Drill Cuttings Re-Injection

Abstract

A method for re-injecting formation solids into a subsurface formation includes obtaining a volume of solid particles from drilling returns, and then obtaining an aqueous operations fluid comprising at least one surfactant. Mixing a volume of the operations fluid with the volume of solid particles to form a slurry which is injected into a disposal well which includes a NAF filter cake. Then injecting the slurry into one or more fractures formed in the subsurface formation such that the slurry contacts the NAF filter cake en route to the one or more fractures.

Description

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional No. 61/557,764, filed Nov. 9, 2011.

BACKGROUND OF THE INVENTION

This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present disclosure. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.

FIELD OF THE INVENTION

This invention relates generally to the field of wellbore operations. More specifically, the invention relates to the re-injection of drill cuttings and solids generated during the formation of a wellbore.

GENERAL DISCUSSION OF TECHNOLOGY

In the drilling of oil and gas wells, a wellbore is formed using a drill bit that is urged downwardly at a lower end of a drill string. The drill bit is rotated against a rock face in order to form a cylindrical borehole in the subsurface. During most drilling processes, the drill string is rotated from the surface, thereby imparting rotational movement to the drill bit downhole. In some processes, a downhole motor is provided for rotating the drill bit.

During the drilling process, a drilling fluid, or “mud,” is circulated through the drill string. The mud is forced downwardly through the drill string, out ports in or near the drill bit, and back up to the surface through an annular area formed between the joints of drill pipe and the surrounding subsurface formation. The process of rotating the drill bit and circulating mud causes the subsurface rock to be cut and eroded at ever-increasing depths as the wellbore is formed. As a result, pieces of formation are dislodged from the earth and carried up to the surface. These pieces represent bits of sand, clay, shale, quartz, or other rock, which are collectively referred to in the industry as “cuttings.”

Typically, the drill cuttings are circulated back to the surface and then separated from the drilling fluid using solids control equipment. The solids control equipment will include screens or so-called “shakers” that filter out the majority of solids while releasing the drilling mud. Samples of the cuttings may be captured where they are logged for correlated depth, and then analyzed. However, the majority of the cuttings are simply disposed of while the reclaimed drilling fluid is re-circulated into the drill string.

The disposal of drill cuttings and other solid wastes generated by drilling operations has come under scrutiny. Specifically, environmental regulations in some areas prevent the disposal of drill cuttings, especially when such cuttings contain residual non-aqueous fluids, or NAF's. Moreover, environmental policies of some operators' may require the cleaning of cuttings or other special handling before disposal. Accordingly, drilling companies have begun using a re-injection procedure for some drilling operations.

Cuttings re-injection operations, or “CRI,” generally started in the late 1980's. A drill-cuttings injection operation involves the collection of materials from solids-control equipment on the rig, and transportation of the materials to a slurrification unit. Frequently, the cuttings are ground into small particles in the presence of water to form the slurry. The slurry is then transferred to a holding tank for final rheological conditioning. The conditioned drill cuttings slurry is pumped through a casing annulus or a string of tubing in a well. The well may be a specially-formed disposal well. The cuttings slurry is then pumped into subsurface fractures created by injecting the slurry under high pressure into a disposal formation.

The injection (or re-injection) of drill cuttings offers an attractive solution to the disposal of cuttings from a drilling operation. In this respect, CRI can achieve minimal discharge of solids, as even the wastes generated from a re-injection operation are returned to the subsurface. Additionally, there are no future cleanup liabilities once the disposal well is plugged. For offshore operations in areas with environmental restrictions for the disposal of cuttings, and where large volumes of cuttings are generated, re-injection offers an economically attractive option compared to the transportation of cuttings onshore, or extensive de-oiling or other treatment.

As one might anticipate, various challenges exist with respect to CRI. Perhaps the most important is the slurry rheology design. Slurry rheology design includes slurry viscosity, suspension capacity, and particle size limitations. The slurry must have adequate viscosity and solids-carrying capacity to transport the particles into the formation. Further, the particles must be able to enter the fractures to avoid plugging, either along the wellbore or in the fracture.

Another challenge relates to the presence of filter cake. During a drilling process, the drilling fluid is placed in the bore of the drill string. The drilling fluid increases the hydrostatic pressure at the bottom of the wellbore. This, in turn, controls the flow of formation fluids into the wellbore. The drilling mud also helps to keep the drill bit cool and clean during drilling. In addition, the viscous drilling mud helps to carry the drill cuttings away from the rock face and up to the surface for analysis and/or disposal, as noted above.

An additional function of the drilling mud is to leave a filter cake along the wall of the wellbore. In this respect, as a wellbore is drilled through a permeable, hydrocarbon-bearing formation, the drilling mud will form a “filter cake.” The filter cake helps to prevent fluid leak-off into a formation during drilling, and also helps to maintain wellbore stability. At the same time, the filter cake creates at least a partial barrier to the injection of solid drill cuttings into a disposal formation. In this respect, the filter cake particles can reduce permeability of the rock in the near-wellbore region. This is particularly true with respect to filter cakes formed from a non-aqueous fluid (NAF), such as an oil-based or synthetic oil-based drilling mud.

A need exists for an improved method of re-injecting drill cuttings into a disposal formation. Further, a need exists for an improved method of re-injecting cuttings through a wellbore having a filter cake, wherein the method uses a slurry that also remediates a filter cake having NAF fluids therein.

SUMMARY OF THE INVENTION

The methods described herein have various benefits in the conducting of oil and gas exploration and production activities.

A method for re-injecting drill cuttings into a subsurface formation is first provided. In one embodiment, the method first includes obtaining a volume of solid particles from drilling returns. The solid particles primarily represent formation cuttings.

The method then includes obtaining an aqueous operations fluid comprising at least one surfactant. The operations fluid preferably comprises surfactant present in solution at a concentration greater than about 0.01 wt % and less than about 20.0 wt % based on water in the operations fluid.

In the present methods, the surfactant may be made up of a weak acid, a weak base, or both. In one aspect, the surfactant is an alkyl acid surfactant, an organo-anionic surfactant, or mixtures thereof. Where the surfactant is or includes an organo-anionic surfactant, the organo-ionic surfactant is preferably selected from the group comprising monoethanol ammonium alkyl aromatic sulfonic acid, monoethanol ammonium alkyl carboxylic acid, and mixtures thereof.

The operations fluid may be injected into the borehole of a disposal well in order to remediate a NAF filter cake along the borehole. Preferably, the method also includes mixing a volume of the operations fluid with the volume of solid particles to form an operations fluid slurry. The method then includes pumping the slurry into the disposal well.

The method further includes injecting the slurry into one or more fractures formed in the subsurface formation. Injection is conducted in such a manner that the slurry contacts the NAF filter cake en route to the one or more fractures. Because of the weak base—weak acid formulation of the slurry, the NAF filter cake is degraded, thereby facilitating the injection of the slurry into fractures along the wellbore.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the present inventions can be better understood, certain drawings, charts, graphs and/or flow charts are appended hereto. It is to be noted, however, that the drawings illustrate only selected embodiments of the inventions and are therefore not to be considered limiting of scope, for the inventions may admit to other equally effective embodiments and applications.

FIG. 1 presents a side view of a well site wherein a well is being completed. Known surface equipment is provided to support wellbore tools (not shown) above and within a wellbore. The well is a disposal well for the injection of drill cuttings.

FIG. 2 is a flow chart showing steps for a method of re-injecting drill cuttings, in one embodiment.

FIG. 3 is a flow chart showing steps for a method of re-injecting drill cuttings, in an alternate embodiment.

DETAILED DESCRIPTION OF CERTAIN EMBODIMENTS

Definitions

For purposes of the present application, it will be understood that the term “hydrocarbon” refers to an organic compound that includes primarily, if not exclusively, the elements hydrogen and carbon. Hydrocarbons may also include other elements, such as, but not limited to, halogens, metallic elements, nitrogen, oxygen, and/or sulfur. Hydrocarbons generally fall into two classes: aliphatic, or straight chain hydrocarbons, and cyclic, or closed ring hydrocarbons, including cyclic terpenes. Examples of hydrocarbon-containing materials include any form of natural gas, oil, coal, and bitumen that can be used as a fuel or upgraded into a fuel.

As used herein, the term “hydrocarbon fluids” refers to a hydrocarbon or mixtures of hydrocarbons that are gases or liquids. For example, hydrocarbon fluids may include a hydrocarbon or mixtures of hydrocarbons that are gases or liquids at formation conditions, at processing conditions or at ambient conditions (15° C. and 1 atm pressure). Hydrocarbon fluids may include, for example, oil, natural gas, coalbed methane, shale oil, pyrolysis oil, pyrolysis gas, a pyrolysis product of coal, and other hydrocarbons that are in a gaseous or liquid state.

As used herein, the terms “produced fluids” and “production fluids” refer to liquids and/or gases removed from a subsurface formation, including, for example, an organic-rich rock formation. Produced fluids may include both hydrocarbon fluids and non-hydrocarbon fluids. Production fluids may include, but are not limited to, oil, natural gas, pyrolyzed shale oil, synthesis gas, a pyrolysis product of coal, carbon dioxide, hydrogen sulfide and water (including steam).

As used herein, the term “fluid” refers to gases, liquids, and combinations of gases and liquids, as well as to combinations of gases and solids, combinations of liquids and solids, and combinations of gases, liquids, and solids.

As used herein, the term “gas” refers to a fluid that is in its vapor phase at 1 atm and 15° C.

As used herein, the term “oil” refers to a hydrocarbon fluid containing primarily a mixture of condensable hydrocarbons.

As used herein, the term “subsurface” refers to geologic strata occurring below the earth's surface.

As used herein, the term “formation” refers to any definable subsurface region regardless of size. The formation may contain one or more hydrocarbon-containing layers, one or more non-hydrocarbon containing layers, an overburden, and/or an underburden of any geologic formation. A formation can refer to a single set of related geologic strata of a specific rock type, or to a set of geologic strata of different rock types that contribute to or are encountered in, for example, without limitation, (i) the creation, generation and/or entrapment of hydrocarbons or minerals, and (ii) the execution of processes used to extract hydrocarbons or minerals from the subsurface.

The terms “zone” or “zone of interest” refers to a portion of a formation containing hydrocarbons. Alternatively, the formation may be a water-bearing interval.

For purposes of the present patent, the term “production casing” includes a liner string or any other tubular body fixed in a wellbore along a zone of interest.

As used herein, the term “drilling returns” means a slurry containing a liquid and a solid, wherein the slurry includes drill cuttings from a subsurface formation.

As used herein, the term “wellbore” refers to a hole in the subsurface made by drilling or insertion of a conduit into the subsurface. A wellbore may have a substantially circular cross section, or other cross-sectional shapes. As used herein, the term “well,” when referring to an opening in the formation, may be used interchangeably with the term “wellbore.”

DESCRIPTION OF SELECTED SPECIFIC EMBODIMENTS

The inventions are described herein in connection with certain specific embodiments. However, to the extent that the following detailed description is specific to a particular embodiment or a particular use, such is intended to be illustrative only and is not to be construed as limiting the scope of the inventions.

FIG. 1 presents a side view of a well site 100 wherein a well is being completed. The well is a disposal well for the injection of drill cuttings.

The well site 100 generally includes a wellbore 150 and a wellhead 170. The wellbore 150 includes a bore 115 for receiving drilling equipment and fluids. The bore 115 extends from the surface 105 of the earth, and into the earth's subsurface 110. The wellbore 150 is being completed in a subsurface formation, indicated by bracket 160.

The wellbore 150 is first formed with a string of surface casing 120. The surface casing 120 has an upper end 122 in sealed connection with a lower master fracture valve 125. The surface casing 120 also has a lower end 124. The surface casing 120 is secured in the wellbore 150 with a surrounding cement sheath 112.

The wellbore 150 also includes a lower string of casing 130. The lower string of casing 130 is also secured in the wellbore 150 with a surrounding cement sheath 114. The lower string of casing 130 has an upper end 132 in sealed connection with an upper master fracture valve 135. The lower string of casing 130 also has a lower end 134.

In the well site 100 of FIG. 1, the lower string of casing 130 does not extend to a bottom 136 of the wellbore 150. Instead, a lower portion of the wellbore 150 is left uncased. In this way, the wellbore 150 is completed as an open-hole, particularly along the subsurface formation 160. However, it is understood that the wellbore 150 could be completed as a cased hole. In this instance, the lower string of casing 130 would be a string of “production casing” that extends to the bottom 136 of the wellbore 150. In that instance, the casing would be perforated to allow for fluid communication between the bore 115 of the wellbore 150 and the subsurface formation 160.

It is understood that the depth of the wellbore 150 may extend many thousands of feet below the earth surface 105. In this way, the subsurface formation 160 may be fractured without concern over creating fluid communication with any near-surface aquifers.

As noted, the well site 100 also includes a wellhead 170. The wellhead 170 is used during the completion phase of the wellbore 150. The wellhead 170 includes one or more blow-out preventers. The blow-out preventers are typically remotely actuated in the event of operational upsets. In more shallow wells, or in wells having lower formation pressures, the master fracture valves 125, 135 may be the blow-out preventers. In either event, the master fracture valves 125, 135 are used to selectively seal the bore 115.

The wellhead 170 and its components are used for flow control and hydraulic isolation during rig-up operations, during fracturing and fluid injecting operations, and during rig-down operations. The wellhead 170 may include a crown valve 172. The crown valve 172 is used to isolate the wellbore 150 in the event a lubricator (not shown) or other components are placed above the wellhead 170. The wellhead 170 further includes side outlet injection valves 174. The side outlet injection valves 174 are located within fluid injection lines 171. The fluid injection lines 171 provide a means for the injection of fracturing fluids, weighting fluids, and/or drill cuttings slurry into the bore 115, with the injection of the fluids being controlled by the valves 174.

The piping from surface pumps (not shown) and tanks (not shown) used for injection of fluids are in fluid communication with the valves 174. Appropriate hoses, fittings and/or couplings (not shown) are employed. The fluids are then pumped into the lower string of casing 130 and the open-hole portion of the wellbore 150, adjacent subsurface formation 160.

It is understood that the various wellhead components shown in FIG. 1 are merely illustrative. A typical completion operation will include numerous valves, pipes, tanks, fittings, couplings, gauges, and other fluid control devices. These may include a pressure-equalization line and a pressure-equalization valve (not shown) for positioning a tool string above the lower valve 125 before a tool string is dropped into the bore 115. Downhole equipment may be run into and out of the wellbore 150 using an electric line, slick line or coiled tubing. Further, a drilling rig or other platform may be employed, with jointed working tubes or coiled tubing being used as needed.

The wellbore 150 has been formed through the use of a drill string and connected drill bit (not shown). Further, the drilling process involved the use of a drilling fluid, or mud.

There are three main categories of drilling fluids: water-based muds, non-aqueous muds, and gaseous drilling fluids. Non-aqueous muds, sometimes referred to as non-aqueous fluids (NAFs), are muds where the base fluid is an oil. Environmental considerations aside, NAFs are often preferred over water-based muds and gaseous drilling fluids, as NAFs generally offer increased lubrication of the drill string and drill bit. This is particularly advantageous in deviated and horizontal drilling operations where the drill string is forced to slide within and rotate upon the wellbore wall. In this situation, the non-aqueous-based fluid provides a slick film along which tubular bodies and equipment may glide while moving across non-vertical portions of the wellbore.

NAFs also help stabilize shale formations more effectively than do water-based or gaseous muds. NAFs also withstand greater heat without breaking down, and beneficially tend to form a thinner filter cake than water-based muds.

The filter cake from a NAF is comprised primarily of water droplets, weighting agent particles, and drilled cuttings previously suspended in the drilling mud. The filter cake forms a thin, low-permeability layer along permeable portions of the borehole. Beneficially, the filter cake at least partially seals permeable formations exposed by the bit. This helps prevent the loss of the liquid portion (or filtrate) of the drilling fluids into the formations during the wellbore forming process. The filter cake also helps prevent the surrounding rock matrix from sloughing into the wellbore. Of note, the drilling process can be ongoing for days or even weeks.

A low-permeability filter cake is also desirable for running completion equipment in the wellbore. For example, it is sometimes desirable to run the completion hardware in a clear brine to prevent solids plugging of a sand control screen. The filter cake prevents the completion brine from rapidly leaking off to the formation as the completion hardware is run. In addition, a low-permeability filter cake helps prevent the gravel used in a gravel pack from bridging off during gravel placement due to a loss of hydration in the slurry.

In the well site 100 of FIG. 1, a filter cake is shown at 162. The filter cake lines a wall 164 of the open hole portion of the wellbore 150 adjacent subsurface formation 160. The filter cake comprises a NAF fluid.

There are two general categories of NAF fluids: oil-based muds (OBMs) and synthetic-based muds (SBMs). A common example of a base fluid for an OBM is diesel oil. SBMs use a synthetic oil rather than a natural hydrocarbon as the base fluid. An example of a base fluid for a SBM is palm oil. SBMs are most often used on offshore rigs as SBMs have the beneficial properties of an OBM, but lower toxicity. This is of benefit when the drilling crew is working in an enclosed area, as may be the case on an offshore drilling rig operating in an arctic environment.

The drilling fluid used for a particular job is generally selected to avoid formation damage. For example, in various types of shale formations, the use of conventional water-based muds can result in a deterioration and collapse of the formation. Similarly, muds made from fresh water can cause clays in a sandstone or other type formation to swell and dislodge. This, in turn, can negatively affect the permeability of the sandstone near the wellbore. The use of an oil-based formulation circumvents these problems.

As noted, a conventional oil-based drilling mud formulation is comprised basically of oil. Examples of oil include diesel oil and mineral oil. An OBM may also include a thickener, or “viscosification agent.” Examples of viscosification agents are amine-treated clays such as bentonite. Neutralized sulfonated ionomers have also been proposed as viscosification agents. An OBM may also include a wetting agent.

A NAF will also include a water phase. This typically represents sodium chloride or calcium chloride brine. The NAF will also then include a surfactant as an emulsifying agent. An example of a surfactant is an alkaline soap of fatty acids. The surfactant aids in blending the base oil with the brine and stabilizing the continuous oil emulsion. Finally, a weighting agent may be used. An example of a weighting agent is barite or barium sulfate.

An entire science has developed around producing beneficial filter cake properties. Filter cake properties include cake thickness, toughness, slickness, and permeability. Such properties are important as the cake that forms on permeable regions of a wellbore can be beneficial to an operation, or may be detrimental to an operation. For example, the problems that a filter cake may present include reduced permeability during production and/or injection operations. This includes reduced permeability during a drill cuttings re-injection operation.

Many publications and inventions have been directed to the creation and destruction of filter cakes. Exemplary teachings known in the art include the use of chelating agents to extract metallic weighting agents from filter cakes, the use of acidic treatment fluids to dissolve the filter cake elements, and/or the use of surfactants to clean the filter cake from the surface of a wellbore. Exemplary publications of such teachings may be found in U.S. Pat. Publ. No. 2008/0110621, which is incorporated herein in its entirety by reference. Other exemplary related publications may be found in U.S. Pat. No. 5,909,774; U.S. Pat. No. 6,631,764; U.S. Pat. No. 7,134,496; U.S. Pat. Publ. No. 2007/0029085, U.S. Pat. Publ. No. 2008/0110618; and in Lirio Quintero, et al, Single-phase Microemulsion Technology for Cleaning Oil or Synthetic-Based Mud, 2007 AADE National Technical Conference (Apr. 10-12, 2007).

As noted above, filter cakes formed from non-aqueous muds tend to have a lower permeability. This is beneficial while the wellbore is being formed; however, filter cakes formed from an oil-based or synthetic oil-based drilling mud are more difficult to remediate. While the decreased permeability of NAF filter cakes may suggest using aqueous drilling fluids to avoid the NAF filter cake, some implementations require NAF drilling fluids. This, in turn, may complicate the remediation of the filter cake, often necessitating complex treatment fluids. While known solutions provide some level of remediation, the conventional approaches are costly and complex. Accordingly, a need exists for an improved method for remediating NAF filter cake, particularly for the purpose of improving drill cuttings re-injection operations.

Returning to FIG. 1, fractures 165 are shown extending away from the wall 164 of the wellbore 150. The fractures 165 have been formed by injecting drill cuttings as part of a slurry. The fractures extend through the filter cake 162.

It is proposed herein to remediate the NAF filter cake 162 prior to or during the injection of drill cuttings. The operations fluid includes a base aqueous fluid having at least one surfactant. The base aqueous fluid is referred to herein as an operations fluid. The surfactant is preferably an alkyl acid surfactant, an organo-anionic surfactant, or mixtures thereof.

It is recognized here that surfactants, in the generalized sense of the term, have been used in hydrocarbon recovery operations for a variety of purposes. Indeed, drilling fluids themselves oftentimes have a surfactant component. Surfactants have also been used for cleaning filter cake and drilling fluids off of downhole equipment. However, a review of the conventional compositions and methods reveals that for drilling fluid remediation methods, the cleaning fluid has employed either a strong acid or a strong base.

The use of a strong acid provides the foundation for acid-based remediation efforts. Strong acids include sulfuric acids and hydrochloric acids. The use of strong bases, such as in the form of cationic surfactants, zwitterionic surfactants, and/or alkali-metal-based surfactants, form the foundation for conventional surfactant-based remediation efforts.

Conventional surfactants typically are formed from a strong base and a weak acid (i.e., a strong/weak surfactant). When using such a surfactant, a remediation fluid will typically require a co-solvent, such as an alcohol, to improve the solubility of the strong/weak surfactant. This is particularly true in high-salinity slurries or muds. However, the use of a co-solvent increases the cost of the slurry, increases the complexity of the fluid make-up, and requires additional clean-up efforts.

It is also noted that many of the conventional, strong/weak anionic surfactants require the use of a co-surfactant. Examples of a co-surfactant are a non-ionic surfactant or a cationic surfactant. Adding a co-surfactant forms a micro-emulsion or nano-emulsion. Here again, the use of a co-surfactant increases costs, complexity, and clean-up requirements.

The conventional wisdom of surfactant-based remediation compositions and methods is analogous to cleaning methods in other fields, where it is generally accepted that a strong base cleans better than a weak base, and that a surfactant incorporating a strong base will be most effective at cleaning. In contrast, organo-anionic surfactants are formed by a weak base and a weak acid, forming what can be referred to as a weak/weak surfactant or, in the terms of the present disclosure, an organo-anionic surfactant. The use of a weak base as the building block for a filter cake remediation fluid is counter-intuitive based upon the prior literature and conventional technology, but has been found to be effective as a remediation fluid, as will be seen herein.

Weak acids and bases generally fall within the intermediate pH range. The pH of a solution depends on both the concentration and the degree of ionization. Weak acids and weak bases are only partially ionized in their solutions.

In one embodiment, the surfactant is an alkyl acid surfactant having the general formula:

{S—Z}

wherein:

• • S is selected from the group comprising linear and branched alkyl and aryl alkyl hydrocarbon chains of 8 to 24 carbons, and
  • Z is an acid group selected from the group comprising sulfonic acids, carboxylic acids, phosphoric acids, and mixtures thereof.

Preferably, S is an aryl alkyl hydrocarbon chain. Preferably, the aryl group of the aryl alkyl hydrocarbon is a 1-ring or 2-ring aromatic group. More preferably, the aryl group is a 1-ring aromatic group. Non-limiting examples of 1-ring aromatic groups are benzene and xylene. Non-limiting examples of an alkyl aromatic hydrocarbon chain is dodecyl benzene, decyl xylene and decyl benzene.

Preferably, Z is a sulfonic acid group. However, the acid may be an organic acid, such as alkyl acids, alkyl aromatic acids, or mixtures thereof. Further, exemplary organic acids may include alkyl carboxylic acids, aromatic carboxylic acids, alkyl sulfonic acids, aromatic sulfonic acids, alkyl phosphoric acids, aromatic phosphoric acids, or mixtures thereof, forming a weak acid.

In another embodiment, the surfactant is an organo-anionic surfactant having the general formula:

{R—X}⁻⁺{Y}

wherein:

• • R is selected from the group comprising linear and branched alkyl and aryl alkyl hydrocarbon chains,
  • X is an acid selected from the group comprising sulfonic acids, carboxylic acids, phosphoric acids, and mixtures thereof, and
  • Y is an organic amine selected from the group comprising monoethanol amine, di-ethanol amine, tri-ethanol amine, ethylene di-amine, propylene diamine, di-ethylene tri-amine, tri-ethylene tetra-amine, tetra ethylene pent-amine, di-propylene tri-amine, tri-propylene tetra-amine, tetra-propylene pentamine, and mixtures thereof.

While a variety of weak organic bases may be used in the present compositions and methods, organic amines are preferred. Preferably, the organic amine is monoethanol amine, diethanol amine, triethanol amine, or mixtures thereof.

Based on the representative acids and bases described herein, the number of available organo-anionic surfactants is potentially very large. While a variety of organo-anionic surfactants are within the scope of the present disclosure, they all have one feature in common: the organo-anionic surfactants of the present disclosure comprise an anionic acid whose counter ion is a mono-, di-, or tri-ethanol ammonium cation.

Organo-anionic surfactants may be prepared by contacting a weak acid, such as an organic acid or other acid described above, with a weak base, such as an organic amine or other base described above. Contacting can be done at any temperature, but preferably in the range of −50° C. to 200° C. The preferred temperature range for the acid-base reaction will depend on the choice of weak acid and weak base.

The amount of base that is used in the reaction may be equal to the molar equivalent of the weak or organic acid. As an illustration, if the weak acid is an organic acid of molecular weight 200, and the weak base is of molecular weight 100, then in the case of molar equivalent, the weight ratio of base:acid is 2:1.

In some implementations, the organo-anionic surfactant may be formed by contacting a neat base with a neat acid. The resulting organo-anionic surfactant may then be incorporated into an aqueous fluid. Additionally or alternatively, in some implementations, each of the weak base and the weak base may be dissolved in separate aqueous solutions that are then mixed to contact the base and the acid to form the organo-anionic surfactant in an aqueous solution.

The operations fluid can also contain mixtures of alkyl acid surfactant and organo-anionic surfactant. Preferably, the operations fluid contains a mixture of alkyl acid surfactants and organo-anionic surfactants. When mixtures are used, the ratio of alkyl acid surfactant to organo-anionic surfactant in the mixture can vary from 99:1 to 1:99. The surfactant components are preferably dissolved or dispersed in water. The operations fluid then comprises mixtures of organo-anionic surfactants, alkyl acid surfactants, and water.

The total surfactant concentration may be greater than about 0.01 wt % and less than about 20 wt %, based on the weight of water. Preferably, the total concentration of surfactant may be greater than about 0.01 wt % and less than about 10 wt %, and more preferably the total surfactant concentration may be greater than about 0.01 wt % and less than about 2 wt %.

The operations fluid including the organo-anionic surfactants and alkyl acid surfactants may further comprise dissolved salts, such as chloride and sulfate salts of calcium and potassium. The amount of dissolved salts, when included, may be greater than about 0.01 wt % and less than about 25 wt %, based on the weight of water. Preferably, greater than about 0.01 wt % and less than about 5 wt %. The operations fluid may further comprise alcohols such as methanol, ethanol, propanol, butanol, pentanol, hexanol, heptanol, octanol and mixtures thereof. The alcohols, when included, may be greater than about 0.001 wt % and less than about 15 wt %, based on the weight of water.

As noted, it is proposed herein to inject drill cuttings as part of a slurry, wherein the slurry includes an aqueous fluid having at least one surfactant. The base aqueous fluid is referred to as an operations fluid. One exemplary method of utilizing the operations fluid is in a method of remediating a NAF filter cake in a well prior to drill cuttings re-injection. An illustrative implementation includes:

• • obtaining an operations fluid comprising at least one surfactant in water;
  • pumping a volume of the operations fluid into a well including a NAF filter cake, wherein the volume of operations fluid is pumped to contact the NAF filter cake; and
  • thereafter, pumping a volume of drill cuttings slurry.
    The slurry may include the operations fluid.

The effectiveness of the drill cuttings injection operation depends on the ability of the injected drill cuttings slurry to filter through the formation face. The formation face may be plugged by NAF filter cakes. If the operations fluid can remediate the NAF filter cake, then the permeability of the near-wellbore formation is increased. This, in turn, allows for rapid filtration of the drill cuttings slurry into a disposal formation. More specifically, a drill cuttings slurry may be injected through the bore 115 of the well site 100, and into the fractures 165 in the subsurface formation 160.

The following non-limiting example is an illustration of the effectiveness of a surfactant-based operational fluid to remediate a NAF filter cake.

First, a simulated drill cuttings base slurry was prepared. The composition of the slurry is shown in Table 1, below.

	TABLE 1
	Component	Quantity
	SBM-based fluid	52.5	ml
	Simulated seawater	406	ml
	Simulated drill solids (Rev-Dust)	178	g

The SBM-based fluid may be, for example, XP-2. This is a Baroid Halliburton® product, that is generally a n-paraffin based fluid.

The slurry had a density (specific gravity) of 1.2 SG. An oil/water/solids ratio of 10/75/15 (by volume) was provided.

Rheological properties were obtained for the base slurry using a 6-speed, coaxial direct-indicating oilfield viscometer. The viscometer used was a FANN 35 product. After obtaining rheological properties of the base slurry at room temperature (25° C., 75° F.), a xanthan gum-based biopolymer was added. An example of a xanthan gum-based biopolymer is Greenbase™ Flowzan® Biopolymer. The gum-based biopolymer was added to obtain a viscosified simulated drill cuttings slurry.

Table 2 provides the viscosity data for the simulated drill cuttings slurry.

TABLE 2
Fann 35 Dial		Slurry + 2 lb/bbl GB
Reading,		Flowzan (0.8 lb/bbl
25° C., 75° F.	Base Slurry	active)
600	19	112
300	14	79
200	12	66
100	9	49
6	8	28
3	7	27
Gels	10/16/21	26/44/52
PV/YP	5/9	33/46

The viscosified simulated drill cuttings slurry was filtered through a high temperature high pressure cell at ambient temperature and 100 psi differential pressure. 8.6 ml of fluid filtered through after 30 minutes. The resulting filter cake was thin but very sticky and exhibited high shear stress. This was due to the high concentration of simulated drill solids which made up the injection slurry.

Next, a 1 wt % solution of a surfactant was made in water. The surfactant was an alkyl acid surfactant having the general formula:

{S—Z}

wherein:

• • S is dodecyl benzene, and
  • Z is sulfonic acid.

This is one example of an operational fluid of the instant invention. The S may actually be any compound selected from the group comprising linear and branched alkyl and aryl alkyl hydrocarbon chains of 8 to 24 carbons. The Z may be any acid selected from the group comprising sulfonic acids, carboxylic acids, phosphoric acids, or mixtures thereof.

To 1 gram of the filter cake was added 10 ml of the operational fluid. The new solution was mixed for 20 seconds using a magnetic stir bar. The filter cake was observed to immediately break up. The break-up of the filter cake upon addition of the operations fluid is evidence of NAF filter cake remediation of a drill cuttings slurry.

FIG. 2 is a flow chart showing steps for a method 200 of re-injecting drill cuttings, in one embodiment. The drill cuttings are injected into a subsurface formation. An operations fluid having at least one surfactant is used.

The method 200 first includes obtaining a volume of solid particles from drilling returns. This is shown in Box 210. The term “volume” is used merely to conveniently reflect broadly that a quantity of cuttings has been obtained, regardless of whether such quantity was obtained based upon mass, volume, randomly, selectively, by type or whatever means is used to collect or obtain such quantity. The method 200 then includes obtaining an aqueous operations fluid comprising at least one surfactant. This is seen in Box 220. The operations fluid preferably comprises surfactant present in solution at a concentration greater than about 0.01 wt % and less than about 20.0 wt % based on water in the operations fluid.

In the method 200, the surfactant is made up of a weak base and a weak acid. In one aspect, the surfactant is an alkyl acid surfactant, an organo-anionic surfactant, or mixtures thereof. Where the surfactant is or includes an organo-anionic surfactant, the organo-anionic surfactant is preferably selected from the group comprising monoethanol ammonium alkyl aromatic sulfonic acid, monoethanol ammonium alkyl carboxylic acid, and mixtures thereof.

The method 200 also includes mixing a volume of the operations fluid with the volume of solid particles. This is provided at Box 230. In this way, a slurry is formed. The method 200 then includes pumping the slurry into a disposal well. The disposal well includes a NAF filter cake. This is shown at Box 240.

The method 200 further includes injecting the slurry into one or more fractures formed in the subsurface formation. This is seen in Box 250. Injection is conducted in such a manner that the slurry contacts the NAF filter cake en route to the one or more fractures. Because of the preferred weak base—weak acid formulation of the slurry, the NAF filter cake is degraded, thereby facilitating the injection of the slurry into fractures along the wellbore.

As an additional step, the operator may choose to pump a volume of the aqueous operations fluid into the disposal well without the slurry. This is indicated at Box 260. The pumping step of Box 260 is preferably performed prior to the pumping step of Box 240.

FIG. 3 is a flow chart showing steps for a method 300 of re-injecting drill cuttings, in an alternate embodiment. The drill cuttings are again injected into a subsurface formation. An operations fluid having at least one surfactant is used.

The method 300 first includes obtaining a volume of solid particles from drilling returns. This is shown in Box 310. The method 300 then includes obtaining an aqueous operations fluid comprising at least one surfactant. This is seen in Box 320. The operations fluid of the method 300 is in accordance with the operations fluid of the method 200, in its various embodiments. In this respect, the surfactant is preferably made up of a weak base and a weak acid. In one aspect, the surfactant is an alkyl acid surfactant, an organo-anionic surfactant, or mixtures thereof. Where the surfactant is or includes an organo-anionic surfactant, the organo-ionic surfactant is preferably selected from the group comprising monoethanol ammonium alkyl aromatic sulfonic acid, monoethanol ammonium alkyl carboxylic acid, and mixtures thereof.

The operations fluid preferably comprises surfactant present in solution at a concentration greater than about 0.01 wt % and less than about 20.0 wt % based on water in the operations fluid.

The method 300 also includes pumping a volume of the operations fluid into a disposal well. This is provided at Box 330. The disposal well includes a NAF filter cake along the borehole. The purpose of pumping the operations fluid into the wellbore is to remediate the NAF filter cake along an open-hole portion, thereby making the filter cake more permeable.

The operations fluid may be adapted to remediate the filter cake by performing at least one of: 1) altering the wettability of the NAF filter cake from oil wetting to water wetting; and 2) extracting non-aqueous fluid associated with the NAF filter cake. This occurs due to the surfactant having an oil-extracting capability.

The method 300 further includes preparing a slurry of aqueous fluid with the volume of solid particles. This is shown at Box 340. The aqueous fluid may be the same as the operations fluid. The method 300 then includes injecting the slurry into one or more fractures formed in the subsurface formation. This is seen in Box 350. Injection is conducted at a pressure that is above the formation parting pressure.

In one aspect, the slurry is injected intermittently in batches into the disposal formation. This batch process involves injecting approximately the same volumes of slurry and then waiting for a period of time after each injection. Each batch injection may last from a few hours to a few days, with shut-in times provided in between. The batch injections may take place at low pump rates, such as about 2.0 to 8.0 bpm.

After the batch re-injection cycles are concluded, the disposal well may be further drilled, and then completed as a producer or a water injector.

It can be understood that the present disclosure provides compositions comprising alkyl acid surfactants or organo-anionic surfactants for use in drill cuttings re-injection operations. The compositions are useful when the well bore includes a NAF filter cake. More particularly the compositions are useful when drill cuttings are to be re-injected into the well bore containing NAF filter cakes.

While it will be apparent that the inventions herein described are well calculated to achieve the benefits and advantages set forth above, it will be appreciated that the inventions are susceptible to modification, variation and change without departing from the spirit thereof.

Claims

1. A method for re-injecting drill cuttings into a subsurface formation, comprising:

obtaining a volume of solid particles from drilling returns;

obtaining an aqueous operations fluid comprising at least one surfactant;

mixing a volume of the operations fluid with the volume of solid particles, thereby forming a slurry;

pumping the slurry into a disposal well, wherein the disposal well includes a NAF filter cake;

injecting the slurry into one or more fractures formed in the subsurface formation such that the slurry contacts the NAF filter cake en route to the one or more fractures.

2. The method of claim 1, wherein the surfactant is an alkyl acid surfactant, an organo-anionic surfactant, or mixtures thereof.

3. The method of claim 2, wherein the organo-anionic surfactant has the general formula:

{R—X}−+{Y}

wherein: R is selected from the group comprising linear and branched alkyl and aryl alkyl hydrocarbon chains, X is an acid, and Y is an organic amine.

4. The method of claim 3, wherein X is selected from the group comprising sulfonic acids, carboxylic acids, phosphoric acids, and mixtures thereof.

5. The method of claim 3, wherein Y is selected from the group comprising monoethanol amine, di-ethanol amine, tri-ethanol amine, ethylene di-amine, propylene diamine, di-ethylene tri-amine, tri-ethylene tetra-amine, tetra ethylene pent-amine, di-propylene tri-amine, tri-propylene tetra-amine, tetra-propylene pentamine, and mixtures thereof.

6. The method of claim 3, wherein the organo-anionic surfactant is selected from the group comprising monoethanol ammonium alkyl aromatic sulfonic acid, monoethanol ammonium alkyl carboxylic acid, and mixtures thereof.

7. The method of claim 2, wherein the alkyl acid surfactant has the general formula:

{S—Z}

wherein: S is selected from the group comprising linear and branched alkyl and aryl alkyl hydrocarbon chains of 8 to 24 carbons, and Z is an acid group selected from the group comprising sulfonic acids, carboxylic acids, phosphoric acids, and mixtures thereof.

8. The method of claim 1, wherein the operations fluid comprises surfactant present in solution at a concentration greater than about 0.01 wt % and less than about 20.0 wt % based on water in the operations fluid.

9. The method of claim 1, wherein:

the operation fluid further comprises dissolved salts; and

the concentration of dissolved salts is greater than about 0.1 wt % and less than about 25.0 wt % based on the weight of water in the aqueous fluid.

10. The method of claim 9, wherein the dissolved salts comprise (i) chloride salt of calcium, (ii) chloride salt of potassium, (iii) sulfate salt of calcium, (iv) sulfate salt of potassium, and (v) combinations thereof.

11. The method of claim 1, wherein:

the operation fluid further comprises an alcohol; and

the concentration of alcohol is greater than about 0.001 wt % and less than about 15.0 wt % based on the weight of water in the aqueous fluid.

12. The method of claim 11, wherein the alcohol comprise methanol, ethanol, propanol, butanol, pentanol, hexanol, heptanol, octanol, and combinations thereof.

13. The method of claim 1, further comprising:

pumping a volume of the aqueous operations fluid into the disposal well without the slurry prior to pumping the slurry into the disposal well.

14. The method of claim 1, wherein the surfactant is comprised substantially of a weak acid and a weak base.

15. A method for re-injecting drill cuttings into a subsurface formation, comprising:

obtaining a volume of solid particles from drilling returns;

obtaining an aqueous operations fluid comprising at least one surfactant;

pumping a volume of the aqueous operations fluid into a disposal well in order to remediate a NAF filter cake residing alone a borehole of the disposal well;

preparing a slurry of aqueous fluid with the volume of solid particles;

pumping the slurry into the disposal well, wherein the disposal well includes a NAF filter cake;

injecting the slurry into one or more fractures formed in the subsurface formation.

16. The method of claim 16, wherein the surfactant is an alkyl acid surfactant, an organo-anionic surfactant, or mixtures thereof.

17. The method of claim 16, wherein preparing a slurry of aqueous fluid with the volume of solid particles comprises mixing a portion of the operations fluid with the volume of solid particles.

18. The method of claim 16, wherein the organo-anionic surfactant has the general formula:

{R—X}−+{Y}

wherein: R is selected from the group comprising linear and branched alkyl and aryl alkyl hydrocarbon chains, X is an acid, and Y is an organic amine.

19. The method of claim 18, wherein X is selected from the group comprising sulfonic acids, carboxylic acids, phosphoric acids, and mixtures thereof.

20. The method of claim 18, wherein Y is selected from the group comprising monoethanol amine, di-ethanol amine, tri-ethanol amine, ethylene di-amine, propylene diamine, di-ethylene tri-amine, tri-ethylene tetra-amine, tetra ethylene pent-amine, di-propylene tri-amine, tri-propylene tetra-amine, tetra-propylene pentamine, and mixtures thereof.

21. The method of claim 18, wherein the organo-anionic surfactant is selected from the group comprising monoethanol ammonium alkyl aromatic sulfonic acid, monoethanol ammonium alkyl carboxylic acid, and mixtures thereof.

22. The method of claim 16, wherein the alkyl acid surfactant has the general formula:

{S—Z}

wherein: S is selected from the group comprising linear and branched alkyl and aryl alkyl hydrocarbon chains of 8 to 24 carbons, and Z is an acid group selected from the group comprising sulfonic acids, carboxylic acids, phosphoric acids, and mixtures thereof.

23. The method of claim 15, wherein the operations fluid comprises surfactant present in solution at a concentration greater than about 0.01 wt % and less than about 20.0 wt % based on water in the operations fluid.

24. The method of claim 15, wherein the surfactant is comprised substantially of a weak acid and a weak base.