EP2235318B1 - Procede de detection de la pression de formation - Google Patents

Procede de detection de la pression de formation Download PDF

Info

Publication number
EP2235318B1
EP2235318B1 EP08866416.4A EP08866416A EP2235318B1 EP 2235318 B1 EP2235318 B1 EP 2235318B1 EP 08866416 A EP08866416 A EP 08866416A EP 2235318 B1 EP2235318 B1 EP 2235318B1
Authority
EP
European Patent Office
Prior art keywords
gas
drilling fluid
annulus
pressure
drill
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Not-in-force
Application number
EP08866416.4A
Other languages
German (de)
English (en)
Other versions
EP2235318A1 (fr
Inventor
Mark W. Alberty
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
BP Corp North America Inc
Original Assignee
BP Corp North America Inc
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Priority claimed from US12/004,175 external-priority patent/US8794350B2/en
Application filed by BP Corp North America Inc filed Critical BP Corp North America Inc
Publication of EP2235318A1 publication Critical patent/EP2235318A1/fr
Application granted granted Critical
Publication of EP2235318B1 publication Critical patent/EP2235318B1/fr
Not-in-force legal-status Critical Current
Anticipated expiration legal-status Critical

Links

Images

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
    • 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
    • E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
    • 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
    • E21B44/00—Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions

Definitions

  • the present disclosure relates in general to methods of drilling wellbores, for example, but not limited to, wellbores for producing hydrocarbons from subterranean formations, and more particularly to methods of distinguishing circulated gases from connection gas or gas influx in a drilling oil or gas well.
  • Drilling techniques for producing wellbores to great depths in the earth are well known and are widely used, especially in the exploration for and production of hydrocarbons.
  • These wells are typically produced by the use of a drill bit positioned on the lower end of a drill string which is supported for rotation to cause the bit to drill into the earth with the drilling being stopped periodically, with the drill string being lifted and supported on slips or similar devices so that a new section of pipe can be attached to the top drill pipe section.
  • These drill pipe sections are fitted with upset ends so that they can be threaded with male fittings on one end and female fittings on the other end.
  • These drill pipe sections are typically about 30 feet long and when joined together can be used to drill for great distances into the earth.
  • a drill string is positioned from a surface into the wellbore and to the bottom of the wellbore so that the bit can be rotated.
  • the bit is typically rotated by passing a drilling fluid downwardly through the drill pipe to drive the drill bit and extend the bottom of the hole downwardly.
  • Drilling fluids are well known and comprise water-based drilling fluid and oil-based drilling fluid. Further specialized drilling fluids, such as drill-in fluids may also be used.
  • the drilling fluids are typically made up to have a specific gravity so that a column of drilling fluid of a height equal to the wellbore depth exerts a bottom hole pressure equal to the anticipated pressure in the formations penetrated by the wellbore over the entire depth of the well.
  • This drilling fluid pressure tends to inhibit the production of gases and oil formation fluids into the wellbore or to the surface when greater than the formation pressure. It also inhibits events such as kicks and blow-outs where high pressure permeable formations are encountered.
  • the industry has developed numerous techniques for detecting such kicks and blow-outs early to prevent significant damage to the drilling apparatus and to prevent blowing the entire mud column out of the wellbore and possibly contaminating the surrounding area with hydrocarbons.
  • the well may be drilled slightly over-balanced but the drilling fluid may have a weight insufficient to maintain over-balance on the well if the pumps are stopped. This is also an under-balanced condition when the pumps are off.
  • the pressure resulting from the weight of the column of the drilling fluid is referred to as a hydrostatic pressure.
  • This hydrostatic pressure also can be greater than or less than the pressure in the formation. Desirably this hydrostatic pressure is to be slightly greater than the pressure in the formations penetrated by the wellbore for a safety perspective.
  • One desire of this invention is to detect the condition of the hydrostatic pressure being slightly less than the pressure in the formations penetrated by the well when these conditions are first observed in the pumps off condition when the hydrostatic pressure in the well is slightly less than in the pumps on condition.
  • an over-balance i.e., a hydrostatic pressure greater than the pressure in the pores of the formations penetrated by the wellbore
  • little, if any, gas will enter the wellbore from the formations during drilling.
  • portions of the drilling fluid will enter the permeable formations and constitute an obstacle to the production of fluids from those formations.
  • the hydrostatic pressure in the well during pumping of the drilling fluid is slightly over-balanced relative to the formation pressure with the hydrostatic pressure being slightly less when the pumps are off, either due to the loss of the friction of the fluid movement or as a result of a slight swabbing effect from lifting the bit off bottom to set the drill string into the slips.
  • very small amounts of formation gas can enter the wellbore from low permeability formations, such as shale. This gas may exist as a free fluid in the formation or it may be dissolved in water. The presence of this small amount of gas entering the wellbore is indicative that a higher-pressure formation may be exposed in the wellbore. As a result, it is desirable to check this gas periodically to determine whether the amount of gas entering the well under comparable conditions is increasing or stable when pumps are turned on and off.
  • the low permeability shale formations encapsulate the high permeability reservoirs and provide the barrier or trap for hydrocarbons which accumulate in these reservoirs. Most low permeability shale achieve pressure equilibrium with those reservoirs.
  • the fluids in the formation can flow into the well at high rates and volume and produce the kick that creates the unstable and potentially unsafe condition drilling operators desire to avoid.
  • the most commonly used methods of making this determination is to separate the gas from the drilling fluid at the surface. This is an effective method for determining how much gas may be in the drilling fluid but unfortunately in a well of any substantial depth it may take two to three hours for this drilling fluid to reach the earth surface. This may be too late to avoid drilling into a high-pressure permeable formation without making adequate preparations. Failure to take adequate preparations before drilling into a permeable high-pressure formation may result in a kick and potential blowout.
  • fluids flowing from the formation may carry gas either dissolved in the fluid (oil or water) or in a free state in the rock into the well which can be easily detected with these surface devices.
  • the surface measured gas increases, this can be an indication that the formation pressure is greater than the hydrostatic pressure created by the drilling fluid.
  • the above-described surface detection method is most effective when the pore pressure of the formation lies between the pumps-off and pumps-on pressures. This condition creates the maximum contrast between pumps-off and pumps-on gas content in the mud. It can then be used to narrow the estimate of formation pore pressure to a value that lies between these two pressures.
  • the mud at the bottom of the well must be circulating back to the surface to determine if the amount of gas in the mud has increased as a result of turning the pumps off. This can take many hours to do and usually results in a significant delay in understanding if the phenomena is occurring and assessing the magnitude of the formation pressure relative to the drilling fluid pressure. Significant savings could occur in drilling time if the amount of gas in the drilling fluid could be assessed downhole before the fluid is circulated out the well.
  • Mud being pumped down the well through the drill pipe may contain recirculated gas or may contain air added to the mud through circulation across the shale shakers or introduced as an air bubble at the time drill pipe connections are made at the surface.
  • Applicant's previously filed application serial number 12/004,175 describes how to analyze gas content in drilling fluids in the annulus; however, the most suitable gas detection devices used downhole to monitor gases in the annulus are not capable of distinguishing freshly introduced formation gas from circulated gas. These gases need to be distinguished so as not to lead to a false conclusion that the well is underbalanced due to the detection of circulated gas downhole.
  • WO 99/00575 describes drilling systems utilizing sensors for determining downhole parameters relating to the fluid in the wellbore during drilling of the wellbores.
  • circulated gas can be identified by placing a detector sensitive to the gas in the drill string behind the drill bit, in certain embodiments at the same level as the detectors monitoring the gas present in the annulus, to monitor the amount of gas present in the drilling fluid inside the drill pipe.
  • the detected gas levels can then be tracked volumetrically as a function of the drilling fluid volumes pumped to recognize when those gasses pass the detectors monitoring the annulus. In this manner the observed annulus gas volumes can be corrected to remove the effects of circulated gas or air. This could be accomplished by placing detectors sensitive to the gas in the drill string behind and near the bit to assess the amount of gas present.
  • “behind and near” the bit means the sensors nearest the bit (when discussing sensors inside the drill pipe only, in the annulus only, or both) should be within 500 feet [150 meters] of the bit, or 400 feet [120 meters], or 300 feet [90 meters], or 200 feet [60 meters], or 100 feet [30 meters], in some case within 50 feet [15 meters] of the bit, so as to allow the gas to enter the well and be measured, with additional detectors optionally placed along the drill string (when discussing sensors inside the drill pipe only, in the annulus only, or both) to assess the movement of the gas out of the well or to detect influxes of gas up the well.
  • sensors inside the drill pipe, and/or in the annulus could be positioned every 2000 feet [614 meters], every 1500 feet [460 meters], every 1000 feet [307 meters] or so back to surface, or at least the previous casing point. This would allow monitoring expansion of the gas with the decrease in hydrostatic pressure as the gases move upward in the well and to detect pressure from additional gases entering the well at a shallower depth.
  • the physical properties of the gases typically found in the drilling fluid at downhole pressures and temperatures may be studied, and the results used to determine the different physical properties of the drilling fluid that could be used to measure the gas content (drilling fluid density, drilling fluid velocity, and the like).
  • Methods and apparatus disclosed herein are applicable to both on-shore (land-based) and offshore (subsea-based) drilling.
  • a first aspect of the disclosure is a method of drilling a well while distinguishing circulated gas or air from pumps-off gas in a drilling fluid at downhole pressure and temperature, the method comprising:
  • the method comprises tracking detected gas levels volumetrically as a function of the drilling fluid volumes pumped to recognize when recirculated gases or air pass detectors monitoring gas content in the annulus. In this manner the observed annulus gas volumes may be corrected to remove the effects of circulated gas or air.
  • additional sensors sensitive to parameters indicative of circulating gas or air may also be placed along the drill string to assess the movement of recirculated gasses or air out of the well, or to detect influxes of gases up the well.
  • one or more physical properties (density, velocity, temperature, pressure, conductivity, resistivity, and the like) of drilling fluids containing recirculating gasses and air typically found in the mud at downhole pressures and temperatures may be measured in real-time, and the real-time measurements compared with measurements obtained using control samples to determine the actual gas content at downhole conditions.
  • the detecting circulated gas or air inside the drill string, or a physical property indicative of such gasses, whether behind and near the drill bit, distributed along the drill string both inside and outside of the drill pipe (in the annulus), may proceed using any one or more known measuring techniques which are already described in the literature and understood by those in the art.
  • common methods used for gas detection downhole include the methods and apparatus described in U.S. Pat. Nos. 3,872,721 ; 5,859,430 ; 6,465,775 ; and 6,995,369 .
  • Techniques for measuring other wellbore fluid properties, from which gas content may be deduced, are described for example in U.S. Pat. Nos. 6,208,586 ; 5,850,369 ; 6,640,625 , and Published U.S. Pat. Application Nos. 2008047337 ; 2007227241 ; and 2007016464 .
  • the method further comprises using the information on whether pressure of the wellbore fluid is greater than the formation fluid pressure to locate a point of lost circulation or a well fluid influx in the well.
  • the information on location of lost circulation or well fluid influx may be used to diagnose the root cause of the lost circulation or fluid influx.
  • the method comprises selecting an appropriate treatment, and placing a well treatment where the problem has developed in the well.
  • Another aspect of the disclosure comprises a method for detecting pumps-off gas in drilling fluid in a wellbore during drilling from an earth surface and penetrating a plurality of subterranean formations comprising at least one high pressure, low permeability formation encapsulating a high pressure, high permeability formation, the method comprising:
  • the comparing step (f) may occur continuously or intermittently during drilling.
  • a system for distinguishing circulated gas or air from pumps-off gas in a drilling mud or fluid at downhole pressure and temperature comprising:
  • the methods and apparatus described herein may provide other benefits, and the methods for obtaining the gas content in the drill string and/or annulus are not limited to the methods and apparatus noted herein; other methods and apparatus may be employed. Certain embodiments may include temperature and pressure measuring sensors in the vicinity of the gas detection sensors for measuring temperature and pressure near the gas sensors and using the temperatures and pressures to correct acoustic measurements.
  • a wellbore 10 extends from an earth surface 12 through an overburden 14 and through formations 16, 18, 20, 22, 24 and 26. Some of these formations may be oil-bearing or gas-bearing formations while others may be shale formations which contain pressured fluids.
  • a drill pipe (also referred to herein as a drill string) 34 is positioned to extend from the earth surface to a drill bit 36. Drilling fluid is pumped through the drill string as illustrated by arrows 38 and recovered as illustrated by arrows 40. No equipment has been illustrated for performing this operation since such equipment is considered to be well known to those skilled in the art.
  • the drilling fluid injected through lines 38 passes through drill bit 36 and is discharged as illustrated by arrows 40 through an annulus 60 between an inside 44 of wellbore 10 and an outside 62 of drill pipe 34.
  • This drilling fluid is typically passed to a drill cuttings separation section and is typically degassed and adjusted to the desired composition and thereafter reinjected.
  • a first enlarged section 46 is positioned on an upper end of the drill pipe 34.
  • a section of enlarged section 48 is positioned on an end of a second drill pipe 50 so that they may be matingly joined.
  • the slips 52 support slightly lifted drill pipe 34 while second pipe section 50 is joined to the drill pipe 34.
  • a centralizer 58 is commonly used to maintain drill pipe 34 in a central portion of the wellbore.
  • Sensors 54 for sensing gas or a parameter indicative of gas in the annulus are illustrated near a bottom 64 of the drill string. Sensors 54 are referred to herein as “annulus sensors” for reasons that will become apparent. Annulus sensors 54 are desirably placed at a distance from about 1 to about 200 feet (about 0.3 meter to about 60 meters) above the bottom 64 of drill pipe 34. Annulus sensors 54 may be positioned as a portion of a drill pipe section or they may be attached to the inside or the outside of the drill pipe. With some types of sensors the annulus sensors 54 could be positioned inside drill pipe 34.
  • the annulus sensors 54 for sensing gas or parameter indicative of gas in the annulus may be positioned in the drill pipe; in other embodiments, the annulus sensors 54 for sensing gas or parameter indicative of gas in the annulus may be positioned on the outside of the drill pipe.
  • Annulus sensors 54 are effective to sense the amount of gas contained in the drilling fluid in the annulus, particularly to distinguish the amount of gas during times when the pumps are turned off compared to the amount of gas when pumps are on.
  • the pressure reduction in the drilling fluid during a pumps-off condition will be substantially less in some wells (as high as 300 psi, about 2 MPa, in some cases) than when the drilling fluid pumps are on.
  • This information is desirably transmitted up the drill string as known to those skilled in the art, by connectors passing along the drill string. While not illustrated in FIG 1 , a plurality of annulus sensors 54 could be used. The plurality of annulus sensors 54 could be distributed along drill pipe 62 from drill bit 36 back to the surface. Annulus sensors 54 provide information which can be used to determine the amount of gas in the drilling fluid at the bottom of the well during periods when the pumps are shut down.
  • drilling fluid being pumped down the well through the drill pipe may contain recirculated gas or may contain air added to the drilling fluid through circulation across the shale shakers or introduced as an air bubble at the time drill pipe connections are made at the surface.
  • the most suitable gas detection devices used downhole to monitor the annulus such as annulus sensors 54 in FIG. 1 , are not capable of distinguishing freshly introduced formation gas from circulated gas. These gases need to be distinguished so as not to lead to a false conclusion that the well is underbalanced due to the detection of circulated gas downhole.
  • recirculated and/or air gas can be identified and distinguished from fresh influx gas in the wellbore by placing one or more sensors 55 sensitive to the recirculating gas and/or air gas in the drill string behind the drill bit, in certain embodiments at the same level as annulus sensors 54 (although not necessarily) to monitor the amount of gas present in the drilling fluid inside the drill pipe.
  • Sensors 55 will be referred to herein as "drill string sensors” to distinguish them from annulus sensors 54.
  • the detected internal drill string gas levels can then be tracked volumetrically as a function of the drilling fluid volumes pumped to recognize when recirculating gasses and/or air pass annulus sensors 54. In this manner the observed annulus gas volumes measured by annulus sensors 54 may be corrected to remove the effects of circulated gas and/or air measured by drill string sensors 55.
  • drill string sensors 55 for sensing gas or a parameter indicative of gas in the drill string are illustrated near a bottom 64 of the drill string, similar to the position of annulus sensors 54, although this is mainly for convenience, and is not strictly necessary.
  • Drill string sensors 55 are desirably placed at a distance from about 1 to about 200 feet (about 0.3 meter to about 60 meters) above the bottom 64 of drill pipe 34.
  • Drill string sensors 55 may be positioned as a portion of a drill pipe section or they may be attached to the inside or the outside of the drill pipe. With some types of sensors the drill string sensors 55 could be positioned inside drill pipe 34.
  • drill string sensors 55 for sensing gas or parameter indicative of gas in the drill string may be positioned in the drill pipe; in other embodiments, drill string sensors 55 for sensing gas or parameter indicative of gas in the drill string may be positioned on the outside of the drill pipe.
  • Drill string sensors 55 are effective to sense the amount of gas contained in the drilling fluid in the drill string during drilling fluid flow or during period of no or little drilling fluid flow in the drill string. This information allows correction of the annulus sensors 54 and provides a more accurate basis for estimating the amount of pressure generated by the formation against the hydrostatic pressure of the drilling fluid. This information is desirably transmitted up the drill string as known to those skilled in the art, by connectors passing along the drill string. While not illustrated in FIG 1 , a plurality of drill string sensors 55 could be used. The plurality of drill string sensors 55 could be distributed along drill pipe 62 from drill bit 36 back to the surface.
  • the sensors 54 and 55 may be of any suitable type, such as pulse-echo, density, ultrasonic, velocity, sonic impedance, acoustic impedance and the like, as known to those skilled in the art. They may be the same or different from each other. In certain embodiments, sensors 54 will be all one type, while sensors 55 will all be of a different type. In certain other embodiments, all sensors 54 and 55 will be identical in operation. The particular type sensors required are not considered to constitute part of the present disclosure but rather the use of the sensors to perform the methods claimed in the present disclosure is considered to constitute the present disclosure. Sensors 54 and 55 could be positioned on, inside or outside of the drill pipe and adapted to detect comparable values for the drill fluid in the drill pipe and in the annulus.
  • FIG 2 a second embodiment of the present invention is illustrated.
  • the upper portion of wellbore 10 has been cased with a casing 30 supported in place in the wellbore by cement 32.
  • the drilling fluid is injected as described through drill pipe 34 as illustrated by arrows 38 with the drilling fluid being passed downwardly through drill pipe 34, out through drill bit 36 and upwardly through the annulus as illustrated by arrows 40 to recovery through a recovery line 42.
  • a centralizer 58 is also used.
  • annulus sensors 54 and drill string sensors 55 positioned near a bottom 64 of drill pipe 34, a plurality of sensors 54 and 55 are arranged along the length of drill pipe 34.
  • Sensors 54 will affect a measurement of the amount of gas which may be leaking into the wellbore at levels above the bottom of the wellbore. This can be of considerable interest in the event that formations penetrated by the wellbore tend to become more active in releasing materials into the wellbore at the hydrostatic pressure of the drilling fluid. It will be noted that the hydrostatic pressure of the drilling fluid will be somewhat less at the upper portions of the formation than at the bottom of the wellbore.
  • circulated gas can be identified and an amount of gas present in the drilling fluid inside the drill pipe may be quantified.
  • the detected gas levels can be tracked volumetrically as a function of the drilling fluid volumes pumped to recognize when those gasses pass the detectors monitoring the annulus. In this manner the observed annulus gas volumes can be corrected to remove the effects of circulated gas or air.
  • gas concentration in the drilling fluid may be determined during a pumps-off period and then may be compared to a standard gas amount to determine whether the weight of the drilling fluid should be increased or whether other steps should be taken to control the wellbore. Particularly, it may be desirable to compare this gas measurement to previous gas measurements in the same well taken at an earlier pumps-off period or while the pumps were on.
  • the gas concentration is measured at each pumps-off period and more frequently if significant changes are detected. This provides an indication as to whether the pressure in the formation is increasing relative to the pressure in the well as indicated by the result of gases entering the wellbore increasing at pumps-off conditions. Alternatively, other standards can be adopted to determine whether amounts of gases entering the wellbore are excessive.
  • an increase in gas entry into the bottom of the wellbore will be detected upon the drill bit approaching a high pressure formation. This enables the operator to weight the drilling fluid more heavily to impose a back pressure upon the drilling fluid contained in the annulus or the like to control the well.
  • the methods of the present disclosure provide an effective method for determining a meaningful number related to conditions at the bottom of the borehole in substantially real time.
  • the amount of gas contained in the drilling fluid is indicative of the amount of gas-containing materials entering the wellbore annulus from the surrounding formations.
  • knowledge of the recirculating gasses or air allows correction of the measured annulus gas amounts. This information is very helpful in controlling the well, adjusting the weight of the drilling fluid and the like.
  • quantities of gas on the order of 0.01 and up to in excess of 5.0 vol.% as measured at surface conditions or greater can be detected downhole.
  • these methods will detect relatively small amounts of gas in the drilling fluid near the downhole annulus sensor to enable the detection of trends.
  • These quantities of gas do not exert appreciable pressure and are detectable at the wellhead using conventional gas detection techniques and while indicative of gas invasion into the well, are not normally detected downhole by existing testing systems for detecting large gas bubbles.
  • the methods of the present disclosure enable early detection of increasing gas levels before the gas concentrations can reach problematic levels. These methods may be used by comparing successive annulus gas readings under similar conditions, as well as comparing to gas measured in the drill string by the drill string sensors.
  • the background or baseline value may be a previous quantitative measurement of annulus gas, a measurement of drill string gas, or another indicia of the background conditions. This early detection enables the driller to take corrective action much earlier than if the drilling fluid were analyzed for the same or similar information at the surface.
  • FIG. 3 illustrates a method embodiment of the present disclosure in flowchart form.
  • Embodiment 300 of FIG. 3 illustrates in box 302 drilling a well with a drilling fluid, a drill string, and a drill bit from an earth surface through a formation.
  • Box 304 illustrates pumping the drilling fluid through the drill string, drill bit, and into an annulus between the drill string and a wellbore. It should be pointed out that the steps illustrated in FIG. 3 are merely for illustrating the concepts of the disclosure; it is not intended that the steps must be taken sequentially or in parallel.
  • Box 306 indicates measuring, while drilling, a parameter of the drilling fluid indicative of circulated gas or air inside the drill string behind and near the drill bit using one or more sensors.
  • Box 305 illustrates supporting at least one annulus gas sensor by the drill pipe near the bottom of the drill pipe and positioned to sense the amount of gas in the drilling fluid in the annulus at a depth of the at least one annulus gas sensor.
  • Box 307 illustrates periodically stopping pumping, and detecting the amount of gas in the drilling fluid in the annulus at the level of the at least one sensor during pumping periods before and after stopping of pumping.
  • the next step, illustrated by box 308 is communicating the result to a human-readable interface at the surface.
  • Box 310 illustrates comparing the amount of gas in the drilling fluid in the annulus at the level of the at least one sensor during the pumping periods.
  • a primary interest lies in using one or more of the methods and apparatus described above to correct observed annulus gas volumes to remove the effects of circulated gas or air, and using this information to diagnose, make decisions on, and implement changes to drilling fluid weight, density, or other parameter.
  • the skilled operator or designer will determine which methods, apparatus and drilling fluids are best suited for a particular well and formation to achieve the highest efficiency without undue experimentation.
  • Methods and apparatus in accordance with the present disclosure may include means for measuring drilling fluid temperature and annular fluid pressure of fluids flow (or not flowing) inside the drill string, and/or flowing (or not flowing) in the annulus.
  • Suitable temperature measurement means include thermocouples, thermistors, resistant temperature detectors (RTDs), and the like.
  • Suitable fluid pressure measurement means include piezoelectric sensors, fiber optic sensors, strain gauges, microelectromechanical (MEMS) sensors, and the like.
  • the apparatus and methods of the present disclosure may also include means for calculating temperature- and pressure-corrected measurement values using the measured temperatures and fluid pressures.
  • Suitable means for calculating include digital computers, and the like, either hard-wired or wirelessly connected to the drill string or tools in the drill string, and which may include wired or wireless connections to human-readable devices, such as video CRT screens, printers, and the like.
  • Useful drilling muds for use in the methods of the present disclosure include water-based, oil-based, and synthetic-based muds.
  • the choice of formulation used is dictated in part by the nature of the formation in which drilling is to take place. For example, in various types of shale formations, the use of conventional water-based muds can result in a deterioration and collapse of the formation. The use of an oil-based formulation may circumvent this problem.
  • a list of useful muds would include, but not be limited to, conventional muds, gascut muds (such as air-cut muds), balanced-activity oil muds, buffered muds, calcium muds, deflocculated muds, diesel-oil muds, emulsion muds (including oil emulsion muds), gyp muds, oil-invert emulsion oil muds, inhibitive muds, killweight muds, lime muds, low-colloid oil muds, low solids muds, magnetic muds, milk emulsion muds, native solids muds, PHPA (partially-hydrolyzed polyacrylamide) muds, potassium muds, red muds, saltwater (including seawater) muds, silicate muds, spud muds, thermally-activated muds, unweighted muds, weighted muds, water muds, and combinations of these
  • Useful mud additives include, but are not limited to asphaltic mud additives, viscosity modifiers, emulsifying agents (for example, but not limited to, alkaline soaps of fatty acids), wetting agents (for example, but not limited to dodecylbenzene sulfonate), water (generally a NaCl or CaCl 2 brine), barite, barium sulfate, or other weighting agents, and normally amine treated clays (employed as a viscosification agent). More recently, neutralized sulfonated ionomers have been found to be particularly useful as viscosification agents in oil-based drilling muds. See, for example, U.S. Pat. Nos.
  • neutralized sulfonated ionomers are prepared by sulfonating an unsaturated polymer such as butyl rubber, EPDM terpolymer, partially hydrogenated polyisoprenes and polybutadienes. The sulfonated polymer is then neutralized with a base and thereafter steam stripped to remove the free carboxylic acid formed and to provide a neutralized sulfonated polymer crumb.
  • unsaturated polymer such as butyl rubber, EPDM terpolymer, partially hydrogenated polyisoprenes and polybutadienes.
  • the sulfonated polymer is then neutralized with a base and thereafter steam stripped to remove the free carboxylic acid formed and to provide a neutralized sulfonated polymer crumb.
  • the mud system used may be an open or closed system. Any system used should allow for samples of circulating mud to be taken periodically, whether from a mud flow line, a mud return line, mud motor intake or discharge, mud house, mud pit, mud hopper, or two or more of these.
  • the drilling rig operator (or owner of the well) has the opportunity to adjust the density, specific gravity, weight, viscosity, water content, oil content, composition, pH, flow rate, solids content, solids particle size distribution, resistivity, conductivity, and combinations of these properties of the mud.
  • the mud report may be in paper format, or more likely today, electronic in format.
  • the change in one or more of the list parameters and properties may be tracked, trended, and changed by a human operator (open-loop system) or by an automated system of sensors, controllers, analyzers, pumps, mixers, agitators (closed-loop systems).
  • Drilling as used herein may include, but is not limited to, rotational drilling, directional drilling, non-directional (straight or linear) drilling, deviated drilling, geosteering, horizontal drilling, and the like.
  • Rotational drilling may involve rotation of the entire drill string, or local rotation downhole using a drilling mud motor, where by pumping mud through the mud motor, the bit turns while the drillstring does not rotate or turns at a reduced rate, allowing the bit to drill in the direction it points.
  • a turbodrill may be one tool used in the latter scenario.
  • a turbodrill is a downhole assembly of bit and motor in which the bit alone is rotated by means of fluid turbine which is activated by the drilling mud. The mud turbine is usually placed just above the bit.
  • Bit or “drill bit”, as used herein, includes, but is not limited to antiwhirl bits, bicenter bits, diamond bits, drag bits, fixed-cutter bits, polycrystalline diamond compact bits, roller-cone bits, and the like.
  • the choice of bit like the choice of drilling mud, is dictated in part by the nature of the formation in which drilling is to take place.
  • the rate of penetration (ROP) during drilling methods of this disclosure depends on permeability of the rock (the capacity of a porous rock formation to allow fluid to flow within the interconnecting pore network), the porosity of the rock (the volume of pore spaces between mineral grains expressed as a percentage of the total rock volume, and thus a measure of the capacity of the rock to hold oil, gas, or water), and the amount or percentage of vugs.
  • the operator or owner of the well wishes the ROP to be as high as possible toward a known trap (any geological structure which precludes the migration of oil and gas through subsurface rocks, causing the hydrocarbons to accumulate into pools), without excess tripping in and out of the wellbore.
  • the drilling contractor or operator is able to drill more confidently and safely, knowing the pore pressure in the formation ahead of the drill bit before the drill bit actually penetrates the hydrocarbon-bearing region.

Landscapes

  • Engineering & Computer Science (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Mechanical Engineering (AREA)
  • Earth Drilling (AREA)

Claims (19)

  1. Procédé de forage d'un puits (10) tout en faisant la distinction entre le gaz ou l'air de circulation et le gaz provenant des pompes dans un fluide de forage à une pression et température de fond de trou, le procédé comprenant les opérations consistant à :
    a) forer un puits à l'aide d'un fluide de forage, d'un train de tiges (34) et d'un trépan (36) à partir d'une surface terrestre (12) à travers une formation à pression élevée à faible perméabilité englobant une formation à pression élevée et à haute perméabilité (16, 18, 20, 22, 24, 26), le fluide de forage étant pompé à travers le train de tiges (38), le trépan et jusque dans un espace annulaire (60) entre le train de tiges et un puits de forage (10), le train de tiges comprenant un ou plusieurs capteurs (54, 55) détectant un paramètre indicatif d'un gaz ou de l'air de circulation dans le fluide de forage lequel s'écoule à travers le train de tiges, au moins un des capteurs étant positionné dans le train de tiges derrière le trépan, et à proximité de ce dernier ;
    b) mesurer, pendant le forage, un paramètre du fluide de forage lequel est indicatif du gaz ou de l'air de circulation à l'intérieur du train de tiges derrière le trépan, et à proximité de ce dernier, grâce à l'utilisation des capteurs (55) ;
    c) faire soutenir au moins un capteur de gaz d'espace annulaire (54) par la tige de forage (34) derrière le trépan, et à proximité de ce dernier, afin de détecter une quantité de gaz dans le fluide de forage dans l'espace annulaire derrière le trépan, et à proximité de ce dernier, au cours du pompage à une profondeur dudit au moins un capteur de gaz d'espace annulaire ;
    d) détecter une quantité de gaz dans le fluide de forage dans l'espace annulaire derrière le trépan, et à proximité de ce dernier, grâce à l'utilisation dudit au moins un capteur de gaz d'espace annulaire, et assurer le suivi des niveaux de gaz ayant été détectés en termes volumétriques en tant que fonction des volumes de fluide de forage pendant des périodes de forage qui sont antérieures et postérieures à une période pendant laquelle le pompage est arrêté, et rectifier les volumes de gaz d'espace annulaire afin d'éliminer les effets du gaz ou de l'air de circulation ;
    e) communiquer le résultat des étapes (b) à (d) à une interface lisible par l'homme au niveau de la surface au cours du forage, afin de permettre à un opérateur de comparer la quantité de gaz dans le fluide de forage dans l'espace annulaire à la profondeur dudit au moins un capteur pendant les périodes qui sont antérieures et postérieures à la période pendant laquelle le pompage a été arrêté, et par conséquent déterminer si la pression du fluide de puits de forage est supérieure à la pression du fluide de la formation derrière le trépan, et à proximité de ce dernier ; et
    f) évaluer la pression de la formation par rapport à une pression de puits de forage, et ajuster un paramètre du fluide de forage.
  2. Procédé selon la revendication 1, l'opération de mesure du paramètre du fluide de forage indicatif du gaz ou de l'air de circulation à l'intérieur du train de tiges comprenant la mesure du paramètre dans le fluide de forage s'écoulant à travers le train de tiges à un niveau identique qu'un capteur de gaz d'espace annulaire lequel surveille le gaz présent dans du fluide s'écoulant à travers l'espace annulaire.
  3. Procédé selon la revendication 1, comprenant en outre des paramètres de détection qui sont indicatifs du gaz ou de l'air en circulation grâce à l'utilisation de capteurs placés le long du train de tiges pour évaluer le mouvement des gaz ou de l'air recirculés hors du puits, ou pour détecter des afflux de gaz qui remontent du puits.
  4. Procédé selon la revendication 1, l'opération de mesure comprenant la mesure d'une ou de plusieurs propriétés physiques sélectionnées parmi les suivantes, à savoir : densité, vitesse, température, pression, conductivité et résistivité du fluide de forage contenant des gaz et/ou de l'air de recirculation à des températures et pressions de fond de trou.
  5. Procédé selon la revendication 4, la propriété physique étant mesurée en temps réel, et les mesures en temps réel étant comparées avec des mesures obtenues grâce à l'utilisation d'échantillons de contrôle pour déterminer la teneur effective en gaz dans des conditions de fond de trou.
  6. Procédé selon la revendication 1, l'opération de mesure utilisant une technique sélectionnée parmi les suivantes, à savoir : écho par impulsions, densité, ultrasonique, vitesse, impédance sonique et impédance acoustique, ainsi que des combinaisons de celles-ci.
  7. Procédé selon la revendication 1, le paramètre du fluide de forage étant sélectionné parmi les postes suivants, à savoir : poids, densité, poids spécifique, densité API, conductivité thermique, pH, viscosité, compressibilité, conductivité thermique, salinité et activité de l'eau.
  8. Procédé destiné à détecter du gaz provenant des pompes dans du fluide de forage dans un puits de forage (10) au cours d'un forage à partir d'une surface terrestre (12) et pénétrant dans une pluralité de formations souterraines (16, 18, 20, 22, 24, 26) comprenant au moins une formation à pression élevée à faible perméabilité englobant une formation à pression élevée et à haute perméabilité, le procédé comprenant les opérations consistant à :
    a) pomper (38) du fluide de forage à travers une tige de forage (34) se prolongeant dans un puits de forage afin de procurer une certaine pression au fluide de forage dans la tige de forage, et décharger le fluide de forage à partir d'une extrémité inférieure de la tige de forage pour l'amener dans un trépan (36) et un espace annulaire (60) entre une face externe (62) de la tige de forage (34) et une face interne (44) du puits de forage (10) afin de forer le puits de forage jusqu'à une profondeur plus grande ;
    b) faire soutenir au moins un capteur de gaz d'espace annulaire (54, 55) par la tige de forage à proximité de l'extrémité inférieure (64) de la tige de forage, ledit au moins un capteur de gaz d'espace annulaire détectant la quantité de gaz dans le fluide de forage dans l'espace annulaire à une profondeur dudit au moins un capteur ;
    c) assurer le suivi des niveaux de gaz en termes volumétriques en tant que fonction des volumes de fluide de forage pompés pour reconnaître le moment auquel des gaz ou de l'air recirculés passent devant ledit au moins un capteur de gaz d'espace annulaire lequel surveille la teneur en gaz dans l'espace annulaire ;
    d) rectifier le volume de gaz d'espace annulaire ayant été mesuré afin d'éliminer les effets du gaz ou de l'air de circulation ayant été mesuré à l'intérieur de la tige de forage ;
    e) arrêter périodiquement le pompage du fluide de forage pendant une ou plusieurs périodes temporelles ; et
    f) comparer des quantités rectifiées de gaz détectées par ledit au moins un capteur de gaz d'espace annulaire dans le fluide de forage dans l'espace annulaire au niveau dudit au moins un capteur pendant des périodes temporelles de pompage afin de déterminer un changement dans une quantité de gaz dans l'espace annulaire laquelle résulte de l'arrêt périodique du pompage ; et
    g) évaluer la pression de la formation par rapport à la pression de puits de forage, et ajuster le poids du fluide de forage et autres.
  9. Procédé selon la revendication 8, le puits de forage étant foré à une profondeur plus grande à un état de sous-équilibre.
  10. Procédé selon la revendication 8, le puits de forage se trouvant à un état de sous-équilibre pendant une ou plusieurs des périodes lorsque le pompage a été arrêté.
  11. Procédé selon la revendication 8, le puits de forage se trouvant à un état de sous-équilibre à une pression de fluide de forage hydrostatique.
  12. Procédé selon la revendication 8, une pression interstitielle des formations souterraines dans lesquelles pénètre la tige de forage se situant entre une pression de pompage du fluide de forage et une pression du fluide de forage hydrostatique.
  13. Procédé selon la revendication 8, ledit au moins un capteur étant monté dans une section de la tige de forage.
  14. Procédé selon la revendication 8, ledit au moins un capteur étant monté sur la face externe de la tige de forage.
  15. Procédé selon la revendication 8, le capteur étant sélectionné parmi le groupe consistant en capteurs d'écho par impulsions, de densité, ultrasoniques, de vitesse, d'impédance sonique et d'impédance acoustique.
  16. Procédé selon la revendication 8, la quantité de gaz dans le fluide de forage au cours d'une période lorsque le pompage a été arrêté étant comparée à une quantité antérieure de gaz détectée au cours d'une période antérieure lorsque le pompage avait été arrêté.
  17. Procédé selon la revendication 8, une pluralité de capteurs étant positionnée en une pluralité d'emplacements le long d'une longeur de la tige de forage.
  18. Procédé selon la revendication 8, l'une au moins des pluralités de capteurs étant positionnée à une distance d'environ 1 pied à environ 1500 pieds [460 mètres] au-dessus du trépan le long d'une longueur de la tige de forage.
  19. Procédé selon la revendication 8, le puits de forage se trouvant à un état de sous-équilibre au cours du pompage.
EP08866416.4A 2007-12-19 2008-11-25 Procede de detection de la pression de formation Not-in-force EP2235318B1 (fr)

Applications Claiming Priority (3)

Application Number Priority Date Filing Date Title
US12/004,175 US8794350B2 (en) 2007-12-19 2007-12-19 Method for detecting formation pore pressure by detecting pumps-off gas downhole
US12/271,000 US20090159334A1 (en) 2007-12-19 2008-11-14 Method for detecting formation pore pressure by detecting pumps-off gas downhole
PCT/US2008/084630 WO2009085496A1 (fr) 2007-12-19 2008-11-25 Procédé de détection de la pression de formation

Publications (2)

Publication Number Publication Date
EP2235318A1 EP2235318A1 (fr) 2010-10-06
EP2235318B1 true EP2235318B1 (fr) 2015-03-04

Family

ID=40404894

Family Applications (1)

Application Number Title Priority Date Filing Date
EP08866416.4A Not-in-force EP2235318B1 (fr) 2007-12-19 2008-11-25 Procede de detection de la pression de formation

Country Status (3)

Country Link
US (1) US20090159334A1 (fr)
EP (1) EP2235318B1 (fr)
WO (1) WO2009085496A1 (fr)

Cited By (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2022203672A1 (fr) * 2021-03-24 2022-09-29 Halliburton Energy Services, Inc. Système de forage avec système de détection de gaz destiné à être utilisé dans le forage d'un puits

Families Citing this family (26)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US8794350B2 (en) * 2007-12-19 2014-08-05 Bp Corporation North America Inc. Method for detecting formation pore pressure by detecting pumps-off gas downhole
US9228401B2 (en) * 2008-09-15 2016-01-05 Bp Corporation North America Inc. Method of determining borehole conditions from distributed measurement data
US9567843B2 (en) 2009-07-30 2017-02-14 Halliburton Energy Services, Inc. Well drilling methods with event detection
GB2480940B (en) 2010-01-05 2015-10-07 Halliburton Energy Services Inc Well control systems and methods
US8632625B2 (en) 2010-06-17 2014-01-21 Pason Systems Corporation Method and apparatus for liberating gases from drilling fluid
EP2609282A4 (fr) * 2010-08-26 2015-11-04 Halliburton Energy Services Inc Système et procédé permettant un forage géré sous pression
CN102128026B (zh) * 2011-04-06 2013-04-17 北京六合伟业科技股份有限公司 随钻地层压力测量装置
CN103459755B (zh) 2011-04-08 2016-04-27 哈利伯顿能源服务公司 钻井中的自动立管压力控制
US9249638B2 (en) 2011-04-08 2016-02-02 Halliburton Energy Services, Inc. Wellbore pressure control with optimized pressure drilling
US9222350B2 (en) 2011-06-21 2015-12-29 Diamond Innovations, Inc. Cutter tool insert having sensing device
US8783381B2 (en) 2011-07-12 2014-07-22 Halliburton Energy Services, Inc. Formation testing in managed pressure drilling
WO2013009305A1 (fr) * 2011-07-12 2013-01-17 Halliburton Energy Services, Inc. Essai des couches lors d'un forage à pression gérée
EA032178B1 (ru) 2013-02-25 2019-04-30 Эволюшн Инжиниринг Инк. Встроенная забойная система с несколькими телеметрическими подсистемами
US10370952B2 (en) 2014-01-09 2019-08-06 Halliburton Energy Services, Inc. Drilling operations that use compositional properties of fluids derived from measured physical properties
CN105089609B (zh) * 2014-04-18 2017-09-08 中国石油化工集团公司 用于控制井筒压力的方法
EP2957934A1 (fr) * 2014-06-18 2015-12-23 Services Petroliers Schlumberger Systèmes et procédés permettant de déterminer la matière de remplissage annulaire sur la base de mesures de résistivité
CN104500054B (zh) * 2014-12-15 2017-07-07 中国石油天然气集团公司 地层孔隙压力的确定方法及装置
US10197481B2 (en) * 2015-03-02 2019-02-05 Halliburton Energy Services, Inc. Optical measurement system
US10689980B2 (en) * 2016-05-13 2020-06-23 Schlumberger Technology Corporation Downhole characterization of fluid compressibility
CN111364979B (zh) * 2020-03-23 2023-05-23 中国石油大学(华东) 一种基于超声波的井下气侵监测系统
US11414963B2 (en) * 2020-03-25 2022-08-16 Saudi Arabian Oil Company Wellbore fluid level monitoring system
CN111980691B (zh) * 2020-09-03 2024-06-07 中国石油天然气集团有限公司 利用井下烃类检测确定地层压力的测定系统
CN111980692B (zh) * 2020-09-03 2024-06-07 中国石油天然气集团有限公司 一种基于井下全烃含量检测的压井方法
US11746629B2 (en) * 2021-04-30 2023-09-05 Saudi Arabian Oil Company Autonomous separated gas and recycled gas lift system
US11624265B1 (en) 2021-11-12 2023-04-11 Saudi Arabian Oil Company Cutting pipes in wellbores using downhole autonomous jet cutting tools
CN114922614A (zh) * 2022-06-24 2022-08-19 西南石油大学 一种控压钻井工况下的地层压力监测方法

Family Cites Families (47)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3872721A (en) * 1973-02-28 1975-03-25 Exxon Production Research Co Downhole gas detector system
US4412130A (en) * 1981-04-13 1983-10-25 Standard Oil Company Downhole device to detect differences in fluid density
US4447338A (en) * 1981-08-12 1984-05-08 Exxon Research And Engineering Co. Drilling mud viscosification agents based on sulfonated ionomers
US4442011A (en) * 1981-12-21 1984-04-10 Exxon Research And Engineering Co. Drilling mud viscosification agents based on sulfonated ionomers
US4949575A (en) * 1988-04-29 1990-08-21 Anadrill, Inc. Formation volumetric evaluation while drilling
US5006845A (en) * 1989-06-13 1991-04-09 Honeywell Inc. Gas kick detector
US5214251A (en) * 1990-05-16 1993-05-25 Schlumberger Technology Corporation Ultrasonic measurement apparatus and method
US5130950A (en) * 1990-05-16 1992-07-14 Schlumberger Technology Corporation Ultrasonic measurement apparatus
US5283768A (en) * 1991-06-14 1994-02-01 Baker Hughes Incorporated Borehole liquid acoustic wave transducer
US7185718B2 (en) * 1996-02-01 2007-03-06 Robert Gardes Method and system for hydraulic friction controlled drilling and completing geopressured wells utilizing concentric drill strings
US5741962A (en) * 1996-04-05 1998-04-21 Halliburton Energy Services, Inc. Apparatus and method for analyzing a retrieving formation fluid utilizing acoustic measurements
US5859430A (en) * 1997-04-10 1999-01-12 Schlumberger Technology Corporation Method and apparatus for the downhole compositional analysis of formation gases
AU8164898A (en) * 1997-06-27 1999-01-19 Baker Hughes Incorporated Drilling system with sensors for determining properties of drilling fluid downhole
US6119772A (en) * 1997-07-14 2000-09-19 Pruet; Glen Continuous flow cylinder for maintaining drilling fluid circulation while connecting drill string joints
US6670605B1 (en) * 1998-05-11 2003-12-30 Halliburton Energy Services, Inc. Method and apparatus for the down-hole characterization of formation fluids
US6230557B1 (en) * 1998-08-04 2001-05-15 Schlumberger Technology Corporation Formation pressure measurement while drilling utilizing a non-rotating sleeve
US6429784B1 (en) * 1999-02-19 2002-08-06 Dresser Industries, Inc. Casing mounted sensors, actuators and generators
US6427125B1 (en) * 1999-09-29 2002-07-30 Schlumberger Technology Corporation Hydraulic calibration of equivalent density
US6401538B1 (en) * 2000-09-06 2002-06-11 Halliburton Energy Services, Inc. Method and apparatus for acoustic fluid analysis
US6585044B2 (en) * 2000-09-20 2003-07-01 Halliburton Energy Services, Inc. Method, system and tool for reservoir evaluation and well testing during drilling operations
US6465775B2 (en) * 2000-12-19 2002-10-15 Schlumberger Technology Corporation Method of detecting carbon dioxide in a downhole environment
US6484816B1 (en) * 2001-01-26 2002-11-26 Martin-Decker Totco, Inc. Method and system for controlling well bore pressure
US6598457B2 (en) * 2001-04-05 2003-07-29 Buckman Laboratories International, Inc. Method and apparatus for measuring the amount of entrained gases in a liquid sample
US6712138B2 (en) * 2001-08-09 2004-03-30 Halliburton Energy Services, Inc. Self-calibrated ultrasonic method of in-situ measurement of borehole fluid acoustic properties
GB2380802B (en) * 2001-10-12 2003-09-24 Schlumberger Holdings Method and apparatus for pore pressure monitoring
US6675914B2 (en) * 2002-02-19 2004-01-13 Halliburton Energy Services, Inc. Pressure reading tool
US6926081B2 (en) * 2002-02-25 2005-08-09 Halliburton Energy Services, Inc. Methods of discovering and correcting subterranean formation integrity problems during drilling
US6640625B1 (en) * 2002-05-08 2003-11-04 Anthony R. H. Goodwin Method and apparatus for measuring fluid density downhole
US7318343B2 (en) * 2002-06-28 2008-01-15 Shell Oil Company System for detecting gas in a wellbore during drilling
US6814142B2 (en) * 2002-10-04 2004-11-09 Halliburton Energy Services, Inc. Well control using pressure while drilling measurements
US7036362B2 (en) * 2003-01-20 2006-05-02 Schlumberger Technology Corporation Downhole determination of formation fluid properties
US7331223B2 (en) * 2003-01-27 2008-02-19 Schlumberger Technology Corporation Method and apparatus for fast pore pressure measurement during drilling operations
WO2004090557A2 (fr) * 2003-04-01 2004-10-21 Halliburton Energy Services, Inc. Determination d'une pression anormale au moyen de diagraphies de resonance magnetique nucleaire
CA2524075A1 (fr) * 2003-05-02 2004-11-18 Baker Hughes Incorporated Procede et appareil pour analyseur optique perfectionne
US6995360B2 (en) * 2003-05-23 2006-02-07 Schlumberger Technology Corporation Method and sensor for monitoring gas in a downhole environment
CN1946920A (zh) * 2004-03-17 2007-04-11 贝克休斯公司 用于储层流体表征的井下流体分析用方法和装置
GB0407982D0 (en) * 2004-04-08 2004-05-12 Wood Group Logging Services In "Methods of monitoring downhole conditions"
US6997055B2 (en) * 2004-05-26 2006-02-14 Baker Hughes Incorporated System and method for determining formation fluid parameters using refractive index
US6995369B1 (en) * 2004-06-24 2006-02-07 Kla-Tencor Technologies Corporation Scanning electron beam apparatus and methods of processing data from same
US8442839B2 (en) 2004-07-16 2013-05-14 The Penn State Research Foundation Agent-based collaborative recognition-primed decision-making
US7240546B2 (en) * 2004-08-12 2007-07-10 Difoggio Rocco Method and apparatus for downhole detection of CO2 and H2S using resonators coated with CO2 and H2S sorbents
US7614302B2 (en) * 2005-08-01 2009-11-10 Baker Hughes Incorporated Acoustic fluid analysis method
US20080047337A1 (en) * 2006-08-23 2008-02-28 Baker Hughes Incorporated Early Kick Detection in an Oil and Gas Well
US7280918B2 (en) * 2005-08-08 2007-10-09 Knowledge Systems, Inc. Method and system for combining seismic data and basin modeling
US7516655B2 (en) * 2006-03-30 2009-04-14 Baker Hughes Incorporated Downhole fluid characterization based on changes in acoustic properties with pressure
WO2007124330A2 (fr) * 2006-04-20 2007-11-01 At Balance Americas Llc système de sécurisation de pression pour UNE utilisation avec un circuit de régulation de pression annulaire dynamique
US8794350B2 (en) * 2007-12-19 2014-08-05 Bp Corporation North America Inc. Method for detecting formation pore pressure by detecting pumps-off gas downhole

Cited By (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2022203672A1 (fr) * 2021-03-24 2022-09-29 Halliburton Energy Services, Inc. Système de forage avec système de détection de gaz destiné à être utilisé dans le forage d'un puits

Also Published As

Publication number Publication date
US20090159334A1 (en) 2009-06-25
EP2235318A1 (fr) 2010-10-06
WO2009085496A1 (fr) 2009-07-09

Similar Documents

Publication Publication Date Title
EP2235318B1 (fr) Procede de detection de la pression de formation
US10190407B2 (en) Methods for evaluating inflow and outflow in a subterraean wellbore
US9765583B2 (en) Interval density pressure management methods
US7950472B2 (en) Downhole local mud weight measurement near bit
US6296056B1 (en) Subsurface measurement apparatus, system, and process for improved well drilling, control, and production
Cayeux et al. Toward drilling automation: On the necessity of using sensors that relate to physical models
US9228430B2 (en) Methods for evaluating cuttings density while drilling
US20110220350A1 (en) Identification of lost circulation zones
US20130048380A1 (en) Wellbore interval densities
US8991520B2 (en) Mathematical modeling of shale swelling in water based muds
US8794350B2 (en) Method for detecting formation pore pressure by detecting pumps-off gas downhole
CA2910218C (fr) Surveillance, detection, commande et diagraphie de boue de puits pour un forage a double gradient
Aldred et al. Using downhole annular pressure measurements to improve drilling performance
Smith et al. Application of multiphase flow methods to horizontal underbalanced drilling
US10753203B2 (en) Systems and methods to identify and inhibit spider web borehole failure in hydrocarbon wells
KAPPA Production Logging
AU761499B2 (en) Subsurface measurement apparatus, system and process for improved well drilling, control, and production
Amirov et al. Reservoir Geomechanics, Geomechanical Evaluation and Wellbore Stability Handbook/Manual for Students
Basuki Successful Application of Real-Time Pore Pressure and Fracture Gradient Modeling in Deepwater Exploration Wells

Legal Events

Date Code Title Description
PUAI Public reference made under article 153(3) epc to a published international application that has entered the european phase

Free format text: ORIGINAL CODE: 0009012

17P Request for examination filed

Effective date: 20100719

AK Designated contracting states

Kind code of ref document: A1

Designated state(s): AT BE BG CH CY CZ DE DK EE ES FI FR GB GR HR HU IE IS IT LI LT LU LV MC MT NL NO PL PT RO SE SI SK TR

AX Request for extension of the european patent

Extension state: AL BA MK RS

DAX Request for extension of the european patent (deleted)
17Q First examination report despatched

Effective date: 20120203

GRAP Despatch of communication of intention to grant a patent

Free format text: ORIGINAL CODE: EPIDOSNIGR1

INTG Intention to grant announced

Effective date: 20140915

GRAS Grant fee paid

Free format text: ORIGINAL CODE: EPIDOSNIGR3

GRAA (expected) grant

Free format text: ORIGINAL CODE: 0009210

AK Designated contracting states

Kind code of ref document: B1

Designated state(s): AT BE BG CH CY CZ DE DK EE ES FI FR GB GR HR HU IE IS IT LI LT LU LV MC MT NL NO PL PT RO SE SI SK TR

RAP1 Party data changed (applicant data changed or rights of an application transferred)

Owner name: BP CORPORATION NORTH AMERICA INC.

REG Reference to a national code

Ref country code: GB

Ref legal event code: FG4D

REG Reference to a national code

Ref country code: CH

Ref legal event code: EP

REG Reference to a national code

Ref country code: IE

Ref legal event code: FG4D

REG Reference to a national code

Ref country code: AT

Ref legal event code: REF

Ref document number: 714085

Country of ref document: AT

Kind code of ref document: T

Effective date: 20150415

REG Reference to a national code

Ref country code: DE

Ref legal event code: R096

Ref document number: 602008037022

Country of ref document: DE

Effective date: 20150416

REG Reference to a national code

Ref country code: NO

Ref legal event code: T2

Effective date: 20150304

REG Reference to a national code

Ref country code: AT

Ref legal event code: MK05

Ref document number: 714085

Country of ref document: AT

Kind code of ref document: T

Effective date: 20150304

Ref country code: NL

Ref legal event code: VDEP

Effective date: 20150304

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: FI

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20150304

Ref country code: SE

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20150304

Ref country code: ES

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20150304

Ref country code: HR

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20150304

Ref country code: LT

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20150304

REG Reference to a national code

Ref country code: LT

Ref legal event code: MG4D

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: GR

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20150605

Ref country code: LV

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20150304

Ref country code: AT

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20150304

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: NL

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20150304

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: EE

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20150304

Ref country code: RO

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20150304

Ref country code: PT

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20150706

Ref country code: CZ

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20150304

Ref country code: SK

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20150304

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: PL

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20150304

Ref country code: IS

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20150704

REG Reference to a national code

Ref country code: DE

Ref legal event code: R097

Ref document number: 602008037022

Country of ref document: DE

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: IT

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20150304

PLBE No opposition filed within time limit

Free format text: ORIGINAL CODE: 0009261

STAA Information on the status of an ep patent application or granted ep patent

Free format text: STATUS: NO OPPOSITION FILED WITHIN TIME LIMIT

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: DK

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20150304

26N No opposition filed

Effective date: 20151207

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: SI

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20150304

REG Reference to a national code

Ref country code: DE

Ref legal event code: R119

Ref document number: 602008037022

Country of ref document: DE

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: MC

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20150304

Ref country code: LU

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20151125

REG Reference to a national code

Ref country code: CH

Ref legal event code: PL

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: CH

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20151130

Ref country code: LI

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20151130

REG Reference to a national code

Ref country code: IE

Ref legal event code: MM4A

REG Reference to a national code

Ref country code: FR

Ref legal event code: ST

Effective date: 20160729

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: BE

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20150304

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: IE

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20151125

Ref country code: DE

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20160601

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: FR

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20151130

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: BG

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20150304

Ref country code: HU

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT; INVALID AB INITIO

Effective date: 20081125

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: CY

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20150304

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: TR

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20150304

Ref country code: MT

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20150304

PGFP Annual fee paid to national office [announced via postgrant information from national office to epo]

Ref country code: NO

Payment date: 20191129

Year of fee payment: 12

PGFP Annual fee paid to national office [announced via postgrant information from national office to epo]

Ref country code: GB

Payment date: 20191127

Year of fee payment: 12

REG Reference to a national code

Ref country code: NO

Ref legal event code: MMEP

GBPC Gb: european patent ceased through non-payment of renewal fee

Effective date: 20201125

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: NO

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20201130

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: GB

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20201125