Classifications

• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B47/00—Survey of boreholes or wells
  • E21B47/10—Locating fluid leaks, intrusions or movements
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
  • E21B21/08—Controlling or monitoring pressure or flow of drilling fluid, e.g. automatic filling of boreholes, automatic control of bottom pressure
  • E21B21/085—Underbalanced techniques, i.e. where borehole fluid pressure is below formation pressure
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B47/00—Survey of boreholes or wells
  • E21B47/10—Locating fluid leaks, intrusions or movements
  • E21B47/107—Locating fluid leaks, intrusions or movements using acoustic means
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B49/00—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
  • E21B49/08—Obtaining fluid samples or testing fluids, in boreholes or wells
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B49/00—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
  • E21B49/08—Obtaining fluid samples or testing fluids, in boreholes or wells
  • E21B49/087—Well testing, e.g. testing for reservoir productivity or formation parameters

Definitions

• the present invention relates generally to testing and evaluating a section of
• the present invention relates to methods, systems and tools used in testing and evaluation of a subsurface well formation during drilling of the wellbore.
• a reservoir is formed of one or more subsurface rock formations containing a
• the reservoir rock is porous and permeable.
• permeability relates to the reservoir fluids' ability to move through the rock and be
• a reservoir is an invisible, complex physical system that must be
• the present invention is primarily directed to wellbore and formation evaluation while drilling “underbalanced.” Underbalanced drilling is a well construction process
• hydrostatic pressure is less than the actual pressure within the pore spaces of the
• the drilling fluid may enter the formation from the
• the amount of gas included in the surface flow is particularly important in
• the volume of gas per unit of time, or flow rate is a critical parameter.
• the rate of gas flow from the formation is affected by the back-pressure exerted through the wellbore.
• a well log is a recording, usually continuous, of a
• RFT formation tests
• Drill stem testing requires the stopping of the drilling process, logging to
• Drill stem testing can be very time consuming and the analysis is often indeterminate or incomplete. Generally,
• the packers are set and reset to isolate each reservoir
• productability of the well is permeability.
• the fluid flows through the
• the parameter of "permeability" is a manager
• Permeability is expressed as an area. However, the customary unit of permeability is
• Parameters such as bottomhole temperature and pressure are acquired through a bottomhole assembly during actual drilling operations and the acquired values are transmitted to the surface.
• the drilling assembly drills the wellbore to a point above the formation of interest.
• the measuring instruments in subsurface instruments carried by the drilling assembly are calibrated with surface measuring instruments at the well surface. The calibration is performed by evaluating injected and
• An important feature of the present invention is the use of an ultrasonic gas flow meter in the surface measurements of gas being produced from the formation to permit unrestricted flow measurements that accurately reflect the formation's flow
• a chromatograph is used in the surface measurements of annular fluid
• a second method of the present invention utilizes a downhole device to obtain
• the bottomhole temperature and pressure may be any suitable bottomhole temperature and pressure.
• the drilling operation may be stopped and the well shut in to determine density and/or viscosity of the produced fluids.
• the measured parameters at the bit are transmitted to the well surface using fluid pulse telemetry or other suitable means.
• the downhole data is transmitted to the well surface using fluid pulse telemetry or other suitable means.
• Another means of obtaining the necessary data for these novel methods of formation evaluation is to have the downhole measurements taken and stored in a
• This recorded data is considered “near real-time” because it is not transmitted to the surface from downhole.
• This near real-time data from downhole is synchronized and merged with either surface measurements of hydrocarbon production or downhole measurements from the subsurface measurement instrument and used to compute the permeability and
• the choice is usually based upon required placement accuracy of the wellbore, or
• a novel downhole flow measuring tool comprises a part of the present invention.
• the downhole tool connects between the drill string and bit. Blades on the tool provide
• the tool structure functions as a drilling stabilizer and, while rotating, positively directs the well fluid into the fluid recesses where various transducers carried by the
• This latter feature is particularly useful in horizontal drilling application where the well fluids may tend to stratify vertically.
• Figure 1 is a schematic illustration of a system of the present invention used to evaluate a subsurface formation being intersected by a wellbore during well construction;
• Figure 2 is an elevation of an integral blade stabilizer body having energy measurement transducers used for subsurface measurements while drilling;
• Figure 3 is a partial cross section taken along the line 2-2 of Figure 1 illustrating
• Figure 3A is an enlarged view of a focusing notch employed with the induction
• Figure 3B is an enlarged view of illustrating details in the construction of the
• Figure 1 illustrates a system of the present invention indicated generally at 10.
• the system 10 is employed to determine the permeability of a formation F that is to be penetrated by a wellbore B.
• a drilling assembly comprising a bit 11 , drilling stabilizer 12, subsurface measuring and recording instrument 13 and drill string 14 extend from the wellbore B to the wellbore surface T. Only a portion of the bottomhole assembly is
• a measuring system 20 used in the evaluation of a formation F is equipped with
• the measuring system 20 measures and evaluates the fluids flowing into the wellbore B through the drill string 14 and measures and evaluates the fluids returning to the top or surface of the wellbore T through an annulus A formed between the drill string and the wellbore.
• evaluating "flow" of a fluid is intended to include measurement or evaluation of
• characteristics of the fluid such as temperature, pressure, resistivity, density, composition, volume, rate of flow and other variable characteristics or parameters of the fluid.
• the calibrated analysis section 23 may be supplemented with subsurface parameter values obtained from a subsurface values section 24.
• the data from the section 24 are delivered from either a data resource 25 or from an actual downhole
• Data provided by the data resource section 25 may be data
• the actual downhole measurements are provided through a real-time system section 27 or a near real-time system section 28.
• flow values are to be inferred or deduced from measurements or assumed values of related parameters, the system 20 is calibrated and checked before the wellbore B is
• the system calibration process and checking are preferably performed between
• the top of the formation F may be determined using a geological marker from an offset well, seismic data or reservoir contour mapping.
• the calibration performed by circulating a known quantity and density of a
• the calibration process is employed to establish a standard or control to detect or determine changes in measurements that result from
• the following parameters are measured for a minimum of three different back-pressure values obtained at the annulus A while
• the time required for the fluid to complete circulation through the drilling assembly and return to the surface through the annulus is monitored and recorded.
• a circulation time measurement is performed with the assistance
• material may be a carbide, or an inert substance such as neon gas, or a short half-life
• radioactive material or other suitable material.
• the drilling operation is resumed and the drilling assembly is used to extend the wellbore into the formation F.
• the rate of penetration is preferably maintained at a rate below 25 meters per hour.
• the weight on bit and rotary or bit motor speeds are maintained as constant as possible to enhance the accuracy of the results of the system measurements.
• the bottomhole pressure can be adjusted by manipulation of the drilling fluid densities, pump rates and
• the point at which the drill bit 11 encounters the top of the formation F may be determined by closely monitoring the system 20 for any significant change in the
• reservoir flow and pressure response are established while injecting fluid into the drill string 14 from the surface and combining the injected fluids with fluids flowing from the reservoir F into the wellbore B.
• the measurements l)-IV) are made and recorded for a preferred period of time
• Bottoms up time is the time required to flow fluid at the bottom of the wellbore to the well surface.
• annular flow does not stabilize at this increased back-pressure, the back-pressure is reduced by 25 percent and the annular flow is maintained for 1.5 to 15 times the bottoms up time to test for stabilization of the annular flow.
• the next step in the method is to reduce the circulating back-pressure or
• bottomhole pressure by 30 to 40 percent, preferably not to exceed 35 percent of the
• back-pressure is increased, using either a surface choke or by increasing the
• bottomhole pressure to a safe drilling level and then stabilized over a period of from 1.5 to 15 times the bottoms up time.
• Drilling is resumed and the borehole B is extended to the formation F at a steady
• sensor points variable measurements l)-IV) are continuously monitored and recorded.
• Drilling is continued until the formation F has been fully traversed. Once the wellbore extends below the bottom of the formation by 2 to 10 meters, drilling is stopped. Fluid
• IPR Inflow Production
• Evaluation of the formation F using the measurements and data obtained in the described process may be enhanced with the use of a computer model 29 of the reservoir.
• the computer model can account for variances attributable to multiple
• the computer model may be employed to more accurately project well production and reserve estimates. Presentation of the evaluation and activation of
• a kick alarm 31 provides early warning of an influx of formation fluids into the wellbore.
• the methods of the present invention may also be practiced in a system using data obtained directly with downhole flow measurement instruments that comprise a
• direct downhole flow measurement instruments are substantially the same as those employed when downhole flow parameters are determined inferentially or are obtained
• FIGS. 2 and 3 illustrate details in a preferred subsurface measurement tool
• the measurement tool 50 is illustrated connected to a drill bit 51 to function as part of
• a near-bit stabilizer may be employed at other near-bit locations within a bottomhole drilling assembly and need not necessarily be
• the instrument tool 50 includes three separate types of detection devices in the vicinity of the drill bit permitting a large number of combinations of signals to be analyzed thereby producing increased flexibility and accuracy in both measurement while drilling (MWD) and formation
• the instrument tool 50 is equipped with an axially extending body 52 having a central, axially developed passage 55 for conveying fluid between a first axial tool end
• tool 50 is connected at its first end 56 to a bit 51 and at its second axial end 57 to a
• monitoring and recording tool 66 that processes and records the measurements taken
• the instrument tool 50 records and/or transmits measurements to the well surface. Recorded measurements are retained in the recorded memory until the
• drilling assembly is retrieved to the well surface or the measurements may be transmitted to the surface through fluid pulse telemetry or other suitable communication means.
• the tools 50 and 66 are connected with the measuring system 20 for real-time
• converters in the measuring system 20 process signals detected at the transducer
• the measuring system is a microprocessor system within the components 23, 29 and 30.
• the measuring system is a microprocessor system within the components 23, 29 and 30.
• recesses 70, 71 and 72 are illustrated in Figure 3 between dotted lines 73, 74 and 75, respectively, and external tool surfaces 76, 77 and 78, respectively, of the tool 50.
• the primary monitored indicator of flow in the recesses 70, 71 and 72 is
• a marker comprising a bubble of gas or a gaseous cluster entrained within
• transducers determine a rate of movement of the bubble marker past the transducers.
• Energy transducers are carried by the blades for evaluating characteristics of fluid contained in the fluid receiving recesses. The measured characteristics are convertible into a measure of the flow rate of the fluid flowing through the recesses.
• acoustic transducer receivers 85 and acoustic transducer transmitters 86 are carried in the blades 61 and 60, respectively.
• Electromagnetic induction transmitting transducers 90 and electromagnetic receiving transducers 91 are carried
• the energy transducers carried by the tool 50 are deployed
• transducers to detect variable parameters associated with axial movement of fluid flowing through the recesses with which the transducers are associated. Accordingly, three acoustic receivers 85a, 85b and 85c are deployed at axially spaced locations
• transmitters 90a and 90b are axially deployed along the blade 60 and three electromagnetic receivers 91a, 91b and 91c are axially deployed along the blade 62.
• Capacitive transducers are also deployed at circumferentially and axially spaced
• Capacitive transducers 95, 96 and 97 are displayed in Figure 3 at only one axial location. Similar arrays of capacitive transducers (not illustrated) are deployed at other axially spaced locations between the
• transducers are preferably located high within the protected areas between the
• the blades function to form fluid channeling recesses to confine the fluid being monitored and also provide protective structure for the energy transmitters.
• the induction transmitting antennas of the transducers 90 are positioned within notches in the blade 62 that have curved shapes with sloping surfaces 90b that slightly increase from a parabolic shape to produce an over focusing from a parallel beam to a concentrated point at the receiving transducers 91.
• Over focusing of the transmitter signal counteracts dispersion caused by bubbles and rock cuttings in the fluid flowing past the sensors.
• the angles between the transmitters and receivers are preferably optimized for vector processing relating to typical rotation speeds and expected fluid velocities.
• the capacitance transducers 95, 96 and 97 are preferably provided with concave surface electrode shapes 95a to improve contact with the convex surfaces of bubbles or rounded oil globules entrained within the fluid flowing past the transducers.
• Gas bubble shapes change sizes as a function of changing depth and pressure within the wellbore.
• the capacitance transducers preferably protrude slightly radially from the body of the tool body 50 with the concave surface shapes having an increasing curvature toward the top 95b of the tool 50 to permit better contact of the surface with both small and larger bubbles.
• the larger curvature at the top of the transducers permits improved matching of shapes of the smaller bubbles or oil globules with the transducers.
• the smaller curvature at the bottom 95a of the transducers forms a better match with the external surfaces of larger bubbles or globules. ln operation, the acoustic and electromagnetic transducers in the tool 50 and
• associated instruments in the recording tool 66 monitor the characteristics of the fluid intercepted in the travel paths of the energy signals traveling between transducers.
• the capacitive transducers monitor the characteristics of the fluid engaging the reactive surfaces of the transducers.
• Each of the three acoustic transmitters communicate with
• each of the three acoustic receivers to produced nine transmission paths.
• the paths
• the electromagnetic transducers function similarly to produce a total of six transmission paths.
• the radial and axial displacement of transducer paths produces an array of
• the change in capacitance along the axial distribution of the capacitive transducers provides a measure of the flow past the monitoring surfaces.
• the measuring process performed by the tool 50 is preferably done while the
• Rotation of the tool 50 also permits each set of three detection systems
• the blades ofthe tool protect the measuring devices
• Rotation of the tool produces centrifuging of certain fluids that enter the fluid
• the tool 50 may be used as a kick detector during the construction of the well.
• the tool's kick detection capability stems from its ability to recognize changes in the
• a stethoscope type or amplified sound detection and filtering system in the component 31 enables a crewman to hear a kick warning pulse
• the tool 50 may also be used to indicate early wellbore stability problems.
• actions may be taken to reduce excessive "washing out” or widening of the borehole after increased cuttings volumes from weaker formations are detected.

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• Engineering & Computer Science (AREA)
• Geology (AREA)
• Life Sciences & Earth Sciences (AREA)
• Mining & Mineral Resources (AREA)
• Physics & Mathematics (AREA)
• General Life Sciences & Earth Sciences (AREA)
• Environmental & Geological Engineering (AREA)
• Geochemistry & Mineralogy (AREA)
• Fluid Mechanics (AREA)
• Geophysics (AREA)
• Mechanical Engineering (AREA)
• Acoustics & Sound (AREA)
• Earth Drilling (AREA)
• Geophysics And Detection Of Objects (AREA)
• Investigation Of Foundation Soil And Reinforcement Of Foundation Soil By Compacting Or Drainage (AREA)
• Examining Or Testing Airtightness (AREA)
• Drilling And Boring (AREA)
• Analysing Materials By The Use Of Radiation (AREA)
• Supply Devices, Intensifiers, Converters, And Telemotors (AREA)

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• 2001
  • 2001-09-19 CA CA002547584A patent/CA2547584C/en not_active Expired - Lifetime
  • 2001-09-19 WO PCT/US2001/029325 patent/WO2002088522A1/en not_active Ceased
  • 2001-09-19 EP EP01971214A patent/EP1397579B1/de not_active Expired - Lifetime
  • 2001-09-19 DE DE60137974T patent/DE60137974D1/de not_active Expired - Fee Related
  • 2001-09-19 DE DE60140827T patent/DE60140827D1/de not_active Expired - Lifetime
  • 2001-09-19 EP EP08004186A patent/EP1936112B1/de not_active Expired - Lifetime
  • 2001-09-19 AT AT08004186T patent/ATE452280T1/de not_active IP Right Cessation
  • 2001-09-19 CA CA002448404A patent/CA2448404A1/en not_active Abandoned
  • 2001-09-19 AT AT01971214T patent/ATE425344T1/de not_active IP Right Cessation

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