Patent Grant
8726987
This application claims priority from U.S. Provisional Patent Application Ser. No. 61/389,978, filed on Oct. 5, 2010, incorporated herein by reference in its entirety.
This disclosure generally relates to testing and sampling of earth formations or reservoirs. More specifically, this disclosure relates to evaluating a parameter of interest of an earth formation in-situ during drilling operations, and, in particular, performing the evaluation using an extendable element configured to evaluate the parameter of interest.
To obtain hydrocarbons such as oil and gas, boreholes are drilled by rotating a drill bit attached at a drill string end. A large proportion of the current drilling activity involves directional drilling, i.e., drilling deviated and horizontal boreholes to increase the hydrocarbon production and/or to withdraw additional hydrocarbons from the earth's formations. Modern directional drilling systems generally employ a drill string having a bottom hole assembly (BHA) and a drill bit at an end thereof that is rotated by a drill motor (mud motor) and/or by rotating the drill string. A number of downhole devices placed in close proximity to the drill bit measure certain downhole operating parameters associated with the drill string. Such devices typically include sensors for measuring downhole temperature and pressure, azimuth and inclination measuring devices and a resistivity-measuring device to determine the presence of hydrocarbons and water. Additional down-hole instruments, known as logging-while-drilling (LWD) tools, are frequently attached to the drill string to determine the formation geology and formation fluid conditions during the drilling operations.
Boreholes are usually drilled along predetermined paths and the drilling of a typical borehole proceeds through various formations. The drilling operator typically controls the surface-controlled drilling parameters, such as the weight on bit, drilling fluid flow through the drill pipe, the drill string rotational speed and the density and viscosity of the drilling fluid to optimize the drilling operations. The downhole operating conditions continually change and the operator must react to such changes and adjust the surface-controlled parameters to optimize the drilling operations. For drilling a borehole in a virgin region, the operator typically has seismic survey plots which provide a macro picture of the subsurface formations and a pre-planned borehole path. For drilling multiple boreholes in the same formation, the operator also has information about the previously drilled boreholes in the same formation.
Hydrocarbon zones may be tested during or after drilling. One type of test involves producing fluid from the formation and collecting samples with a probe or dual packers, reducing pressure in a test volume and allowing the pressure to build-up to a static level. This sequence may be repeated several times at several different depths or point within a single borehole. Testing may include exposing the formation or a sample from the formation to stimuli, such as acoustic energy or electromagnetic energy. From these tests, information can be derived for estimating parameters of interest regarding the formation.
Samples brought up through the borehole may become contaminated by other material in the borehole, including drilling fluid. This risk of contamination limits the value of surface analysis of the samples. Additionally, some parameters of a formation may only be estimated at the depth and under the conditions where drilling is taking place. The properties of a deeper regions of the formation (outside a mud-invaded zone) may be different from those regions in close proximity to the borehole due to the ingress of drilling fluid, which may mix with or displace native formation fluid. This contamination may result in erroneous measurements of properties of the deeper regions of the formation. There is a need for methods and apparatus for evaluating parameters of interest of a formation during the drilling process. The present disclosure discusses methods and apparatuses that satisfy this need.
In aspects, the present disclosure generally relates to the testing and sampling of underground formations or reservoirs. More specifically, this disclosure relates to evaluating a parameter of interest of an earth formation in-situ during drilling operations, and, in particular, performing the evaluation using an extendable element configured to evaluate the parameter of interest.
One embodiment according to the present disclosure includes an apparatus for evaluating a parameter of interest of an earth formation, comprising: a bottom hole assembly (BHA) having a longitudinal axis; and at least one extendable element disposed on the BHA, the at least one extendable element including a drill bit with a nozzle configured to receive a formation fluid, the drill bit being configured to penetrate the earth formation in a direction inclined to the longitudinal axis.
Another embodiment according to the present disclosure includes a method of evaluating a parameter of interest of an earth formation, comprising: conveying a bottom hole assembly (BHA) having a longitudinal axis into a borehole; using at least one drill bit on at least one extendable element on the BHA for penetrating the earth formation to form a channel in a direction inclined to the longitudinal axis, wherein the earth formation is penetrated beyond a contaminated zone; and evaluating the parameter of interest.
Examples of the more important features of the disclosure have been summarized rather broadly in order that the detailed description thereof that follows may be better understood and in order that the contributions they represent to the art may be appreciated.
For a detailed understanding of the present disclosure, reference should be made to the following detailed description of the embodiments, taken in conjunction with the accompanying drawings, in which like elements have been given like numerals, wherein:
This disclosure generally relates to the testing and sampling of underground formations or reservoirs. In one aspect, this disclosure relates to evaluating a parameter of interest of an earth formation in-situ during drilling operations, and, in another aspect, to evaluating a parameter of interest of an earth formation or a formation fluid using an extendable element configured to evaluate the parameter of interest. The parameter of interest may include, but is not limited to, one or more of: (i) pH of the formation fluid or wellbore drilling fluid, (ii) H2S concentration, (iii) density, (iv) viscosity, (v) temperature, (vi) rheological properties, (vii) thermal conductivity, (viii) electrical resistivity, (ix) chemical composition, (x) reactivity, (xi) radiofrequency properties, (xii) surface tension, (xiii) infra-red absorption, (xiv) ultraviolet absorption, (xv) refractive index, (xvi) magnetic properties, (xvii) nuclear spin, (xviii) permeability, (xix) porosity, (xx) nuclear-resonance properties, and (xxi) acoustic properties. Fluid in the formation may be contaminated by contact with drilling fluid and other materials located near the borehole wall, either inside or outside the borehole. The extendable element may include a drill bit for penetrating the formation so that a nozzle or probe may contact formation fluid or an area of the formation that has not been contaminated. The drill bit may also include one or more sensors for estimating a parameter of interest of the formation. The one or more sensors may be configured to estimate, but are not limited to, one or more of: (i) electromagnetic radiation, (ii) electric current, (iii) electrostatic potential, (iv) magnetic flux, (v) acoustic wave propagation, (vi) nuclear radiation, (vii) nuclear-resonance properties, (viii) electrical impedance, and (xix) mechanical force. The drill bit may also include a stimulus source configured to generate a response from the formation. The source may be configured to generate, but is not limited to, (i) electromagnetic radiation, (ii) electric current, (iii) voltage, (iv) magnetic fields, (v) acoustic waves, (vi) nuclear radiation, and (vii) mechanical force. The drill bit and extendable element may be configured to create a channel in the formation. The channel may be inclined relative to a longitudinal axis of the bottom hole assembly. In some embodiments, extendable element may include one or more packers or seals to isolate the portion of the formation with unadulterated formation fluid from sections of the formation that are contaminated or from drilling fluid in the borehole. In some embodiments, the fluid in the channel may be replaced with another fluid. The another fluid may be used to perform one or more of: (i) cleaning the channel, (ii) improving coupling for measurement source and/or receiver devices, and (iii) modifying the channel or formation chemically or physically. The nozzle of the drill bit may be connected to a conduit that runs through the extendable element and configured to receive and preserve the purity of the formation fluid as the formation fluid is moved from the formation into a bottom hole assembly. Within the bottom hole assembly, or drilling assembly, the formation fluid may be stored and/or analyzed by additional sensors or test equipment. In some embodiments, the formation fluid may be transported through the conduit using a pump or pressure differential.
The present disclosure is susceptible to embodiments of different forms. There are shown in the drawings, and herein will be described in detail, specific embodiments of the present disclosure with the understanding that the present disclosure is to be considered an exemplification of the principles of the disclosure, and is not intended to limit the disclosure to that illustrated and described herein. Indeed, as will become apparent, the teachings of the present disclosure can be utilized for a variety of well tools and in all phases of well construction and production. Accordingly, the embodiments discussed below are merely illustrative of the applications of the present disclosure.
A suitable drilling fluid 131 (also referred to as the “mud”) from a source 132 thereof, such as a mud pit, is circulated under pressure through the drill string 120 by a mud pump 134. The drilling fluid 131 passes from the mud pump 134 into the drill string 120 via a desurger 136 and the fluid line 138. The drilling fluid 131a from the carrier 122 discharges at the borehole bottom 151 through openings in the drill bit 150. The returning drilling fluid 131b circulates uphole through the annular space 127 between the drill string 120 and the borehole 126 and returns to the mud pit 132 via a return line 135 and drill cutting screen 185 that removes the drill cuttings 186 from the returning drilling fluid 131b. A sensor S1 in line 138 provides information about the fluid flow rate. A surface torque sensor S2 and a sensor S3 associated with the drill string 120 respectively provide information about the torque and the rotational speed of the drill string 120. Tubing injection speed is determined from the sensor S5, while the sensor S6 provides the hook load of the drill string 120.
In some applications, the drill bit 150 is rotated by only rotating the drill pipe 122. However, in many other applications, a downhole motor 155 (mud motor) disposed in the drilling assembly 190 also rotates the drill bit 150. The rate of penetration for a given BHA 190 largely depends on the WOB or the thrust force on the drill bit 150 and its rotational speed.
The mud motor 155 is coupled to the drill bit 150 via a drive shaft disposed in a bearing assembly 157. The mud motor 155 rotates the drill bit 150 when the drilling fluid 131 passes through the mud motor 155 under pressure. The bearing assembly 157, in one aspect, supports the radial and axial forces of the drill bit 150, the down-thrust of the mud motor 155 and the reactive upward loading from the applied weight-on-bit.
A surface control unit or controller 140 receives signals from the downhole sensors and devices via a sensor 143 placed in the fluid line 138 and signals from sensors S1-S6 and other sensors used in the system 100 and processes such signals according to programmed instructions provided to the surface control unit 140. The surface control unit 140 displays desired drilling parameters and other information on a display/monitor 142 that is utilized by an operator to control the drilling operations. The surface control unit 140 may be a computer-based unit that may include a processor 147 (such as a microprocessor), a storage device 144, such as a solid-state memory, tape or hard disc, and one or more computer programs 146 in the storage device 144 that are accessible to the processor 147 for executing instructions contained in such programs. The surface control unit 140 may further communicate with a remote control unit 148. The surface control unit 140 may process data relating to the drilling operations, data from the sensors and devices on the surface, data received from downhole, and may control one or more operations of the downhole and surface devices. The data may be transmitted in analog or digital form.
The BHA may also contain formation evaluation sensors or devices (also referred to as measurement-while-drilling (“MWD”) or logging-while-drilling (“LWD”) sensors) determining resistivity, density, porosity, permeability, acoustic properties, nuclear-magnetic resonance properties, formation pressures, properties or characteristics of the fluids downhole and other desired properties of the earth formation 195 surrounding the drilling assembly 190. Such sensors are generally known in the art and for convenience are generally denoted herein by numeral 165. The drilling assembly 190 may further include a variety of other sensors and devices 159 for determining one or more properties of the BHA (such as vibration, bending moment, acceleration, oscillations, whirl, stick-slip, etc.) and drilling operating parameters, such as weight-on-bit, fluid flow rate, pressure, temperature, rate of penetration, azimuth, tool face, drill bit rotation, etc.) For convenience, all such sensors are denoted by numeral 159. Device 159 may include an evaluation module 200.
The drilling assembly 190 includes a steering apparatus or tool 158 for steering the drill bit 150 along a desired drilling path. In one aspect, the steering apparatus may include a steering unit 160, having a number of force application members 161a-161n, wherein the steering unit is at least partially integrated into the drilling motor. In another embodiment the steering apparatus may include a steering unit 158 having a bent sub and a first steering device 158a to orient the bent sub in the wellbore and the second steering device 158b to maintain the bent sub along a selected drilling direction.
The MWD system may include sensors, circuitry and processing software and algorithms for providing information about desired dynamic drilling parameters relating to the BHA, drill string, the drill bit and downhole equipment such as a drilling motor, steering unit, thrusters, etc. Exemplary sensors include, but are not limited to, drill bit sensors, an RPM sensor, a weight on bit sensor, sensors for measuring mud motor parameters (e.g., mud motor stator temperature, differential pressure across a mud motor, and fluid flow rate through a mud motor), and sensors for measuring acceleration, vibration, whirl, radial displacement, stick-slip, torque, shock, vibration, strain, stress, bending moment, bit bounce, axial thrust, friction, backward rotation, BHA buckling and radial thrust. Sensors distributed along the drill string can measure physical quantities such as drill string acceleration and strain, internal pressures in the drill string bore, external pressure in the annulus, vibration, temperature, electrical and magnetic field intensities inside the drill string, bore of the drill string, etc. Suitable systems for making dynamic downhole measurements include COPILOT, a downhole measurement system, manufactured by BAKER HUGHES INCORPORATED. Suitable systems are also discussed in “Downhole Diagnosis of Drilling Dynamics Data Provides New Level Drilling Process Control to Driller”, SPE 49206, by G. Heisig and J. D. Macpherson, 1998.
The MWD system 100 can include one or more downhole processors at a suitable location such as 178 on the BHA 190. The processor(s) can be a microprocessor that uses a computer program implemented on a suitable machine readable medium that enables the processor to perform the control and processing. The machine readable medium may include ROMs, EPROMs, EAROMs, EEPROMs, Flash Memories, RAMs, Hard Drives and/or Optical disks. Other equipment such as power and data buses, power supplies, and the like will be apparent to one skilled in the art. In one embodiment, the MWD system utilizes mud pulse telemetry to communicate data from a downhole location to the surface while drilling operations take place. The surface processor 147 can process the surface measured data, along with the data transmitted from the downhole processor, to evaluate formation lithology. While a drill string 120 is shown as a conveyance system for sensors 165, it should be understood that embodiments of the present disclosure may be used in connection with tools conveyed via rigid (e.g. jointed tubular or coiled tubing) as well as non-rigid (e.g. wireline, slickline, e-line, etc.) conveyance systems. A downhole assembly (not shown) may include a bottom hole assembly and/or sensors and equipment for implementation of embodiments of the present disclosure on either a drill string or a wireline.
In some embodiments, evaluation module 200 may include a communication unit (not shown) and power supply (not shown) for two-way communication to the surface and supplying power to the downhole components. In some embodiments, evaluation module 200 may include a downhole controller (not shown) configured to control the evaluation unit 200. Results of data processed downhole may be sent to the surface in order to provide downhole conditions to a drilling operator or to validate test results. The controller may pass processed data to a two-way data communication system disposed downhole. The communication system downhole may transmit a data signal to a surface communication system (not shown). There are several methods and apparatus known in the art suitable for transmitting data. Any suitable system would suffice for the purposes of this disclosure.
While the foregoing disclosure is directed to the one mode embodiments of the disclosure, various modifications will be apparent to those skilled in the art. It is intended that all variations be embraced by the foregoing disclosure.
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