Formation evaluation while drilling

Abstract

Methods and systems for drilling a wellbore that traverses a subterranean formation employ a computational model that relates input data representing at least one drilling performance parameter (or change therein) at one or more drilling conditions to output data representing at least one petrophysical formation property. Data representing at least one drilling performance parameter (or change therein) at one or more drilling conditions while drilling is determined by sweeping wellbore pressure over a range of pressures and measuring and analyzing wellbore pressures and associated drilling performance parameters, and such data is used as input data to the computational model, which generates output data representing at least one petrophysical formation property associated with the input data. The data output by the model can be added to well log of formation properties, which can be used to set or adjust the direction of drilling.

Description

CROSS REFERENCE TO RELATED APPLICATIONS

[0001] This application claims the benefit of U.S. Provisional Application Ser. No. 63 / 766458 entitled "FORMATION EVALUATION WHILE DRILLING", filed March 4, 2025, which is incorporated herein by reference in its entirety.FIELD

[0002] The present disclosure relates to methods and systems that generate a log of formation properties while drilling a wellbore that traverse a subterranean rock formation.BACKGROUND

[0003] Logging while drilling tools are commonly used to measure and log formation properties while drilling a wellbore that traverse a subterranean rock formation. The logging while drilling tools can employ a wide variety of measurements to characterize different formation properties, such as gamma ray (GR) measurements to characterize different rocks and mineral types and lithology in the formation; bulk density and porosity of the formation; neutron porosity measurements; resistivity and attenuation and phase-shift resistivity measurements at different transmitter spacings and frequencies to identify potential hydrocarbon zones (by differentiating between conductive water-filled formations and resistive hydrocarbon-bearing zones) and relevant geological boundaries (such as faults or fractures); sonic measurements to characterize formation porosity and lithology and relevant geological boundaries (such as faults or fractures); nuclear magnetic resonance (NMR) measurements to characterize formation porosity and fluid analysis; and downhole formation sampling and analysis that characterizes formation pressure, fluid composition, PVT properties, and fluid properties such as gas / oil ratio (GOR), fluid density, and viscosity.

[0004] Such logging while drilling tools are expensive to build, operate and maintain, which can increase drilling costs.SUMMARY

[0005] According to one or more aspects of the disclosure, methods and systems are provided for drilling a wellbore that traverses a subterranean formation, which employ a computational model that relates input data representing at least one drilling performance parameter (or change therein) at one or more drilling conditions to output data representing at least one petrophysical formation property. In embodiments, the drilling condition(s) can correspond to one or more levels of underbalanced drilling, one or more levels of overbalanced drilling, or balanced drilling. The one or more levels of underbalanced drilling can be represented by a corresponding "underbalanced drilling" state or status and ratio(s) or percentage(s) or difference(s) of wellbore pressure relative to formation pressure with the wellbore pressure less than the formation pressure. The one or more levels of overbalanced drilling can be represented by a corresponding "overbalanced drilling" state or status and ratio(s) or percentage(s) or difference(s) of wellbore pressure relative to formation pressure with the wellbore pressure greater than the formation pressure. Balanced drilling can be represented by a corresponding "balanced drilling" state or status with the wellbore pressure matching the formation pressure. A wellbore pressure sweeping varies wellbore pressure over a range of pressures close to the formation pressure while drilling the wellbore, and the wellbore pressures and associated drilling performance parameters are measured and analyzed while drilling to determine data representing at least one measured drilling performance parameter (or change therein) in at least one drilling condition, which is supplied as input data to the model. The model outputs data representing at least one petrophysical formation property associated with the input data. The data representing the petrophysical formation property(ies) output by the model can be added to a well log of formation properties, which can be used to set or adjust the direction of drilling the wellbore.

[0006] In embodiments, the at least one petrophysical formation property represented by the output data of the model can include formation pressure, porosity, permeability, fluid type, other suitable petrophysical formation property, or combinations thereof.

[0007] In embodiments, the range of pressures of the wellbore pressure sweeping can include pressures that lead to overbalanced drilling and underbalanced drilling and balanced drilling.

[0008] In embodiments, the at least one drilling performance parameter that is part of the computational model and that is determined while drilling the wellbore can include, or be derived from, at least one of: ROP, WOB, torque, and MSE.

[0009] In embodiments, the at least one drilling performance parameter that is part of the computational model and that is determined while drilling the wellbore can include, or be derived from, a change in MSE at a predefined overbalanced drilling condition.

[0010] In embodiments, the wellbore pressure sweeping can be performed without measuring or knowing the formation pressure of the formation.

[0011] In embodiments, the wellbore pressure sweeping can vary the wellbore pressure by adjusting one or more drilling parameters selected from surface choke pressure, constituent drilling fluids or drilling fluid flow rates.

[0012] In embodiments, the one or more drilling conditions associated with the at least one drilling performance parameter (or change therein) of the computational model and the at least one drilling performance parameter (or change therein) determined while drilling can correspond to one or more levels of underbalanced drilling.

[0013] In embodiments, the one or more levels of underbalanced drilling can be represented by a predefined "underbalanced drilling" state or status and ratio(s) or percentage(s) or difference(s) of wellbore pressure relative to formation pressure with the wellbore pressure less than the formation pressure.

[0014] In embodiments, the one or more drilling conditions associated with the at least one drilling performance parameter (or change therein) of the computational model and the at least one drilling performance parameter (or change therein) determined while drilling can correspond to one or more levels of overbalanced drilling.

[0015] In embodiments, the one or more levels of overbalanced drilling can be represented by a predefined "underbalanced drilling" state or status and ratio(s) or percentage(s) or difference(s) of wellbore pressure relative to formation pressure with the wellbore pressure less than the formation pressure.

[0016] In embodiments, the one or more drilling conditions associated with the at least one drilling performance parameter (or change therein) of the computational model and the at least one drilling performance parameter (or change therein) determined while drilling can correspond to balanced drilling.

[0017] In embodiments, the balanced drilling can be represented by a predefined "balanced drilling" state or status with the wellbore pressure matching the formation pressure.

[0018] In embodiments the method can further involve monitoring and controlling one or more drilling parameters while drilling the wellbore to maintain one or more predefined levels of underbalanced drilling.

[0019] In embodiments the method can further involve monitoring and controlling one or more drilling parameters while drilling the wellbore to maintain one or more predefined levels of overbalanced drilling.

[0020] In embodiments the method can further involve monitoring and controlling one or more drilling parameters while drilling the wellbore to maintain balanced drilling.

[0021] In embodiments, the drilling can employ a drill string that employs coiled tubing.

[0022] In embodiments, the determination of the at least one petrophysical formation property output by the model and added to the well log can avoid the use of one or more while drilling tools, which can reduce drilling costs.

[0023] Other aspects are described and claimed.

[0024] 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.BRIEF DESCRIPTION OF THE DRAWINGS

[0025] The subject disclosure is further described in the detailed description which follows, in reference to the noted plurality of drawings by way of non-limiting examples of the subject disclosure, in which like reference numerals represent similar parts throughout the several views of the drawings as described below. FIGS. 1A and 1B, collectively, is a flow chart that embodies a method of drilling in accordance with the present disclosure; FIG. 2 illustrates an example directional drilling system that can embody aspects of the present disclosure; FIG. 3 illustrates an example coiled tubing drilling rig that can embody aspects of the present disclosure; and FIG. 4 is a schematic block diagram of an example computer system that can embody aspects of the present disclosure. DETAILED DESCRIPTION

[0026] It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments. Specific examples of components and arrangements are described below to simplify the disclosure. These are, of course, merely examples, and are not intended to be limiting. In addition, the disclosure may repeat reference numerals and / or letters in the various examples. This repetition is for the purpose of simplicity and clarity and is not in itself dictating a relationship between the various embodiments and / or configurations discussed.

[0027] As used herein, the terms connect, connection, connected, in connection with, and connecting may be used to mean in direct connection with or in connection with via one or more elements. Similarly, the terms couple, coupling, coupled, coupled together, and coupled with may be used to mean directly coupled together or coupled together via one or more elements. Terms such as up, down, top and bottom and other like terms indicating relative positions to a given point or element may be utilized to more clearly describe some elements. Commonly, these terms relate to a reference point such as the surface from which drilling operations are initiated.

[0028] The present disclosure is directed to methods and drilling systems that drill a wellbore that traverses a subterranean formation, which includes sweeping wellbore pressure over a range of pressures close to the formation pressure of the formation while drilling, and monitoring the wellbore pressures and associated drilling performance parameters measured while drilling to determine data representing at least one measured drilling performance parameter or change thereof at one or more drilling conditions. In embodiments, the drilling condition(s) can correspond to one or more levels of underbalanced drilling, one or more levels of overbalanced drilling, or balanced drilling. The one or more levels of underbalanced drilling can be represented by a corresponding "underbalanced drilling" state or status and ratio(s) or percentage(s) or difference(s) of wellbore pressure relative to formation pressure with the wellbore pressure less than the formation pressure. The one or more levels of overbalanced drilling can be represented by a corresponding "overbalanced drilling" state or status and ratio(s) or percentage(s) or difference(s) of wellbore pressure relative to formation pressure with the wellbore pressure greater than the formation pressure. Balanced drilling can be represented by a corresponding "balanced drilling" state or status with the wellbore pressure matching the formation pressure. The data representing at least one measured drilling performance parameter or change thereof at one or more drilling conditions is supplied as input data to a computational model, which outputs at least one petrophysical formation property (such as formation pressure, porosity, permeability, and fluid type) associated with the input data. The at least one petrophysical formation property output by the model can be added to a well log of formation properties. The well log of formation properties can be used to set or adjust the direction of drilling the wellbore, for example, such that the wellbore traverses the desired producing zone of the formation.

[0029] In embodiments, the range of pressures of the wellbore pressure sweeping step can include pressures that lead to overbalanced drilling and underbalanced drilling and balanced drilling (at the transition between overbalanced drilling and underbalanced drilling). Underbalanced drilling and overbalanced drilling are two commonly used techniques for drilling wells, each with distinct advantages and applications.

[0030] Underbalanced drilling is a drilling condition where the drilling fluid pressure (or force per unit area) exerted on a formation exposed in a wellbore is less than the internal fluid pressure of the formation (or formation pressure). If sufficient porosity and permeability exist, formation fluids (e.g., oil, gas, water, steam) can enter the wellbore. Varying levels of underbalanced drilling can be represented by a predefined "underbalanced drilling" state or status and ratios or percentages or differences of wellbore pressure relative to formation pressure with the wellbore pressure less than the formation pressure.

[0031] The rate of drilling typically increases as the underbalanced drilling condition is approached. Underbalance drilling can improve wellbore productivity. This is the main driver for underbalanced drilling with coiled tubing. However, increasing the differential pressure during underbalanced drilling can lead to formation instability and cause the wellbore to collapse and the drilling tool getting stuck. This is a known issue in underbalanced drilling with coiled tubing.

[0032] Overbalanced drilling is a drilling condition where the drilling fluid pressure (or force per unit area) exerted on a formation exposed in a wellbore is greater than the internal fluid pressure of the formation (formation pressure). This excess pressure can prevent formation fluids (e.g., oil, gas, water, steam) from entering the wellbore. Varying levels of overbalanced drilling can be represented by a predefined "overbalanced drilling" state or status and ratios or percentages or differences of wellbore pressure relative to formation pressure with the wellbore pressure greater than the formation pressure.

[0033] Excessive overbalance drilling can dramatically slow the drilling process by effectively strengthening the near-wellbore rock and limiting removal of drilled cuttings. In addition, high levels of overbalance drilling coupled with poor mud properties can cause differential sticking problems. Furthermore, with overbalanced drilling, the mud can form a filter cake with fine particulates blocking pores in the formation to reduce drilling fluid loss into the formation. However, increasing the differential pressure during overbalanced drilling can result in fracture of the formation and massive fluid loss.

[0034] Balanced drilling is a drilling condition where the drilling fluid pressure (or force per unit area) exerted on a formation exposed in a wellbore is equal to the internal fluid pressure of the formation (formation pressure). Balanced drilling occurs at the transition between underbalanced drilling and overbalanced drilling. Balanced drilling can be represented by a predefined "balanced drilling" state or status.

[0035] Because the internal fluid pressure of the formation (formation pressure or pore pressure) can vary from one formation to another and between zones in a formation, the conditions of underbalanced drilling and overbalanced drilling and balanced drilling can vary from one formation to another and between zones in a formation, and it can be difficult to determine the conditions of underbalanced drilling and overbalanced drilling and balanced drilling for a formation or for zones in a formation. To address this issue, a specialized logging while drilling tool can be used to make real-time pressure measurements during the drilling process by performing a brief pressure drawdown and buildup test against the formation at specific depths. This provides data on the formation pressure (also referred to as pore pressure) and fluid characteristics without stopping the drilling operation completely. However, building, operating, and maintaining the specialized logging while drilling tool is expensive, which can increase the drilling costs.

[0036] In embodiments, the wellbore pressure sweeping step can vary the wellbore pressure by one or more operations, which can include i) operating a choke at surface that controls the flow out of the well, ii) by changing the density of the drilling fluid or the split of liquid and gas in the drilling fluid, and iii) by changing the flow rate of the drilling fluid. A downhole sensor that measures and monitors the fluid pressure in the annulus of the wellbore can be used to provide feedback and measurement of the wellbore pressure during the drilling. Such operations can avoid the use of the specialized logging while drilling tool that measures the formation pressure.

[0037] FIGS. 1A and 1B is a flowchart that illustrates an embodiment of the present disclosure.

[0038] In block 101, a computational model is constructed that relates input data representing at least one drilling performance parameter (or change therein) at one or more drilling conditions to at least one petrophysical formation property.

[0039] In embodiments, the input data of the computational model of 101 that represents at least one drilling performance parameter (or change therein) can include or be derived from the rate of penetration (ROP), weight on bit (WOB), torque, and mechanical specific energy (MSE).

[0040] In embodiments, the output data of the computational model of 101 that represents at least one petrophysical formation property can include formation porosity, formation permeability, formation fluid type, other suitable formation property, or a combination thereof.

[0041] In embodiments, the drilling condition(s) of the input data of the computational model of 101 can correspond to one or more levels of underbalanced drilling, one or more levels of overbalanced drilling, or balanced drilling. The one or more levels of underbalanced drilling can be represented by a predefined "underbalanced drilling" state or status and ratio(s) or percentage(s) or difference(s) of wellbore pressure relative to formation pressure with the wellbore pressure less than the formation pressure. The one or more levels of overbalanced drilling can be represented by a predefined "overbalanced drilling" state or status and ratio(s) or percentage(s) or difference(s) of wellbore pressure relative to formation pressure with the wellbore pressure greater than the formation pressure. Balanced drilling can be represented by a predefined "balanced drilling" state or status with wellbore matching the formation pressure.

[0042] In embodiments, the computational model of 101 can be constructed from analysis of previous drilling data in comparable operations or through theoretical models or from laboratory type experiments. The computational model can be constructed using data correlation methods, curve-fitting (such as linear and nonlinear regression, least squares, and exponential curve fitting) or machine learning training. The level(s) of underbalanced drilling can be represented by a predefined "underbalanced drilling" state or status and ratio(s) or percentage(s) or difference(s) between the hydrostatic head of the drilling fluid and the internal fluid pressure of the formation (formation pressure) with the hydrostatic head of the drilling fluid greater than the formation pressure. The level(s) of overbalanced drilling can be represented by a predefined "overbalanced drilling" state or status and ratio(s) or percentage(s) or difference(s) between the hydrostatic head of the drilling fluid and the formation pressure with the hydrostatic head of the drilling fluid less than the formation pressure. Balanced drilling can be represented by a predefined "balanced drilling" state or status with the hydrostatic head of the drilling fluid matching the formation pressure. The hydrostatic head of the drilling fluid, which is typically expressed in units of psi or Pa, can be determined from the drilling fluid density and the vertical depth of the drilling tool in the wellbore, or by a direct measurement with a pressure transducer measuring the annulus pressure within the wellbore. The formation pressure, which is also typically expressed in units of psi or Pa, can be determined by downhole fluid sampling of formation fluids or other formation fluid characterization methods.

[0043] In embodiments, the computational model of 101 can be implemented by a correlation or regression model (e.g., correlation, linear regression, ordinary least squares regression, stepwise regression, multivariate adaptive regression splines, locally estimated scatterplot smoothing, logistic regression, etc.), a rule system model (e.g., cubist, one rule, zero rule, repeated incremental pruning to produce error reduction), a Bayesian model (e.g., naive Bayes, average on-dependence estimators, Bayesian belief network, Gaussian naive Bayes, multinomial naive Bayes, Bayesian network), a decision tree model (e.g., classification and regression tree, iterative dichotomiser 3, C4.5, C5.0, chi-squared automatic interaction detection, decision stump, conditional decision tree, M5), a dimensionality reduction model (e.g., principal component analysis, partial least squares regression, Sammon mapping, multidimensional scaling, projection pursuit, principal component regression, partial least squares discriminant analysis, mixture discriminant analysis, quadratic discriminant analysis, regularized discriminant analysis, flexible discriminant analysis, linear discriminant analysis, etc.), an instance model (e.g., k-nearest neighbor, learning vector quantization, self-organizing map, locally weighted learning, etc.), a clustering model (e.g., k-means, k-medians, expectation maximization, hierarchical clustering, etc.), etc.

[0044] In other embodiments, the computational model of 101 can be implemented by a machine-learning (ML) model. For example, the ML model can be one or more of a support vector machine (SVM) model, a k-nearest neighbors (KNN) model, an ensemble classifier model, a neural network (NN) model, a deep learning model (e.g., deep Boltzmann machine, deep belief network, convolutional neural network, stacked autoencoder, etc.), an ensemble model (e.g., random forest, gradient boosting machine, bootstrapped aggregation, AdaBoost, stacked generalization, gradient boosted regression tree, etc.), a neural network model (e.g., radial basis function network, perceptron, back-propagation, Hopfield network, etc.), a regularization model (e.g., ridge regression, least absolute shrinkage and selection operator, elastic net, least angle regression). As an example, a training method may include various actions that may operate on a dataset to train the ML model. As an example, a dataset may be split into training data and test data where test data may provide for evaluation. A method may include cross-validation of parameters and best parameters, which may be provided for model training.

[0045] The torque, WOB and ROP of the drilling are coupled to one another. The MSE of the drilling can be used as a drilling performance parameter in the model of 101. MSE can be derived from the torque and WOB as follows: MSE = 1 A WOB + 24 π T DOC . where A is the area of the wellbore, WOB is the weight on bit, T is the drilling torque, and DOC is the penetration of the bit per revolution.

[0046] Note that other formulations of MSE can be used. Furthermore, formulations can be used to link ROP to the torque and WOB. In other embodiments, surface measurements of these parameters can be used to characterize MSE, but downhole measurements of torque and weight on bit can be more accurate and consistent.

[0047] In embodiments, the computation model of 101 can relate a change in MSE to a drilling condition (i.e., a level of underbalanced drilling or level of overbalanced drilling or balanced drilling). The relation between MSE and the drilling condition can be non-linear. At high levels of overbalanced drilling, the MSE can be constant with changes in differential pressure but as the differential pressure moves closer to balanced drilling and underbalanced drilling, the drilling efficiency will increase and the MSE will drop. In this manner, a measure of change in MSE with pressure difference can be input to the model of 101 to provide an estimate of formation pressure. Furthermore, a transform can be used to adapt the change in MSE to an equivalent MSE at a predefined overbalanced drilling level, which can be used as a correlation of MSE at the predefined overbalanced drilling level to a one or more petrophysical formation properties. In this configuration, the computational model can output one or more petrophysical formation properties from the measured change in MSE.

[0048] In alternate embodiments, the shape of the curve that relates MSE to change in wellbore pressure (which is expected to be non-linear in form) can be correlated directly to formation porosity or other petrophysical formation properties. This correlation can be derived from drilling data and may be embodied by a machine learning system as described herein.

[0049] At block 103, at one or more measured depths while drilling a wellbore, drilling parameters can be adjusted to sweep wellbore pressure over a range of pressures close to the formation pressure of the formation.

[0050] In embodiments, the range of pressures of the wellbore pressure sweeping of block 103 can include pressures that lead to overbalanced drilling and underbalanced drilling and balanced drilling (which occurs at the transition between overbalanced drilling and underbalanced drilling).

[0051] In embodiments, the wellbore pressure sweeping of block 103 can vary the wellbore pressure using feedback from a downhole sensor that measures and monitors the fluid pressure in the annulus of the wellbore.

[0052] In embodiments, the wellbore pressure sweeping of block 103 can adjust one or more drilling parameters (such as surface choke pressure, constituent drilling fluids or drilling fluid flow rates) to vary the wellbore pressure.

[0053] In block 105, while varying or sweeping the wellbore pressures in 103, wellbore pressures and associated drilling performance parameters (such as ROP, WOB, torque and MSE) are measured and analyzed while drilling to determine data representing at least one measured drilling performance parameter (or change therein) at one or more drilling conditions.

[0054] The data that represents at least one drilling performance parameter (or change therein) as determined in 105 corresponds to the input data of the computational model of 101. In embodiments, the data that represents at least one drilling performance parameter (or change therein) as determined in 105 can include, or be derived from, the rate of penetration (ROP), weight on bit (WOB), torque, and mechanical specific energy (MSE) in a manner that corresponds to the input data of the computational model of 101.

[0055] In embodiments, the one or more drilling condition(s) of 105 can correspond to one or more levels of underbalanced drilling, one or more levels of overbalanced drilling, or balanced drilling. The one or more levels of underbalanced drilling can be represented by a predefined "underbalanced drilling" state or status and ratio(s) or percentage(s) or difference(s) of wellbore pressure relative to formation pressure with the wellbore pressure less than the formation pressure. The one or more levels of overbalanced drilling can be represented by a predefined "overbalanced drilling" state or status and ratio(s) or percentage(s) or difference(s) of wellbore pressure relative to formation pressure with the wellbore pressure greater than the formation pressure. Balanced drilling can be represented by a predefined "balanced drilling" state or status with wellbore matching the formation pressure.

[0056] In embodiments, the internal fluid pressure of the formation fluids (formation pressure or pore pressure) is unknown and thus not available to determine the level of underbalanced drilling or overbalanced drilling or balanced drilling. Instead, the method sweeps the drilling fluid wellbore pressure and maps the drilling fluid wellbore pressure measurements to the at least one drilling performance parameter while drilling. The resulting data can be processed to identify the formation pressure of the formation and thus map one or more drilling performance parameters (or a change therein) to the drilling condition(s). This mapping can be used to extract data representing one or more drilling performance parameters (such as ROP, WOB, torque and MSE) (or a change therein) at the one or more drilling conditions while drilling.

[0057] In embodiments, the wellbore pressure sweeping of block 103 and the measurement and analysis of block 105 can avoid the use of the specialized logging while drilling tool that measures the formation pressure, which can reduce drilling costs.

[0058] In block 107, the data of 105 (which represents at least one measured drilling performance parameter at one or more drilling conditions) is used as input data to the computational model of 101, which outputs at least one petrophysical formation property associated with the input data.

[0059] In block 109, the at least one petrophysical formation property output by the model in 107 can be added to a log of formation properties for the measured depth in the wellbore.

[0060] In block 111, the operations of 103 to 109 can be optionally repeated for additional measured depths while drilling the wellbore.

[0061] In block 113, the log of formation properties can be used to set or adjust the direction of drilling the wellbore, for example, such that the wellbore traverses the desired producing zone of the formation.

[0062] In embodiments, the drilling parameters can be monitored and controlled while drilling the wellbore to maintain one or more predefined levels of underbalanced drilling. In other embodiments, the drilling parameters can be monitored and controlled while drilling the wellbore to maintain one or more predefined levels of overbalanced drilling. In yet other embodiments, the drilling parameters can be monitored and controlled while drilling the wellbore to maintain balanced drilling.

[0063] In embodiments, the at least one petrophysical formation property output by the computational model and added to the well log as part of the drilling operations can be determined without the use of one or more while drilling tools, which can reduce drilling costs.

[0064] FIG. 2 is a schematic illustration of an embodiment of a directional drilling system, generally denoted by the numeral 210, which can incorporate embodiments of the present disclosure. The drilling system 210 uses a drilling assembly or bottomhole assembly (BHA) 212 for drilling a wellbore 214. While a land-based rig is shown, these concepts and the methods are equally applicable to offshore drilling systems. The system 210 may include a drill string 216 suspended from rig 220. The drill string 216 can include jointed tubulars (commonly referred to as drill pipe) or coiled tubing (FIG. 3). In one non-limiting configuration, the BHA 212 includes a drill bit 230, a steering tool 232 (with a drilling motor), and a sensor sub 232.

[0065] The BHA 212 may also include one or more flow control devices that control the flow of drilling fluid through the bore of the drill string 216. Illustrative flow control devices may include, but are not limited to, check-valves, flow stop valves, unidirectional valves, switchable valves, and switchable bi-directional valves. These flow control devices may be used to ensure that drilling fluid flows along a desired direction during drilling operations. For example, during conventional drilling operations, drilling fluid is pumped from a surface supply 222 into the drill string 216. This drilling fluid flows down a bore of the drill string 216, exits at the drill bit 230, and returns via the annulus 218 surrounding the drill string 216 to a choke (not shown) at the surface. One or more flow control devices may be configured to prevent unwanted backflow of drilling fluid up the bore of the drill string 216 to the surface. The choke can be used to vary the wellbore pressure during the pressure sweeping operations while drilling as part of the method of FIGS. 1A and 1B. Additionally or alternatively, the fluid density of the drilling fluid and / or the flow rate of the drilling fluid can be adapted / controlled to vary the wellbore pressure during the pressure sweeping operations while drilling as part of the method of FIGS. 1A and 1B.

[0066] The sensor sub 232 can include a pressure sensor configured to measure pressure of the drilling fluid in the annulus 218 adjacent the BHA 212 (for example, as part of block 103 of the method of FIGS. 1A and 1B). The pressure measurements of the sensor sub 232 can be communicated by a telemetry system to a surface controller (not shown) for processing and analysis as part of the method of FIGS. 1A and 1B.

[0067] The steering tool 232 can be operated to control the attitude of the drill bit 230 such that it maintains a desired target attitude to propagate wellbore 214 along the desired path, for example as part of block 113 of the method of FIGS. 1A and 1B. The steering tool 232 can include a push-the-bit RSS system or a point-the-bit RSS system. According to embodiments, the steering tool 232 can be a closed-loop system that interfaces directly with BHA sensors to control the attitude of the drill bit 230.

[0068] In embodiments, the drilling system can employ a coiled tubing drilling rig that deploys a drill string that includes coiled tubing. An example coiled tubing drilling rig is illustrated in FIG. 3, which includes a wheeled carrier or trailer 320 which is adapted to be pulled by a motorized vehicle. The trailer 320 has wheels 322 located near its rear, and a hitch 324 located near its front for attachment to a motorized vehicle (not shown). The trailer 320 also has a lowered middle portion 326 so as to lower the center of gravity of the components placed on this portion of the trailer 320. While the wheeled carrier of the preferred embodiment rig has been described and illustrated as being one which is adapted to be pulled by a motorized vehicle, it is to be understood that the wheeled carrier may itself be self-propelled.

[0069] The trailer 320 has mounted thereon retractable outriggers or stabilizer legs 328 for stabilizing and levelling the rig for drilling. Three stabilizer legs 328 are located on each side of the rig, at the front of the lowered middle portion 326, the rear of the lowered middle portion 326 and at the rear of the trailer 320. The stabilizer legs 328 can have pontoons 329 mounted at their ends to ensure positive contact with the ground.

[0070] Near the rear of the trailer 320 is mounted a drilling substructure 330, which is essentially a raised platform supporting a rotary table and a mast 334. Stairs 336 are attached to the substructure 330 to allow workers to ascend to the substructure 330.

[0071] The rotary table is a collar adapted to engage down-hole equipment including tubing (coiled tubing or jointed-pipe for example) through the use of slips or wedges, and which is hydraulically powered for rotation. The rotary table is used to engage and rotate (or prevent rotation of) equipment inserted therein. The substructure 330 also has BOP hangers 337 mounted below the rotary table to allow raising and lowering of BOP's (blow-out preventers) off and onto a wellhead.

[0072] The mast 334 is pivotally attached to the substructure 330 at mast mounting pins 338 for pivotal movement between a horizontal transportation position and a vertical operating position as shown. The vertical / horizontal orientation of the mast 334 can be controlled by a hydraulic cylinder 340 connected at its ends to the trailer 320 and the mast 334.

[0073] A coiled tubing injector platform 342 is mounted on the front of the mast 334. A coiled tubing injector 348 is mounted atop the injector platform 342 and includes a series of rollers and guides (not shown in detail) used to push, pull and guide coiled tubing 354 into and out of the well. The structure and functionality of coiled tubing injector 348 is well known and will not be discussed in detail herein. Extending from the top of the injector 348 is an injector arch 356 used to guide the coiled tubing 354 in a gentle arch prior to entry into the injector 348. Extending below the injector 348 is a telescoping lubricator 358 which serves to guide the coiled tubing 354 as it exits the injector 348. The lubricator 358 can be telescoping to permit access to the coiled tubing during connection / disconnection with a bottom hole assembly (FIG. 2).

[0074] A top drive 360 is supported by the mast 334. The top drive 360 can engage and rotate downhole equipment (which equipment may or may not be in the well when engaged or rotated by the top drive 360) such as jointed-pipe, bottom hole assembly (BHA) elements, etc. The structure and functionality of the top drive 360 is well known in the field and will not be discussed in detail herein.

[0075] Near the forward end of the lowered middle portion 326 of the trailer 320 is a spindle 374 for mounting a coiled tubing spool 376, which is a spool having coiled tubing 354 wound thereon. The coiled tubing spool 376 is rotated during drilling operations by a spool drive motor 378 connected to the spindle 374 by chains or belts 380. As coiled tubing 354 exits the coiled tubing spool 376 during drilling operations, it is guided and straightened by a coiled tubing guidance system, in this case a level wind 382 projected above the spindle 374. From the level wind 382, the coiled tubing 354 extends up to the injector arch 356. The coiled tubing guidance system also serves to wind the coiled tubing 354 evenly across the coiled tubing spool 376 when the coiled tubing 354 is being rewound back onto the spool 376. In the alternative to a level wind 382 which guides incoming coiled tubing 354 back and forth across the coiled tubing spool 376, the guidance system may also include, for example, a traversing system.

[0076] Also located on the trailer are an engine 384 for providing the power required to operate the various drilling components, a hydraulic tank 386 for storing hydraulic fluids for use in operating the various hydraulic cylinders located on the rig, a hydraulic cooler 388 for cooling the hydraulic fluid, a fuel tank 390 for storage of fuel for the engine 384, and a mast rest 392 located near the front of the trailer 320 extending above the trailer for supporting the mast 334 when the mast 334 is in transportation position.

[0077] In operation, the rig is stored and transported with the mast 334 in its transportation position, namely with the mast 334 in a substantially horizontal position. Once a site for a well has been identified, the trailer 320 is positioned such that the mast 334 when erected will be in line with the axis of the well to be drilled. When the trailer 320 is in position, the stabilizer legs 328 are extended such that their pontoons engage the ground. The stabilizer legs 328 are then adjusted so as to level the trailer 320. The mast 334 is then erected from its transportation position to its vertical operating position. If a coiled tubing spool 376 is not already mounted on the spindle 374, one is put in place, and then the coiled tubing 354 is threaded through the level wind 382 up through the injector arch 356 and into the coiled tubing injector 348.

[0078] In a typical drilling application, the top drive 360 will then be used to drill a pilot hole using jointed pipe. The process of jointed-pipe drilling is well known to those in the relevant field and is not discussed in detail here. The coiled tubing injector 348 and top drive 360 are then configured to suspend a drilling BHA on the coiled tubing / drill string 354, which is run into the pilot hole and operated to drill the wellbore.

[0079] FIG. 4 illustrates an example device 2500, with a processor 2502 and memory 2504 that can be configured to implement various embodiments of the methods and processes as discussed in the present application, including the construction and storage of the model for use while drilling and the while drilling operations that process the measured drilling parameters and access the model and generate and output the well log as part of the method of FIGS. 1A and 1B.

[0080] Memory 2504 can also host one or more databases and can include one or more forms of volatile data storage media such as random-access memory (RAM), and / or one or more forms of nonvolatile storage media (such as read-only memory (ROM), flash memory, and so forth).

[0081] Device 2500 is one example of a computing device or programmable device and is not intended to suggest any limitation as to scope of use or functionality of device 2500 and / or its possible architectures. For example, device 2500 can comprise one or more computing devices, programmable logic controllers (PLCs), etc.

[0082] Further, device 2500 should not be interpreted as having any dependency relating to one or a combination of components illustrated in device 2500. For example, device 2500 may include one or more computers, such as a laptop computer, a desktop computer, a mainframe computer, etc., or any combination or accumulation thereof.

[0083] Device 2500 can also include a bus 2508 configured to allow various components and devices, such as processors 2502, memory 2504, and local data storage 2510, among other components, to communicate with each other.

[0084] Bus 2508 can include one or more of any of several types of bus structures, including a memory bus or memory controller, a peripheral bus, an accelerated graphics port, and a processor or local bus using any of a variety of bus architectures. Bus 2508 can also include wired and / or wireless buses.

[0085] Local data storage 2510 can include fixed media (e.g., RAM, ROM, a fixed hard drive, etc.) as well as removable media (e.g., a flash memory drive, a removable hard drive, optical disks, magnetic disks, and so forth). One or more input / output (I / O) device(s) 2512 may also communicate via a user interface (UI) controller 2514, which may connect with I / O device(s) 2512 either directly or through bus 2508.

[0086] In one possible implementation, a network interface 2516 may communicate outside of device 2500 via a connected network. A media drive / interface 2518 can accept removable tangible media 2520, such as flash drives, optical disks, removable hard drives, software products, etc. In one possible implementation, logic, computing instructions, and / or software programs comprising elements of module 2506 may reside on removable media 2520 readable by media drive / interface 2518.

[0087] In one possible embodiment, input / output device(s) 2512 can allow a user (such as a human annotator) to enter commands and information into device 2500, and also allow information to be presented to the user and / or other components or devices. Examples of input device(s) 2512 include, for example, sensors, a keyboard, a cursor control device (e.g., a mouse), a microphone, a scanner, and any other input devices known in the art. Examples of output devices include a display device (e.g., a monitor or projector), speakers, a printer, a network card, and so on.

[0088] Various systems and processes of present disclosure may be described herein in the general context of software or program modules, or the techniques and modules may be implemented in pure computing hardware. Software generally includes routines, programs, objects, components, data structures, and so forth that perform particular tasks or implement particular abstract data types. An implementation of these modules and techniques may be stored on or transmitted across some form of tangible computer-readable media. Computer-readable media can be any available data storage medium or media that is tangible and can be accessed by a computing device. Computer readable media may thus comprise computer storage media. "Computer storage media" designates tangible media, and includes volatile and nonvolatile, removable, and non-removable tangible media implemented for storage of information such as computer readable instructions, data structures, program modules, or other data. Computer storage media include, but are not limited to, RAM, ROM, EEPROM, flash memory or other memory technology, CD-ROM, digital versatile disks (DVD) or other optical storage, magnetic cassettes, magnetic tape, magnetic disk storage or other magnetic storage devices, or any other tangible medium which can be used to store the desired information, and which can be accessed by a computer.

[0089] Some of the methods and processes described above can be performed by a processor. The term "processor" should not be construed to limit the embodiments disclosed herein to any particular device type or system. The processor may include a computer system. The computer system may also include a computer processor (e.g., a microprocessor, microcontroller, digital signal processor, general-purpose computer, special-purpose machine, virtual machine, software container, or appliance) for executing any of the methods and processes described above. The computer system may further include a memory such as a semiconductor memory device (e.g., a RAM, ROM, PROM, EEPROM, or Flash-Programmable RAM), a magnetic memory device (e.g., a diskette or fixed disk), an optical memory device (e.g., a CD-ROM), a PC card (e.g., PCMCIA card), or other memory device.

[0090] Alternatively, or additionally, the processor may include discrete electronic components coupled to a printed circuit board, integrated circuitry (e.g., Application Specific Integrated Circuits (ASIC)), and / or programmable logic devices (e.g., a Field Programmable Gate Arrays (FPGA)). Any of the methods and processes described above can be implemented using such logic devices.

[0091] Some of the methods and processes described above can be implemented as computer program logic for use with the computer processor. The computer program logic may be embodied in various forms, including a source code form or a computer executable form. Source code may include a series of computer program instructions in a variety of programming languages (e.g., an object code, an assembly language, or a high-level language such as C, C++, or JAVA). Such computer instructions can be stored in a non-transitory computer readable medium (e.g., memory) and executed by the computer processor. The computer instructions may be distributed in any form as a removable storage medium with accompanying printed or electronic documentation (e.g., shrink wrapped software), preloaded with a computer system (e.g., on system ROM or fixed disk), or distributed from a server or electronic bulletin board over a communication system (e.g., the Internet or World Wide Web).

[0092] 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.

[0093] The foregoing outlines features of several embodiments so that those skilled in the art may better understand the aspects of the disclosure. Those skilled in the art should appreciate that they may readily use the disclosure as a basis for designing or modifying other processes and structures for carrying out the same purposes and / or achieving the same advantages of the embodiments introduced herein. Those skilled in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the disclosure, and that they may make various changes, substitutions and alterations herein without departing from the spirit and scope of the disclosure. The scope of the invention should be determined only by the language of the claims that follow. The term "comprising" within the claims is intended to mean "including at least" such that the recited listing of elements in a claim are an open group. The terms "a," "an" and other singular terms are intended to include the plural forms thereof unless specifically excluded.

Claims

1. A method of drilling a wellbore that traverses a subterranean formation, the method comprising: i) constructing or providing a computational model that relates input data that represents at least one drilling performance parameter (or change therein) at one or more drilling conditions to output data that represents at least one petrophysical formation property; ii) sweeping wellbore pressure over a range of pressures while drilling the wellbore and measuring and analyzing wellbore pressures and associated drilling performance parameters to determine data representing at least one drilling performance parameter (or change therein) at one or more drilling conditions; iii) supplying the data representing at least one drilling performance parameter (or change therein) at one or more drilling conditions of ii) as input data to the computational model of i), which generates output data that represents at least one petrophysical formation property associated with the input data; and iv) adding the data representing the at least one petrophysical formation property output by the model in iii) to a well log of formation properties.

2. The method of claim 1, further comprising: v) setting or adjusting the direction of drilling the wellbore based on the well log of formation properties.

3. The method of claim 1 or 2, wherein: the range of pressures of the wellbore pressure sweeping of ii) includes pressures that lead to overbalanced drilling and underbalanced drilling and balanced drilling.

4. The method of any one of the preceding claims, wherein: the at least one petrophysical formation property output by the computational model in iii) includes at least one of: formation pressure, porosity, permeability, and fluid type.

5. The method of any one of the preceding claims, wherein: the at least one drilling performance parameter that is part of the computational model of i) and that is determined while drilling the wellbore in ii) includes, or is derived from, at least one of: ROP, WOB, torque, and MSE; and / or the at least one drilling performance parameter that is part of the computation model of i) and that is determined while drilling the wellbore in ii) includes, or is derived from, a change in MSE at a predefined overbalanced drilling condition.

6. The method of any one of the preceding claims, wherein: the wellbore pressure sweeping of ii) is performed without measuring or knowing the formation pressure of the formation; and / or the wellbore pressure sweeping of ii) varies the wellbore pressure by adjusting one or more drilling parameters selected from surface choke pressure, constituent drilling fluids or drilling fluid flow rates.

7. The method of any one of the preceding claims, wherein: the one or more drilling conditions associated with the at least one drilling performance parameter (or change therein) of the computational model of i) and the at least one drilling performance parameter (or change therein) determined while drilling in ii) corresponds to one or more levels of underbalanced drilling.

8. The method of claim 7, wherein: the one or more levels of underbalanced drilling are represented by a predefined "underbalanced drilling" state or status and ratio(s) or percentage(s) or difference(s) of wellbore pressure relative to formation pressure with the wellbore pressure less than the formation pressure.

9. The method of any one of the preceding claims, wherein: the one or more drilling conditions associated with the at least one drilling performance parameter (or change therein) of the computational model of i) and the at least one drilling performance parameter (or change therein) determined while drilling in ii) corresponds to one or more levels of overbalanced drilling.

10. The method of claim 9, wherein: the one or more levels of overbalanced drilling are represented by a predefined "overbalanced drilling" state or status and ratio(s) or percentage(s) or difference(s) of wellbore pressure relative to formation pressure with the wellbore pressure less than the formation pressure.

11. The method of any one of the preceding claims, wherein: the one or more drilling conditions associated with the at least one drilling performance parameter (or change therein) of the computational model of i) and the at least one drilling performance parameter (or change therein) determined while drilling in ii) corresponds to balanced drilling, wherein: the balanced drilling are preferably represented by a predefined "balanced drilling" state or status with the wellbore pressure matching the formation pressure.

12. The method of any one of the preceding claims, further comprising: monitoring and controlling one or more drilling parameters while drilling the wellbore to maintain one or more predefined levels of underbalanced drilling, wherein the drilling preferably employs a drill string that employs coiled tubing; and / or monitoring and controlling one or more drilling parameters while drilling the wellbore to maintain one or more predefined levels of overbalanced drilling; and / or monitoring and controlling one or more drilling parameters while drilling the wellbore to maintain balanced drilling.

13. The method of any one of the preceding claims, wherein: determining the at least one petrophysical formation property output by the model and added to the well log avoids the use of one or more while drilling tools, which can reduce drilling costs.

14. A system for use in drilling a wellbore that traverses a subterranean formation, the system comprising: at least one processor configured to i) store a computational model that relates input data that represents at least one drilling performance parameter (or change therein) at one or more drilling conditions to output data that represents at least one petrophysical formation property; ii) determine data representing at least one drilling performance parameter (or a change therein) at one or more drilling conditions from analysis of wellbore pressures and associated drilling performance parameters that are measured while sweeping wellbore pressure over a range of pressures while drilling the wellbore; iii) supply the data representing at least one drilling performance parameter (or a change therein) at one or more drilling conditions of ii) as input data to the computational model of i), which generates output data that represents at least one petrophysical formation property associated with the input data; and iv) add the data representing the at least one petrophysical formation property output by the model in iii) to a well log of formation properties.

15. The system of claim 14, wherein: the at least one petrophysical formation property output by the computational model in iii) includes at least one of: formation pressure, porosity, permeability, and fluid type; and / or wherein: the at least one drilling performance parameter that is part of the computational model of i) and that is determined while drilling the wellbore in ii) includes, or is derived from, at least one of: ROP, WOB, torque, and MSE.

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