Patent Application
20240084654
The present disclosure relates generally to the field of model-building for selection of down-hole well fluids, and more specifically, to the analysis of properties for the selection of well cuttings and well fluids to be used in combination down-hole in well operations.
In the most basic sense, rotary drilling operations typically involve attaching a drill bit on a lower end of a drill string to form a drilling tool and rotating the drill bit along with the drill string into a subterranean formation to create a wellbore through which subsurface formation fluids may be recovered. During drilling operations, a fluid known as drilling mud or drilling fluid is normally pumped down bore of the drill pipe, and circulated up the annular space which is formed between the external surface of said drill pipe and the internal surface of the wellbore. The basic functions of drilling mud are: (1) to cool and lubricate the drill bit and downhole equipment during drilling operations; (2) to transport pieces of drilled-up rock and other debris from the bottom of the hole to the surface; (3) to suspend such rock and debris during periods when circulation is stopped; (4) to provide hydrostatic pressure to control encountered subsurface pressures; and (5) to seal the porous rock in the well with an impermeable filter cake.
As circulated drilling mud returns to the earth's surface and is pumped out of a well, the mud contains pieces of broken, drilled-up rock and other solid debris known as “cuttings” or “drill cuttings”. In most cases, an effluent mud stream flowing out of a well, together with associated drill cuttings, is directed to one or more devices which are designed to separate such drill cuttings from the mud. Such devices include, but are not limited to, shale shakers, desanders, desilters, hydrocyclones and centrifuges.
Shale shakers are essentially screens that are used to separate drill cuttings from the drilling mud. In many cases, shale shakers utilize a series of screens arranged in a tiered manner relative to each other and are often made to vibrate in order to increase the quality of such separation. The bulk drilling mud passes through the screens by gravity, while the predominantly solid cuttings are inhibited from passing through and instead pass over the end of the screens. Certain shale shakers are designed to filter coarse material while other shale shakers are designed to remove finer particles from the drilling mud. Shale shakers and other similar devices are frequently necessary to efficiently separate drill cuttings from drilling mud.
Once drill cuttings and other debris have been separated from the bulk mud stream flowing out of a well, it is necessary to dispose of such cuttings. Unfortunately, the disposal of drill cuttings can present a number of different problems. Often, the most economical way to dispose of drill cuttings would simply be to discharge said cuttings directly into the surrounding environment, such as in a mud pit or discharged from an offshore platform or drill ship into the water. Even though drill cuttings leaving a shale shaker or other separation device may have been separated from a well's effluent mud stream, such cuttings nonetheless can include entrained mud and other fluids which could be damaging to the environment.
In order for drilling mud to accomplish its intended objectives, it is often necessary to control certain characteristics of such drilling mud. Chemicals and/or other additives are often mixed into such drilling muds for control of certain parameters. Common drilling mud additives include gelling agents (e.g., colloidal solids and/or emulsified liquids), weighting materials, and other chemicals which are used to maintain mud properties within desired parameters. Although drilling mud has historically been water-based, improved results have been obtained using oil-based or synthetic-based muds, especially in severe drilling environments. Many of these additives, oil-based muds and synthetic-based muds can potentially impact the environment.
Drill cuttings are frequently transported from a drilling rig to an off-site facility for disposal. In order to accomplish such off-site disposal, drill cuttings are generally loaded into boxes or other storage containers for transportation away from the rig. While this solution can be generally functional, it is not without potential problems.
One problem associated with the off-site disposal of drill cuttings is increased cost. In most cases, special equipment is needed to move fluid-laden drill cuttings from a rig's shale shakers to another location on the rig where storage containers are loaded. Such equipment is often in the form of complicated and elaborate conveyors, augers and/or vacuum units. Moreover, large numbers of storage containers must be rented or purchased in order to accommodate such cuttings. All of this added equipment and labor increases the costs associated with the drilling process. This additional equipment can present logistical and/or safety problems on many rigs.
Another problem associated with off-site disposal of drill cuttings is potential environmental impact. Such off-site disposal of drill cuttings does not necessarily guarantee an overall reduction or elimination of environmental impact. Cuttings containers must be transported to a rig, loaded with cuttings, and thereafter moved to an off-site storage facility. Trucks, vessels or other means of transportation must typically be employed to transport the containers to and from the rig.
Drill cuttings may potentially be used in treatment fluids such as spacers, in which, the cuttings are recovered from well drilling operations, ground into particulate material, and may be recycled through use in a number of applications. The ground drilling cuttings may be incorporated into well treatment fluids, including but not limited to drilling fluids, spacers, flushes, completion fluids, fracturing fluids, and efficiency fluids. When formulated with well treatment fluids, the ground drill cuttings may serve as, for example, a weighting agent and/or scouring agent. The low cost of these ground drilling cuttings makes them well suited for use in efficiency fluid systems, which take advantage of the large volumes of fluids that can be deployed on a cost per volume basis. However, difficulties arise because the drill cuttings must be suspended in the well treatment fluid, which can require significant time in analyzing and testing drill cuttings, grinding sizes and treatment fluids to determine suitable combinations.
The drawings included with this application illustrate certain aspects of the embodiments described herein. However, the drawings should not be viewed as exclusive embodiments. The subject matter disclosed herein is capable of considerable modifications, alterations, combinations, and equivalents in form and function, as will be evident to those skilled in the art with the benefit of this disclosure.
The present disclosure may be understood more readily by reference to this detailed description, including the figures. For simplicity and clarity of illustration, where appropriate, reference numerals may be repeated among the different figures to indicate corresponding or analogous elements. In addition, numerous specific details are set forth in order to provide a thorough understanding of the embodiments described herein. However, it will be understood by those of ordinary skill in the art that the embodiments described herein can be practiced without these specific details. In other instances, methods, procedures and components have not been described in detail so as not to obscure the related relevant feature being described. Also, the description is not to be considered as limiting the scope of the embodiments described herein. The drawings are not necessarily to scale and the proportions of certain parts may have been exaggerated to better illustrate details and features of the present disclosure.
Definitions: As used herein the following terms have the indicated meaning.
A well can include, without limitation, an oil, gas, or water production well, or an injection well. As used herein, a “well” includes at least one wellbore. A wellbore can include vertical, inclined, and horizontal sections, and it can be straight, curved, or branched. As used herein, a “well” also includes the near-wellbore region.
A near-wellbore region is the subterranean material and rock of the subterranean formation surrounding the wellbore. The near-wellbore region is generally considered to be the region within approximately 100 feet radially of the wellbore.
As used herein, “into a well” means and includes into any section of the well, including into the wellbore or into the near-wellbore region via the wellbore.
As used herein, the term “wellbore” includes any cased, and any uncased, open-hole section of the wellbore. A portion of a wellbore may be an open hole or cased hole. In an open-hole wellbore section, a tubing string may be placed into the wellbore. The tubing string allows fluids to be introduced into or flowed from a remote section of the reservoir. In a cased-hole wellbore section, a casing is placed into the wellbore that can also contain a tubing string. A wellbore can contain an annulus. Examples of an annulus include but are not limited to: the space between the wellbore and the outside of a tubing string in an open-hole wellbore; the space between the wellbore and the outside of a casing in a cased-hole wellbore; and the space between the inside of a casing and the outside of a tubing string in a cased-hole wellbore.
“Down-hole operations” or “subterranean operations” means any operation that requires the performance of some action or procedure below the surface of the earth, including, but not limited to, actions or procedures performed in the course of recovering oil, gas, and/or other substances from a formation below the surface of the earth. Generally, these are drilling, completion and workover operations, and thus, include operations related to the drilling of the wellbore, operations for making the well ready for production after drilling operations, and operations to repair or stimulate an existing production well for the purpose of restoring, prolonging or enhancing the production of hydrocarbons.
A “treatment fluid” is a fluid use in down-hole operations. Often these will comprise an oil or aqueous base fluid, and can include gelling agents, viscosifiers, and other additives that support the down hole operation. A treatment fluid may be used in a variety of subterranean operations. As used herein, the term “treatment,” or “treating,” does not imply any particular action by the fluid or any particular component thereof, but instead refers to any use related to a subterranean operation in conjunction with a desired function and/or for a desired purpose. For example, a fluid may be used to drill a wellbore in a subterranean formation or to complete a wellbore in a subterranean formation, as well as numerous other purposes.
As indicated above, “drill cuttings” or “cuttings” refer to pieces of broken, drilled-up rock and other solid debris produced from drilling the wellbore.
“Wellbore fluids” broadly refers to fluids in the wellbore and includes treatment fluids, and hydrocarbons or aqueous fluids produced from subterranean formations.
The present invention provides a method of designing smart environmental-efficiency fluids for use in down-hole operations in a well. The smart environmental-efficiency fluid comprises a treatment fluid and drilling cuttings, wherein at least one of the treatment fluid and drill cuttings are designed during the method.
Determining the material characteristics of drill cuttings obtained from various downhole environments can be critical in determining their effect on the compatibility and efficacy of an efficiency fluid. Without knowing the material characteristics of drill cuttings obtained from different wells, there exists a large number of unknown factors that prevent an ideal efficiency fluid composition from being formulated and implemented. In general, an ineffective efficiency fluid may be unstable and have particle settling leading to a non-homogenous fluid that is difficult to pump, it may cause jamming in downhole valves, ports or other equipment, or it may have a non-optimal rheology for mud recovery.
Efficiency fluids comprising drill cuttings effectiveness may be determined or predicted by a drill cuttings analysis system. For example, the drill cuttings analysis system can include multiple sensors capable of analyzing a sample retrieved from a wellbore to identify the sample's material characteristics such as chemical, physical, mechanical, and dimensional properties. The analysis system can analyze the sample to generate a three-dimensional (“3D”) mapping of the various characteristics of the sample. The system can also include a database of baseline 3D mappings built by analyzing drill cuttings of various composition, size, shape or other properties. The drill cuttings analysis system can compare the 3D mapping of the drill cutting of unknown material characteristics against baseline 3D mappings in the database to determine one or more material characteristics of the sample, which may be indicative of how the drill cuttings will perform in and affect the characteristics of an efficiency fluid. If the drill cutting sample's material characteristics are unsuitable for a desired wellbore application, a change can be made, such as blending the sample with other more desirable cuttings or altering the formulation of rheological and other physicochemical characteristics of the efficiency fluid (i.e. adding viscosifiers, adding more or less suspending aids, etc.).
Material characteristics include physical properties, mechanical properties, chemical properties, and/or dimensional properties, all of which are distinct from one another. Examples of physical properties can include density, porosity, strength, permeability, degree of crystallinity, volume fraction of a chemical component, pore throat sizes, surface area of particles, total surface area and average surface area of a chemical component, Log-mean diameter (LMD), Log-mean standard deviation (LMSD), a given geometric shape factor of a chemical component. Examples of mechanical properties can include compressive strength, Young's Modulus, Poisson's ratio, strain-to-failure, and toughness. Examples of chemical properties can include chemical composition and solubility. Examples of dimensional properties can include size, shape and specific gravity.
In some examples, the drill cutting analysis system can develop 3D mappings for control samples of drill cuttings which have been correlated to efficiency fluid performance factors. A sample of drill cuttings of unknown properties can then be obtained and analyzed using multiple sensors simultaneously to generate a 3D mapping and compared to the material characteristics and efficiency fluid effectiveness of the control samples. This comparison can guide the formulation of successful efficiency fluids. Furthermore, the analysis results and correlated efficiency fluid effectiveness can be added to the database which can help to better generate appropriate formulations for future efficiency fluids. Ultimately this database can be further developed and resourced via artificial intelligence algorithms. The database can further enhance the speed at which decisions are made regarding efficiency fluid formulations. Knowing the material characteristics can allow for more engineered and tailored designs to meet the specific rheology and wellbore requirements, resulting in reduction of remedial work caused by efficiency fluid failure.
For example, various sensors can be used to analyze the material characteristics of a cement sample. The sensors (but not limited to) can perform X-Ray Computing Tomography (“CT”), Focused Ion-Beam Scanning Electron Macroscopy (“FIB-SEM”) with X-Ray Diffraction (“XRD”), X-Ray Fluorescence (“XRF”), Energy Dispersive Spectroscopy (“EDS”), Nuclear Magnetic Resonance (“NMR”), or any combination of these, on a sample in a sequential or concurrent manner. The sensors can be components of the drill cuttings analysis system, which can execute test software that integrates the outputs from the sensors to form the 3D mapping of the cement sample.
The cement analysis system and accompanying test software can be trained or otherwise calibrated to identify and measure material characteristics of drill cutting samples. The 3D mappings related to the components of drill cuttings can be stored as separate 3D mappings in the database, which may be associated or correlated with desirable or undesirable material characteristics, which may include artificial intelligence algorithms. For example, a 3D mapping corresponding to calcium carbonate (Mohs hardness=3), which may be undesirable for wellbore cleaning, and a 3D mapping corresponding to quartz (Mohs hardness=7) which may be desirable for wellbore cleaning can be stored in the database. In addition to 3D mappings for chemical characteristics, the drill cuttings analysis system can store and be further calibrated using baseline 3D mappings for physical characteristics such as crystalline phase. For example, a 3D mapping corresponding to high porosity (typically lower density), which may be undesirable for wellbore cleaning, and a 3D mapping corresponding to low porosity (typically higher density) which is desirable for wellbore cleaning can be stored in the database. In another physical characteristic example, a 3D mapping corresponding to a drill cutting which is composed of hard crystalline regions contained in the interior of a relatively soft amorphous matrix, which may be undesirable for wellbore cleaning, and a 3D mapping corresponding drill cutting which is composed of relatively soft amorphous regions contained in a hard crystalline matrix, which may be desirable for wellbore cleaning, can be stored in the database. Furthermore, the drill cuttings analysis system can store and be further calibrated using baseline 3D mappings for physical characteristics such as drill cutting size and shape. For example, a 3D mapping corresponding to a drill cutting with relatively high sphericity, which may be undesirable for wellbore cleaning, and a 3D mapping corresponding to a drill cutting with low sphericity and high angularity, which is desirable for wellbore cleaning, can be stored in the database.
Referring now to the drawings, various features, examples, and applications of the system and method of the current disclosure will now be further illustrated.
Still referring to
The bulk of the drilling mud for the depicted mud system is in mud pit 12. Mud from the mud pit 12 is circulated through the overall mud system depicted schematically in
During standard drilling operations, mud exiting the wellbore annulus 10 through flow line 8b often includes drill cuttings and other debris encountered in wellbore 4. Such drill cuttings are generated downhole as a result of the drilling process. Such drill cuttings and other debris would typically contaminate the overall quality of the mud system if allowed to remain in the active mud system. Accordingly, the mud and drill cuttings mixture leaving the well is directed to a separation device, such as shale shakers 16. It is to be understood that any number of separation devices could be used for this purpose; however, for purposes of illustration in
For reasons described above, handling and disposal of drill cuttings discharged from shale shakers 16 has conventionally been problematic. In many cases, it is possible to collect such drill cuttings for transportation and eventual disposal. However, it is frequently beneficial to dispose or use the cuttings at the drilling rig location and avoid the transportation and offsite disposal of said cuttings.
The solutions and methods of the present invention are applicable to designing environmental-efficiency fluids for use in a verity of down-hole operations. For example, the fluids can be applicable as drilling fluids, completion fluids and workover fluids such as fracturing fluids.
The exemplary methods and compositions disclosed herein may directly or indirectly affect one or more components or pieces of equipment associated with the preparation, delivery, recapture, recycling, reuse, and/or disposal of the disclosed compositions. For example, and with reference to
The proppant source 40 can include a proppant for combination with the fracturing fluid. In an embodiment the proppant source 40 can include ground drilling cuttings. The system may also include additive source 70 that provides one or more additives (e.g., gelling agents, weighting agents, and/or other optional additives) to alter the properties of the fracturing fluid. For example, the other additives 70 can be included to reduce pumping friction, to reduce or eliminate the fluid's reaction to the geological formation in which the well is formed, to operate as surfactants, and/or to serve other functions.
The pump and blender system 50 receives the fracturing fluid and combines it with other components, including proppant from the proppant source 40 and/or additional fluid from the additives 70. The resulting mixture may be pumped down the well 60 under a pressure sufficient to create or enhance one or more fractures in a subterranean zone, for example, to stimulate production of fluids from the zone. Notably, in certain instances, the fracturing fluid producing apparatus 20, fluid source 30, and/or proppant source 40 may be equipped with one or more metering devices (not shown) to control the flow of fluids, proppants, and/or other compositions to the pumping and blender system 50. Such metering devices may permit the pumping and blender system 50 can source from one, some or all of the different sources at a given time, and may facilitate the preparation of fracturing fluids in accordance with the present disclosure using continuous mixing or “on-the-fly” methods. Thus, for example, the pumping and blender system 50 can provide just fracturing fluid into the well at some times, just proppants at other times, and combinations of those components at yet other times.
The well is shown with a work string 112 extending from the surface 106 into the wellbore 104. The pump and blender system 50 is coupled a work string 112 to pump the fracturing fluid 108 into the well bore 104. The working string 112 may include coiled tubing, jointed pipe, and/or other structures that allow fluid to flow into the well bore 104. The working string 112 can include flow control devices, bypass valves, ports, and or other tools or well devices that control a flow of fluid from the interior of the working string 112 into the subterranean zone 102. For example, the working string 112 may include ports adjacent the well bore wall to communicate the fracturing fluid 108 directly into the subterranean formation 102, and/or the working string 112 may include ports that are spaced apart from the well bore wall to communicate the fracturing fluid 108 into an annulus in the well bore between the working string 112 and the well bore wall.
The working string 112 and/or the well bore 104 may include one or more sets of packers 114 that seal the annulus between the working string 112 and well bore 104 to define an interval of the well bore 104 into which the fracturing fluid 108 will be pumped.
While not specifically illustrated herein, the disclosed methods and compositions may also directly or indirectly affect any transport or delivery equipment used to convey the compositions to the fracturing system 20 such as, for example, any transport vessels, conduits, pipelines, trucks, tubulars, and/or pipes used to fluidically move the compositions from one location to another, any pumps, compressors, or motors used to drive the compositions into motion, any valves or related joints used to regulate the pressure or flow rate of the compositions, and any sensors (i.e., pressure and temperature), gauges, and/or combinations thereof, and the like.
The present invention is related to system and methods of designing smart environmental-efficiency fluids, which are treatment fluid compositions comprising ground drilling cuttings. The cuttings are recovered from well drilling operations, ground into particulate material, and may be recycled through use in a number of applications. The method provides for designing ground drilling cuttings and/or the treatment fluid so as to incorporate the drill cuttings into treatment fluids in a manner to maximize the suspension of drill cuttings in the treatment fluid, ensure the drill cuttings stay homogeneously dispersed in the treatment fluid, prevent jamming in the flow paths of the wellbore, and efficiency fluids. The method can ensure a proper concentration of drill cuttings so as to clean the wellbore while also not being too much so as to create particle jamming in the wellbore flow path restrictions. As will be realized from this disclosure, when formulated with well treatment fluids, the drill cuttings may serve as, for example, a weighting agent and/or scouring agent.
Turning now to
At the start of the process, a set of drill-cutting properties are defined in step 402. The set of drill-cutting properties are properties of the drilling cuttings that affect the ability of the drill cuttings to be carried by a fluid. For example, the set of drill-cuttings properties can include at least one of density, particle size distribution, shape factor, oil content or hardness for the drill cuttings. Though typically, the set of properties includes each of density, particle size distribution, shape factor, oil content and hardness for the drill cuttings.
Generally, the density will be a specific gravity value; however, other density values can be used. Particle size distribution (PSD) is the amount of, typically by mass, of particles present according to size. Particle size distributions is a description of the fact that not every particle in the drill cuttings has the same size. There is a range of sizes present. The particles size distribution will generally be defined as a DX value, where “X” is the percentage of the particles having a size less than a value. For example, if the D90 is 1000 nm, then 90 percent of the drill cutting particles will have a size of 1000 nm or less. For example, the PSD can be determined using dynamic light scattering such as carried out by an instrument such as, but not limited to, a Mastersizer 3000 marketed by Malvern Panalytical, a Spectris company.
Shape factor is a value that is affected by an objects shape and helps to define that shape. While any suitable shape factor may be utilized for the process, one shape factor that can be used is one that is defined as the ratio of Dequiv to Dlongest. Where Dequiv is the diameter of a sphere that has the equivalent volume as the particle. And Dlongest is the longest straight line that can be drawn from the particles most distanced surfaces, such as the length of a fiber. In this example, the shape factor for a perfect sphere will equal 1.0.
Oil content reflects the amount of hydrocarbons that is accompanies the drill particles. Since the drill particles are cuttings from drilling the well, they are recovered down hole with drilling mud that contains hydrocarbons, from the drilling mud and/or hydrocarbons form subterranean formations. Generally, the oil content will be reduced by separating the cutting from the hydrocarbons after recovery from downhole. For example, as centrifuge can be used to determine oil content.
Particle hardness can be determined by any suitable method, such as using a Mohs Hardness Scale, which can be determined using various techniques known the art. For example, hardness can be measured based on the particles relative resistance to scratching such as by scratching the particle with another substance of known hardness on the Mohs Hardness Scale.
Also, at the start of the process, a set of wellbore conditions are defined. The wellbore conditions are reflective of the conditions downhole which will affect the environmental efficiency fluid. For example, the set of wellbore conditions can include at least one of temperature(s) downhole, pressure(s) downhole, pH of wellbore fluid, or salinity of wellbore fluid. In some embodiments, the set of wellbore conditions will include each of temperature, pressure, pH of wellbore fluid, and salinity of wellbore fluid.
After defining the properties and conditions, step 404 creates an analysis of a rheological model generated from the set of wellbore conditions and the set of drill-cutting properties to determine a set of rheological properties for the treatment fluid and a concentration of drill cuttings, which allow for use of the drill cuttings with the treatment fluid. For example, mathematical algorithms can be used to determine treatment fluid properties and/or drill cutting concentration that will achieve one or more of the following:
The set of rheological properties determined will typically be, but not limited to, Generalized Herschel Bulkley Model (GHB) where by the following terms are defined: Tau,o=yield stress or yield point; Mu,oo which is the high shear rate viscosity parameter; m=shear stress exponent (typically ranging from 0.01 to 2) and n=shear rate exponent (typically ranging from 0.02 to 2). These four parameters are used to describe the relationship between shear rate and shear stress of a wide spectrum of fluids, ranging from but not limited to: Newtonian; Power Law; Bingham Plastic; Herschel-Bulkley; Casson; Heinz; Heinz-Casson; and so forth. The generalized GHB equation can be expressed as follows: SS=Tau,o{circumflex over ( )}m+[(Mu,oo*SR){circumflex over ( )}n]*(Tau,ref{circumflex over ( )}(m−n)), where
After the set of rheological properties have been determined, steps of producing the environmental-efficiency fluid can be based on the rheological properties and the concentration of drill cuttings determined in step 405.
For example, as illustrated in
Once the available components are determined, a formulation is determined in step 408. The formulation is for the treatment fluid based on selected components from the available components such that the formulation is predicted to have the set of rheological properties determined in step 404 and 405. For example, algorithms can be used to predict how types and amounts of components will affect the rheological properties of the treatment fluid and its ability to effectively transport a given set of cuttings that have specific ranges of: specific gravity, shape factors, and particle size distributions.
Once a formulation is determined, it is tested in step 410 to confirm that the rheological properties of the resulting treatment fluid match those determined in step 404. If the properties match, then the resulting treatment fluid can be blended with the drill cuttings in step 412 to produce the environmental-efficiency fluid for use in the well.
In step 504, a set of drill-cutting properties are defined as discuss above for step 402. The drill cuttings are typically ones on hand and may or may not have been processed subsequent to removal from the well to reduce size or remove oil.
Next in step 506, an analysis of a rheological model generated from the set of drill-cutting properties and the set of drill cuttings properties is created so as to determine a target particle size distribution for the drill cuttings based on a target drill cuttings concentration for use of the drill cuttings with the preselected treatment fluid. In some embodiments, a set of wellbore conditions will be defined and used in creating the analysis, so as to ensure that the preselected treatment fluid can adequately suspend the drill cuttings with flow restriction in the well. The wellbore conditions will generally be the same as those discussed above for the embodiment of
In step 508 and 510, the particle size distribution of the drill cuttings is reduced to match the target particle size distribution determined in step (e) to produced modified drill cuttings.
For example, the drill cuttings can be crushed or cut so as to generally reduce the size of the particles and then the larger particles can be separated from the smaller particles to achieve the target particle sized distribution. For example, as shown in
Optionally, at this stage testing 512 can be carried out to determine if the appropriate target particle sized distribution has been achieved.
Finally, the environmental-efficiency fluid is produced by combining or blending the modified drill cuttings with the treatment fluid in step 514.
Turning now to
Similar to the process of
Optionally, the drill cuttings can have their particle size distribution reduced before being placed in storage. The reduction can be carried out as described for the method of
Optionally, a set of wellbore conditions for the down-hole operation can be defined. These can be used in the analysis discussed below in a manner similar to the processes above.
In step 610, an analysis is created of a rheological model generated from the set of wellbore conditions and the set of drill-cutting properties to determine a set of rheological properties for the treatment fluid so as to suspend a target concentration of drill cuttings in the treatment fluid during the down-hole operation. Optionally, once the rheological properties are determined they can be confirmed by testing to ensure that they meet the required suspension characteristic for use of the drilling cuttings in the treatment fluid (Step 612). As in the process of
Finally, the environmental-efficiency fluid can be produced (steps 614 & 616) based on the rheological properties, the concentration of drill cuttings and/or the components available. The fluid can then be pumped downhole (step 618) for use in the treatment operation.
The above methods can use algorithms for determining formulations that meet density and rheology requirements. For example, apparent viscosity (AVIS) could be determined using:
AVIS,100(cP)=Ao*(n)Bn*E(Bw+Bgel+B1015)
Where: Ao=1650 and has units of cP
As shown in
For example, the minimum yield point to suspend the largest cuttings could be determined using:
Tau,o=A,Tau,o*{Ao*(n)Bn*EXP(Bw+Bgel+B1015)}B,Tau,o
Where:
In
Steps of the method of the present disclosure can be carried out on a computer system capable of carrying out the functionality described herein. For example, the method relies on generating a rheological model and creating an analysis of the rheological model, such steps are well suit for carrying out on a computer utilizing algorithms similar to the ones discussed herein.
For example, such computer systems can include one or more processors, main memory-preferably random-access memory (RAM), and may also include a secondary memory. The secondary memory may include, for example, one or more hard disk drives and/or one or more removable storage drives, as are known in the art.
The computer system will typically include an input/output (I/O) interface, which provides the computer system 400 to access the monitor, keyboard, mouse, printer, scanner, plotter, and alike.
The above disclosure, and embodiments thereunder, are exemplified by methods and systems defined by the following numbered paragraphs.
Therefore, the present compositions and methods are well adapted to attain the ends and advantages mentioned, as well as those that are inherent therein. The particular examples disclosed above are illustrative only, as the present treatment additives and methods may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to be the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative examples disclosed above may be altered or modified, and all such variations are considered within the scope and spirit of the present treatment additives and methods. While compositions and methods are described in terms of “comprising,” “containing,” “having,” or “including” various components or steps, the compositions and methods can also, in some examples, “consist essentially of” or “consist of” the various components and steps. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range are specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee.
