Earth formations may be used for various purposes such as hydrocarbon production, geothermal production, and carbon dioxide sequestration. Typically, boreholes are drilled into the formations to provide access to them. The boreholes are drilled by a drilling rig that rotates a drill bit at the end of a drill string. Various drilling parameters are input to the drilling rig such as rotational speed, weight on bit, rate-of-penetration (ROP), flow rate or fluid type in order to drill a borehole while preventing borehole breakouts and fractures from occurring. Borehole breakouts and fractures are indications that the specific drilling parameters may have caused the borehole wall to be over-stressed. Hence, it would be appreciated in the drilling industry if the drilling parameters could be selected to prevent over-stressing of a borehole while it is being drilled.
Disclosed is a method for estimating a time at which a pressure window relevant observation occurred relating to an event that occurred in an open borehole penetrating an earth formation. The method includes receiving with a processor a pressure window relevant observation that provides input to adjusting a pressure window for drilling fluid for drilling the borehole. The method further includes estimating with the processor a time window in which at least one selection from a group consisting of a physical parameter, a chemical parameter, and a process that caused the pressure window relevant observation to occur, the time window having a start time and an end time.
Also disclosed is an apparatus for estimating a time at which a pressure window relevant observation occurred relating to an event that occurred in an open borehole penetrating an earth formation. The apparatus includes a processor, which is configured to receive a pressure window relevant observation that provides input to adjusting a pressure window for drilling fluid for drilling the borehole, and estimate a time window in which at least one selection from a group consisting of a physical parameter, a chemical parameter, and a process that caused the pressure window relevant observation to occur, the time window having a start time and an end time.
The following descriptions should not be considered limiting in any way. With reference to the accompanying drawings, like elements are numbered alike:
A detailed description of one or more embodiments of the disclosed apparatus and method presented herein by way of exemplification and not limitation with reference to the Figures.
Disclosed are method and apparatus for drilling a borehole penetrating an earth formation. More specifically, a method and system are disclosed for automatically updating a pressure window for safe drilling by an integrated analysis of drill string or drilling operations and wellbore stability relevant events in the environment of a borehole or at the surface. The method and system includes identifying one or more dysfunctions during a drill string or drilling operation and assigning physical parameters such as temperature and or pressure to the dysfunctions. Physical parameters may be derived from measurements downhole or from physical models if direct measurements are not available or if locations of measurements are not the same as locations of interest (e.g., location of dysfunction), so that an interpolation or extrapolation of the physical properties is necessary.
Drilling operations or drill string operations include any movements or activities that are conducted when a borehole is created. More specifically, drilling or drill string operations include on-bottom drilling, tripping out of the hole, tripping into the hole, coring, re-logging, any kind of reaming or under-reaming, setting a casing, running a wireline operation, or setting a liner while drilling. Also, activities where the drill string is not altered may belong to a drilling operation, such as waiting on weather, waiting on maintenance, etc. In addition, unintentional drill string movements such as rig heave for offshore rigs are considered as a drill string operation. It is well understood that any of the above mentioned operations or activities may be conducted under flow-on conditions, where drilling fluid is circulated through the drill string and back through the annulus to the surface. Reverse circulation down the annulus and back to the surface through the drill string is also considered a flow-on condition. Likewise, the above mentioned drilling operations may be conducted under flow-off condition, where no drilling fluid is circulated. Also, it is well understood that the above mentioned drilling or drill string operations may be conducted while rotating the drill string (rotary mode) or while not rotating the drill string (sliding more).
During a drilling or drill string operation, the drill string, the bottom-hole assembly, the bit, the drilling fluid or any other device or component of the drilling system may behave in a way that is not desirable or harmful for the drilling or drill string operation, which is hereafter referred to as a drilling or drill string dysfunction. A drilling or drill string dysfunction includes vibrations of any kind of the drill string or the bottom hole assembly, the drill pipe, drill string or bottom hole assembly getting stuck when trying to pull out of hole or trying to run into the hole, swab or surge effects due to fast movements of the drill string, pack-offs due to inefficient hole cleaning Those drilling dysfunctions may be automatically detected by analysis and interpretation of downhole measurements-while-drilling (MWD) data, logging-while-drilling (LWD) data, and of surface logging data such as the surface-weight-on-bit, the flow back pressure, the pump pressure, etc.
Drilling or drill string operational dysfunctions are oftentimes causing instable wellbore conditions which can result in drilling operational challenges including the abandonment of a wellbore in the worst case. Therefore, in addition to automatically detecting drilling or drill string dysfunctions, events, features or incidents, which are indications for an instable wellbore, may also be automatically detected. Among others, such features include borehole breakouts, washouts or other unintentional hole enlargements detected by LWD images of the borehole wall or detected by LWD caliper logs, cavings detected at the mud shaker at the surface, drilling-induced tensile fractures detected by LWD image sensors, losses of drilling mud into the formation, or a fluid entry into the formation termed a kick.
Wellbore stability relevant events, features or incidents can be used to update the pressure window for safe drilling operations if the downhole physical properties such as the downhole annular pressure and temperature conditions are known. What is usually not precisely known is the exact time at which a wellbore stability relevant incident or feature was created because either the downhole LWD sensors pass the feature at some time after the bit or because the feature, (e.g., the cavings) need to be transported to the surface by the drilling mud before they can be detected. Therefore, an integrated analysis of drilling dysfunctions and wellbore stability events is desirable.
A sensor detects a location of a borehole abnormality and other sensors measure physical properties such as pressure and temperature in the vicinity of the abnormalities. Alternatively a plurality of sensors measure physical properties and analyze those measurements to detect borehole abnormalities. A mathematical geo-mechanical model of the formation is updated or calibrated using estimates of the properties at the abnormality location using the measurements. Because the exact properties at the abnormality may not be known, the properties may be estimated with a statistical uncertainty. The term “geomechanical model” relates to a mathematical model of the earth formation, which calculates mechanical stresses in an earth formation at one or more depths using properties measured or identified by one or more downhole tools. Parameters from laboratory investigations may also be used if direct measurements of formation properties are not possible or not available. In addition, information, parameters and data may be used from offsite wells for the geo-mechanical model. The geo-mechanical model may include one or more equations for calculating the mechanical stresses and the compressive and tensile failure of the formation around the borehole. By inputting the latest and most accurate logged measurements, the geomechanical model can provide the most accurate estimates of the stresses and formation rock failure. Further, drilling parameters can be selected such that drilling operations do not result in pressures and temperatures that cause the formation stresses to be exceeded. The model, in addition, may incorporate pressure and temperature data from previously drilled boreholes that may or may not have a borehole abnormality. For example, if in a previously drilled borehole a certain combination of pressure and temperature is associated with a borehole abnormality, then that information may be incorporated into the model as a combination that should be avoided to prevent the creation of a borehole abnormality in a currently drilled borehole.
The drilling pressure window is depicted in
Caliper (or borehole diameter) logs or images of the borehole wall are used to detect abnormalities (also referred to as features) such as breakouts and drilling-induced tensile fractures. These features develop due to excessive re-distributed stresses around the wellbore as a result of excessive annulus pressure and/or temperature. The amount of stress re-distribution depends on the in-situ prevailing Earth stresses (orientation and magnitude), the formation pore pressure, the offload applied by the drilling fluid pressure to the wellbore wall and the temperature difference between the annulus and the formation. Other types of wellbore stability relevant features are washouts in brittle shales or, more general, in fractured rock. Washouts are fully circumferential hole enlargements caused by drilling fluid penetrating into the fractured matrix and thereby decreasing the effective stress around the wellbore which ultimately leads to sloughing of formation material into the annulus of the borehole. Both borehole breakouts and washouts by sloughing formations create cavings which are transported by the drilling fluid to the surface. Cavings are larger pieces of rock (compared to cuttings which develop from the rock-bit interaction) and the shape of the cavings provides information about the failure mechanism that is prevailing in the downhole formation.
The transport of cavings from the downhole formation to the surface by the drilling fluid can be estimated when fluid density and rheology as well as the operating conditions of the drilling process like flow rate and drill string rotary speed are known. Including the operation process history in the transport modeling further increases the accuracy of the prediction. Therefore, whenever cavings are detected at the surface, an approximate time at which the cavings have been created may be inferred, although an uncertainty has to be assigned to the estimated time. The uncertainty originates from the unknown location of the rock failure and from the accuracy of estimating the transport properties of the drilling mud. Of course, the uncertainty of the cavings creation time reduces with more accurate transportation models and failure location measurements.
Also transported with the drilling fluid is gas which escapes from the formation into the borehole annulus if the formation pore pressure is larger than the pressure of the drilling fluid. Detection of gas by sensors installed at the surface of a rig is therefore another means to calibrate the pressure window. Upon the detection of gas at the surface, the origin of that gas may be inferred from an appropriate model for the transport and flow of gas from a downhole formation to the surface, and physical parameter assigned to the gas readings.
Knowledge of the annular pressure and temperature conditions during the development of the features can thus be used to constrain the in-situ Earth stresses. One uncertainty for constraining the in-situ stresses are the unknown pressure and temperature conditions which prevailed during the creation of the features (such as breakouts, washouts, and/or drilling-induced tensile fractures). In general, the features could have been created at any time between the bit and a sensor (image, caliper) passing the depth of the feature. Hence, any pressure and temperature condition prevailing during that time could have caused the feature. Compared to wireline runs, while-drilling sensors pass a particular depth a short time after the bit drilled the well, so that the pressure and temperature variations between the bit and the sensor are relatively small. Therefore, the annular pressure and temperature conditions which could have caused a geomechanically relevant feature are significantly constrained (i.e., decreased uncertainty of the pressure and temperature conditions) compared to the wireline case where the sensor passes a particular depth after the entire drilling run. Yet, the analysis of the pressure and temperature history between the bit and a sensor can become complex and not all relevant data are always available at the surface. Therefore, an automated analysis and characterization of the pressure and temperature is essential to constrain the in-situ stresses when features are observed or not observed.
Disclosed next with reference to
The downhole tool 10 is configured to perform various measurements on the formation 4 and on the environment in the borehole 2. One or more pressure sensors 12 and one more temperature sensors 13 are included in the downhole tool 10. With multiple sensors of the same type, the same types of sensors may be separated axially from each other. In addition, these and other sensors may also be disposed in various locations along the drill string 6. In one or more embodiments, the pressure and temperature sensors measure the pressure and temperature of the drilling fluid external to the tool 10 and, thus, provide a measurement of pressure and temperature of the formation 4 at the borehole wall adjacent to these sensors. The downhole tool 10 also includes a borehole wall sensor 14. The borehole wall sensor 14 is configured to sense the borehole wall and detect borehole abnormalities such as a breakout, a washout, or a fracture. The term “breakout” relates to a section of a borehole wall that has wall material removed leaving a pocket or indentation. Commonly, breakouts are created at two sides of the borehole, 180 degrees apart from each other. The term “fracture” related to a crack in the formation, which is visible at the borehole wall. The fracture can be axial along the longitudinal axis of the borehole, circumferential, or diagonal (en-echelon). Embodiments of the borehole wall sensor 14 include a caliper tool configured to measure the diameter of the borehole or an imager configured to produce an image of the borehole wall as the tool 10 is being conveyed through the borehole 2. An imager is a tool designed to measure a physical property in circumferential and axial direction. The physical property may be a gamma ray reading, the formation resistivity, the formation bulk density, or other properties which show sufficient variations for different formation properties. The variations may then be plotted to form an image, which may be displayed.
The downhole tool 10 may also include one or more other sensors (not shown) configured to measure one or more properties related to values that may be input into the geo-mechanical model. For example, the geo-mechanical model may require as inputs formation pore pressure, formation temperature, and formation pressure. The other sensors may provide these and other properties. A formation tester (not shown) having an extendible probe to seal to a wall of the borehole and configured to measure formation pressure or extract a sample of formation fluid for analysis may also be included in the downhole tool 10. In one or more embodiments, these properties may have been previously obtained such as from a nearby borehole or previous analysis, and these other sensors may not be required.
Drilling wells causes the in-situ Earth stresses to re-distribute around the borehole. Amongst others, the stress redistribution is affected by the annular pressure applied as a load against the borehole wall and by thermal expansion if the temperature in the formation around the well changes. Both, annular pressures and temperatures vary during the drilling operation.
If the load applied against the borehole wall becomes excessively high and/or the temperature is sufficiently decreased in the formation around the borehole, the minimum principle re-distributed stress becomes tensile, by which fractures are created at the borehole wall. If the load applied against the borehole wall becomes excessively low and/or the temperature is sufficiently increased in the formation around the borehole, the re-distributed shear stress exceeds the rock strength by which parts of the borehole wall break out of the formation, termed breakouts. The observation of breakouts and/or drilling-induced tensile fractures indicates that the annular pressure and/or temperature were excessive, so that the Earth in-situ stresses can be inferred if the additional parameters pore pressure and rock strength are known. This process is termed calibration of the in-situ stresses by observed feature (breakouts and/or drilling-induced tensile fractures).
One uncertainty in the calibration procedure is the unknown pressure and temperature conditions at the time the features were created at the borehole wall, because the time at which the features were created is not known. The time frame for the feature creation is either between two sensors, whenever the first sensor did not show any feature, or between the bit and a sensor passing a specific depth. This uncertainty is illustrated in
Another uncertainty that comes along with the determination of the unknown time at which the feature was created is the resulting unknown distance between the feature and a downhole pressure and/or temperature sensor. In one or more embodiments, multiple sensors are contained in the BHA 10, so that a pressure and/or temperature profile can be acquired along the BHA (c.f.
One example of uncertainty relates to the development of a pack-off somewhere between pressure sensor 1 or 2 and the image sensor (c.f.
The pressure and temperature history between the bit and a sensor detecting a relevant feature (image or acoustic caliper sensor) is shown in
Scenario 2 assumes the detection of a feature in a measured bit depth of 3280 ft. MD, but the feature was detected on an image acquired by the while-drilling image sensor, whose current depth versus time is plotted in the upper graph. The time between the bit and the while-drilling sensor passing the feature at 3280 ft. MD is thus Δt2 (termed bit-sensor time interval hereafter), which is significantly shorter than the time Δt1 plus the time ΔtS. Consequently, the range of pressures and temperatures is smaller in scenario 2.
For simplicity, the following assumptions were made for the calculation of SHmax: (1) hydrostatic pore pressure (formation pressure) distribution; (2) temperature equilibrium in the mud (temperature at the bit equals temperature at the image sensor); (3) geothermal gradient of 3° C./100 m; (4) zero tensile rock strength; (5) vertical borehole axis aligned to one of the principle stress directions; and (6) the drilling fluid pressure difference in the annulus along the BHA is hydrostatic. In addition to this, the dynamic pressure effect could be calculated, if the required input parameters are known, to increase the accuracy of this method. With zero tensile rock strength, σθθmin=0, and SHMax=3Sh min−2pp−Δp−σθθΔT and σθθΔT=(αTEΔT)/(1−υ) where: SHMax represents maximum principle horizontal stress; Shmin represents minimum principle horizontal stress; pp represents pore pressure; ΔT represents difference between mud and formation pressure; Δp represents difference between mud and formation pressure; αT represents thermal expansion coefficient; E represents Young's modulus; and υ represents Poisson ratio.
The lower plot in
The lower plot in
The extraction of the possible pressure and temperature range from the acquired data can become complex whenever the time delay between the bit and the sensor passing a particular depth becomes large and/or whenever not all data are available at the surface, due to either limited telemetry data transfer band width or due to operational conditions. One such condition is the annular pressure measurement under drilling fluid flow-off conditions at which mud-pulse telemetry does not operate. Therefore, an automatic analysis of the pressure and temperature conditions during the bit-sensor time interval and an appropriate characterization is beneficial in a way that it improves and accelerates the analysis of in-situ Earth stress magnitudes once features such as breakouts and/or drilling-induced tensile fractures were detected at the borehole wall. Automatic feature detection from real-time images is beneficial in this context. Also, such an analysis is essential to consider pressure and temperature uncertainties in the data. An appropriate characterization of the pressure and/or temperature history, for example by maximum and minimum values, allows setting a range of possible values as input data for the analysis.
In one or more embodiments, necessary components for an appropriate analysis include: (1) a downhole sensor which is able to detect any feature which is relevant for geomechanical modeling, such as any image sensor (electrical, density, gamma, acoustic) or a caliper (acoustic caliper or other); (2) at least one downhole sensor which is able to continuously measure the downhole annular pressure and temperature conditions (during drilling fluid flow-on conditions); (3) a downhole sensor which is able to measure the pressure and temperature conditions during a connection (during drilling fluid flow-off conditions) either continuous or discrete; (4) or, alternatively a software system which is able to model downhole conditions based on the physics of the drilling operation and surface measurements; (5) a surface sensor or system which is able to detect wellbore stability relevant features or aspects, such as cavings or gas readings; and (6) a downhole and/or surface software system which is able to analyze and characterize the pressure and temperature variations between the bit and the downhole sensor for feature detection passing a particular depth. Downhole implementation is realized on the downhole electronics of any downhole MWD/LWD tools; surface implementation takes place in the surface computer processing system for data acquisition and analysis.
The teachings disclosed herein aim to automatically characterize the downhole annular pressure and temperature history. “Characterization” includes the statistical or other analysis of the pressure and temperature values for the determination of the maximum, average and minimum temperature and pressure during the bit-sensor time interval, as well as other parameters such as skewness and kurtosis, which describe the asymmetry of the histogram and the peakedness of the pressure values, respectively. Also, an average pressure and temperature value of a few (for example 5 or 10) highest (for pressure) and lowest (for temperature) values are another characterization of the pressure and temperature history. Characterization also includes the identification of the completeness of the data together with the determination of the amount of available data, as well as the identification of data gaps (for example during a connection where flow-off pressure data are not transmitted to the surface), and the determination of the accuracy of the data. In this context of available data, modeling is an additive component to further characterize and constrain the pressure and temperature conditions which were prevailing before an image and/or caliper log passed the depth location. Modeling allows transferring pressure and temperature conditions from the sensor positions to any other location along the BHA. Also, modeling yields pressure and/or temperature values whenever measurements do not exist. Also, characterization includes the consideration of the active operation which prevailed between the bit and the sensor (image or caliper) passing a depth. Operations can be drilling, tripping-out-of-hole, reaming and others. Changes in the drilling parameters (e.g., rate of penetration, weight on bit, and rotational speed) and/or fluid properties (mud weight) help to further characterize the pressure and/or temperature history.
Oftentimes, excessively high or low temperature and/or pressure magnitudes are associated with specific drilling operations so that a characterization of features or calibration sources (i.e., measured properties) also includes detecting those drilling operations conducted between the bit and the sensor passing a depth. Relevant operations may be a connection of pipes, tripping into the hole causing a surge effect, tripping out of the hole causing a swab effect, pumping a sweep, changing a mud property such as mud (i.e., drilling fluid) weight, changing the mud flow rate so that the downhole annular pressure is altered, cooling the mud at the surface. In addition, the dynamic behavior of the BHA and/or the drill string, referred to as drilling vibrations, may be responsible for the damage of the borehole wall. Features detected to calibrate the geomechanical model may thus also be attributed by such drilling vibration data.
Another way characterization can be performed is by forward characterization, as illustrated in
The benefit of forward characterization is illustrated in
Physical parameters, chemical parameters, and/or drill string operations occurring within the time window and at a certain depth in an open borehole may cause an event at that depth in the borehole such as a borehole abnormality or an unexpected event such as gas leakage into the borehole. Non-limiting examples of the physical parameter are borehole pressure in the annulus (i.e., between drill string and borehole wall), differential pressure between the borehole and the formation, and drilling fluid temperature in the annulus. These physical parameters at the certain depth may be input into the geo-mechanical model to determine the formation stresses at that certain depth. If the physical parameters are measured at a distance D from the certain depth, then the parameters at the certain depth may be interpolated from the measured parameters using a hydraulic and/or thermal model. One non-limiting example of a chemical parameter is brine saturation of the drilling fluid, which is used to calculate osmotic effects, effects of water adsorption to clay minerals or rock salt solution effects. Certain obtained physical parameters may be used to adjust the pressure window. These parameters include orientation of borehole breakouts, width of borehole breakouts, shape of drilling-induced tensile fractures, orientation of drilling-induced tensile fractures, and rock strength.
It can be appreciated that one or more advantages of the methods and apparatus disclosed above relate to drilling a borehole efficiently using drilling parameters that may aggressively drill the borehole while at the same time being conservative to prevent a borehole abnormality from occurring.
In support of the teachings herein, various analysis components may be used, including a digital and/or an analog system. For example, the downhole electronics 9, the computer processing system 11, or the sensors in the downhole tool 10 may include digital and/or analog systems. The system may have components such as a processor, storage media, memory, input, output, communications link (wired, wireless, pulsed mud, optical or other), user interfaces, software programs, signal processors (digital or analog) and other such components (such as resistors, capacitors, inductors and others) to provide for operation and analyses of the apparatus and methods disclosed herein in any of several manners well-appreciated in the art. It is considered that these teachings may be, but need not be, implemented in conjunction with a set of computer executable instructions stored on a non-transitory computer readable medium, including memory (ROMs, RAMs), optical (CD-ROMs), or magnetic (disks, hard drives), or any other type that when executed causes a computer to implement the method of the present invention. These instructions may provide for equipment operation, control, data collection and analysis and other functions deemed relevant by a system designer, owner, user or other such personnel, in addition to the functions described in this disclosure.
The term “carrier” as used herein means any device, device component, combination of devices, media and/or member that may be used to convey, house, support or otherwise facilitate the use of another device, device component, combination of devices, media and/or member. Other exemplary non-limiting carriers include drill strings of the coiled tube type, of the jointed pipe type and any combination or portion thereof. Other carrier examples include casing pipes, wirelines, wireline sondes, slickline sondes, drop shots, bottom-hole-assemblies, drill string inserts, modules, internal housings and substrate portions thereof.
Elements of the embodiments have been introduced with either the articles “a” or “an.” The articles are intended to mean that there are one or more of the elements. The terms “including” and “having” are intended to be inclusive such that there may be additional elements other than the elements listed. The conjunction “or” when used with a list of at least two terms is intended to mean any term or combination of terms. The terms “first” and “second” are used to distinguish elements and do not denote a particular order. The term “coupled” relates to a first component being coupled to a second component either directly or indirectly through an intermediate component.
It will be recognized that the various components or technologies may provide certain necessary or beneficial functionality or features. Accordingly, these functions and features as may be needed in support of the appended claims and variations thereof, are recognized as being inherently included as a part of the teachings herein and a part of the invention disclosed.
While the invention has been described with reference to exemplary embodiments, it will be understood that various changes may be made and equivalents may be substituted for elements thereof without departing from the scope of the invention. In addition, many modifications will be appreciated to adapt a particular instrument, situation or material to the teachings of the invention without departing from the essential scope thereof. Therefore, it is intended that the invention not be limited to the particular embodiment disclosed as the best mode contemplated for carrying out this invention, but that the invention will include all embodiments falling within the scope of the appended claims.