and complexity of cementing operations design. If the casing is not centralized within the wellbore, the probability of good long-term isolation of the various formations from each other and from leakage to surface over the life of the well may decrease significantly. Similarly, if the casing is not centralized within the wellbore, the difficulty in designing an effective drilling fluid displacement process increases. An effective displacement process must be designed by evaluation of thousands to millions of possible combinations of other variables in the cementing operation in order to compensate for poor centralization of the casing.

[0003] If the displacement process is sub-optimal, the interface between the displaced fluid (the drilling fluid or spacer) and the displacing fluid (the cement slurry) may be unstable and significant intermixing of fluids can occur. Contamination of the cement with spacer or drilling fluids can deleteriously affect the cement material properties (e.g., compressive strength) and the cement's sealing properties. Contamination of the cement slurry with water-based spacer fluids results in dilution of the cement concentration in the mixture. Set time of the mixture is typically extended beyond that of the uncontaminated slurry. Compressive strength is typically decreased because of an increased water-to- cement ratio caused by the contamination of water from the spacer fluid. Some spacers contain additives that retard cement. When retarding additives are present, the set time is further extended and compressive strength further reduced. Delaying (retarding) the set time of the cement can allow fluids, such as gas, oil and water, from exposed formations to enter the annulus and create one or more channels. Remedial cementing or other repairs are often required to seal off any channels.

Summary

[0004] One aspect of the disclosure is a method for sealing a conduit in a wellbore drilled through subsurface formations wherein the wellbore has been drilled using a non-aqueous base drilling fluid. An example method includes mixing cementing material with the drilling fluid. The material is selected to react with aqueous phase components of the drilling fluid to form a solid sealing material.

[0005] In some embodiments the material may be further selected to accelerate setting of the cement and offset the effect of dilution on set time and compressive strength. Contaminated mixtures of cementing material develop properties in the annular space between the conduit and a wall of the wellbore that may prevent creation of any channels caused by influx and migration of formation fluids into and along the annular space.

[0006] Other embodiments may include formulating a non-aqueous drilling fluid containing components of an acid-base cement material. Acid-base reactions may be delayed by keeping the components (the acid and the base) separated until the desired time to form the cement. The acidic and basic components of the acid-base cement may be kept separated in a non-aqueous drilling fluid by several methods. If one component is a solution or a solid dissolved in an aqueous phase to form a solution, then this one component of the acid-base cement may be emulsified with the non-aqueous component of the drilling fluid to form the internal, non-continuous phase of the non-aqueous base drilling fluid. Emulsification encapsulates this component inside an oil coating which prevents contact with a second component of the acid-base cement. The second component may be dispersed in the oil (continuous phase) of the drilling fluid emulsion. If both the acidic and basic components of the acid-base cement are solids, both may be dispersed in the non-aqueous phase of the drilling fluid. The continuous, non-aqueous phase of the drilling fluid coats the particles or both components. Both components must become water-wet for the reaction to occur. Intermixing of this reactive drilling fluid with water-base spacer and cementing fluids destabilizes the emulsion, water-wets the oil-wet components and initiates the reaction between the two components of the acid- base cement. Surfactants and solvents may be included into the spacer and cementing fluids to further enhance destabilization of the emulsion and water-wetting of the components. If the non-aqueous drilling fluid is not contacted by water-based spacer and cementing fluids, the emulsion will destabilize with time due to temperature, pressure, osmotic forces and Ostwald ripening and allow the two components to react and form a solid sealant.

[0007] Other aspects and advantages will be apparent from the description and claims which follow.

Brief Description of the Drawings

[0008] FIG. 1 shows an example apparatus for pumping cement into a wellbore annulus.

Detailed Description

[0009] FIG. 1 shows example equipment for delivery of cement and other fluids into a wellbore. This will be described first and thereafter the detailed description of the cement composition of this disclosure will be set forth. Briefly, the numeral 10 identifies a cement supply. Typically, cement is mixed proximate the wellbore location and is delivered therein through large pumps 11 into a manifold 12. The manifold 12 is connected to a wellhead at 13. As appropriate, a suitable valve 14 may be interposed between the wellhead 13 and the manifold 12. The cement is delivered under suitable pressures at selected flow rates. The nature of the cement 10 will be further explained below. It is known in the art that two or three different fluids may be pumped into the well to complete a cementing job. The manifold 12 is used to deliver these fluids into the wellbore. The pump 11 is connected with suitable supplies of various fluids for delivery of the various cementing fluids.

[0010] At the wellhead 13, a flow meter 15 measures the rate of flow which is normally expressed in barrels per minute. This is the rate of flow of the fluid delivered into the wellbore. The density of the fluid may also be measured proximate the wellhead by a transducer 16. Density is normally indicated in pounds per gallon. As appropriate, a fluid analysis device 17 may be included to make other measurements regarding the pumped fluid. The other measurements may include, for example, fluid viscosity, gel time and the like for the fluid. The transducers 15, 16 and 17 form output data which is input to a control and monitoring system (not shown). Another important variable is the pressure at the wellhead which may be measured by a transducer 18 and which is expressed in pounds per square inch (psi). The pressure transducer 18 is typically calibrated up to several thousand psi. Pressures in this range are not uncommon.

[0011] The wellhead 13 is well known by those skilled in the art. It is connected to a completion "string" in the bore hole 20. The bore hole 20 may be cased or open hole, and is represented in a very general form in FIG. 1. While there may be multiple completion strings, FIG. 1 shows a representative single completion string in the well. This is the string of pipe to be cemented in place in the well; this string of pipe normally encloses a separate tubing string to conduct produced oil and gas to the surface. This string can be uniform from top to bottom but it can also be made in different sections. In the present example, an upper section is identified by the numeral 21. This section is tubing of a specific diameter and flow characteristic and has a certain length and extends to a selected depth in the bore hole 20. The number 22 identifies a second section which is serially connected to a third section 23. The sections 21, 22, and 23 jointly comprise the completion string. Moreover, they may be identical and to that degree only a single section need be mentioned. On the other hand, they may be different, represented by different lengths and typically formed of different diameters of pipe. As an example, the completion string can taper wherein the top section 21 is relatively large in diameter and the bottom section 23 is much smaller in diameter. The completion string terminates at a bottom located opening 24. Again, the precise nature and details of the opening 24 are well known; it may be fitted with various landing nipples supported by packers, bridge plugs and the like; the foregoing have been omitted for sake of clarity in the description of the completion string and the associated equipment. In general, the completion string extends to the bottom or nearly to the bottom of the bore hole 20 where cement is delivered from the opening 24. Cement flows into the annulus 25 when pumped through the completion string. The cement is delivered into the annulus 25 to complete the cementing job. The annulus 25 has been represented in very general form in FIG. 1 and will be understood to be that portion of the wellbore where cement is to be delivered, and may be defined and isolated by packers or bridge plugs (not shown). The annulus 25 may also be temporarily or permanently filled with other fluids either before or after the cement, all for the purpose of completing the cement job and assuring that the cement bond between the completion string and well bore 20 is completed in the desired fashion. The annulus 25 is therefore set forth in very general form on the exterior of the completion string. This fact remains true even should there by multiple pipe strings to multiple zones along the wellbore.

[0012] In the present example, the bore hole 20 has been drilled with a fluid having a non-aqueous continuous liquid phase (commonly referred to as "oil based mud"). Cement compositions for assuring zonal isolation under conditions of incomplete displacement of non-aqueous drilling fluids according to the present disclosure may be obtained by incorporating additives in the non-aqueous drilling fluid that will perform the following functions.

[0013] 1) minimize or offset the deleterious effects of non-aqueous drilling fluid additives and contamination on the material and sealing properties of Portland cement slurries;

[0014] 2) form a cement upon contact and mixing with aqueous cementing fluids;

[0015] 3) may incorporate a surfactant and solvent in the spacer, cement and/or drilling fluid to enhance water absorption by the drilling fluid.

[0016] The sealing material setting reaction may be activated by contact or mixing of the non-aqueous base drilling fluid with aqueous cementing fluids including, for example, chemical washes, prefiushes, spacers and Portland cement slurry. The sealing material setting reaction of the sealing material in the non-aqueous drilling fluid may also be activated by destabilization of the drilling fluid emulsion by temperature, pressure, osmotic forces and Ostwald ripening forces over time if not contacted or intermixed with an aqueous component of the cementing fluid.

[0017] Additives may be included in the drilling fluid and placed in the wellbore prior to running the pipe (conduit), liner or casing and the conduit is filled with these fluids. Optionally, the non-aqueous drilling fluid may be pumped ahead of the aqueous cementing fluids (spacer and cement).

[0018] Non-aqueous drilling fluid formulations according to the present disclosure may be activated by water-based cementing fluids to form a seal for a channel created by incomplete displacement of drilling fluid in the entire annular cross-section during cementing. The present disclosure may include the following, as non-limiting examples.

[0019] A basis for the below described example formulations is that many non-aqueous drilling fluids, particularly synthetic base drilling fluids using paraffin or olefin base oils, have additives that act as very powerful retarders and strength reducers for Portland cement. The presence of these retarding additives increases the effect of contamination on set time and compressive strength of Portland cement beyond that of simple dilution of the concentration of cement in the mixture. Table 1 and Table 2 show the effect of retarding additives on Portland cement set time and compressive strength.

Table 1 - Effect of Water Dilution on Cement Formulation

The drilling fluid composition in Example Formulation 1 (described below) is composed of an emulsion of 11.0 pound per gallon (lb/gal) density calcium chloride brine emulsified in an internal olefin oil having an average carbon chain length of 15 to 18 (an example olefin is sold under the trademark Neodene 1518. NEODENE is a registered trademark of Shell Oil Company, Houston, Texas). The volumetric oil/water ratio was 70:30. The density of the emulsion was 7.88 pounds per gallon. The drilling fluid was weighted up (increased in density) to 12 pounds per gallon by combining 35.4 gallons of the emulsion with 226 pounds of barite to produce one barrel final volume.

[0020] For Portland cement, the effect of dilution of the cement slurry with water produces a nearly linear increase in initial set time and corresponding decrease in compressive strength. The same amount of dilution with a synthetic base drilling fluid containing polyamide type emuslifiers and amine- or carboxylic acid-derivative type wetting agents produces a significantly greater increase in initial set time and much greater decrease in compressive strength for Portland cement. In this example, more than 20 percent synthetic base drilling fluid contamination of a Portland cement slurry can increase the setting time by more than 150 percent and decrease final compressive strength by more than 75 percent. Above about 30 percent synthetic base drilling fluid contamination by volume in a Portland cement slurry can result in a mixture that will never set or develop significant compressive strength depending upon temperature pressure conditions in the wellbore.

[0021] Example Formulation 1 : Incorporation of high aluminate cement in the drilling fluid may fluid may be used as one example formulation. High aluminate cement is high strength cement that accelerates the set of Portland cement.

[0022] In the present Example Formulation 1 an amount of high aluminate cement

(described below) is included in the drilling fluid spotted in the wellbore prior to running the conduit. The Formulation will still include some Portland cement. If the Portland cement is contaminated by the drilling fluid containing this high aluminate cement, the detrimental effect on setting time and final compressive strength of the Portland cement will be decreased. Additionally the water, surfactants and solvents utilized in spacers and Portland cement slurries will destabilize the emulsion of the non-aqueous drilling mud and allow water to activate the high aluminate cement to set and form a solid that can seal any channels left by any undisplaced drilling fluid.

[0023] The high aluminate cement may replace all or part of the density increasing

(weighting) materials such as barite, hematite, calcium carbonate, manganese tetraoxide, ilmenite, etc. used in the drilling fluid. High aluminate cement (HAC) is a hydraulic cement based upon calcium aluminate chemistry while Portland cements are based upon calciumsilicates and calcium aluminosilicates. Example compositions of HAC that may be used in some examples include those sold under the trademarks Secar 41, Secar 51, Secar 71, Secar 80, Ciment Fondu. SECAR is a registered trademark of Kerneos Corporation, 8 Rue des Graviers, 92200 Neuilly Sur Seine, France. In some examples, the HAC concentration in the drilling fluid may be in the range of about 10 to 400 pounds per barrel (lbs/bbl), more preferably in a range of about 20 to 250 lbs/bbl and even more preferably in a range of 50 to 150 lbs/bbl. In such concentration ranges there is usually enough HAC in the drilling fluid to accelerate and offset the strength reduction of the Portland cement slurry when the two are mixed in different volumetric ratios. For example a synthetic base drilling fluid having 100 lbs/bbl Secar 71 would provide 50 lbs/bbl of HAC cement to a barrel of a 1 : 1 (50:50% mix) volume ratio to a Portland cement slurry. It would be 25 lbs/bbl for a 1 :3 (25:75%) volume ratio with Portland cement. It may be preferable that the amount of HAC in any mixture of the drilling fluid and Portland cement not be less than 10 lbs/bbl, more preferably not less than 25 lb/bbl and more preferably not less than 50 lbs/bbl.

Table 3 - Effect of 12 lb/gal Synthetic Base Mud Containing High Aluminate Cement on Cement Formulation.

[0025] The drilling fluid composition in the present example is composed of an emulsion of 11.0 pounds per gallon (lb/gal) calcium chloride brine emulsified in an internal olefin oil having an average carbon chain length of 15 to 18. (e.g., Neodene 1518). The volumetric oil/water ratio was 70:30. The density of the emulsion was 7.88 pounds per gallon. The drilling fluid was weighted up to 12 pounds per gallon by combining 33.8 gallons of the emulsion with 119 pounds of barite and 119 pounds of a blend of high aluminate cement products and 10 pounds of lithium carbonate to produce one barrel final volume. It may be observed in Table 3 that set time increase and compressive strength reduction with respect to dilution is substantially improved over plain Portland cement by adding HAC as explained above.

[0026] Example Formulation 2: A non-aqueous drilling fluid may be prepared with an acidic phosphate brine internal (discontinuous) phase and incorporate a metal oxide such as magnesium oxide, magnesia rich spinel, zinc oxide, zirconium oxide and/or aluminum oxide (such as high aluminate cement). The emulsion thus formed will destabilize over time or through contact with a water-based spacer and cement fluids to allow the phosphate and metal oxide to react to form a phosphate-bonded ceramic cement.

[0027] Phosphates can be liquid ammonium polyphosphate fertilizers (11-34-0 or 11-37-

0 NPK ratios), mononammonium phosphate, potassium hydrogen phosphate (etc). Powdered materials are dissolved to form a saturated solution and then emulsified into the internal phase of the drilling fluid.

[0028] Polycarboxylic acids (polyacrylic acid) may be liquid solutions or solids dissolved in water to form the internal phase of the non-aqueous continuous phase drilling fluid.

[0029] In the present example, the typical oil/water ratio (external phase/internal phase) for the emulsions are 50:50 to 95:5, so the acidic phosphate solution could be 5 to 50 percent of the internal phase of the emulsion. There may be no solids in the composition so as not to increase the density.

[0030] As the density of the drilling fluid increases, the volume of weighting agent

(and/or magnesium oxide) goes up as well. In many drilling fluids, the maximum solids tolerance is 40 percent by volume, more commonly between 0 and 35 percent and most commonly between 0 an 30 percent. Therefore, the amount of acidic phosphate solution in the total volume of mud could range from about 2 to 40 percent for lightly weighted (low density muds) down to 2 to 20 percent for high density muds.

[0031] An example formulation using an acidic phosphate as the internal phase of the synthetic base drilling fluid is provided. The base fluid for the drilling fluid is prepared by emulsifying 10.4 gallons of ammonium polyphosphate fertilizer (10-34-0) solution in 24.3 gallons of an internal olefin oil having an average carbon chain length of 15 to 18. (e.g., Neodene 1518). The volumetric oil/water ratio was 70:30. The density of the emulsion was 8.15 pounds per gallon. The drilling fluid was weighted up to 12 pounds per gallon by combining 34.7 gallons of the emulsion with 104.9 pounds of barite and 116.5 pounds of a blend of calcined magnesium oxides having a particle size distribution similar to barite to produce one barrel final volume. This fluid reacts to form a solid within several minutes upon mixing with a water base spacer fluid containing surfactants and gly col-ether mutual solvents.

[0032] Polyacrylic acid solutions, such as Noverite K-7058, K-732 and K-752 may be substituted for the ammonium polyphosphate solution as the internal (non-continuous) phase of the emulsion.

[0033] Solutions of dry powdered acidic phosphates (monoammonium phosphate, potassium hydrogen phosphate, etc) may be prepared and substituted for the ammonium polyphosphate solution as the internal (non-continuous) phase of the emulsion.

[0034] Example Formulation 3: Add a metal oxide and dry powdered phosphates

(monoammonium phosphate, potassium hydrogen phosphate, etc) to the drilling fluid. Similarly, solid polycarboxylic acids may be incorporated into the continuous (nonaqueous) phase of the drilling fluid. When contacted by water (from cementing fluids or from the aqueous internal phase of the emulsion) the acidic phosphate or polycarboxylic acid reacts with the metal oxide to form a phosphate-bonded ceramic cement or a polycarboxylate cement to seal the conduit in the annular space. Weight fractions of dry powdered phosphate to metal oxide in the range of 1 :10 through 1 :1 may be expected to work. [0035] An example formulation incorporating dry, acidic phosphate salts in the drilling fluid may be composed of an emulsion of 11.0 lb/gal calcium chloride brine emulsified in an internal olefin oil having an average carbon chain length of 15 to 18. (e.g., Neodene 1518). The volumetric oil/water ratio was 70:30. The density of the emulsion was 7.88 pounds per gallon. The drilling fluid was weighted up to 12 pounds per gallon by combining 33.5 gallons of the emulsion with 80 pounds of barite and 112 pounds of a magnesia-rich spinel and 40 pounds of monopotassium phosphate to produce one barrel final volume. This fluid reacts to form a solid within several minutes upon mixing with a water base spacer fluid containing surfactants and glycol-ether mutual solvents.

[0036] Magnesium oxide may be substituted for magnesia-rich spinel and amounts adjusted for the difference in specific gravity between the materials.

[0037] Generally the spacer (a fluid buffer disposed between the drilling fluid and the cement slurry) is water based, using clay (bentonite, attapulgite, etc) and/or a polymer such as hydroxyethylcellulose, carboxymethylhydroxyethylcellulose, xanthan gum, welan gum, schleroglucan gum, ethylene oxide-propylene oxide copolymers, polyacrylamide polymer, copolymers and terpolymers. Generally speaking, strong water wetting, oil-in-water emulsifying surfactants are used. Most common types are nonionic ethoxylated alcohols but also sulfonate surfactants, betaines or blends or ethoxylated alcohols with ethoxylated alcohol sulfonate or sulfates may be used in some embodiments.

[0038] Concentrations are typically less than 15 percent by volume of the spacer (total surfactant concentration) and more commonly between 2 and 10 percent by volume of the spacer.

[0039] Cement compositions and methods for using them may enable better sealing of the annular space between a wellbore conduit and the wall of the wellbore where conditions inhibit ideal circulation of the cementing slurry and/or there is contamination of the cementing slurry with non-aqueous drilling fluid.

[0040] While the invention has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the invention as disclosed herein. Accordingly, the scope of the invention should be limited only by the attached claims.

Claims

Claims What is claimed is:

1. A method for sealing a conduit in a wellbore drilled through subsurface formations, the wellbore having been drilled using a non-aqueous base drilling fluid, the method comprising:

mixing cementing material with the drilling fluid, the material selected to react with aqueous phase components of the drilling fluid to form a solid sealing material; and

pumping the mixed cementing material into an annular space between the conduit and a wall of the wellbore.

2. The method of claim 1 wherein the cementing material comprises high aluminate cement.

3. The method of claim 1 wherein the cementing material comprises powdered metal oxide and dry powdered phosphate.

4. The method of claim 3 wherein the dry powdered phosphate is water-soluble and is initially disposed in a non-aqueous phase of the drilling fluid.

5. The method of claim 1 wherein the cementing material comprises acidic phosphate brine and a metal oxide.

6. The method of claim 5 wherein the acidic phosphate brine is disposed in the aqueous phase of the drilling fluid and the metal oxide is initially disposed in the non-aqueous phase.

7. The method of claim 5 wherein the acidic phosphate brine comprises at least one of monoammonium phosphate, potassium hydrogen phosphate, monopotassium phosphate, dipotassium phosphase, monosodium phosphase and disodium phosphate.

8. The method of claim 1 wherein the cementing materials comprises Portland cement.

9. The method of claim 1 further comprising adding a surfactant into at least one of the drilling fluid, the drilling fluid mixed with the cementing material and a spacer fluid disposed between the drilling fluid and the drilling fluid mixed with the cementing material.

10. The method of claim 1 wherein the cementing material comprises polycarboxylic acids.

11. The method of claim 10 wherein the polycarboxylic acids are initially disposed in the non-aqueous phase of the drilling fluid.

12. The method of claim 10 wherein the polycarboxylic acids are disposed in the aqueous phase of the drilling fluid.