Managing lost circulation of drilling fluid

Abstract

Techniques for managing lost circulation of a drilling fluid in a subterranean reservoir include generating a 3D natural fracture model that includes a 3D discrete fracture network and a brittleness model for a subterranean formation; converting the 3D discrete fracture network into a 2D model to determine a continuous fracture density property; predicting a plurality of fluid-flow pathways using the continuous fracture density property modeled for each brittleness; and determining, based on the predicted plurality of fluid-flow pathways, a lost circulation strategy that includes a plurality of lost circulation remedies configured to implement in response to encountering a lost circulation of a drilling fluid into the subterranean formation from a wellbore with a drilling rig and a drilling fluid.

Description

TECHNICAL FIELD

[0001] The present disclosure describes apparatus, systems, and methods for managing lost circulation of drilling fluid and, more particularly, predicting lost circulation of drilling fluid into one or more formations through modeling of natural fractures within the formations.BACKGROUND

[0002] In rotary drilling of oil and gas wells, the drilling fluid is circulated through a drill string down the drill bit and then back to the surface through the annulus between the wellbore and the drill string. The drilling fluid maintains hydrostatic pressure on the subterranean formations through which the wellbore is drilled to prevent pressurized formation fluid from entering the wellbore and to circulate drilled cuttings out of the wellbore. If the wellbore fluids cannot be circulated out of the hole (fully or partially) due to any kind of subterranean conditions, it is termed “lost circulation.”SUMMARY

[0003] In an example implementation, a method for managing lost circulation of a drilling fluid in a subterranean reservoir includes generating, with one or more hardware processors of a control system, a 3D natural fracture model that includes a 3D discrete fracture network and a brittleness model for a subterranean formation; converting, with the one or more hardware processors, the 3D discrete fracture network into a 2D model to determine a continuous fracture density property; predicting, with the one or more hardware processors, a plurality of fluid-flow pathways using the continuous fracture density property modeled for each brittleness; determining, based on the predicted plurality of fluid-flow pathways, a lost circulation strategy that includes a plurality of lost circulation remedies; subsequent to the determination of the lost circulation strategy, drilling a portion of a wellbore from the terranean surface into the subterranean formation with a drilling rig and a drilling fluid; during the drilling of the portion of the wellbore, encountering lost circulation of the drilling fluid into the subterranean formation from the wellbore; and in response to encountering the lost circulation, performing a wellbore operation that includes at least one of the plurality of lost circulation remedies.

[0004] An aspect combinable with the example implementation includes completing drilling of the wellbore into the subterranean formation subsequent to performing the wellbore operation.

[0005] In another aspect combinable with one, some, or all of the previous aspects, the subterranean formation includes a plurality of natural fractures, and the 3D discrete fracture network includes the plurality of natural fractures.

[0006] Another aspect combinable with one, some, or all of the previous aspects includes logging the portion of the wellbore to determine one or more logged properties subsequent to drilling the portion of the wellbore from the terranean surface into the subterranean formation.

[0007] In another aspect combinable with one, some, or all of the previous aspects, logging the portion of the wellbore to determine one or more logged properties includes performing at least one high precision temperature (HPT) logging run to generate at least one HPT log of the portion of the wellbore; and performing at least one spectral noise logging (SNL) run to generate at least one spectral noise log of the portion of the wellbore.

[0008] In another aspect combinable with one, some, or all of the previous aspects, performing at least one spectral noise logging (SNL) run to generate at least one spectral noise log of the portion of the wellbore includes performing a first SNL run at flowing conditions of the wellbore to generate a first spectral noise log of the portion of the wellbore; and performing a second SNL run at shut-in conditions of the wellbore to generate a second spectral noise log of the portion of the wellbore.

[0009] Another aspect combinable with one, some, or all of the previous aspects includes generating a composite log that includes a fracture density index, the predicted plurality of fluid-flow pathways, the at least one HPT log, and the at least one spectral noise log of the wellbore; and comparing, with the one or more hardware processors, the predicted plurality of fluid-flow pathways with portions of the at least one HPT log, and the at least one spectral noise log.

[0010] In another aspect combinable with one, some, or all of the previous aspects, the plurality of lost circulation remedies include a first set of lost circulation remedies associated with a first magnitude of lost drilling fluid within a pumping capacity of the drilling rig; and a second set of lost circulation remedies associated with a second magnitude of lost drilling fluid outside of the pumping capacity of the drilling rig.

[0011] In another aspect combinable with one, some, or all of the previous aspects, the first set of lost circulation remedies include a first lost circulation remedy of pumping fibrous material to the portion of the wellbore and a second lost circulation remedy of a wellbore strengthening treatment, and the second set of lost circulation remedies include a third lost circulation remedy of creating a wedge effect in the subterranean formation.

[0012] In another example implementation, a computer-implemented method performed with one or more hardware processors includes generating, with one or more hardware processors of a control system, a 3D natural fracture model that includes a 3D discrete fracture network and a brittleness model for a subterranean formation; converting, with the one or more hardware processors, the 3D discrete fracture network into a 2D model to determine a continuous fracture density property; predicting, with the one or more hardware processors, a plurality of fluid-flow pathways using the continuous fracture density property modeled for each brittleness; and determining, with the one or more hardware processors and based on the predicted plurality of fluid-flow pathways, a lost circulation strategy that includes a plurality of lost circulation remedies configured to implement in response to encountering a lost circulation of a drilling fluid into the subterranean formation from a wellbore with a drilling rig and a drilling fluid.

[0013] In an aspect combinable with the example implementation, the subterranean formation includes a plurality of natural fractures, and the 3D discrete fracture network includes the plurality of natural fractures.

[0014] Another aspect combinable with one, some, or all of the previous aspects includes generating at least one log of the portion of the wellbore of one or more logged properties of at least a portion of the wellbore drilled from the terranean surface into the subterranean formation.

[0015] In another aspect combinable with one, some, or all of the previous aspects, the at least one log of the one or more logged properties includes at least one high precision temperature (HPT) log of the portion of the wellbore; and at least one spectral noise logging (SNL) log of the portion of the wellbore.

[0016] In another aspect combinable with one, some, or all of the previous aspects, the at least one spectral noise logging (SNL) log of the portion of the wellbore includes a first spectral noise log of the portion of the wellbore that includes a first SNL log run at flowing conditions of the wellbore; and a second spectral noise log of the portion of the wellbore that includes a second SNL log run at shut-in conditions of the wellbore.

[0017] Another aspect combinable with one, some, or all of the previous aspects includes generating, with the one or more hardware processors, a composite log that includes a fracture density index, the predicted plurality of fluid-flow pathways, the at least one HPT log, and the at least one spectral noise log of the wellbore; and comparing, with the one or more hardware processors, the predicted plurality of fluid-flow pathways with portions of the at least one HPT log, and the at least one spectral noise log.

[0018] In another aspect combinable with one, some, or all of the previous aspects, the plurality of lost circulation remedies include a first set of lost circulation remedies associated with a first magnitude of lost drilling fluid within a pumping capacity of the drilling rig; and a second set of lost circulation remedies associated with a second magnitude of lost drilling fluid outside of the pumping capacity of the drilling rig.

[0019] In another aspect combinable with one, some, or all of the previous aspects, the first set of lost circulation remedies include a first lost circulation remedy of pumping fibrous material to the portion of the wellbore and a second lost circulation remedy of a wellbore strengthening treatment, and the second set of lost circulation remedies include a third lost circulation remedy of creating a wedge effect in the subterranean formation.

[0020] In another example implementation, a computing system includes one or more memory modules that store instructions; and one or more hardware processors communicably coupled to the one or more memory modules and configured to execute the instructions to perform operations. The operations include generating a 3D natural fracture model that includes a 3D discrete fracture network and a brittleness model for a subterranean formation; converting the 3D discrete fracture network into a 2D model to determine a continuous fracture density property; predicting a plurality of fluid-flow pathways using the continuous fracture density property modeled for each brittleness; and determining, based on the predicted plurality of fluid-flow pathways, a lost circulation strategy that includes a plurality of lost circulation remedies configured to implement in response to encountering a lost circulation of a drilling fluid into the subterranean formation from a wellbore with a drilling rig and a drilling fluid.

[0021] In an aspect combinable with the example implementation, the subterranean formation includes a plurality of natural fractures, and the 3D discrete fracture network includes the plurality of natural fractures.

[0022] In another aspect combinable with one, some, or all of the previous aspects, the operations include generating at least one log of the portion of the wellbore of one or more logged properties of at least a portion of the wellbore drilled from the terranean surface into the subterranean formation.

[0023] In another aspect combinable with one, some, or all of the previous aspects, the at least one log of the one or more logged properties includes at least one high precision temperature (HPT) log of the portion of the wellbore; and at least one spectral noise logging (SNL) log of the portion of the wellbore.

[0024] In another aspect combinable with one, some, or all of the previous aspects, the at least one spectral noise logging (SNL) log of the portion of the wellbore includes a first spectral noise log of the portion of the wellbore that includes a first SNL log run at flowing conditions of the wellbore; and a second spectral noise log of the portion of the wellbore that includes a second SNL log run at shut-in conditions of the wellbore.

[0025] In another aspect combinable with one, some, or all of the previous aspects, the operations include generating a composite log that includes a fracture density index, the predicted plurality of fluid-flow pathways, the at least one HPT log, and the at least one spectral noise log of the wellbore; and comparing the predicted plurality of fluid-flow pathways with portions of the at least one HPT log, and the at least one spectral noise log.

[0026] In another aspect combinable with one, some, or all of the previous aspects, the plurality of lost circulation remedies include a first set of lost circulation remedies associated with a first magnitude of lost drilling fluid within a pumping capacity of the drilling rig; and a second set of lost circulation remedies associated with a second magnitude of lost drilling fluid outside of the pumping capacity of the drilling rig.

[0027] In another aspect combinable with one, some, or all of the previous aspects, the first set of lost circulation remedies include a first lost circulation remedy of pumping fibrous material to the portion of the wellbore and a second lost circulation remedy of a wellbore strengthening treatment, and the second set of lost circulation remedies include a third lost circulation remedy of creating a wedge effect in the subterranean formation.

[0028] Implementations of apparatus, systems, and methods for managing lost circulation in drilling a wellbore into a subterranean reservoir according to the present disclosure may include one or more of the following features. For example, aspects of the present disclosure can predict a presence of special flow-paths defined as critical stress fractures, which conventionally, cannot be physically captured on normal logs but are modeled. As another example, aspects of the present disclosure further validate the presence of the critical fractures by being able to physically capture them through actual fluid movement (for example, behind a casing) on logged parameters from areas that were predicted in a model. Aspects of the present disclosure can provide for physical measurements of fracture contributions, which further serves to calibrate three-dimensional fracture models. Aspects of the present disclosure can provide a workflow for a holistic and practical solution to managing lost circulation while drilling. Aspects of the present disclosure can incorporate various pieces of technologies to deliver a more robust end product to manage lost circulation, such as introducing fracture density mapping and high precision logging services that enhance the definition or the main parameters of the problem to allow easier management.

[0029] The details of one or more implementations of the subject matter described in this disclosure are set forth in the accompanying drawings and the description below. Other features, aspects, and advantages of the subject matter will become apparent from the description, the drawings, and the claims.BRIEF DESCRIPTION OF THE DRAWINGS

[0030] FIG. 1 is a schematic diagram of a wellbore system formed into one or more naturally fractured hydrocarbon production zones into which lost circulation can occur according to the present disclosure.

[0031] FIG. 2 is an example method for managing lost circulation encountered when forming a wellbore into a subterranean formation according to the present disclosure.

[0032] FIGS. 3A-3B are a diagram and graph, respectively, that describe a stress state on a discrete portion of a subterranean formation according to the present disclosure.

[0033] FIG. 4 shows several graphical representations of a brittleness property of a discrete portion of a subterranean formation according to the present disclosure.

[0034] FIGS. 5A-5B show graphical representations of a 2D fracture network as input for the line density computation according to the present disclosure.

[0035] FIG. 6 shows a graphical representation of a gray-scale normalization of the fracture density index (FDI) according to the present disclosure.

[0036] FIG. 7 shows a diagram of an injection profile using water along a horizontal wellbore formed into a naturally-fractured formation according to the present disclosure.

[0037] FIG. 8 shows a diagram of a production profile with gas along a horizontal wellbore formed into a naturally-fractured formation according to the present disclosure.

[0038] FIG. 9 shows a diagram of fracture distribution varied between stages on a horizontal wellbore formed into a naturally-fractured formation according to the present disclosure.

[0039] FIG. 10 is a schematic diagram of an example control system according to the present disclosure.DETAILED DESCRIPTION

[0040] The present disclosure describes example implementations of systems and methods for managing lost circulation of drilling fluid into one or more subterranean formations during drilling operations to form one or more wellbores. In example implementations, systems and methods for managing lost circulation predict, establish, diagnose, and correct low formation integrity problems during the drilling of subterranean wellbore intervals. For example, example implementations manage weak wellbores by predicting their occurrence and estimating their characteristics of naturally occurring fractures (for example, fracture dimensions, fracture intensity, etc.). Having a reasonable idea of the anticipated fracture zone / loss zone, implementations according to the present disclosure utilize (select and treat) many lost circulation methods available to manage lost circulation.

[0041] Generally, subterranean formations being drilled through often contain naturally occurring or drilling induced weak zones having low tensile strengths and / or openings such as natural fractures, faults, and high permeability streaks. Induced or natural formation fractures, and faults serve as conduits for fluid losses and their presence causes lost circulation. In other situations, like the infill drilling of wells in long-term producing fields the reservoir pressure depletes owing to large volumes of fluid extraction and the formations tend to weaken as the closure stress increases with declining reservoir pressures.

[0042] The weak zones in such wellbores exhibit poor pressure holding integrity and are subject to failure because of the hydrostatic pressure or the combination of the hydrostatic and friction pressure exerted against the walls of the wellbores while drilling. The pressures exerted exceed the strength of the weak zones in the wellbore and cause wellbore fluid losses into the formation. Furthermore, in exploration drilling it is sometimes difficult to have a good understanding of the regional pressure trends and the complex structural elements which when coupled with the challenges in properly interpreting seismic data leads to encounters of unanticipated pressure regression zones saddled between geo-pressured, shale-bound sands. In such cases the mud weight (MW) margin can become critical where fractional changes in mud weight can cause lost circulation or flow from the formation. Potential risks when drilling through a narrow-margin zone are wellbore instability, wellbore fracturing, and consequently, lost circulation, which, in turn, can lead to nonproductive drilling time, sidetracks, or even losing the well.

[0043] Accordingly, when the first signs of poor wellbore pressure holding integrity appear, rig operators are often forced to prematurely set casing or run a liner in the well bore. In many cases plugging back the well must be implemented to allow casing to be set or to drill an adjacent sidetrack or bypass well bore. These incidents of lost circulation can lead to many problems including but not limited to, increasing the delivery time of the well, formation damage, wellbore instability issues, stuck pipe, etc. Because of these obstacles, millions of dollars are spent every year to mitigate and / or stop lost circulation.

[0044] The challenges described above can be broadly categorized in two categories: a) lost circulation resulting from induced fracturing or by drilling through permeable zones having intergranular porosity while using high mud weight overbalance, and b) severe lost circulation due to naturally fractured, cavernous or vugular formation intervals in a sub-hydrostatic pressure environment. The magnitude and complexity of the lost circulation problem in the latter case can sometimes be insurmountable. In such dire lost circulation cases alternative drilling methods such as foam drilling, managed pressure drilling, drilling with a mud cap or setting aside a casing string to case-off this problematic hole section should be considered.

[0045] The first type of lost circulation problem is addressed by many operators by extending the fracture gradient of the formation using wellbore strengthening methods. Technical theories, mathematical models and different types of lost circulation materials help design and achieve sufficient wellbore strengthening to drill through troublesome zones. However, the foremost requirement in managing lost circulation is predicting its occurrence and it is even more critical to estimate its characteristics (such as fracture dimensions, fracture intensity, etc.). Having a reasonable idea of the anticipated fracture zone / loss zone, it is possible to utilize (select and treat) lost circulation methods to solve these problems.

[0046] FIG. 1 is a schematic diagram of a wellbore system 10 that includes a naturally fractured formation 40 into which a wellbore 20 is formed. Generally, FIG. 1 illustrates a portion of one embodiment of the wellbore system 10 in which wellbore 20 is formed into the naturally fractured subterranean formation (or reservoir) 40 for the production of one or more hydrocarbon fluids to a terranean surface 12 (through the wellbore 20 and, if used, one or more wellbore tubular strings). Naturally fractured subterranean formation 40 that holds the hydrocarbon fluid(s) can be present beneath several other formation rock layers. The formation 40 can include a primary porous medium of the formation rock. An irregular system of microscopic fractures and small cavities or vugs can be typically present in the primary porous rock medium. Natural fractures 75 in the formation 40 can also be present across a wide range of scale, ranging from microfractures to extensive fractures or faults of thousands of meters. The vertical extent of natural fractures 75 is often controlled by thin layers in the form of shale beds or laminations, or by weak layers of rock in carbonate sequences in the earth.

[0047] Natural fractures 75 can be abundant structural features in the formation 40. As described above, natural fractures 75 may be caused by a variety of factors including stress in the formation from tectonic forces, which cause folds and the like. It is typical that a hydrocarbon producing reservoir (such as formation 40) contains some natural fractures 75, but as described the location and extent of such natural fractures 75 is not directly determinable. Natural fractured reservoirs are difficult systems to characterize and difficult to engineer and predict. Natural fractured reservoirs are an important element in reservoir performance, and it is also important to recognize the performance characteristics of a naturally fractured reservoir.

[0048] Natural fractures 75 can significantly affect hydrocarbon migration and trap location in the subsurface formations, as well as flow of hydrocarbons to wellbores during production. Knowledge of the presence and extent of natural fractures can significantly improve reservoir development and reduce hydrocarbon production risks. Conventional methods to produce a natural fracture model are based on rock properties (Porosity, density, etc.) and fracture characterization along the wells using in some case the post stack seismic attribute as a drive for natural fracture prediction. The conventional methodologies have been based on assumption taking the fracture description from the wells and extrapolate those into the grid model following a conceptual model.

[0049] As shown, the wellbore system 10 accesses a subterranean formation 40 that provides access to hydrocarbons located in such subterranean formation 40. A drilling assembly (not shown) may be used to form the wellbore 20 extending from the terranean surface 12 and through one or more geological formations in the Earth. One or more subterranean formations, such as subterranean formation 40, are located under the terranean surface 12. As will be explained in more detail below, one or more wellbore casings, such as an intermediate casing 30 and production casing 35, may be installed in at least a portion of the wellbore 20. In some embodiments, a drilling assembly used to form the wellbore 20 may be deployed on a body of water rather than the terranean surface 12. For instance, in some embodiments, the terranean surface 12 may be an ocean, gulf, sea, or any other body of water under which hydrocarbon-bearing formations may be found. In short, reference to the terranean surface 12 includes both land and water surfaces and contemplates forming and developing one or more wellbore systems 10 from either or both locations.

[0050] In some embodiments of the wellbore system 10, the wellbore 20 may be cased with one or more casings. As illustrated, the wellbore 20 includes a conductor casing 25, which extends from the terranean surface 12 shortly into the Earth. A portion of the wellbore 20 enclosed by the conductor casing 25 may be a large diameter borehole. Additionally, in some embodiments, the wellbore 20 may be offset from vertical (for example, a slant wellbore). Even further, in some embodiments, the wellbore 20 may be a stepped wellbore, such that a portion is drilled vertically downward and then curved to a substantially horizontal wellbore portion. Additional substantially vertical and horizontal wellbore portions may be added according to, for example, the type of terranean surface 12, the depth of one or more target subterranean formations, the depth of one or more productive subterranean formations, or other criteria.

[0051] Downhole of the conductor casing 25 can be the intermediate casing 30. The intermediate casing 30 may enclose a slightly smaller borehole and protect the wellbore 20 from intrusion of, for example, freshwater aquifers located near the terranean surface 12. The wellbore 20 may than extend vertically downward. This portion of the wellbore 20 may be enclosed by the production casing 35. Other casings, not specifically shown in this figure, can be included within the wellbore system 10 without departing from the scope of this disclosure. Further, other tubulars (such as liners or otherwise), along with casings, can generally be referred to as “wellbore tubulars” in the present disclosure.

[0052] As shown in FIG. 1, a cement layer 55 (or cement 55) is installed in an annulus between each illustrated casing (conductor casing 25, intermediate casing 30, and production casing 35) and the adjacent geologic formation (such as subterranean formation 40). Cement 55 can be circulated downward, during the construction of the wellbore system 10, through one or more casings and back upward into the annulus between the particular casing and the adjacent geologic formation in order to, for example, bond the casing to the formation. Once solidified in the annulus, the cement 55 can provide a barrier to fluid entry into the wellbore 20 as well as maintain the casings in place.

[0053] In the schematic of FIG. 1, a logging tool 100 is shown run into the wellbore 20 on a downhole conveyance 50 (such as a wireline, slickline, coiled tubing, or other conveyance). The logging tool 100, in this figure, can represent one or more logging tools 100 that are run into the wellbore 20 (sequentially in different trips or along the same conveyance 50 in a single trip) to sense or measure one or more logged parameters of the subterranean formation 40 and / or wellbore 20. As wellbore system 10 can also represent a drilling system with a drilling rig (not shown), reference number 100 can also represent a bottom hole assembly with a drill bit (BHA) 100 that is coupled to a drill string 50.

[0054] In some aspects and as explained in more detail in this disclosure, the one or more logged parameters can be applied to the concepts of critically stressed fractures and fracture apertures to choose one or more sets of perforation clusters (in other words, fracture zones) in a cased hole completion (such as wellbore 20) or one or more fracturing stage intervals in an open hole completion of the wellbore 20. The one or more logged parameters can be applied in a workflow as a validation technique of a three-dimensional (3D) natural fracture model by providing parameters to physically identify a fluid contribution behind pipe through predicted fractures.

[0055] In some aspects, the one or more logged parameters can be high precision temperature (HPT) logging and spectral noise logging (SNL), which can be used in conjunction with a high precision temperature modeling technique. In some aspects, and as shown through fracturing analysis, that spectral noise logging data have a high degree of correlation with a formation image log used for an identification of different types of fractures, faults, and textural features). However, a formation image log tool can only give an idea of the reservoir structure at the time a well is put on production while new fractures can frequently develop when the well is put on production or some of the fractures identified in the open-hole section stay inactive. Thus, the present disclosure and workflow include critical stress fracture modeling that improves the static formation image log data in combination with an integration of the logged parameters (HPT and / or SNL) to analyze a fluid flow behind a casing in the formation. In some aspects of the present disclosure, active fracture flow zones can be distinctly outlined by the one or more logged parameters to validate the presence of critical fractures.

[0056] As shown in FIG. 1, a logging control system (or control system) 999 can be communicably coupled (wired or wirelessly) to the logging tool 100 to receive and process the logged one or more parameters of the wellbore 20 and / or the formation 40. In some aspects, the logging control system 999 can receive or download the measured or sensed logging parameters subsequent to one or more logging operations performed with the logging tool 100. In some aspects, the logging control system 999 can receive the measured or sensed logging parameters during one or more logging operations performed with the logging tool 100 (for example, in real time as the logging tool 100 is measuring or sensing logged parameters, such as HPT and / or SNL). In some aspects, the logging control system 999 comprises a micro-processor based computing (or distributed) computing system.

[0057] FIG. 2 is an example method 200 for determining and validating one or more predicted hydrocarbon production zones of a subterranean formation. In some aspects, one or more steps of method 200 can be performed with or by the control system 999 of FIG. 1 (with wellbore system 10). Method 200 can begin at step 202, which includes generating a 3D natural fracture model that includes a 3D discrete fracture network and a brittleness model for a subterranean formation into which a wellbore is formed. In some aspects, step 202 can be performed in accordance with the disclosure of U.S. Pat. No. 10,607,043, which is incorporated in its entirety herein by reference. For example, reservoir parameters and properties from a plurality of disciplines of earth science regarding formation 40 are obtained, assembled and stored in logging control system 999. The reservoir parameters can include seismic attributes from seismic surveys; rock and mechanical properties from geological modeling of the formation 40; measures from structural restoration models; rock geological characterizations obtained from formation core samples (of formation 40) and well logs performed in the wellbore 20; and reservoir engineering measures obtained from production measures and reservoir simulations of the subterranean formation 40.

[0058] The assembled reservoir parameters are subjected to fracture modeling. One of the main components for natural fractures prediction under step 202 is the geomechanical model, wherein an in situ stress regime and the paleo-stress deformation accumulated by different geological time have been included into the method 200. In the context of the present invention, the in situ stress regime is a condition where the stress field is unperturbed or is in equilibrium without any production or influences of perforated wells.

[0059] Turning to FIG. 3A, this figure shows a schematic 300 of a critically stressed formation as formation 40. Schematic 300 shows how stresses (σ1 through σ3) on a discrete portion of the formation 40. FIG. 3B shows a graph 350 with x-axis of effective normal stress (σ) and shear stress (τ) act on the discrete portion of the formation 40. Generally, permeability in the formation 40 is equal or substantially equal to the permeability from normal closure plus the permeability from shear dilatation.

[0060] In some aspects, the main fluid flow pathways of hydrocarbon fluid flow in a reservoir are discriminated from a 3D Discrete Fracture Network (DFN) resulting from a geomechanics and natural fracture prediction (NFP) modeling workflow. The present disclosure applies the concepts of critically stressed fractures and fracture apertures estimation described in U.S. Pat. No. 10,607,043. From the different fracture sets existing within the reservoir, only certain fractures may be optimally oriented under “in situ stress” for shearing reactivation, and therefore, hydraulically more conductive. Fracture aperture computed using a micro-resistivity method confirms that fractures closer to failure by shear stress exhibit larger apertures and therefore, they are expected to have higher permeability. The result of this analysis is a discretized 3D Fracture Network, containing only fractures representing main fluid pathways in the reservoir. FIGS. 3A-3B illustrate the concept of critically stressed fractures.

[0061] The natural fracture system of formation 40 is closely related with the current and past deformation due the stress variation through the geological time. Different types of fractures can be created during those episodes. For instance, step 202 can include two phases or stages. A first processing stage takes the form of a geomechanics fracture controller, while a second processing stage produces a predicted natural fracture model.

[0062] The geomechanics fracture controller involves integration between a paleo-stress from a structural restoration model obtained for several stages in geological time, and current stress regime conditions obtained through geomechanical numerical simulation model. This step involves seismic volume interpretation techniques and attributes that can be applied to detect possible faults and natural fractures alignments by using post stack discontinuities attributes, azimuthal analysis and elastic seismic inversion.

[0063] The natural fracture model prediction processing stage is performed to quantify fracture density in the subterranean formation 40 using the geomechanics fracture controller results, and fracture characterization provided from core samples and borehole well log images from a borehole image (BHI) analysis process. This sub-step can also determine fracture dimensions and their properties into the discrete fracture model, as will be described. Examples of the fracture properties include fracture position, orientation, geometry, porosity, aperture, permeability, and the like.

[0064] In the fracture modeling validation or confirmation processing step, the fracture model is cross-checked or validated using reservoir production data. If necessary, the natural fracture model may need to be upscaled to conform to a fine-scale cell grid of geological model and reproduce the natural fracture distribution and their properties, for comparison with the reservoir production data for validation proposes. Several types of reservoir production data can be used to calibrate the fracture model with reservoir engineering data. Example of such reservoir production data are results of measures obtained from: PTA (Pressure Transient Analysis), tracers, drilling operation events, PLT (production logs), and the like.

[0065] Considering the natural fracture model prediction processing stage, a seismic fracture detection process is provided with seismic attributes obtained from seismic volume results. The seismic attributes provided are attributes related to natural fractures detections or dislocation detections. Examples of such attributes obtained from the seismic dislocations attribute analysis results are variance, anti-tracking, flatness, curvature, and the like. It should be understood that other seismic attributes might also be provided. Seismic fracture attributes cannot be compared straight forward at wellbore scale due to resolutions issues. However, seismic attributes can be used as a seismic fracture controller or conduct for minor fractures detected at wellbore scale, if the relations regarding to the locations and intensity between them exist.

[0066] Advance seismic fracture detection may also be performed, if desired, during the seismic fracture detection process using azimuthal seismic analysis, in order to capture the variations of the wave propagation at different directions. Such variations in wave propagation form anisotropic volumes in the subterranean formation 40 and are helpful in detecting fractures. This azimuthal analysis requires knowledge regarding whether the anisotropy response in the formation 40 is due to natural fractures or caused by another reason. In order to identify whether the anisotropy response maybe azimuthal shear anisotropy, sonic acoustic acquisition can be performed at the well location. An example of azimuthal seismic analysis is described in: Gray, F. D. and Head, K. J., 2000, Fracture Detection in the Manderson Field: A 3D AVAZ Case History: The Leading Edge, Vol. 19, No. 11, 1214-1221; and Khalid Al-Hawas, Mohammed Ameen, Mohammad Wahab, and Ed Nebrija, Saudi Aramco, Dhahran, Saudi Arabia Colin Macbeth, Heriot-Watt University, Edinburgh, U. K., 2003, “Delineation of Fracture Anisotropy Signatures in Wudayhi Field by azimuthal seismic data, the Leading Edge.”

[0067] A 1D mechanical earth model (MEM) of the geomechanics fracture controller determines the rock mechanical properties and stress regime conditions in the subterranean formation 40. The 1D MEM process starts with computing the elastic rock mechanical properties deriving from well logs and rock mechanical tests; and using additional information as reservoir formation pressures and a Formation Integrity Test (FIT), the in situ stress regime can be predicted and mechanical stratigraphy (Geomechanical Facies) computed. Thus, mechanical stratigraphy conforms the rock mechanical response to the geological deformation process and can be used as constraints for natural fractures presence, constraining their development to some particular layer through brittleness concepts, depending also of the deformation magnitude. Additionally, the maximum horizontal stress direction which can be detected by a Borehole Image Analysis (BHI), and the in situ stress magnitude derived from 1D MEM process are used to predict the stress regime.

[0068] A 2D / 3D geomechanics forward model process of the natural fracture model prediction processing stage combines a structural model and displacement, paleo-stress and strain measures from the structural restoration model with petrophysical properties from a geological model. The results take the form of structural restoration as horizons displacement and deformation using boundary conditions. The 2D / 3D geomechanics forward model process is performed as a Finite Element Method (FEM) using geomechanics numerical simulation software, to estimate the tensor stress regime corresponding to the deformation estimate from structural restoration at the in situ stress conditions.

[0069] As part of step 202 and in generating the 3D natural fracture model, a rock brittleness index can be developed. For example, a rock brittleness property can be differentiated when subjected to stress; it breaks without significant plastic deformation. Brittle materials absorb relatively little energy prior to fracture, even those of high strength. In a complex heterogeneous fracture rock mass (such as formation 40), the brittleness property can be modeled using neuronal network classification taking as inputs the elastic properties and stress regime producing mechanical facies. Those mechanical facies can have some proportional relation with the distribution of natural fractures.

[0070] This correlation can be evaluated using a histogram filtered by density fracture. For example, FIG. 4 shows several graphical representations of a brittleness property of a discrete portion of a subterranean formation, such as subterranean formation 40. The graphical representations 400, 420, and 450 show a 3D brittleness model related to the density of natural fractures 75 in the subterranean formation 40. For example, graph 400 includes a histogram of numerical values 406a-406f that represent numerical values (measured on the y-axis 404) for each discrete brittleness value (measured on x-axis 402). As shown, there is a higher number (406a) of more brittle portions of the formation 40 than least brittle portions (406f). Fracture density 408 is inversely proportional to brittleness. Graph 420 is plot of Young's Modulus (YM) and Poisson Ratio (PR); the mechanical properties of the rock. As seen in the graph a rock with low PR value and high YM value is highly brittle while on the right end of the plot with high PR value and low YM the rock tends to be more ductile. This correlation from graph 420 is extended to the entire field in graph 450 and the propensity of fracture density is related to the brittleness of the rock.

[0071] Step 202 can also include converting the 3D discrete fracture network into a 2D model to determine a continuous fracture density property. For instance, the 3D discrete fracture network representing critically stressed fluid pathways resulting from step 202 can be converted into 2D lines to compute a continuous fracture density property by, for example, an available GIS geo-processing software (commercial and open) with tools to compute line density (for example, Esri-ArcGISTM) to generate a raster map representing fracture density per area. A suitable color -indexed palette can be assigned in order to visually spot areas where natural fractures are more concentrated. FIGS. 5A-5B show a 2D fracture network as input for the line density computation. For instance, FIG. 5A shows graphical representation 500 of a 2D fracture network that represents the main fluid pathways. FIG. 5B shows graphical representation 550 of a computed line density raster using the 2D fracture network as input.

[0072] FIG. 6 shows a gray-scale normalization of the fracture density index (FDI). More specifically, graphical representation 600 is a gray scale normalized image from the 2D raster map to represent a relative variability of the fluid-flow paths concentration. The highly concentrated areas of flow-paths with darker gray and the lowest concentrated areas of flow paths with white color.

[0073] Method 200 can continue at step 204, which includes predicting a plurality of fluid-flow pathways using the fracture density property modeled for each brittleness. For example, fluid-flow paths for the natural fractures can be predicted using the equivalent fracture density modeled for each brittleness index class (of FIG. 5A) defined on the histogram as shown in graph 400, combined with the response on Fracture Density Index normalized (shown in FIG. 6).

[0074] Method 200 can continue at step 206, which includes determining a lost circulation strategy based on the predicted fluid-flow paths. For example, it can be advantageous to be prepared ahead of time in controlling wellbore lost circulation. Traditionally, a basic lost circulation control contingency plan is normally available on a drilling rig, but its effectiveness can be very limited and, in some cases, completely inadequate. One of the essential evaluations to be made once lost circulation begins is whether the loss rates exceed the rig's pumping capabilities. Generally, loss rates within the pumping capabilities can be improved with the proper application of conventional sacked sealing materials aided by proper understanding of the loss mechanism. Extreme losses seen in naturally fractured, cavernous types of formation are difficult to control. The fluid loss rates in such circumstances exceed the pumping capacity of the rig and cannot be replenished by rig; drilling ahead is stopped until some fluid returns can be established through lost circulation treatment. An essential component to achieve success is having an idea of the geometry of the natural fracture (for example, dimensions of fractures) so that the correct or most efficient lost circulation mitigation approach can be taken.

[0075] Steps 202 and 204 of method provide for modeling a naturally fractured reservoir to determine or predict fluid-flow paths, which is then used to determine an appropriate lost circulation control strategy. Utilizing the integrated fracture models as generated in step 202 can provide a good prediction of the fracture properties leading to the ability to design lost circulation treatments rather than use “trial & error” practices during drilling operations.

[0076] Method 200 utilizes the predicted fluid-flow paths to improve the chances of success of mitigating lost circulation by collecting relevant well parameters and well condition information such as: 1. Location of the lost circulation interval (top and bottom); 2. A reasonable estimate of the pressure within the zone; 3. Some determination of the fracture dimensions (i.e., size of the openings into the zone); and 4. Presence of cross-flow between an over-pressured zone and a loss interval.

[0077] For example, the integrated fracture models can help properly build lost circulation contingencies prior to drilling the problematic zones. For simplicity, the lost circulation treatment designs determined in step 206 can broadly be classified under two categories of loss situations: a) losses “within” the rig pump's pumping capacity and b) “beyond” the pump's capacity. In some aspects, there can be further sub-sets to this category i) a fracture width limit that can be controlled and ii) a width limit that is beyond control.

[0078] Treatment within the rig pump's capacity includes solving several lost circulation issues. An example lost circulation treatment in this category includes a minor seepage losses situation. Materials used effectively for minor losses are “fibers and fillers”: fibrous material, such as straw, cane fiber, paper, etc.; granular materials, such as ground nut hulls and saw-dust; flake material, such as cellophane, mica, etc. and a combination of these materials.

[0079] Another example lost circulation treatment in this category includes wellbore strengthening treatments. This is a practice that elevates the breakdown limit of a narrow-margin wellbore through proper formulation and design of bridging material. By increasing the breakdown limit the well can be drilled to a deeper depth than it could otherwise. Wellbore strengthening solutions can apply to a wide range of lost circulation conditions. The crux of the issue can be summarized to fracture width management to control fluid losses, i.e., the remedial treatment should have the ability to seal off the fracture width effectively to be successful. Larger fracture widths will result in higher loss rates and vice versa. Note that the fluid loss rates will affect the rig's pump capacity and ability to control losses.

[0080] The distinction between the lower end of wellbore strengthening application and the higher end is the fracture width. For example, it can be shown that the minimum frac width size fits in the 0 to 350 μm (micrometer) range (0.35mm or 0.0137″) and the higher range would exceed 9 mm (0.35″). The accepted practices for wellbore strengthening in the lower range entail ensuring stability of the wellbore walls and the fracture wings induced while drilling by using different materials. The stability of the wellbore wall is secured by an effective wellbore stress redistribution, which helps prevent initiation of secondary fractures from the wellbore.

[0081] Simultaneously, the stability of the existing fracture wings is secured by partial closure of the fractures on the solid LCM aggregate, therefore decreasing the likelihood of their unstable propagation through the rock. Mathematical solutions (such as described in SPE / IADC-184609-MS reference Halliburton and Abousleiman) are available for these conditions. The types of sealant and LCM products chosen include selected grades of ground marble (GM), resilient graphite carbon (RGC), and ground nutshell (GNS) particles.

[0082] The optimal LCM blend composition corresponding to the obtained maximum extended margin for the wellbore lost circulation limit, ECDmax (Equivalent circulating density-maximum value), can be selected using the following example criteria. One example is particle size distribution. The method selects blend particles size D50 equal to the estimated pre-LCM fracture width with ±10% tolerance for deviation. Another example criteria is blend stiffness. The LCM aggregate stiffness values acquired from laboratory data of uniaxial compression tests with an allowance of ±0.5 for the obtained average optimal stiffness values.

[0083] Treatment beyond the rig pump's capacity includes solving several lost circulation issues. For example, larger fracture widths will result in higher loss rates which can also be treated with wellbore strengthening technologies but may overrun the rig pump's capability.

[0084] The accepted practices for wellbore strengthening in the higher fracture width range (around 0.014″-0.35″) can require creating a “wedge effect” in the formation. Successful “wedge effects” have been created in the formation with an impermeable, deformable, cohesive, extremely viscous fluid that does not bond to the faces of the fractures but widens the fracture (for example, causes a wedge) and seals to increase the pressure containment integrity of the wellbore. The higher end in the fracture width range (beyond what is mentioned here) will be determined by the materials available to create a successful seal in the fracture.

[0085] If it is determined that the pressure holding integrity is inadequate in the initial wellbore interval, a fracture dimension and wedge effect simulation software and other calculations can be performed to determine the feasibility of a fracture sealing composition to increase the pressure holding integrity. This analysis helps the operator select a fracture sealing composition with required properties such as rapid friction pressure development (for example, as described in SPE 87094, U.S. Pat. No. 7,308,936, and IADC 104947). These simulations can be performed using a commercially available hydraulic fracturing simulator, such as one that models a frictional criterion where a specific pressure differential AP across the wedge (from start near wellbore to end of wedge) does not exceed to make the wedge unstable.

[0086] The functional dependence of differential pressure on wedge length and fracture or slot width can be established using appropriate laboratory tests using the fluid of choice. The actual pressure improvement can be determined in an iterative manner by changing the well bore pressure until all the required constraints are satisfied. These constraints are: 1. The wedge material volume remains constant; 2. The relevant wedge stability criterion is satisfied; and 3. The stress intensity factor at the tip of the fracture does not exceed the critical stress intensity factor value.

[0087] The fracture sealing compositions useful in accordance with step 206 of method 200 can include hardenable resins comprised of a resin and catalyst for providing additional strength to the sealing compositions. Examples of sealing composition components include, but are not limited to, Vulcanizing agents, weighting materials, aqueous rubber latexes, hardenable resins, resin catalysts and mixtures thereof. Alternatively, one of many delayed sealant systems such as delayed cross-linking polymer solutions, cement slurries and settable drilling fluids can be spotted in the wellbore interval containing one or more fractures prior to the placement of the fracture sealing composition in the fractures so that the delayed sealing composition enters the fractures first.

[0088] Wells with natural fractures, vugular, or cavernous formations can have very large openings allowing unrestricted flow of whole drilling fluid (or “mud”). Such formations, when coupled with low reservoir pressure gradient (i.e., well below the freshwater gradient, <0.4 psi / ft) the mud loss rate can generally exceed the rig's pumping capabilities to fill up the well. Due to the size of the openings and the pressure differential in such cases, it is rare that conventional lost circulation pills can help control the losses. Even cementing attempts will fail because the slurry will tend to overrun into the fractures due to its own high hydrostatic pressure in the wellbore.

[0089] These well conditions generally require more than one treatment; thus, by the modeling generated in steps 202 and 204, these issues can be solved earlier in a drilling process. For example, steps 202 and 204 can provide additional information. This information (for example, within the initial 3D fracture modeling) offers an early insight into the potential loss circulation problem expected at a defined depth(s). As described here with respect to (optional) step 210, the running of HPT / SNL log can gather information required to help solve the issue. These parameters within the information are, for example, pressure in the loss zone, location of losses in the wellbore, length of the loss interval, a determination if there is cross-flow between exposed zones in the wellbore as a result of the reduced hydrostatics in the wellbore, and losses distribution in the wellbore, which can be used to size of the frac dimensions in the wellbore.

[0090] In some aspects, pressure information can be of primary importance when a complete loss of drilling fluid returns is being experienced. Without this information, the control of the flow of treatment material into the loss zone is left to guesswork and, consequently, the outcome of the treatment attempt is left to chance. Procedures to allow proper placement of control fluid losses in such situations is to use cement retainers (that can isolate hydrostatic pressures) or use plug setting tools (like plug catchers) to ensure least contamination of fluids or use sacrificial pipes that can allow spotting fast-setting cement plugs. The lost circulation fluids in such situations can range from bulk fillers such as mud sacks, burlap bags, canvas, hay, sawdust, styrofoam packing pellets, tires, lumber, etc. The method of treatment and type and size of material can depend on the character, depth, hole size and interval length of the problem. The materials are either loaded into the open hole and pushed into the zone or they are loaded into open-ended drill pipe and pumped into the zone. Reactive fluids used can be liquid sodium silicate and cement slurry trains, “gunk squeeze” materials, lightweight additives with cement, fast-setting cement slurries, foam cement slurries, et.

[0091] In some aspects, a magnitude and complexity of the lost circulation problem in some cases can be insurmountable. In such dire lost circulation cases, alternative drilling methods such as foam drilling, managed pressure drilling, drilling with a mud cap or setting aside a casing string to case-off this problematic hole section can be predicted in step 206.

[0092] Method 200 can continue at step 208, which includes drilling a wellbore into a zone of interest of the subterranean formation and encountering lost circulation while drilling. In some aspects, step 208 includes drilling a new wellbore (for example, recently drilled). Alternatively, the wellbore can be an existing wellbore that is recompleted.

[0093] Method 200 can continue at step 210, which is optional and includes logging the wellbore to determine one or more logged properties. For example, as shown, the logging tool 100 (or multiple logging tools) can be run into the fractured wellbore 20 and measure or sense one or more logged properties. In some aspects, step 210 includes a combination of Spectral Noise Logging (SNL) and High Precision Temperature (HTP) logging. For example, temperature logging can be an efficient technique to locate inflow intervals in the reservoir, evaluate inflow rates in them and the drawdown pressure that creates temperature disturbance, detects cross-flows in the wellbore and / or behind casing and checks for casing, tubing and bottom-hole leakages. Temperature logging can detect wellbore flows with rates much below a mechanical spinner's threshold. Another application of temperature logging is picking flow zones behind unperforated casing that develop through behind-casing channeling. Such findings can be verified or discarded through numerical simulation of temperature logs.

[0094] Regarding SNL, fluid movement generates acoustic noise and the intensity (amplitude) of the noise is proportional to the differential pressure. The noise spectrum on the other hand depends on the medium in which the fluid moves. Larger pores generate low frequency noise whereas small pores produce high frequency noise. However, the boundaries of the frequency spectrum are not well defined and there are overlaps. Nonetheless, a High Definition Spectral Noise Tool (SNL-HD) (implemented in logging tool 100) can provide reasonable information about the nature of the noise origin. It is based on the analysis of data acquired by a broadband high-definition spectral acoustic logging tool. The acoustic signal component produced by fluid flow through the rock matrix can be distinguished from other acoustic signals caused, for example, by wellbore or channel flows by its frequency features. The layer formation pressure is determined by numeric simulation using an empirical correlation between the reservoir fluid flow velocity, pressure gradient, and the reservoir-related component of acoustic power.

[0095] In some aspects, step 210 can include both HPT logging and SNL. For example, fluids moving through the reservoir to the well system have thermal mass and can heat or cool the areas they touch. These temperature changes carry information about fluid behavior, particularly flow rates and profiles. However, the physical laws of thermo-hydrodynamics are complex, and the interactions between them even more so. Numerical temperature simulations are therefore used to model the wellbore, multilayer reservoir and surrounding rocks as well as fluid flows in multilayer reservoir system and a wellbore with respect to cross-flows and channeling between the units. It is coupled by the thermodynamic effects that occur while fluid flows through the formation 40 and wellbore 20. The comparison of computed model results with HPT logging data enhances the interpretation of temperature data and quantifies wellbore and reservoir performance. Combining both HPT logging and SNL with array production logging provides a complete evaluation of borehole and behind liner flow and allows for better optimization of reservoir production in such challenging environment. Modeling can show that, along with wellbore flow and reservoir pressure verification, HPT logging is capable to distinguish the active reservoir zones behind perforations, which cannot be reliably captured by spinners.

[0096] The use of HPT / SNL logs (as in step 210) run in injection and production modes reveal the presence (or absence) of natural fractures inconspicuous in reservoirs known to be extremely tight with very low permeabilities. Using the HPT / SNL log combination to locate fracture inflows and quantify inflow profiles in hydraulically fractured wells can be complemented by a 3D fracture model used for validating the presence of natural fractures. These logs enable establishing flow profiles with different fluids (gas or liquids), which can be applied in different well conditions to extend the investigation to vertical wells and in long horizontal wellbores for fracture identification, fracture contribution, and fracture distribution. Using advanced thermodynamic and hydrodynamic models, temperature, pressure, and other well system data can be transformed into accurate and continuous reservoir flow profiles. Thus, the modeled reservoir in combination with the acoustic data (SNL log) can distinguish between flow regimes (for example, linear flow) to help identify natural fractures (or hydraulic fractures) along the wellbore.

[0097] Method 200 can continue at step 212, which includes executing the lost circulation control strategy to cure losses encountered in step 208. The executed lost circulation control strategy can include one or more of the strategies determined in step 206. Method 200 can continue at step 214, which includes the continuation of drilling the wellbore after curing lost circulation losses.

[0098] Examples presented in the present disclosure show several scenarios showing fluid distribution profile in open hole and cased hole completions. Fluid distribution in a long lateral is highly dependent on the heterogeneity of the reservoir where natural fractures and high permeability streaks can dominate most of the fluid intake at certain loss / injection rates. By changing the injection rates a varied fluid distribution profile can be generated. Conversely in a production (well-flowing) mode, a remarkably different fluid distribution profile is revealed from the same wellbore where prolific zones at deeper depths get an opportunity to produce without its contribution being masked by shallower prolific zones. Several different salient points can be picked from these examples; one performed prior to hydraulic fracturing of the well and the other after hydraulic fracturing. These examples show how to identify the contributing zones in different completions which will work analogously in wellbores experiencing lost circulation.Example 1

[0099] In Example 1 as shown in graph 700 of FIG. 7 and graph 800 of FIG. 8, a horizontal gas well is completed with open hole packers and multi-stage frac sleeves. As shown in graph 700, section 702 shows wellbore depth in feet, section 704 shows a sketch of the wellbore, section 706 shows pressure of the injected water, section 708 shows wellbore temperature, section 710 shows the SNL log, section 712 shows the MDrift injection, and section 714 shows the formation flow injection profile. Graph 800 shows a production profile with gas along the horizontal wellbore in Example 1. As shown in graph 800, section 802 shows wellbore depth in feet, section 804 shows a sketch of the wellbore, section 806 shows pressure of the gas, section 808 shows wellbore temperature, section 810 shows the SNL log, and section 812 shows the shows the formation flow production profile.

[0100] In Example 1, the open hole packers however were not properly set and interzonal communication was observed through most of the wellbore. An injection test (using water) and the production test (with gas, shown in FIG. 8) established interzonal communication within the wellbore and generated different flow distribution profiles. Note that the toe-end zone received a small portion (<3%) of the injection fluid during the injection test (graph 700) but had 15% contribution in the production mode (graph 800 in FIG. 8). This highlights the role of using different fluids for the tests at different rates and in different flow modes to properly identify the prolific zones. Since these were tight rock formations, their contributions established zones with natural fractures and their relative fluid flowing capacities.Example 2

[0101] In Example 2 as shown in graph 900 of FIG. 9, an unconventional gas well was completed with open hole packers and frac sleeves. As shown in graph 900, section 902 shows wellbore depth in feet, section 904 shows a sketch of the wellbore, section 906 shows wellbore temperature, section 908 shows the SNL log (flowing), and section 910 shows the SNL log (transient or shut-in).

[0102] This completion in Example 2 had seven stages with 19 ports aiming to place corresponding fractures. The interpretation of spectral noise logging and high precision temperature after multi-stage fracturing identified the presence of 22 active fractures; 17 were offset from flow ports, and 5 aligned with the flow ports with unique signatures. The fracture distribution varied between stages with an average of three active fractures per stage with exception of stage number 7 near the wellbore heel with only one induced active fracture, and stage number 6 with almost 6 contributing active fractures as shown in graph 900. This example is another case history where significantly sized fractures were identified behind pipe using HPT / SNL logs.

[0103] FIG. 10 is a schematic diagram of a control system 1000. The control system 1000 can be used for the operations described in association with any of the computer-implemented methods described previously. The system 1000 is intended to include various forms of digital computers, such as laptops, desktops, workstations, personal digital assistants, servers, blade servers, mainframes, and other appropriate computers. The system 1000 can also include mobile devices, such as personal digital assistants, cellular telephones, smartphones, and other similar computing devices. Additionally, the system can include portable storage media, such as, Universal Serial Bus (USB) flash drives. For example, the USB flash drives may store operating systems and other applications. The USB flash drives can include input / output components, such as a wireless transmitter or USB connector that may be inserted into a USB port of another computing device.

[0104] The system 1000 includes a processor 1010, a memory 1020, a storage device 1030, and an input / output device 1040. Each of the components 1010, 1020, 1030, and 1040 are interconnected using a system bus 1050. The processor 1010 is capable of processing instructions for execution within the system 1000. The processor may be designed using any of a number of architectures. For example, the processor 1010 may be a CISC (Complex Instruction Set Computers) processor, a RISC (Reduced Instruction Set Computer) processor, or a MISC (Minimal Instruction Set Computer) processor.

[0105] In one implementation, the processor 1010 is a single-threaded processor. In some implementations, the processor 1010 is a multi-threaded processor. The processor 1010 is capable of processing instructions stored in the memory 1020 or on the storage device 1030 to display graphical information for a user interface on the input / output device 1040.

[0106] The memory 1020 stores information within the system 1000. In one implementation, the memory 1020 is a computer-readable medium. In one implementation, the memory 1020 is a volatile memory unit. In some implementations, the memory 1020 is a non-volatile memory unit.

[0107] The storage device 1030 is capable of providing mass storage for the system 1000. In one implementation, the storage device 1030 is a computer-readable medium. In various different implementations, the storage device 1030 may be a floppy disk device, a hard disk device, an optical disk device, or a tape device.

[0108] The input / output device 1040 provides input / output operations for the system 1000. In one implementation, the input / output device 1040 includes a keyboard and / or pointing device. In some implementations, the input / output device 1040 includes a display unit for displaying graphical user interfaces.

[0109] Certain features described can be implemented in digital electronic circuitry, or in computer hardware, firmware, software, or in combinations of them. The apparatus can be implemented in a computer program product tangibly embodied in an information carrier, e.g., in a machine-readable storage device for execution by a programmable processor; and method steps can be performed by a programmable processor executing a program of instructions to perform functions of the described implementations by operating on input data and generating output. The described features can be implemented advantageously in one or more computer programs that are executable on a programmable system including at least one programmable processor coupled to receive data and instructions from, and to transmit data and instructions to, a data storage system, at least one input device, and at least one output device. A computer program is a set of instructions that can be used, directly or indirectly, in a computer to perform a certain activity or bring about a certain result. A computer program can be written in any form of programming language, including compiled or interpreted languages, and it can be deployed in any form, including as a stand-alone program or as a module, component, subroutine, or other unit suitable for use in a computing environment.

[0110] Suitable processors for the execution of a program of instructions include, by way of example, both general and special purpose microprocessors, and the sole processor or one of multiple processors of any kind of computer. Generally, a processor will receive instructions and data from a read-only memory or a random access memory or both. The essential elements of a computer are a processor for executing instructions and one or more memories for storing instructions and data. Generally, a computer will also include, or be operatively coupled to communicate with, one or more mass storage devices for storing data files; such devices include magnetic disks, such as internal hard disks and removable disks; magneto-optical disks; and optical disks. Storage devices suitable for tangibly embodying computer program instructions and data include all forms of non-volatile memory, including by way of example semiconductor memory devices, such as EPROM, EEPROM, and flash memory devices; magnetic disks such as internal hard disks and removable disks; magneto-optical disks; and CD-ROM and DVD-ROM disks. The processor and the memory can be supplemented by, or incorporated in, ASICs (application-specific integrated circuits).

[0111] To provide for interaction with a user, the features can be implemented on a computer having a display device such as a CRT (cathode ray tube) or LCD (liquid crystal display) monitor for displaying information to the user and a keyboard and a pointing device such as a mouse or a trackball by which the user can provide input to the computer. Additionally, such activities can be implemented via touchscreen flat-panel displays and other appropriate mechanisms.

[0112] The features can be implemented in a control system that includes a back-end component, such as a data server, or that includes a middleware component, such as an application server or an Internet server, or that includes a front-end component, such as a client computer having a graphical user interface or an Internet browser, or any combination of them. The components of the system can be connected by any form or medium of digital data communication such as a communication network. Examples of communication networks include a local area network (“LAN”), a wide area network (“WAN”), peer-to-peer networks (having ad-hoc or static members), grid computing infrastructures, and the Internet.

[0113] While this specification contains many specific implementation details, these should not be construed as limitations on the scope of any inventions or of what may be claimed, but rather as descriptions of features specific to particular implementations of particular inventions. Certain features that are described in this specification in the context of separate implementations can also be implemented in combination in a single implementation. Conversely, various features that are described in the context of a single implementation can also be implemented in multiple implementations separately or in any suitable subcombination. Moreover, although features may be described above as acting in certain combinations and even initially claimed as such, one or more features from a claimed combination can in some cases be excised from the combination, and the claimed combination may be directed to a subcombination or variation of a subcombination.

[0114] Similarly, while operations are depicted in the drawings in a particular order, this should not be understood as requiring that such operations be performed in the particular order shown or in sequential order, or that all illustrated operations be performed, to achieve desirable results. In certain circumstances, multitasking and parallel processing may be advantageous. Moreover, the separation of various system components in the implementations described above should not be understood as requiring such separation in all implementations, and it should be understood that the described program components and systems can generally be integrated together in a single software product or packaged into multiple software products.

[0115] A number of implementations have been described. Nevertheless, it will be understood that various modifications may be made without departing from the spirit and scope of the disclosure. For example, example operations, methods, or processes described herein may include more steps or fewer steps than those described. Further, the steps in such example operations, methods, or processes may be performed in different successions than that described or illustrated in the figures. Accordingly, other implementations are within the scope of the following claims.

Claims

1. A method for managing lost circulation of a drilling fluid in a subterranean reservoir, comprising:generating, with one or more hardware processors of a control system, a 3D natural fracture model that includes a 3D discrete fracture network and a brittleness model for a subterranean formation;converting, with the one or more hardware processors, the 3D discrete fracture network into a 2D model to determine a continuous fracture density property;predicting, with the one or more hardware processors, a plurality of fluid-flow pathways using the continuous fracture density property modeled for each brittleness;determining, based on the predicted plurality of fluid-flow pathways, a lost circulation strategy that comprises a plurality of lost circulation remedies;subsequent to the determination of the lost circulation strategy, drilling a portion of a wellbore from the terranean surface into the subterranean formation with a drilling rig and a drilling fluid;during the drilling of the portion of the wellbore, encountering lost circulation of the drilling fluid into the subterranean formation from the wellbore; andin response to encountering the lost circulation, performing a wellbore operation that comprises at least one of the plurality of lost circulation remedies.

2. The method of claim 1, comprising completing drilling of the wellbore into the subterranean formation subsequent to performing the wellbore operation.

3. The method of claim 1, wherein the subterranean formation comprises a plurality of natural fractures, and the 3D discrete fracture network comprises the plurality of natural fractures.

4. The method of claim 1, comprising logging the portion of the wellbore to determine one or more logged properties subsequent to drilling the portion of the wellbore from the terranean surface into the subterranean formation.

5. The method of claim 4, wherein logging the portion of the wellbore to determine one or more logged properties comprises:performing at least one high precision temperature (HPT) logging run to generate at least one HPT log of the portion of the wellbore; andperforming at least one spectral noise logging (SNL) run to generate at least one spectral noise log of the portion of the wellbore.

6. The method of claim 5, wherein performing at least one spectral noise logging (SNL) run to generate at least one spectral noise log of the portion of the wellbore comprises:performing a first SNL run at flowing conditions of the wellbore to generate a first spectral noise log of the portion of the wellbore; andperforming a second SNL run at shut-in conditions of the wellbore to generate a second spectral noise log of the portion of the wellbore.

7. The method of claim 4, comprising:generating a composite log that includes a fracture density index, the predicted plurality of fluid-flow pathways, the at least one HPT log, and the at least one spectral noise log of the wellbore; andcomparing, with the one or more hardware processors, the predicted plurality of fluid-flow pathways with portions of the at least one HPT log, and the at least one spectral noise log.

8. The method of claim 1, wherein the plurality of lost circulation remedies comprise:a first set of lost circulation remedies associated with a first magnitude of lost drilling fluid within a pumping capacity of the drilling rig; anda second set of lost circulation remedies associated with a second magnitude of lost drilling fluid outside of the pumping capacity of the drilling rig.

9. The method of claim 8, wherein the first set of lost circulation remedies comprise a first lost circulation remedy of pumping fibrous material to the portion of the wellbore and a second lost circulation remedy of a wellbore strengthening treatment, and the second set of lost circulation remedies comprise a third lost circulation remedy of creating a wedge effect in the subterranean formation.

10. A computer-implemented method performed with one or more hardware processors, comprising:generating, with one or more hardware processors of a control system, a 3D natural fracture model that includes a 3D discrete fracture network and a brittleness model for a subterranean formation;converting, with the one or more hardware processors, the 3D discrete fracture network into a 2D model to determine a continuous fracture density property;predicting, with the one or more hardware processors, a plurality of fluid-flow pathways using the continuous fracture density property modeled for each brittleness; anddetermining, with the one or more hardware processors and based on the predicted plurality of fluid-flow pathways, a lost circulation strategy that comprises a plurality of lost circulation remedies configured to implement in response to encountering a lost circulation of a drilling fluid into the subterranean formation from a wellbore with a drilling rig and a drilling fluid.

11. The computer-implemented method of claim 10, wherein the subterranean formation comprises a plurality of natural fractures, and the 3D discrete fracture network comprises the plurality of natural fractures.

12. The computer-implemented method of claim 10, comprising generating at least one log of the portion of the wellbore of one or more logged properties of at least a portion of the wellbore drilled from the terranean surface into the subterranean formation.

13. The computer-implemented method of claim 12, wherein the at least one log of the one or more logged properties comprises:at least one high precision temperature (HPT) log of the portion of the wellbore; andat least one spectral noise logging (SNL) log of the portion of the wellbore.

14. The computer-implemented method of claim 13, wherein the at least one spectral noise logging (SNL) log of the portion of the wellbore comprises:a first spectral noise log of the portion of the wellbore that comprises a first SNL log run at flowing conditions of the wellbore; anda second spectral noise log of the portion of the wellbore that comprises a second SNL log run at shut-in conditions of the wellbore.

15. The computer-implemented method of claim 12, comprising:generating, with the one or more hardware processors, a composite log that includes a fracture density index, the predicted plurality of fluid-flow pathways, the at least one HPT log, and the at least one spectral noise log of the wellbore; andcomparing, with the one or more hardware processors, the predicted plurality of fluid-flow pathways with portions of the at least one HPT log, and the at least one spectral noise log.

16. The computer-implemented method of claim 10, wherein the plurality of lost circulation remedies comprise:a first set of lost circulation remedies associated with a first magnitude of lost drilling fluid within a pumping capacity of the drilling rig; anda second set of lost circulation remedies associated with a second magnitude of lost drilling fluid outside of the pumping capacity of the drilling rig.

17. The computer-implemented method of claim 16, wherein the first set of lost circulation remedies comprise a first lost circulation remedy of pumping fibrous material to the portion of the wellbore and a second lost circulation remedy of a wellbore strengthening treatment, and the second set of lost circulation remedies comprise a third lost circulation remedy of creating a wedge effect in the subterranean formation.

18. A computing system, comprising:one or more memory modules that store instructions; andone or more hardware processors communicably coupled to the one or more memory modules and configured to execute the instructions to perform operations, comprising:generating a 3D natural fracture model that includes a 3D discrete fracture network and a brittleness model for a subterranean formation;converting the 3D discrete fracture network into a 2D model to determine a continuous fracture density property;predicting a plurality of fluid-flow pathways using the continuous fracture density property modeled for each brittleness; anddetermining, based on the predicted plurality of fluid-flow pathways, a lost circulation strategy that comprises a plurality of lost circulation remedies configured to implement in response to encountering a lost circulation of a drilling fluid into the subterranean formation from a wellbore with a drilling rig and a drilling fluid.

19. The computing system of claim 18, wherein the subterranean formation comprises a plurality of natural fractures, and the 3D discrete fracture network comprises the plurality of natural fractures.

20. The computing system of claim 18, wherein the operations comprise generating at least one log of the portion of the wellbore of one or more logged properties of at least a portion of the wellbore drilled from the terranean surface into the subterranean formation.

21. The computing system of claim 20, wherein the at least one log of the one or more logged properties comprises:at least one high precision temperature (HPT) log of the portion of the wellbore; andat least one spectral noise logging (SNL) log of the portion of the wellbore.

22. The computing system of claim 21, wherein the at least one spectral noise logging (SNL) log of the portion of the wellbore comprises:a first spectral noise log of the portion of the wellbore that comprises a first SNL log run at flowing conditions of the wellbore; anda second spectral noise log of the portion of the wellbore that comprises a second SNL log run at shut-in conditions of the wellbore.

23. The computing system of claim 20, wherein the operations comprise:generating a composite log that includes a fracture density index, the predicted plurality of fluid-flow pathways, the at least one HPT log, and the at least one spectral noise log of the wellbore; andcomparing the predicted plurality of fluid-flow pathways with portions of the at least one HPT log, and the at least one spectral noise log.

24. The computing system of claim 18, wherein the plurality of lost circulation remedies comprise:a first set of lost circulation remedies associated with a first magnitude of lost drilling fluid within a pumping capacity of the drilling rig; anda second set of lost circulation remedies associated with a second magnitude of lost drilling fluid outside of the pumping capacity of the drilling rig.

25. The computing system of claim 24, wherein the first set of lost circulation remedies comprise a first lost circulation remedy of pumping fibrous material to the portion of the wellbore and a second lost circulation remedy of a wellbore strengthening treatment, and the second set of lost circulation remedies comprise a third lost circulation remedy of creating a wedge effect in the subterranean formation.

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