Patent Application
20240401476
A formation may break down unintentionally during drilling due to excessive borehole pressure. Conversely, a formation may fail to break down during hydraulic fracturing due to insufficient borehole pressure. To avoid borehole instability in the first situation, and to ensure hydraulic fracturing in the second situation, a method is needed to determine the link between drilling fluid properties and formation strength.
This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.
In general, in one aspect, embodiments are disclosed related to systems and methods for quantifying drilling fluid influence on formation mechanical properties. The methods include obtaining drilling mud formulations and properties; determining a subset of the drilling mud formulations; obtaining core plugs from a subsurface; measuring first rock mechanical properties from the core plugs for each of the subset of the drilling mud formulations; performing a fluid invasion of the core plugs with drilling muds; measuring second rock mechanical properties of the core plugs after the fluid invasion; modeling an effect of the drilling muds on a formation breakdown; determining a mud weight range for each of the subset of the drilling mud formulations; and selecting a preferred drilling mud formulation for a drilling operation based on the mud weight range for the subset of the drilling mud formulations.
In general, in one aspect, embodiments are disclosed related to a non-transitory computer-readable memory comprising computer-executable instructions stored thereon that, when executed on a processor, cause the processor to perform the steps of quantifying drilling fluid influence on formation mechanical properties. The steps include determining a subset of the drilling mud formulations; measuring first rock mechanical properties from the core plugs for each of the subset of the drilling mud formulations; measuring second rock mechanical properties of the core plugs after the fluid invasion; modeling an effect of the drilling muds on a formation breakdown; determining a mud weight range for each of the subset of the drilling mud formulations; and selecting a preferred drilling mud formulation for a drilling operation based on the mud weight range for the subset of the drilling mud formulations.
In general, in one aspect, embodiments are disclosed related to systems configured for quantifying drilling fluid influence on formation mechanical properties. The systems include a computer processor, configured to: determine a subset of drilling mud formulations based on drilling mud properties of historical fracking jobs that were successful, measure first rock mechanical properties from core plugs for each of the subset of drilling mud formulations, measure second rock mechanical properties of the core plugs for each of the subset of drilling mud formulations after a fluid invasion of the core plugs with drilling muds created with each of the subset of drilling mud formulations, model an effect of the subset of drilling mud formulations on a formation breakdown using the drilling mud properties, the first rock mechanical properties, and the second rock mechanical properties, determine a mud weight range for each of the subset of drilling mud formulations based on the effect of the subset of drilling mud formulations on the formation breakdown; and select a preferred drilling mud formulation for a drilling operation based on the mud weight range for the subset of drilling mud formulations. The systems further include a laboratory, configured to: receive the core plugs from a subsurface, determine the drilling mud properties from the subset of drilling mud formulations, measure the first rock mechanical properties from the core plugs for each of the subset of drilling mud formulations, measure the second rock mechanical properties from the core plugs for each of the subset of drilling mud formulations, and perform the fluid invasion of the core plugs with the drilling muds created with each of the subset of drilling mud formulations.
Other aspects and advantages of the claimed subject matter will be apparent from the following description and the appended claims.
Specific embodiments of the disclosed technology will now be described in detail with reference to the accompanying figures. Like elements in the various figures are denoted by like reference numerals for consistency.
In the following detailed description of embodiments of the disclosure, numerous specific details are set forth in order to provide a more thorough understanding of the disclosure. However, it will be apparent to one of ordinary skill in the art that the disclosure may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description.
Throughout the application, ordinal numbers (e.g., first, second, third, etc.) may be used as an adjective for an element (i.e., any noun in the application). The use of ordinal numbers is not to imply or create any particular ordering of the elements nor to limit any element to being only a single element unless expressly disclosed, such as using the terms “before”, “after”, “single”, and other such terminology. Rather, the use of ordinal numbers is to distinguish between the elements. By way of an example, a first element is distinct from a second element, and the first element may encompass more than one element and succeed (or precede) the second element in an ordering of elements.
In the following description of
It is to be understood that the singular forms “a,” “an,” and “the” include plural referents unless the context clearly dictates otherwise. Thus, for example, reference to “a seismic dataset” includes reference to one or more of such seismic datasets.
Terms such as “approximately,” “substantially,” etc., mean that the recited characteristic, parameter, or value need not be achieved exactly, but that deviations or variations, including for example, tolerances, measurement error, measurement accuracy limitations and other factors known to those of skill in the art, may occur in amounts that do not preclude the effect the characteristic was intended to provide.
It is to be understood that one or more of the steps shown in the flowcharts may be omitted, repeated, and/or performed in a different order than the order shown. Accordingly, the scope disclosed herein should not be considered limited to the specific arrangement of steps shown in the flowcharts.
Although multiple dependent claims are not introduced, it would be apparent to one of ordinary skill that the subject matter of the dependent claims of one or more embodiments may be combined with other dependent claims.
Embodiments disclosed herein relate to a method for determining borehole formation stability or, alternatively, fracability, which can be classified into three parts. The first part is drilling fluid selection and formulation, along with rheology characterization. Different types of drilling fluid formulations can be employed in the developed workflow, which can be water based or oil based. The second part of the workflow is rock core selection, characterization, and benchmarking of mechanical properties. Core samples with similar petrophysical properties are selected to measure the mechanical properties at both dry conditions and after being exposed to drilling fluids for shorter and longer time periods. The third part of the workflow is inputting the results of the other two parts into a geomechanical modeling tool, which can predict mud weights that either avoid borehole instability, or else allow for successful fracking without destroying tubulars.
The essential elements of a drilling system (100) within a borehole (117) are presented in
As shown in
Prior to the commencement of drilling, a borehole plan may be generated. The borehole plan may include a starting surface location of the borehole (117), or a subsurface (122) location within an existing borehole (117), from which the borehole (117) may be drilled. Further, the borehole plan may include a terminal location that may intersect with the target zone (118), e.g., a targeted hydrocarbon-bearing formation, and a planned borehole path (103) from the starting location to the terminal location. In other words, the borehole path (103) may intersect a previously located hydrocarbon reservoir (104).
Typically, the borehole plan is generated based on best available information at the time of planning from a geophysical model, geomechanical models encapsulating subterranean stress conditions, the trajectory of any existing boreholes (117) (which one may desire to avoid), and the existence of other drilling hazards, such as shallow gas pockets, over-pressure zones, and active fault planes. In accordance with one or more embodiments, the borehole plan is informed by an extended bandwidth seismic dataset acquired through a seismic survey conducted over the subterranean region of interest (102).
The borehole plan may include borehole geometry information such as borehole diameter and inclination angle. If casing (124) is used, the borehole plan may include casing type or casing depths. Furthermore, the borehole plan may consider other engineering constraints such as the maximum borehole curvature (“dog-log”) that the drillstring (106) may tolerate and the maximum torque and drag values that the drilling system (100) may tolerate.
A borehole planning system (150) may be used to generate the borehole plan. The borehole planning system (150) may comprise one or more computer processors in communication with computer memory containing the geophysical and geomechanical models, the extended bandwidth seismic dataset, information relating to drilling hazards, and the constraints imposed by the limitations of the drillstring (106) and the drilling system (100). The borehole planning system (150) may further include dedicated software to determine the planned borehole path (103) and associated drilling parameters, such as the planned borehole diameter, the location of planned changes of the borehole diameter, the planned depths at which casing (124) will be inserted to support the borehole (117) and to prevent formation fluids entering the borehole (117), and the drilling mud weights (densities) and types that may be used during drilling the borehole (117).
A borehole (117) may be drilled using a drill rig that may be situated on a land drill site, an offshore platform, such as a jack-up rig, a semi-submersible, or a drill ship. The drill rig may be equipped with a hoisting system, such as a derrick (108), which can raise or lower the drillstring (106) and other tools required to drill the well. The drillstring (106) may include one or more drill pipes connected to form a conduit and a bottom hole assembly (BHA) (120) disposed at the distal end of the drillstring (106). The BHA (120) may include a drill bit (105) to cut into subsurface (122) rock. The BHA (120) may further include measurement tools, such as a measurement-while-drilling (MWD) tool and logging-while-drilling (LWD) tool. MWD tools may include sensors and hardware to measure downhole drilling parameters, such as the azimuth and inclination of the drill bit (105), the WOB, and the torque. The LWD measurements may include sensors, such as resistivity, gamma ray, and neutron density sensors, to characterize the rock formation surrounding the borehole (117). Both MWD and LWD measurements may be transmitted to the surface (107) using any suitable telemetry system, such as mud-pulse or wired-drill pipe, known in the art.
To start drilling, or “spudding in” the well, the hoisting system lowers the drillstring (106) suspended from the derrick (108) towards the planned surface location of the borehole (117). An engine, such as a diesel engine, may be used to supply power to the top drive (110) to rotate the drillstring (106). The weight of the drillstring (106) combined with the rotational motion enables the drill bit (105) to drill the borehole (117).
The near surface is typically made up of loose or soft sediment or rock, so large diameter casing (124), e.g., “base pipe” or “conductor casing,” is often put in place while drilling to stabilize and isolate the borehole (117). At the top of the base pipe is the wellhead, which serves to provide pressure control through a series of spools, valves, or adapters. Once near-surface drilling has begun, water or drill fluid may be used to force the base pipe into place using a pumping system until the wellhead is situated just above the surface (107) of the earth.
Drilling may continue without any casing (124) once deeper, or more compact rock is reached. While drilling, a drilling mud system (126) may pump drilling mud from a mud tank on the surface (107) through the drill pipe. Drilling mud serves various purposes, including pressure equalization, removal of rock cuttings, and drill bit cooling and lubrication.
At planned depth intervals, drilling may be paused and the drillstring (106) withdrawn from the borehole (117). Sections of casing (124) may be connected and inserted and cemented into the borehole (117). Casing string may be cemented in place by pumping cement and mud, separated by a “cementing plug,” from the surface (107) through the drill pipe. The cementing plug and drilling mud force the cement through the drill pipe and into the annular space between the casing (124) and the borehole wall. Once the cement cures, drilling may recommence. The drilling process is often performed in several stages. Therefore, the drilling and casing cycle may be repeated more than once, depending on the depth of the borehole (117) and the pressure on the borehole walls from surrounding rock.
Due to the high pressures experienced by deep boreholes (117), a blowout preventer (BOP) may be installed at the wellhead to protect the rig and environment from unplanned oil or gas releases. As the borehole (117) becomes deeper, both successively smaller drill bits (105) and casing string may be used. Drilling deviated or horizontal boreholes (117) may require specialized drill bits or drill assemblies.
A drilling system (100) may be disposed at and communicate with other systems in the well environment. The drilling system (100) may control at least a portion of a drilling operation by providing controls to various components of the drilling operation. In one or more embodiments, the system may receive data from one or more sensors arranged to measure controllable parameters of the drilling operation. As a non-limiting example, sensors may be arranged to measure WOB, drill RPM, flow rate of the mud pumps (GPM), and ROP of the drilling operation. Each sensor may be positioned or configured to measure a desired physical stimulus. Drilling may be considered complete when a target zone (118) is reached, or the presence of hydrocarbons is established.
Drilling operations are designed to minimize both nonproductive time (NPT) and drilling time, thereby avoiding or mitigating actions that may compromise pay-zone productivity. Drilling fluid, also known as drilling mud, is an essential factor for productivity and is evaluated by the value of skin (a factor measuring production efficiency) after the completion of drilling operations.
Formation breakdown failure is a persistent and chronic drilling issue in regions that combine highly stressed regimes, low permeability, deep target reservoirs, and a high pressure/high temperature (HPHT). Formation breakdown occurs when borehole pressures exceed the capacity of rock formations, thus causing fracturing and fluid penetration. In these situations, it is necessary to, not only predict the breakdown pressure, but identify all the factors that can affect breakdown and quantify the contribution of each. When operating within the margins dictated by the completion strength and the formation strength, control over the exact amount of borehole pressure improves the chances of a successful drilling operation. Formation breakdown failure may also occur if the borehole pressure is too low, thus causing compressive and shear failure in rocks.
Hydraulic fracturing presents a related problem, where the goal is to increase borehole pressure on purpose to the point that rock formations fail; fracturing provides access to previously inaccessible resources by pressurizing shale formations to the point of fracture, thus releasing hydrocarbons contained in nonpermeable pore spaces. However, hydraulic fracturing will not reach its goal if formation breakdown is not attainable. Failure to fracture may be caused by petrophysical characteristics of the formation such as an elevated breakdown pressure due to a highly stressed field or low formation permeability. Hydraulic fracturing may also fail due to the well design, including a burst pressure (the pressure at which casing (124) will fail) of completion tubulars that is below the rock fracture pressure. In other words, the well casing (124) will fail before the rock formations fracture, thus endangering the operation.
Embodiments disclosed herein describe a method to determine the link between drilling mud properties and formation strength so that either of the two goals above (inhibiting formation breakdown or enabling hydraulic fracturing) can be correctly handled. The first part of the method includes an analysis of drilling mud formulation and rheology. Investigating both of these elements requires analyzing data and compiling a description of which drilling muds were used to drill intervals of interest, and comparing them with the outcome of the drilling job. The drilling mud data contains a detailed description of formulations and additives used, and implies that an interaction between the drilling mud and rock formation that may influence formation breakdown pressure.
In
Regarding HPHT mud cake (
As described above, the second part or phase of the method disclosed herein is core characterization, where confined compressive tests may be performed on plug twins, one of which is dry, while others are other exposed to a drilling mud. (“Twins” refers to plugs that are close enough to each other as to be considered identical for physical tests. There may be more than 2 core plugs that are twins). Tests on twins determine the effect of fluid invasion on rock mechanical properties and demonstrates that formation damage due to fluid invasion is causing the formation to exhibit different mechanical behaviors. Shifts in mechanical properties have significant implications on the accuracy of geomechanical models for borehole instability and hydraulic fracturing. Quantification of the influence of drilling mud and formation damage on rock mechanical properties reduces the uncertainty in the rock mechanical properties and can greatly enhance the accuracy of geomechanical models for applications such as borehole instability, hydraulic fracturing, subsurface subsidence, and sanding potential.
The effect of drilling mud on a core plug is dependent upon the additives in the fluid; each possible combination may affect formation breakdown pressure differently. To determine the effect of fluid invasion, case studies may be done with the different drilling muds used in field experiments, examining the outcome to highlight relevant trends in the fluids properties. From these studies, two important observations can be made. First, the weighting agents used in these fluids are mostly either barite (BaSO3), potassium chloride (KCl), formate salts, and/or calcium carbonate (CaCO3). Second, due to operational considerations such as the probability of a loss of circulation during drilling, most drilling muds formulations contain a bridging material.
Focused lab experiments may be conducted to investigate the mechanism through which drilling muds contribute to the increased formation breakdown. In these experiments, both synthetic formation brine samples and core samples from a formation of interest may be used to observe the effects of drilling muds. Core flooding experiments may be conducted where core samples are tested in a flow loop with different water-based drilling muds formulations. These drilling muds formulations are barite/KCl/CaCO3 fluid and potassium formate fluid to simulate the most common fluids used in the intervals of interest, and Mn3O4 fluid as an alternative option. These experiments are done to simulate the circulation of the drilling mud into the borehole (117) and to assess the change in the core permeability through condensate injection. The results of the core flooding experiments are shown in
In another experiment, synthetic formation brine samples were mixed with the filtrate fluids produced from the same three water-based drilling muds. This was done to assess the drilling mud compatibility with the synthetic formation brine. The results of this experiment showed that for both of the barite/KCl/CaCO3 fluid filtrate and the Mn3O4 fluid filtrate there were no compatibility issues. For the potassium formate fluid filtrate, a scaling issue is noticeable. When mixing the filtrate of the potassium formate fluid with the synthetic formation brine, a cloudy mixture with precipitation is produced. This indicates that even though this fluid has performed slightly better than the barite/KCl/CaCO3 fluid in the core flooding experiment, it is introducing extra solids into the pores of the formation through scaling.
To further understand the nature of interaction between the drilling muds and the formation, an environmental scanning electron microscope (ESEM) may used to examine the flooded core samples. ESEM may show the placement of the solids within the core sample and identify the depth of penetration. For the core injected with Barite/KCl/CaCO3 fluid, the solids penetrated 53.5% of the core length (3.5 cm out of 6.55 cm). As for the core injected with Mn3O4 fluid, the solids penetrated 4.6% of the core length (0.23 cm out of 4.92 cm). The shape of pore throats and the shape of the solid particles in the fluid for the case of the injected Mn3O4 fluid affect the depth of invasion. Barite/KCl/CaCO3 solids are irregularly shaped, while the Mn3O4 solids are spherical shaped.
While it is known from published literature that invasion and intrusion of solids can be easily linked to formation damage, skin, and reduced production rates, their influence on the formation breakdown pressure during hydraulic fracturing is not as well understood. To link the two experimental parts above to observed variations in the formation breakdown pressure in the field, modeling work is required in the third part of the method of this invention. Modeling, in this case, may be any quantitative method that takes as input the geomechanical tests on the core plugs and outputs recommended mud weight ranges for each drilling mud. The modeling method could be as simple as a spreadsheet that records the relationships between rock properties, mud weight, and formation breakdown pressure. It may also be a finite element modeling tool.
One example of an FEM that can perform the necessary modeling function is a three-dimensional poro-elasto-plastic finite element model for solids that allows for real time calculation during drilling. A poro-elasto-plastic FEM is numerical tool that enables an accurate determination of stress distribution, strain estimation, and shear or compressive failure determination within a solid body. Due to its numerical nature, the tool can provide such distributions and determination through all spatial locations within a solid body. It allows for analysis of the influence of the solid body geometry and heterogenous mechanical properties within the same body.
This particular formulation of an FEM for solids allows for cases where the stress-strain relationship is nonlinear, which may be the case for particular rock types encountered in a borehole (117).
The FEM applies discretization to the physical system of a vibrating BHA (120) in a borehole (117) using the minimization of the total potential energy, which produces the following equilibrium:
where u is the displacement, B and BT are the strain-displacement matrix and its transpose, respectively. NT is the transpose of the quadratic serendipity shape functions vector, which are derived for a 20-node isoparametric brick element (401) that is depicted in
The body and traction forces reflect the in-situ stresses and mud weight loading on the borehole (117). The integrations in Equation (1) are performed at the element volume (Ve) with respect to the volume variable (Ω) or at the element surface (Se) with respect to the area variable (I). The matrix resulting from the integral in the expression to the left is known as the stiffness matrix (Ke).
The finite element model relies on the plastic flow rule for strain hardening to reflect the plastic behavior of the rock, which occurs beyond the yield point. This means that the total strain is the addition of two components, which are poro-elastic strain (εe) and a plastic strain (εp). The plastic flow rule assumes that the flow direction is perpendicular to the yield surface ψ and it is defined as:
where εijp is the plastic strain tensor, σij is the stress tensor, and λ is the plastic strain multiplier. The associative flow rule is applied by assuming that the plastic potential surface is the same as the yield surface ψ. It also assumes the yield surface expands without changing the flow direction. The yield criterion used in this work is the Drucker-Prager criterion, where yielding will take place when the deviatoric stress tensor (Sij) and the mean stress (σm) satisfy the following relationship:
Where constants a0 and a1 are determined experimentally as material properties and are used to correlate the Drucker-Prager criterion to the Mohr-Coulomb criterion.
The following expression for strain hardening is then used to calculate the scalar plastic strain εp from the plastic strain tensor determined by the flow rule:
A flow chart of the driver code (450) and twelve main subroutines of the FEM is shown in
Upon using the solver subroutine (458) to solve the system of equations, as described by Equation (1), and determining the displacements u, the residual forces are determined by the residual evaluation subroutine (460). Furthermore, the residuals are used to check for convergence and equilibrium with the convergence subroutine (462) by subtracting the left-hand side from the right-hand side in the global form, where the left-hand side is the global stiffness matrix multiplied by displacement, and the right-hand side is the body and traction forces. The value obtained from the subtraction of these two quantities should be equal to zero if the equilibrium condition is fully satisfied. However, that is not always achievable. Therefore, a tolerance value is set to check for convergence. An inner loop (466) is repeated, returning to the stiffness matrix subroutine (456) to modify the stiffness matrix. This inner loop (466) is repeated until the residual forces are determined to be less than the set tolerance value. At this point, convergence is said to be achieved; otherwise, the residual forces are carried to the next iteration.
The same process is repeated in an outer load increment loop (468) for each separate load increment, where the load increments are defined in the input file manually. Load increments are a necessity for numerical modeling tools (such as the poro-elasto-plastic geomechanics FEM) to enable the accurate prediction of strain behavior. Once all loops are completed, the output data from the FEM model is compiled and returned using the output subroutine (464). Boundary conditions, the effects of temperature and pressure on the system, plotting, and solver tolerances are controlled by four auxiliary subroutines (470).
An example output of the FEM is shown in
Through the use of the FEM, a drilling plan may be determined, the execution of which produces appreciable cost savings and reduced risk to equipment, the borehole (117), and the human workforce. The drilling plan may include a recommended mud formulation, mud weight, and drilling parameters (WOB, RPM, and ROP) for specific BHA (120) and well designs (e.g., well trajectory, casing point).
If the drilling mud formulation is a member of a subset of drilling mud formulations that passes the criterion, the flowchart moves to Step 506, where a set of identical cores dedicated to testing the drilling mud are analyzed for their petrophysical properties. The petrophysical properties may include porosity, permeability, Young's modulus, Poisson's ratio, rock tensile strength, as well as confined and unconfined compressive strengths. These properties may be measured by the tri-axial testing apparatus (confined and unconfined) or by a Brazilian testing apparatus.
If the criterion was not met by the drilling mud in Step 504, the process moves to Step 514, where it checks whether there are any more drilling mud formulations to test. If so (YES), the process moves to Step 512, where the counter, j, is incremented, and then back to Step 502.
Returning to Step 506, after determining the petrophysical properties of the core plugs associated with drilling mud formulation, j, the process moves to Step 508, where some of the core plugs are subjected to the drilling mud (and one is kept dry as a reference). In Step 510, the petrophysical properties of the core plugs are determined again, after the core plugs are subjected to the drilling mud in Step 508. A scanning electron microscope may be used at this point to determine a cause for formation breakdown if it has occurred in a core plug.
Step 510 proceeds to Step 514, where it is determined whether there are more drilling mud formulations to test. If so, it moves to step 512 (YES), where the counter, j, is incremented, and then back to Step 502. If there are no more drilling mud formulations to test (NO), the flowchart proceeds to Step 516, where the before and after petrophysical properties of the core plugs are entered into a geomechanical model. The geomechanical model may take many forms, for example, including a finite element model (FEM) or an Excel spreadsheet based model. The geomechanical model outputs a range of mud weights between which the borehole (117) will be stable; the upper bound also serves as the value above which hydraulic fracturing is feasible.
Continuing with
As mentioned above, when a mud weight (or, equivalently, borehole pressure) is above a maximum mud weight limit (maximum borehole pressure), the borehole pressure is sufficient to cause tensile failure in the formation rock, which creates a fracture. There are at least two applications of such a situation that are relevant: A first application is in well stimulation operations, like hydraulic fracturing, where the creation of fractures enables hydrocarbon production. Exceeding the maximum mud weight limit is advantageous in this case, because it indicates that a successful hydraulic fracture can be achieved. The borehole pressure limit, in this case, is simply referred to as the borehole fracturing or borehole breakdown pressure. The minimum mud weight (or, equivalently, minimum borehole pressure) has no utility in this application. A second application of one or more embodiments disclosed herein occurs when monitoring to avoid borehole instability. Within this context, exceeding the mud weight limit causes rock tensile failure and formation fracturing, thus leading to an undesired, unintentional, and problematic loss of drilling fluids (i.e., loss of circulation) into the formation. This causes a drilling operation to experience costly non-productive time (NPT). In this case, the mud weight must be kept below the maximum limit. For this application scenario, the minimum mud weight is an important quantity; going below the minimum mud weight pressure incites rock compressive or shear failure. This mode of failure is manifested in borehole breakouts, wash-outs, or enlargements. These breakouts introduce more solids into the wellbore while drilling, which can lead to stuck-pipe incidents, poor hole cleaning, and an increased wellbore diameter.
In summary, the following steps are taken by the method: First, drilling mud formulation is determined. The mud's properties, including its rheology, spurt loss, filtrate volume, mud cake thickness (204), solids content, pH, particle-plugging test (PPT) are determined. A subset of the drilling mud formulations are selected based on their potential to successfully perform hydraulic fracturing and/or not cause borehole instability. Second, core plugs of rock are selected for each drilling mud to be examined, and their mechanical properties are measured before an after subjecting them to the drilling mud. Third, the before and after properties of the core plugs are subjected to the different drilling mud formulations and entered into a geomechanical model. The output of the geomechanical model (e.g., an FEM) is a range of operational mud weights that will allow for successful hydraulic fracturing and/or not cause borehole instability. From the output, a drilling mud is chosen from among those tested to be used in a drilling operation.
The computer (602) can serve in a role as a client, network component, a server, a database or other persistency, or any other component (or a combination of roles) of a computer system for performing the subject matter described in the instant disclosure. The illustrated computer (602) is communicably coupled with a network (630). In some implementations, one or more components of the computer (602) may be configured to operate within environments, including cloud-computing-based, local, global, or other environment (or a combination of environments).
At a high level, the computer (602) is an electronic computing device operable to receive, transmit, process, store, or manage data and information associated with the described subject matter. According to some implementations, the computer (602) may also include or be communicably coupled with an application server, e-mail server, web server, caching server, streaming data server, business intelligence (BI) server, or other server (or a combination of servers).
The computer (602) can receive requests over network (630) from a client application (for example, executing on another computer (602)) and responding to the received requests by processing the said requests in an appropriate software application. In addition, requests may also be sent to the computer (602) from internal users (for example, from a command console or by other appropriate access method), external or third-parties, other automated applications, as well as any other appropriate entities, individuals, systems, or computers.
Each of the components of the computer (602) can communicate using a system bus (603). In some implementations, any or all of the components of the computer (602), both hardware or software (or a combination of hardware and software), may interface with each other or the interface (604) (or a combination of both) over the system bus (603) using an application programming interface (API) (612) or a service layer (613) (or a combination of the API (612) and service layer (613)). The API (612) may include specifications for routines, data structures, and object classes. The API (612) may be either computer-language independent or dependent and refer to a complete interface, a single function, or even a set of APIs. The service layer (613) provides software services to the computer (602) or other components (whether or not illustrated) that are communicably coupled to the computer (602). The functionality of the computer (602) may be accessible for all service consumers using this service layer. Software services, such as those provided by the service layer (613), provide reusable, defined business functionalities through a defined interface. For example, the interface may be software written in JAVA, C++, or other suitable language providing data in extensible markup language (XML) format or another suitable format. While illustrated as an integrated component of the computer (602), alternative implementations may illustrate the API (612) or the service layer (613) as stand-alone components in relation to other components of the computer (602) or other components (whether or not illustrated) that are communicably coupled to the computer (602). Moreover, any or all parts of the API (612) or the service layer (613) may be implemented as child or sub-modules of another software module, enterprise application, or hardware module without departing from the scope of this disclosure.
The computer (602) includes an interface (604). Although illustrated as a single interface (604) in
The computer (602) includes at least one computer processor (605). Although illustrated as a single computer processor (605) in
The computer (602) also includes a memory (606) that holds data for the computer (602) or other components (or a combination of both) that can be connected to the network (630). For example, memory (606) can be a database storing data consistent with this disclosure. Although illustrated as a single memory (606) in
The application (607) is an algorithmic software engine providing functionality according to particular needs, desires, or particular implementations of the computer (602), particularly with respect to functionality described in this disclosure. For example, application (607) can serve as one or more components, modules, applications, etc. Further, although illustrated as a single application (607), the application (607) may be implemented as multiple applications (607) on the computer (602). In addition, although illustrated as integral to the computer (602), in alternative implementations, the application (607) can be external to the computer (602).
There may be any number of computers (602) associated with, or external to, a computer system containing computer (602), wherein each computer (602) communicates over network (630). Further, the term “client,” “user,” and other appropriate terminology may be used interchangeably as appropriate without departing from the scope of this disclosure. Moreover, this disclosure contemplates that many users may use one computer (602), or that one user may use multiple computers (602).
Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims.
