Drill Cuttings Re-Injection
Methods and compositions for re-injecting formation solids such as drillbit cuttings into a subsurface formation including: obtaining a volume of solid particles comprising a non-aqueous fluid; obtaining a slurry-forming fluid, the slurry-forming fluid comprising water, salt, a viscosifying water soluble polymer, and an oily solids aggregator; mixing the obtained solid particles and the slurry-forming fluid to create an injectable slurry; and introducing the injectable slurry into a wellbore for injection into a subsurface formation.
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 INVENTIONThis invention relates generally to the field of wellbore operations. More specifically, in some applications the invention relates to the re-injection of drill cuttings and solids generated during the formation of a wellbore.
GENERAL DISCUSSION OF TECHNOLOGYDuring drilling of a wellbore such as for use in hydrocarbon production operations, a wellbore is formed using a drill string and drill bit while a drilling fluid (generally referred to as drilling “mud”) is circulated through the drill string and bit and then up the backside annulus out of the wellbore, to remove the cuttings. These cuttings typically represent bits of formation rock being drilled, such as clay, shale, quartz, carbonate, etc. Typically, the mud and cuttings are circulated back to the surface where the cuttings are separated from the mud using solids control equipment. The solids control equipment typically includes screens, so-called “shakers,” and gravity separation that filters out the majority of solids while recovering a substantial portion of the drilling mud for reuse. The majority of the recovered cuttings are stored and/or readied for disposal, such as by removal to a remote surface location or injection down a disposal well.
Cuttings re-injection operations (“CRI”) generally started in the late 1980's. CRI may offer an environmentally friendly and economically attractive solution for disposal of cuttings from a drilling operation, particularly cuttings where the base fluid is or comprises an a non-aqueous fluid (NAF) such as an oil or hydrocarbon component. CRI may eliminate surface discharge and provide for the efficient recovery of a portion of the disposal fluid for reuse in other CRI disposal operations. When operations are complete, the disposal well is securely plugged and abandoned.
Environmental regulations in some areas may prevent the immediate surface (or near-surface) disposal or injection of drill cuttings when such cuttings contain residual non-aqueous fluids or NAF's, such as hydrocarbon-based or synthetic-based drilling mud. Disposal procedures may require “cleaning” and otherwise preparing NAF cuttings prior to disposal. A typical drill-cuttings CRI operation may involve processing the solids in a slurrification unit, where the cuttings may be ground into smaller particles in the presence of water to form an aqueous-based slurry. A residual portion of the drilling mud (aqueous or NAF) may also still remain in the aqueous slurry. The slurry may be subjected to still further rheological conditioning. The suitably conditioned drill cuttings slurry may then be injected into a subsurface formation using a wellbore for accessing the formation. The injected slurry is introduced into the formation and into subsurface fractures created by injecting the slurry under relatively high pressure in a disposal formation.
Various technical challenges exist with respect to CRI, such as fluid rheology, avoiding formation plugging and fracture growth. Slurry rheology design includes properties, such as slurry viscosity, suspension capacity, get strength, and particle size limitations. The slurry must have adequate viscosity and solids-carrying capacity to transport the particles into the formation. The particles must be able to enter and move within the fractures to avoid plugging. The oily solids of the NAF can not only adversely change the designed slurry rheology but also directly contribute to plugging of formation pores and result in slowing the desired leak-off of the slurry water. Lack of fluid leak-off may produce excessive fracture growth and/or plugging, leading to increased injection pressures.
When injecting disposal slurries, the created fracture volume must be sufficient to accommodate the injected material. Ideally, the fluid portion of the injected material is permitted to leak off into the formation pores as the slurry is injected such that the created fracture need primarily accommodate the solids portion of the injected material. However, formation and fracture face plugging may prevent fluid leak-off into the formation, thereby requiring the fracture volume to accommodate both the injected solids and a substantial portion of the fluid phase. Such fracture face and formation pore plugging can lead to increased injection pressures, premature fracture filling, and/or potential loss of injection conformance. Need exists for an improved slurry performance for re-injection of drill cuttings, especially regarding NAF drill cuttings, into a disposal formation.
SUMMARY OF THE INVENTIONMethods, compositions, and systems for re-injecting drill cuttings into a subsurface formation are provided. The methods described herein have various benefits related to the conducting of oil and gas exploration and production activities, especially regarding wellbore drilling, and more particularly with regard to disposal of NAF cuttings produced during. The present disclosure includes methods, systems, and apparatus that overcome many of the formation plugging problems related to reinjection of NAF cuttings.
A method is disclosed that includes obtaining a volume of solid particles from NAF drilling returns and introducing the same into a slurry-forming fluid to create injectable slurry. The solid particles primarily represent formation cuttings recovered from a drilling operation, but may also represent various other recovered solids that had been previously added to the NAF drilling fluid, such as lost circulation materials, weighting agents, and formation debris. The solid particles are typically coated with and/or dispersed within some NAF drilling fluid.
A method is disclosed for injecting the solid particles recovered from a NAF drilling cuttings returns fluid stream into a subsurface formation. The method may include obtaining and associated NAF; obtaining a slurry-forming fluid, the slurry-forming fluid including water, a viscosifying water soluble polymer, and an oily solids aggregator; mixing the obtained solid particles and the slurry-forming fluid to create an injectable slurry; and introducing the injectable slurry into a wellbore for injection into a subsurface formation.
An injectable fluid is provided that may be suitable for use in re-injecting solid particles recovered from a NAF drilling fluid into a subsurface formation, the fluid comprising a slurry-forming fluid, the slurry-forming fluid comprising water, a viscosifying water soluble polymer, and an oily solids aggregator and NAF. The injectable fluid may also include drill cuttings, particularly NAF-containing cuttings, or other solid particulates that may be mixes with the slurry-forming fluid.
In the present methods, and compositions, the oily solids aggregator may include at least one ionic water soluble polymer and at least one viscosifying water soluble polymer. Exemplary ionic water soluble polymers may include hydrolyzed polyacrylamide (HPAM) and sulfonated polystyrene. Exemplary viscosifying water soluble polymers may include a polysaccharide, guar gum, xanthan gum, alginate, pectin, cellulosic polymer, carboxyl-methylcellulose (CMC) and xanthan gum, and another hydrocolloid.
The methods and compositions may include a surfactant that comprises 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.
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.
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, natural or synthetic 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 EMBODIMENTSThe 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 or other embodiments.
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
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 or cuttings-slurries 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
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 wherein usually the base fluid is an oil or hydrocarbon-based fluid composition. 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 these situations, 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 and salt 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.
For an injection well however, the wellbore filter cake issues may or may not be as large of a concern as with production wells, depending upon the desired injection use. Injection of fluid below the fracture pressure typically requires removal of the filter cake to establish injection fluid permeability from the wellbore face into the formation matrix, along the axial length of the wellbore injection interval. However, for an injection well operating above the formation fracture pressure, the created fracture will typically extend through the drilling filter cake and into the formation. Injection above fracture pressure is more typical of a well for disposal of drilling fluids containing solid particles. However, subsequently created filter cakes within the injection fracture face may still be a concern by adversely affecting the desired leak-off properties. This disclosure provides an improved method and system for injection of solids-containing non-aqueous fluid slurry, especially such as may be useful for reinjection of cuttings from a non-aqueous drilling operation.
In the well site 100 of
Typically, there are two general categories of NAF fluids: oil-based muds (OBMs) and synthetic-based muds (SBMs). Common examples of base fluids for an OBM are diesel, mineral oil, or sometimes produced crude may be used. SBMs may use 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 environmental toxicity or flammability. 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 hydrocarbon based 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. The presence of both aqueous and nonaqueous fluids and a surfactant creates an emulsion. The oil/water ratio in the liquid phase is commonly in the range of 60/40 to 98/2, or more commonly 70/30 to 90/10. NAF drilling fluids, whether oil based or synthetic based, are also known as invert emulsion systems, as they have an oil or synthetic base fluid as the external or continuous phase and water as the internal phase.
An entire science has developed around producing beneficial filter cake properties. Filter cake properties include cake thickness, toughness, slickness, spurt-loss rates, and permeability at various stages or time. 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 and thinner filter cake than water-based filter cakes. This reduced permeability 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 in preparation for putting a well on production or injection. Remediation of the filter cake is challenging, often necessitating complex treatment fluids and processes. While previously known solutions provided some level of remediation, the conventional approaches remain relatively costly and complex. Accordingly, a need exists for an improved method for remediating NAF filter cake or controlling undesirable buildup of an NAF filter cake during injection of a NAF, particularly for the purpose of improving drill cuttings re-injection operations.
Returning to
Methods and compositions are proposed herein for teaching preparation of injectable slurry containing the cutting solids and an NAF component within the slurry, for use such as in reinjecting drill cuttings or other solid particulates into an earthen formation. Typically, the solids or cuttings are recovered from a NAF drilling cuttings returns fluid stream, such as from a flow-line at the rig or from a cuttings processing unit that grinds and treats the cuttings in preparation for disposal.
A method, composition, and system is disclosed include obtaining or preparing a slurry-forming fluid, the slurry-forming fluid comprising water, a viscosifying water soluble polymer, and an oily solids aggregator. The solid particles may be mixed with the slurry subsequent to combining these components or in conjunction with combining the components to create an injectable slurry. The injectable slurry, including the solids intended for disposal, is introduced into a wellbore for injection into a subsurface formation. Typically introduction into the wellbore is accomplished by pumping the composition at pressure sufficient to create or exceed fracture pressure of the formation. The formation may include one or multiple fracture or fracture intervals or zones, and the fracture may include simple or complex array of fracture planes, both artificially induced and naturally existing within the formation.
According to the present methods, compositions, and systems, the oily solids aggregator comprises two water soluble polymers. One is a water soluble polymer that is useful for increasing the viscosity of the water, typically a salt-containing water, to a viscosity level sufficient for suspending and transporting the solids within the pumping system and wellbore. Gel strength is an optional consideration if desired and may be created if necessary, but most disposal fluid systems do not require significant gel strength. The viscosity required is typically no different from a viscosity range as commonly known for use in reinjecting cuttings.
Any water soluble polymer capable of increasing the viscosity of water can be used to form the viscosifying component of the injectable slurry. One exemplary polymer group is a polysaccharide polymer. A useful polysaccharide polymer is a xanthan polymer. Another useful polymer is carboxyl-methylcellulose (CMC). Other exemplary polymers may include one or more of a polysaccharide, guar gum, xanthan, alginate, pectin, cellulosic polymer, and a viscosifying hydrocolloid. The slurry composition may include the viscosifying water soluble polymer concentration typically in the range of 0.1 to 2 wt % based on the weight of the slurry composition, or in some applications an effective range may be from 0.1 to 1.0 wt %, while in other applications a useful concentration may be from 0.2 to 0.5 wt % based on the weight of the slurry composition. However, these ranges are merely exemplary and the appropriate viscosifying polymer concentration will depend upon the desired slurry viscosity for the application being considered and the type of viscosifying polymer being used. Such preparations for viscosifying water, including salt water, are generally known in the art.
The other water soluble polymer that must be present in the disclosed compositions and methods is the oily solids aggregator polymer. This polymer is a key component of the compositions and methods described herein. The oily solids aggregator polymer is typically an ionic hydrocolloid polymer that is water soluble in salt water that aggregates the solids within the NAF fluid into clumps. The aggregated NAF fluid-solid clumps are typically larger in mean diameter than the mean opening size or pore diameter size in the formation. Thereby, the clumped solid conglomerate is intercepted at the formation fracture face, wellbore borehole face, and/or perforation channel face, and cannot enter the formation pores and plug off the formation permeability and prevent the desired fluid leak-off into the formation. It is desirable to enable the liquid phase of the injected slurry to leak-off into the formation, such that the solids phase, in this case the conglomerated solids, remain within the fracture planes and not enter the formation pores. Thereby, the volumetric size of the fracture planes and widths need substantially only be large enough to accommodate the injected solids and not have to accommodate both the injected solids and liquids. Typically, the water soluble polymer is a water soluble ionic polymer, such as hydrolyzed polyacrylamide (HPAM) polymer, sulfonated polystyrene polymer, and mixtures thereof.
The oily solids aggregator aggregates the 0.2 to 50 micron size oily solid particles that present in the injectable slurry, wherein the size is with reference to a longest axis through a particulate. A more commonly encountered solid particulate size range in reinjected drill cuttings are particulates within the 0.5 to 30 micron size range of oily solids present in the NAF drilling mud. The obtained solids particulates are aggregated in clumps, conglomerates, or aggregates (collectively conglomerates) of sizes of at least 40 microns, and preferably at least 50 microns in three-dimensional mean diameter or greater. Aggregates of size 40 micron and greater are commonly large enough so as not to enter common formation pore sizes or plug off formation pore and permeability, especially aggregates of 50 micron or greater. Thereby, permeability to the cutting slurry fluid is retains such that the aggregates may build up and bridge on the formation face, while permitting the slurry fluids to pass through the solids bridge and enter the formation pores for dissipation therein. Reservoir pore plugging due to oily solids of less than 50 micron mean diameter entering the formation pores and permeability channels is largely inhibited or prevented, such that rapid “leak-off” or filtration of the slurry water occurs. This leads to effective drill cuttings reinjection disposal of mixtures of drill cuttings and NAF drilling muds.
In many applications, the injectable slurry composition comprises from 50 to 80 wt % water, or from 60 to 70 wt % water, based on the total weight of the injectable slurry composition. In many applications, the water will also comprise salt, commonly at least about 0.5 wt % (5 ppt) salt. The salt may include at least one of a dissolved chloride or bromide of at least one of sodium, potassium, calcium, and magnesium.
The slurry forming fluid comprises a mixture or composition comprising at least the water, and the two polymers (the viscosifying water soluble polymer and the ionic water soluble polymer). The injectable slurry composition comprises the slurry forming fluid and the solid particles. The injectable slurry composition includes from 15 to 50 wt % solid particles or “solids” (solid particulates, including drill cuttings and other particulates), or from 20 to 40 wt % solids, or from 20 to 30 wt % solids, based on the total weight of the slurry composition.
A substantial portion, if not all of the solids are obtained from a drilling fluid returns stream, such as at a drilling rig, wherein the drilling fluid comprises an NAF. The objective of the teaching herein pertains to managing the solid particulates in the presence of an NAF for reinjection or disposal. In many applications, the collected solid particulates have generally have not been processed to remove the NAF that coats the particles or is otherwise associated with the recovered solids, such as forming a mixture with the recovered solids. In other applications, the collected solid particulates may have been processed to remove the NAF that coats or is associated with the recovered solids. In the event where the recovered solids had been processed to remove the NAF coating and/or associated NAF fluid, then re-addition of an NAF to either the slurry forming fluid or to the injectable slurry may be necessary to enable the desirable clumping or coalescing of the smaller solid particulates into the aggregates or clumps of at least forty micron is mean diameter in order to prevent entry of the small solids into the formation pores.
Generally, the injectable slurry should comprise from 1 to 30 wt % of NAF, or from 5 to 25 wt % NAF, or from 5 to 20 wt % NAF to enable aggregation or clumping of the solid particulates by the ionic water soluble polymer. Typical concentrations of the non-aqueous fluid are about 10 wt %, but may vary more widely in some applications. The injectable slurry containing the NAF component may for ease of distinction from the comparative aqueous-only injectable slurry fluid compositions, be referred to herein as an NAF composition even though the actual NAF concentration is less than 30 wt %, or even less than 15 wt %.
Hydrolyzed polyacrylamide (HPAM), a commercially available polymer is used to demonstrate the invention as the oily solids aggregator. HPAM is an ionic water soluble polymer whose polymer conformation or shape is sensitive to salt concentration. At low salt concentration, HPAM functions as an aqueous viscosifier, particularly due to non-aligned interlocking of the substantially linear polymer chains. However, at higher salt concentrations, such as at least 0.5 wt % (brackish water), and more particularly at least concentrations of at least 3 to 5 wt % (saline water) or at least 3.5 wt % (typically salinity of seawater), or greater than 5 wt % (brine) up to 26 wt % (saturated brine), the HPAM polymer chains tend to coil up. When the ionically reactive HPAM polymer chains coil up in the presence of salt, they pull apart from each other and lose their viscosifying ability to interlock or crosslink with each other and the aqueous viscosification effect is lost. For this reason, the second water soluble viscosifying polymer is often present to provide viscosification while the ionically reactive polymer provides the desired aggregation of the solids. Thereby, the ionically reactive polymer serves as oily solids aggregator. The viscosifying polymer is preferably a polymer that is less ionically reactive than the ionically reactive, oily solids aggregator polymer.
The ionically reactive, oily solids aggregator polymer beneficially alters the interfacial properties (such as surface tension) between the solids, the water, and the NAF, resulting in clumping and aggregating of the solids into the NAF. The coiled HPAM functions well as an oily solids aggregator. This unique feature enables use of HPAM and related or other ionically reactive water soluble polymer polymers in this invention. Sulfonated polystyrene is another ionically reactive polymeric additive that can function as an oily solids aggregator. In broad terms, water soluble ionic polymers of suitable molecular weight can be used to prepare slurry compositions of the disclosed invention in the presence of salt within the water.
The oily solids aggregator concentration is a function of water salinity of the injectable slurry and functionality of the particular oil solids aggregator, which in these examples is a water soluble polymer that is ionically responsive to salt concentration and which beneficially alters the wettability or interfacial tension properties among the various liquid and solid phases. However, maximum concentrations will not exceed 5 wt %. The HPAM polymer and sulfonated polystyrene polymer are two examples of such polymers.
The oily solids aggregator of the current disclosure may be present in the injectable slurry of 0.01 to 5 wt % based on the total weight of the injectable slurry composition. In other compositions, the oily solids aggregator may be present in the range of 0.01 to 1.0 wt % or from 0.05 to 0.5 wt %, based upon the total weight of the injectable slurry.
In wellbore injectivity applications that are experiencing formation plugging or damage or a buildup of an injection filter cake, a filter cake remediation fluid may also be pumped into the wellbore. The filter cake remediation fluid may be either pumped ahead of the injectable slurry, or spotted in the wellbore prior to pumping the injectable slurry into the wellbore, or combined into the injectable fluid slurry.
The following non-limiting Examples illustrate the invention. High temperature high pressure (HTHP) filtration experiments were conducted.
In a comparative experiment, a water-based fluid slurry composition was prepared using 65 wt % sea water, 0.35 wt % viscosifying water soluble xanthan polymer, and 34.65 wt % of Rev Dust. Rev Dust is a trademarked, standard drill cuttings lab model composition medium commonly used to represent solids drill cuttings solids. Rev Dust is available from Deluxe Testing Equipment, Inc., and comprises crystalline silicas and various other solids. The slurry composition was pressurized at 500 psig and 200 degrees F. (98 degrees C.), with a filter medium comprising an aloxide disk having a permeability of 5D and pore sizes of 20 microns. The results are plotted in
In another comparative Example, the impact of oil based mud on resistance to filtration is shown in
To understand the reason for the increased resistance to filtration, slurry viscosity was determined for each of the two slurries described in
Optical micrographs of the two slurries were also recorded (not illustrated). The water based Rev Dust slurry exhibited a gel-like microstructure, while the water-based slurry containing the oil based component slurry (referred to herein merely as the oil based slurry for convenience) exhibited phase separation and dispersion of the oily solids within and throughout the Rev Dust+OBM slurry. Further and most concerning, the phase separated and dispersed oily solids are finely and widely dispersed inside the phase separated domains. Also, X-Ray absorption cross-section images of the filter frits were recorded through which each the two slurries were filtered. It was observed that the OBM solids invade the pores of the filter and cause plugging. About a 100 micron thick plugged layer of OBM solids is observed in the X-ray image on a cross-sectional view of the filter frits. It was inferred that pore plugging by fine particulates leads to increased resistance to filtration.
Exemplary testing: It was hypothesized from the comparative examples discussed above, that a large clump or aggregation of the small solids into a size that was larger than the pore size or pore throat diameter.
Exemplary testing: As discussed previously above, a core tenet of the current teaching is to aggregate the oily solids of the oil based mud such that the aggregates are too large to enter the formation pores, thus impeding pore plugging by the solids. This aggregation is achieved by using an oily solids aggregator additive. The oily solids aggregator additive aggregates the oily solids and is compatible with the xanthan gum polymer.
Hydrolyzed polyacrylamide (HPAM), a commercially available polymer was used to demonstrate the principles disclosed herein. As discussed above, HPAM is an ionic water soluble polymer having a polymer conformation that is sensitive to salt concentration. At low salt concentration, HPAM polymer chains are relatively straight and elongated, interlacing with the other HPAM polymer chains and functions as a aqueous viscosifier. At higher salt concentration, the HPAM polymer chains tend to coil remain largely independent of the adjacent HPAM polymer chain, such that and the aqueous viscosification effect is lost. We observed that the coiled HPAM can function as an oily solids aggregator. This unique feature and new observation enables use of HPAM in this invention. Sulfonated polystyrene is another polymeric additive that behaves similarly as HPAM and can also function as an oily solids aggregator. In broad terms, water soluble ionic polymers can be used to prepare slurry compositions of the disclosed techniques.
In an exemplary demonstration, a new slurry composition was prepared wherein 0.05 wt % of HPAM oily solids aggregator polymer was included in the base oil based mud composition that was plotted previously in comparative plots of
X-ray absorption photos were taken (not shown) of the filter frit cross-sections for the exemplary composition containing the oily solids aggregator and reflected virtually no invasion of the solids particulates into the pores of the filter frits. Pore plugging prevention was clearly exhibited, affirming the desirable performance of the aggregating slurry compositions and methods disclosed herein. The majority of the solids particles were observed to be collected substantially exclusively on the surface of the filter frit. Also, photomicrographs of the injectable fluid slurry were taken (not shown), wherein the solid particulates were largely observed to be aggregated into clumps of oil solids, most having a mean cross-sectional diameter in excess of 40 microns and even in excess of 50 microns.
INDUSTRIAL APPLICABILITYThe systems and methods disclosed herein are applicable to the oil and gas industries. It is believed that the disclosure set forth above encompasses multiple distinct inventions with independent utility. While each of these inventions has been disclosed in its preferred form, the specific embodiments thereof as disclosed and illustrated herein are not to be considered in a limiting sense as numerous variations are possible. The subject matter of the inventions includes all novel and non-obvious combinations and subcombinations of the various elements, features, functions and/or properties disclosed herein. Similarly, where the claims recite “a” or “a first” element or the equivalent thereof, such claims should be understood to include incorporation of one or more such elements, neither requiring nor excluding two or more such elements.
It is believed that the following claims particularly point out certain combinations and subcombinations that are directed to one of the disclosed inventions and are novel and non-obvious. Inventions embodied in other combinations and subcombinations of features, functions, elements and/or properties may be claimed through amendment of the present claims or presentation of new claims in this or a related application. Such amended or new claims, whether they are directed to a different invention or directed to the same invention, whether different, broader, narrower, or equal in scope to the original claims, are also regarded as included within the subject matter of the inventions of the present disclosure.
Claims
1. A method for injecting solid particles recovered from a NAF drilling cuttings returns fluid stream into a subsurface formation, comprising:
- obtaining solid particles from a drilling returns stream comprising a NAF, the obtained solid particles comprising NAF;
- obtaining a slurry-forming fluid, the slurry-forming fluid comprising water, a viscosifying water soluble polymer, and an oily solids aggregator;
- mixing the obtained solid particles and the slurry-forming fluid to create an injectable slurry; and
- introducing the injectable slurry into a wellbore for injection into a subsurface formation.
2. The method of claim 1, further comprising pumping the injectable slurry into the wellbore and into one or more fractures formed in the subsurface formation.
3. The method of claim 1, wherein the oily solids aggregator comprises an ionic water soluble polymer.
4. The method of claim 1, wherein the oily solids aggregator comprises at least one of hydrolyzed polyacrylamide (HPAM) and sulfonated polystyrene.
5. The method of claim 1, wherein the viscosifying water soluble polymer comprises at least one of a polysaccharide, guar gum, xanthan, alginate, pectin, cellulosic polymer, and a viscosifying hydrocolloid.
6. The method of claim 1, wherein the viscosifying water soluble polymer comprises at least one of carboxyl-methylcellulose (CMC) and xanthan gum.
7. The method of claim 1, wherein the water comprises at least 0.5 wt % (5 ppt) salt based upon the total weight of the water, wherein the salt comprises at least one of a dissolved chloride and bromide salt.
8. The method of claim 1, wherein the slurry-forming fluid aggregates solids within a size range of 0.2 to 50 micron size solid particles.
9. The method of claim 1, further comprising separating the obtained solid particles from at least a portion of the non-aqueous drilling fluid, wherein the separated obtained solid particles comprise a coating of non-aqueous drilling fluid.
10. The method of claim 1, further comprising combining salt water, the water soluble polymer, the oily solids aggregator, and NAF-coated solid particles to form the injectable slurry.
11. The method of claim 1, wherein the water comprises a chloride or bromide salt of at least one of sodium, calcium, and magnesium.
12. The method of claim 1, wherein the injectable slurry comprises from 50 to 80 wt % of water, based upon the total weight of the injectable slurry.
13. The method of claim 1, wherein the injectable slurry comprises from 60 to 70 wt % of water, based upon the total weight of the injectable slurry.
14. The method of claim 1, wherein the injectable slurry comprises from 15 to 50 wt % of solid particles, based upon the total weight of the injectable slurry.
15. The method of claim 1, wherein the injectable slurry comprises from 20 to 30 wt % of solid particles, based upon the total weight of the injectable slurry.
16. The method of claim 1, wherein the injectable slurry comprises from 5 to 25 wt % of NAF, based upon the total weight of the injectable slurry.
17. The method of claim 1, wherein the injectable slurry comprises from 5 to 20 wt % of NAF, based upon the total weight of the injectable slurry.
18. The method of claim 1, wherein the injectable slurry comprises NAF at a concentration of from 1 wt % to 25 wt %, based upon the total weight of the injectable slurry.
19. The method of claim 2, further comprising pumping a volume of a NAF filter cake remediation fluid into the disposal well prior to pumping the injectable slurry.
20. The method of claim 2, further comprising pumping a volume of the NAF into the disposal well prior to pumping the injectable slurry into the disposal well.
21. The method of claim 1, wherein the injectable slurry comprises the oily solids aggregator in the range of 0.01 to 5 wt % based on the total weight of the slurry composition.
22. The method of claim 1, wherein the injectable slurry comprises the oily solids aggregator in the range of 0.01 to 1.0 wt % based on the total weight of the slurry composition.
23. The method of claim 1, wherein the injectable slurry comprises the oily solids aggregator in the range of 0.05 to 0.5 wt % based on the total weight of the slurry composition.
24. An injectable fluid for use in re-injecting solid particles recovered from a NAF drilling fluid into a subsurface formation, comprising:
- a slurry-forming fluid, the slurry-forming fluid comprising water, salt, a viscosifying water soluble polymer, an oily solids aggregator polymer, and a NAF.
25. The fluid of claim 24, further comprising solid particles comprising drill cuttings and the NAF.
26. The fluid of claim 24, wherein the oily solids aggregator comprises an ionically responsive water soluble polymer.
27. The fluid of claim 24, wherein the oily solids aggregator comprises at least one of hydrolyzed polyacrylamide (HPAM) and sulfonated polystyrene.
28. The fluid of claim 24, wherein the water soluble polymer comprises at least one of a polysaccharide, guar gum, alginate, pectin, cellulosic polymer, and another hydro-colloid.
29. The fluid of claim 24, wherein the water soluble polymer comprises at least one of carboxyl-methylcellulose (CMC) and Xanthan gum.
30. The fluid of claim 24, wherein the water comprises at least 0.5 wt % (5 ppt) salt, based upon the total weight of the water in the injectable slurry, wherein the salt comprises at least one of a dissolved chloride and bromide salt of at least one of sodium, potassium, calcium, and magnesium.
31. The fluid of claim 25, further comprising NAF in addition to the NAF that is associated with the drill cuttings.
32. The fluid of claim 24, wherein the slurry-forming fluid further comprises a chloride or bromide salt of at least one of sodium, calcium, and magnesium.
33. The fluid of claim 24, wherein the injectable slurry comprises from 50 to 80 wt % of water, based upon the total weight of the injectable slurry.
34. The fluid of claim 24, wherein the injectable slurry comprises from 60 to 70 wt % of water, based upon the total weight of the injectable slurry
35. The fluid of claim 24, wherein the injectable slurry comprises from 15 to 40 wt % of solid particles, based upon the total weight of the injectable slurry.
36. The fluid of claim 24, wherein the injectable slurry comprises from 20 to 30 wt % of solid particles, based upon the total weight of the injectable slurry.
37. The fluid of claim 24, wherein the injectable slurry comprises from 5 to 30 wt % of NAF, based upon the total weight of the injectable slurry.
38. The fluid of claim 24, wherein the injectable slurry comprises NAF at a concentration of from 1 wt % to 25 wt %, based upon the total weight of the injectable slurry.
39. The fluid of claim 28, wherein the solid particles comprise at least 10 wt % of the solid particles having a mean diameter of from 0.2 to 50 microns, based upon the total weight of the solid particles.
40. The fluid of claim 24 wherein the injectable slurry comprises the oily solids aggregator in the range of 0.01 to 5 wt % based on the total weight of the slurry composition.
41. The fluid of claim 24, wherein the injectable slurry comprises the oily solids aggregator in the range of 0.01 to 1.0 wt % based on the total weight of the slurry composition.
42. The fluid of claim 24, wherein the injectable slurry comprises the oily solids aggregator in the range of 0.05 to 0.5 wt % based on the total weight of the slurry composition.
Type: Application
Filed: May 7, 2014
Publication Date: Nov 12, 2015
Inventor: Ramesh Varadaraj (Bartlesville, OK)
Application Number: 14/272,141
