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WO2004033845A2 - Forage a double gradient dans lequel on utilise une injection d'azote - Google Patents

Forage a double gradient dans lequel on utilise une injection d'azote Download PDF

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Publication number
WO2004033845A2
WO2004033845A2 PCT/US2003/030490 US0330490W WO2004033845A2 WO 2004033845 A2 WO2004033845 A2 WO 2004033845A2 US 0330490 W US0330490 W US 0330490W WO 2004033845 A2 WO2004033845 A2 WO 2004033845A2
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WO
WIPO (PCT)
Prior art keywords
pressure
fluid
riser
wellbore
well
Prior art date
Application number
PCT/US2003/030490
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English (en)
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WO2004033845A3 (fr
Inventor
Leldon Mark Farabee
Carey John Naquin
Patrick Emmett Laursen
Original Assignee
Halliburton Energy Services, Inc.
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Filing date
Publication date
Application filed by Halliburton Energy Services, Inc. filed Critical Halliburton Energy Services, Inc.
Priority to AU2003275270A priority Critical patent/AU2003275270A1/en
Publication of WO2004033845A2 publication Critical patent/WO2004033845A2/fr
Publication of WO2004033845A3 publication Critical patent/WO2004033845A3/fr

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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
    • E21B21/082—Dual gradient systems, i.e. using two hydrostatic gradients or drilling fluid densities
    • 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
    • E21B21/14—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor using liquids and gases, e.g. foams

Definitions

  • the present invention relates generally to methods and apparatus for drilling subsea wells. More specifically, the present invention relates to methods and apparatus for drilling subsea wells using a dual pressure gradient system in the annulus whereby the returns in the upper portion of the annulus have a lower density than the returns in the lower portion of the annulus.
  • a drilling fluid is typically used when drilling a well.
  • This fluid has multiple functions, one of which is to provide pressure in the open wellbore in order to prevent the influx of fluid from the formation.
  • the pressure in the open wellbore is typically maintained at a higher pressure than the fluid pressure in the formation pore space (pore pressure).
  • the influx of formation fluids into the wellbore is called a kick.
  • the formation fluid entering the wellbore ordinarily has a lower density than the drilling fluid, a kick will potentially reduce the hydrostatic pressure within the well and allow an accelerating influx of formation fluid. If not properly controlled, this influx is known as a blowout and may result in the loss of the well, the drilling rig, and possibly the lives of those operating the rig. Therefore, when formation fluid influx is not desired (almost always the case), the formation pore pressure defines a lower limit for allowable wellbore pressure in the open wellbore, i.e. uncased borehole.
  • the open wellbore extends below the lowermost casing string, which is cemented to the formation at, and for some distance above, a casing shoe.
  • deposits from the drilling fluid will collect on wellbore wall and form a filter cake.
  • the filter cake forms an important barrier between the formation fluids contained in the permeable formation at a certain pore pressure and the wellbore fluids that are circulating at a higher pressure.
  • the filter cake provides a buffer that allows wellbore pressure to be maintained above pore pressure without significant losses of drilling fluid into the formation.
  • the wellbore pressure defines an upper limit for allowable wellbore pressure in an open wellbore.
  • the formation immediately below the casing shoe has the lowest fracture pressure in the open wellbore, and therefore it is the fracture pressure at this depth that controls the maximum annulus pressure.
  • the fracture pressure is determined in part by the overburden acting at a particular depth of the formation.
  • the overburden includes all of the rock and other material that overlays, and therefore must be supported by, a particular level of the formation.
  • the overburden includes not only the sediment of the earth but also the water above the mudline.
  • the density of the earth, or sediment provides an overburden gradient of approximately 1 psi per foot.
  • the density of seawater provides an overburden gradient of approximately 0.45 psi/ft.
  • the pore pressure at a given depth is determined in part by the hydrostatic pressure of the fluids above that depth. These fluids include fluids within the formation below the seafloor/mudline plus the seawater from the seafloor to the sea surface.
  • a formation fluid gradient of 0.465 psi/ft is often considered normal.
  • the typical seawater pressure gradient is about 0.45 psi/ft.
  • the differential in gradient between the seawater (or groundwater) and the earth often creates a pore pressure profile and fracture pressure profile that provide a sufficient range of pressure to allow the use of conventional drilling techniques.
  • Figure 1 shows a schematic representation of pore pressure PP and fracture pressure FP.
  • the pressure developed in the wellbore is essentially determined by the hydrostatic pressure of the wellbore fluid, along with pressure variations due to fluid circulation and/or pipe movement.
  • the region of allowable pressure lies between the pore pressure profile, and the fracture pressure profile for that portion of the well between the deepest casing shoe and the bottom of the well.
  • Clean drilling fluid is circulated into the well through the drill string and then returns to the surface through the annulus between the wellbore wall and the drill string.
  • a riser is used to contain the annulus fluid between the sea floor and the drilling rig located on the surface. The pressure developed in the annulus is of particular concern because it is the fluid in the annulus that acts directly on the uncased borehole.
  • the fluid flowing through the annulus typically known as returns, includes the drilling fluid, cuttings from the well, and any formation fluids that may enter the wellbore.
  • the drilling fluid typically has a fairly constant density and thus the hydrostatic pressure in the wellbore vs. depth can typically be approximated by a single gradient starting at the top of the fluid column.
  • the top of the fluid column is generally the top of the riser at the surface platform.
  • the lower static pressure SP must be maintained above the pore pressure PP at the deepest point D2 in the open wellbore. Therefore, the range of allowable pressures for a certain length of uncased wellbore LI, as shown in Figure 1, is limited by the dynamic pressure DP reaching fracture pressure FP at the casing shoe depth Dl and the static pressure SP reaching pore pressure PP at the bottom of the well D2. Once depth D2 is reached, an additional string of casing may then be installed to allow drilling to progress deeper. The shallowest point in the uncased wellbore is then at depth D2. The limiting fracture pressure FP is greater at depth D2 compared to that at depth Dl, therefore the allowable wellbore pressure is increased.
  • Figure 2 represents the typical pore pressure profile PP and fracture pressure profile FP for a well located in deep water (greater than 5000 feet).
  • the pore pressure profile PP and fracture pressure profile FP are closer together in deep water because of the significant amount of overburden from the water depth, thus reducing the acceptable range of pressures for drilling at a particular depth. Because the two profiles are closer together, the range of available pressures for a certain depth is reduced. This range is even further reduced in most drilling practices that include a factor of safety to avoid wellbore pressures approaching the limits of desired operation.
  • An initial maximum drilling fluid density is chosen such that the dynamic pressure 10 will not exceed the fracture pressure at point 12, which is the shallowest point in the open hole.
  • This maximum drilling fluid density is used to define the point 16 where the static pressure profile 14 intersects the pore pressure profile. This forms a region 18 of allowable pressure and indicates a depth 20 above which a string of casing should be set.
  • the maximum density of the drilling fluid may be increased such that the dynamic pressure 22 will not exceed the fracture pressure at point 24, which is now the shallowest point in the open hole.
  • This new maximum drilling fluid density is then used to define the point 28 where the static pressure profile 26 intersects the pore pressure profile. This now defines a second region 30 of allowable pressure and a depth 32 above which casing should be set. This continues until the desired wellbore total depth is reached.
  • the distance that can be drilled before needing to set a casing string, i.e. between depths 20 and 32, is known as a drilling interval.
  • the reduced range of allowable pressures in deep water drilling translates into a shorter drilling interval and an increased number of casing strings when using single-gradient drilling in deep water.
  • the increased number of casing strings increases the cost and complexity of a deep-water well.
  • each successive casing string decreases the size of the wellbore and limits the size of any equipment that has to pass through that region of the well, including the drill bit for the next section of borehole. Therefore, it is desired to drill as far as possible in the region between the pore pressure profile and the fracture pressure profile and minimize the number of casing strings needed in a well.
  • One way to extend the drilling interval is to cause the slope of wellbore pressure profile to approach the slopes of the pore pressure profile and fracture pressure profile, which allows the wellbore pressure to be maintained in the range of allowable pressure to a greater depth, hence a longer drilling interval.
  • Dual- gradient drilling techniques seek to adjust the density of the column of fluid contained in the wellbore.
  • Typical single-gradient drilling technology seeks to control wellbore pressure using a column of substantially constant-density drilling fluid from the bottom of the well back to the rig.
  • dual-gradient drilling seeks to control wellbore pressure by using a lower density fluid, about the same density as seawater, from the rig to the seafloor and then uses a higher density drilling fluid within the actual formation, i.e. between the seafloor and the bottom of the well.
  • Dual-gradient drilling techniques in effect, simulate the drilling rig being located on the seafloor and therefore avoid some of the problems associated with deep-water drilling.
  • dual gradient pressure profiles have a first gradient that extends from a surface platform and a second, greater gradient extending from lower in the annulus, such as from the mud line down into the well.
  • an initial maximum dual-gradient drilling fluid density is chosen such that the dynamic pressure 34 will not exceed the fracture pressure at point 36, which is the shallowest point in the open hole.
  • This maximum drilling fluid density is used to define the point 40 where the static pressure profile 38 intersects the pore pressure profile. This forms a region 42 of allowable pressure and indicates a depth 44, above which a string of casing should be set.
  • the maximum density of the drilling fluid may be increased such that the dynamic pressure 46 will not exceed the fracture pressure at point 48, which is now the shallowest point in the open hole.
  • This new maximum drilling fluid density is then used to define the point 52 where the static pressure profile 50 intersects the pore pressure profile.
  • a greater well depth can be drilled with the same number of casing strings or the same depth can be reached with fewer casing strings.
  • dual-gradient drilling techniques being developed in the industry. Each approach addresses the means of directing the fluids in the system to the surface in similar but mechanically different ways.
  • One technique is to separate at least a portion of the drilling fluid from the riser annulus at the seafloor. That fluid is either returned to the surface through a separate line or processed at the seafloor.
  • Another technique involves pumping the returns back to the surface from the seafloor. Most often these techniques involve placing pumping and fluid cleaning equipment at the seafloor to process the fluid or provide the force needed to return the fluid to the surface or recirculate through the wellbore.
  • These systems are faced with the technological challenges of operating a submerged high rate pump located in a remote, inhospitable location (the sea floor) and the difficulty of the required high rate pumping of the drilling fluid laden with drill cuttings.
  • Another method of decreasing the pressure at the bottom of the riser is to inject a less dense fluid, typically a gas, at the bottom of the riser, resulting in a mixture of decreased density in the riser.
  • a less dense fluid typically a gas
  • the volume of gas required can be impractical for conventionally sized risers, and a conventional low-pressure drilling riser system is not designed to control multi-phase (gas, liquid, and solids) returns.
  • Some of these systems involve allowing seawater to flow into the wellbore to decrease the density of the fluid in the annulus. This adds additional difficulty in then removing the seawater from the drilling fluid once it reaches the surface.
  • the preferred embodiments of the present invention are characterized by a drilling system utilizing a coiled tubing drill string, a high pressure riser, and a system for injecting a gas into the high pressure riser.
  • the preferred drill string also includes a downhole pressure sensing device for monitoring wellbore pressure.
  • the embodiments of the present invention act to reduce the cost and complexity of a dual-gradient drilling system, thereby increasing the efficiency and/or feasibility of deep-water drilling applications.
  • One preferred embodiment includes a high pressure riser extending from a drilling platform at the surface to the seafloor or mud line.
  • the base of the riser is connected to a wellhead that is anchored to the seafloor.
  • Pressure control equipment is preferably disposed on the upper end of the riser at the drilling platform.
  • a bottom hole assembly (BHA) is run on a coiled tubing drill string through the riser and into the subsea formation.
  • the BHA preferably includes a pressure sensing device that can be used in transmitting real-time downhole pressure data to the surface.
  • a riser injection system is provided to inject a lower density fluid into the riser annulus in order to reduce the density of the returns in the riser annulus and therefore reduce the hydrostatic pressure within the wellbore annulus.
  • an inert gas such as nitrogen, is injected into the riser during circulation.
  • the desired dual-gradient condition i.e. the average density of the fluid in the riser is lower than the average density of the fluid in the wellbore below the sea floor.
  • the wellbore pressure can be monitored by the downhole pressure sensor preferably integrated into the bottom hole assembly. Using this pressure information feedback, the rate of gas injection can be varied to result in a wellbore pressure that stays within the range of allowable pressure within the open wellbore.
  • the high-pressure riser with pressure control equipment, preferably including a choke, at the top, can be used to control the pressure of the returns and the expansion of gas within the riser by holding back-pressure at the top of the riser.
  • the gas injection rate in the riser can be increased, resulting in decreased hydrostatic pressure to counteract the friction pressure in order to keep the wellbore pressure below the formation fracture pressure.
  • the above process is reversed in order to keep the wellbore pressure above the formation pore pressure. Constant real-time information on wellbore pressure at the bottom hole assembly enables this process to be controlled to a level of precision not possible with previous approaches.
  • One aspect of the current invention is to utilize a simpler method of decreasing the pressure at the bottom of the riser, when compared with using a pump at the seafloor.
  • the preferred embodiments also provide a more practical method of using gas injection to control the fluid density in the riser, as compared with methods that have neither a high pressure riser nor a capability for real time bottom hole pressure measurement.
  • Yet another aspect of the preferred embodiments is a more effective and precise method of controlling wellbore pressure in order to maintain the pressure between formation pore pressure and formation fracture pressure.
  • Another aspect of the current invention is a method that monitors fluid flowing into and out of the well to detect potential well problems.
  • the drilling fluid and injected fluid put into the annulus are monitored and compared to the fluids that leave the well. If the total flow rate of fluid into the well exceeds the flow rate leaving the well, then fluid is being lost in the well.
  • the present invention comprises a combination of features and advantages that enable it to substantially reduce the complexity and cost associated with using dual-gradient drilling techniques in deep-water wells.
  • Figure 1 is a graphical representation of pressure vs. depth profiles in a surface or shallow- water well
  • Figure 2 is a graphical representation of pressure vs. depth profiles in a deep-water well drilled using single-gradient techniques
  • Figure 3 is a graphical representation of pressure vs. depth profiles for a deep-water well drilled using dual-gradient drilling techniques; and
  • Figure 4 is a schematic representation of one embodiment of a drilling system constructed in accordance with the present invention.
  • an open wellbore should be taken to mean the uncased, exposed wellbore below the lowermost casing string.
  • Returns refer to the fluid flowing towards the surface through the annulus between the drill string and the wellbore or riser wall.
  • the returns generally include drilling fluid, cuttings, possibly formation fluids, and any other fluids injected into the annulus.
  • Slimhole drilling includes those boreholes having a diameter of 6 1/2" or less, regardless of length of interval. Boreholes with a diameter between 6 1/2" and 8 1/2" may also be considered slimhole if they have a very long interval.
  • Subsea well 110 includes a wellhead 116 from which extends a cased wellbore portion 112 that leads to an uncased, open wellbore portion 114.
  • Surface platform 120 supports drill string 130, pressure control equipment 140, telemetry equipment 150, injection equipment 160, and riser 170.
  • a bottom hole assembly (BHA) 132 is suspended from the end of drill string 130 and includes drill bit 134 and pressure sensor 136.
  • Pressure sensor 136 is adapted to provide realtime pressure data from the bottom of well 110. This data can be relayed to telemetry equipment 150 located at surface platform 120.
  • Pressure sensor 136 may preferably be a strain gage pressure transducer, such as series 211-36-760-04 as manufactured by Paine Electronics, or other type of downhole pressure transducer.
  • Drill string 130 is preferably a coiled tubing string capable of two-way communication by transmitting electric signals to and from surface platform 120 and BHA 132. Drill string 130 may also be constructed of any other acceptable tubular material capable of relaying signals between BHA 132 and surface platform 120.
  • One exemplary coiled tubing string is a composite coiled tubing string with embedded electrical conductors, as disclosed in U.S. Patent 6,296,066, titled "Well System,” and hereby incorporated herein by reference for all purposes.
  • An exemplary telemetry system is disclosed in U.S. Patent 6,348,876, hereby incorporated herein by reference. Any other telemetry system could be used including an MWD system or an electric-coil (E-coil) system.
  • Riser 170 forms the conduit between pressure control equipment 140 and wellhead 116 for the circulation of drilling fluids.
  • Riser 170 preferably connects to wellhead 116 by way of a lower marine riser package (not shown).
  • Riser 170 is a high-pressure riser capable of withstanding the full operating pressure of the well.
  • the preferred riser 170 can have an inside diameter as small as 5 to 5 1/2", or smaller.
  • the present invention is not limited to any particular diameter. However, a small diameter is preferred to reduce the annulus and thus the volume flow rate required for the injection fluid.
  • the preferred drill string 130 is also relatively small diameter, such as a 3 1/8" tubing string or smaller.
  • a 5 to 5-1/2 inch riser provides a substantial reduction in cross-sectional area and volume compared to that of a conventional 18-3/4 inch low pressure riser.
  • the quantity and flow rate of fluids required to decrease the density of the returns in a larger diameter riser would require very large pumping packages at the surface.
  • a standard offshore drilling installation may not have available room to support this equipment. Therefore, the use of a small diameter riser is an important feature in being able to minimize the size of equipment required to support subsea fluid injection. For example, risers with inside diameters smaller than eight inches should have a sufficiently small annular area to allow the use of relatively compact pumping packages, separators, and other surface equipment. However, it should be appreciated that a small diameter riser requires the use of a even smaller diameter drilling system. It should also be appreciated that any size riser can be used as long as sufficient subsea fluid injection can be supported.
  • Riser 170 is equipped with a riser injection line 172 preferably extending from the surface to the bottom of the riser near the mud line 108.
  • Injection line 172 leads from injection equipment 160 to riser 170.
  • Injection line 172 does not have to enter the riser at the bottom of the riser and may enter the riser annulus 175 any where along the riser between mud line 108 and the surface 106. It is most efficient to have the injection point 176 as low as possible into riser 170.
  • Riser 170 may also have a pressure transducer 174 at mud line 108.
  • a sensor 174 in the riser annulus 175 proximate to injection point 176 in order to measure the resulting reduction of hydrostatic pressure due to the injection of a gas into the riser 170 through injection line 172.
  • Sensor 174 could also be used to determine the pressure at the bottom of the well by measuring the pressure at the mud line and calculating the pressure at the bottom of the well.
  • the desired dual-gradient drilling condition can be established by injecting a lower density fluid from injection equipment 160, through injection line 172 and into riser 170.
  • Check valves (not shown) are preferably on either end of injection line 172.
  • Check valves operate as one way valves and allow fluid to flow in only one direction and do not require any positive action to actuate.
  • a preferred fluid is an inert gas, such as nitrogen.
  • gases and liquids, having densities less than the returns flowing through the riser annulus 175, may also be used.
  • the injection fluid could be any fluid with a lighter density whether it be air, nitrogen or some other fluid.
  • a gas is preferred because the injection fluid will need to be separated from the returns and particularly the drilling fluid, once it reaches the surface.
  • an injector hose is attached at injection point 176 to riser annulus 175.
  • Nitrogen, or some other acceptable fluid is bubbled into riser annulus 175 to reduce the overall density of the drilling fluid above the injection point 176.
  • a heavier density drilling fluid may be used below injection point 176 and a lighter density drilling fluid above injection point 176.
  • Alternative light-weight fluids may include water, oil, diesel, and other drilling fluid additives.
  • Nitrogen, or some other inert gas, is a preferred fluid because of ease of separation at the surface and non-reactivity with hydrocarbons in the wellbore.
  • Injection equipment 160 is preferably located on surface platform 120 and requires a minimal amount of deck space.
  • Preferable injection equipment 160 has a footprint of about 15 x 20 feet.
  • the preferred nitrogen injection equipment employs a standard membrane unit rather than using bottled nitrogen.
  • Injection equipment 160 is preferably able to pump gas at a pressure of 6,000 psi at a rate of 100 to 300 cubic feet per minute.
  • the pressure of the gas being injected into the riser annulus 175 is preferably equal to or slightly greater than the pressure in the riser annulus at the gas injection point 176.
  • the nitrogen At a water depth of 10,000 feet, the nitrogen itself has an appreciable weight, i.e. density, of about 2.2 pounds per gallon. The pressure of the nitrogen at the injection equipment would be very close to the pressure in riser annulus 175 at the gas injection point 176.
  • Pressure control equipment 140 preferably includes a high-pressure stripper 142 and a flowline 144 having a choke 146.
  • stripper 142 can be closed so as to maintain an elevated back-pressure on riser annulus 175. Drilling returns are removed from riser annulus 175 through flowline 144 and choke 146 to reduce their pressure. Once the injected nitrogen, or other injected fluid, is removed from the drilling fluid, the drilling fluid can be cleaned and recirculated through the well.
  • An alternative embodiment may include disposing the pressure control equipment at the sea floor.
  • a small subsea blowout preventer may be used, rather than a surface blowout preventer, with a low pressure, small diameter riser extending to the surface.
  • the pressure at the bottom of the well is continuously monitored.
  • counteractive measures can be taken to adjust the wellbore pressure by changing the density of the returns in riser annulus 175 by either adding or reducing the quantity of nitrogen, or other light fluid, injected into the riser annulus.
  • the wellbore pressure may also be adjusted by changing the density of the drilling fluid that is pumped into the well. This monitoring and adjusting may be done automatically through the use of software or manually by the operator.
  • the preferred embodiments provide real-time, continuous monitoring of bottom hole pressure.
  • the fluid pressure and the amount of fluid being injected into riser annulus 175 is monitored, preferably at injection system 160.
  • the pumping of drilling fluid is monitored by the pumping equipment. Further, the density and rate of the returns may also be monitored.
  • the bottom hole pressure is also measured to ensure that the down hole pressure for drilling is being maintained between the pore pressure and the fracture pressure.
  • the density of the drilling fluid and the rate at which the drilling fluid is being pumped through the drill string is easily measured at the surface.
  • the fluid injection rate into riser annulus 175 as well as the density and flow rate of the returns coming out of the well are also known or measured. Therefore, the mass flow rate through the well can be represented by: dV ⁇ d ⁇ s
  • QDPD + QlPl Eq.(l) dt -Ps Q R P R ⁇ +V s ⁇ dt
  • Q D and p D are, respectively, the flow rate and density of the drilling fluid entering the well
  • Qi and/? / are, respectively, the flow rate and density of the injected fluid entering the riser
  • V s and p s are, respectively, the volume of the system and the average density of the contents of the system.
  • Q R and P R are, respectively, the flow rate and density of the mixture of drilling fluid and injected fluid exiting the well.
  • mass flowrate out is less than mass flowrate in minus the rate of change of mass within the system, then mud is being lost into the formation i.e. is being lost in the well.
  • Monitoring the mass flow rates into and out of the well provides an alternative to the traditional liquid level monitoring techniques of the prior art. Controlling the density of the drilling fluid in the drill string and the density of the combined drilling and injected fluids in the riser is critical to maintaining the desired conditions for dual-gradient drilling. If there is a pressure sensor available at the mud line 108, that sensor can be used to provide real-time feedback of the pressure at the mud line.
  • This pressure data can be used as input data to a control system that varies the amount of fluid injected into the riser to keep the pressure at the mud line 108 within a desired range.
  • a pressure sensor at or near the bottom of the well and providing in real-time, pressure data to the surface can be used in the same manner to maintain the pressure at the bottom of the wellbore within a desired range.

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Abstract

La présente invention concerne des procédés et un appareil de forage de puits sous-marin en eau profonde dans lesquels on utilise des techniques de forage à double gradient. Une forme de réalisation préférée comprend un tube ascenseur haute pression qui part d'une plate-forme de forage située à la surface et descend jusqu'au plancher océanique. La base du tube ascenseur est connectée à une tête de puits qui est ancrée sur le plancher océanique. Du matériel de régulation de la pression est installé sur l'extrémité supérieure du tube ascenseur au niveau de la plate-forme de forage. Un train de tiges de production spiralé est envoyé dans le tube ascenseur et dans la formation sous-marine. Le train de tiges comprend de préférence un dispositif de détection de la pression qui peut être utilisé pour envoyer à la surface des données de pression de fond de trou en temps réel. Un système d'injection de tube ascenseur est prévu pour injecter un fluide basse densité dans l'espace annulaire du tube ascenseur afin de réduire la densité des fluides dans l'espace annulaire du tube ascenseur et par conséquent, afin de réduire la pression hydrostatique à l'intérieur du puits de forage.
PCT/US2003/030490 2002-10-04 2003-09-29 Forage a double gradient dans lequel on utilise une injection d'azote WO2004033845A2 (fr)

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EP2469013A2 (fr) 2008-02-15 2012-06-27 Pilot Drilling Control Limited Soupape d'arrêt d'écoulement
WO2013116381A3 (fr) * 2012-01-31 2014-05-01 Weatherford/Lamb, Inc. Forage sous pression géré par double gradient
US9347286B2 (en) 2009-02-16 2016-05-24 Pilot Drilling Control Limited Flow stop valve
CN108561118A (zh) * 2012-07-20 2018-09-21 默林科技股份有限公司 地埋操作、系统、通信及相关装置和方法

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EP1637695A1 (fr) * 2000-09-22 2006-03-22 Weatherford/Lamb, Inc. Méthode et appareil pour la monitorisation et le contrôle à distance.
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