NO325188B1 - Procedure for liquid air in drill rigs - Google Patents

Description

Reference to related applications

This application claims priority from US Provisional Application No. 60/271,304 filed on February 23, 2001.

Field of the invention

The invention generally relates to offshore well drilling. More specifically, the invention relates to a method for offshore well drilling that uses low density liquid lift drill risers.

The reason for the invention

Exploration for crude oil and natural gas in deep and very deep waters has resulted in greater use of floating drilling vessels. These vessels can be anchored or dynamically positioned at the drilling site. Deepwater drilling typically involves the use of marine risers. A riser is formed by connecting sections with drill pipe or tubing. The riser is brought into position between the drilling vessel and the wellhead equipment located on the seabed and is used to control the drill pipe and the pipe to the wellhead, and to guide a drilling fluid and cuttings from the wellbore underwater back to the floating vessel. A drill string is enclosed by this riser.

The drill string comprises a drill assembly that carries a drill bit.

A suitable drilling fluid (commonly called drilling mud or mud) is supplied or pumped under pressure by the drilling vessel. This drilling mud is injected at the base of the drill bit. The mud lubricates and cools the drill bit and lifts cuttings out of the wellbore. In conventional offshore drilling, drilling mud is circulated down the drill string and up through an annulus between the drill string and the wellbore below the mud line (seabed) and from the mud line to the surface through the riser/drill string space. US 4,192,392 shows a system for removing solids (drilling cuttings) from a drilling fluid used when drilling a well. The cuttings are fed to a separation system to remove solids, and the solids-free drilling fluid is returned to the drill string.

Drilling mud is very important in the drilling process. It acts as: 1) a lubricant and heat transfer agent, 2) a means of transporting up and displacing parts of the formation cut by the bit, and 3) a fluid seal for important well control purposes. To maintain well control, drilling operators attempt to accurately control the mud density at the surface of the well to avoid many potential problems. A potential problem is lost circulation when a column of drilling mud exerts large hydrostatic pressure, which propagates a fracture in the formation. Formation fluids can unexpectedly enter the wellbore when the hydrostatic pressure falls below the formation pressure. Such an event is called "taking a kick". A blowout occurs when the formation fluid penetrates the wellbore in an uncontrolled manner. Both of these problems become even more difficult to remedy in deep water. In a convention

tional drilling system, the relative density of drilling mud above the seawater together with the length of the riser in deep water, combined with low overpressure results in additional hydrostatic pressure in the riser/drill string annulus and the wellbore/drill string annulus.

due to the small margins between the pore pressures (formation fluid pressure) and fracture pressure (leakage/lost circulation pressure), equivalent circulation density (ECD) is carefully controlled by balancing hole cleaning requirements and circulation rates. The wellbore is also shielded at frequent intervals to maintain well control.

A solution to these problems known in the art is dual-gradient drilling. Dual-gradient drilling is an area of technology that is primarily used to overcome the small pore pressure/fracture gradient margins found in abnormally pressured deepwater wells. As a possible technology, dual-gradient allows drilling in deep and ultra-deep water using fewer well pipe strings than is possible using conventional drilling systems. Because fewer well pipe strings are used, the potential for drilling dual-gradient wells is faster than conventionally drilled wells. Dual-gradient drilling can also improve extended-reach drilling by reducing the effect of circulation pressure loss on bottomhole pressure. Dual-gradient drilling can be used to drill a wellbore with a larger diameter at the bottom of the wellbore, which results in a lower pressure loss per unit length than with wellbores with a smaller diameter.

Different forms of dual-gradient drilling technology that have been developed include pump-lifted and gas-lifted drill risers. Pump-lift systems use pumps positioned close to the seabed to pump the heavy mud/drilling mud returned from the mudline to the drilling vessel to reduce the hydrostatic pressure at the mudline, usually to the resulting pressure from the seawater gradient. US patent 4,813,495 to Leach is illustrative of pump lift systems. This patent discloses a method and apparatus for drilling underwater wells in water depths greater than 3,000 feet (915 meters)

(preferably above 4,000 feet (1,220 meters)), where the returning drilling mud is taken at the seabed and pumped to the surface by means of a centrifugal pump driven by a seawater driven turbine. See also US Patent No. 4,149,603 to Arnold and published PCT application WO9915758. Limitations of the pump lift system include wear and equipment reliability for the subsea pumps and motors. The pump lift system's ability to handle loose and entrained gas is potentially very poor.

The gas lift system uses air or nitrogen to lift the drill return, effectively lowering the hydrostatic pressure in the riser to a seawater pressure gradient. For example, US Patent No. 4,099,583 to Maus discloses a method for offshore drilling and an apparatus that is useful for preventing formation fracturing caused by excessive hydrostatic pressure in the drilling fluid in a drill riser. One or more flowlines are used to draw the drilling fluid away from the upper part of the riser. Grass injected into the flowlines mainly reduces the density of the drilling fluid and helps provide the lift necessary to return the drilling fluid to the surface. The rate of gas injection and drilling fluid withdrawal can be controlled to maintain the hydrostatic pressure in the drilling fluid remaining in the riser and wellbore below the fractional pressure of the formation. See also US Patent No. 3,815,673 to Bruce et al, US 4,063,302 to Howell et al, and US Patent No. 4,091,881 to Maus. Limitations with the gas lift system include insufficient or ineffective cuttings transport, handling of pressurized equipment on board the drilling vessel, and detection of fluid inflow from the formation to the wellbore (kick detection).

Summary of the Invention

In general, the invention relates to a method for drilling a well under a body of water using a drill string that starts by injecting a liquid with a lower density than the density of the drilling mud into the well at a depth below the water surface. This produces a mixture of drilling mud and low-density fluid in the well. The low density fluid may be miscible or immiscible with the drilling mud. The mixture of drilling mud and low-density fluid is withdrawn from an upper end of the well. At least a portion of the low density fluid is separated from the mixture of drilling mud and low density fluid, with at least a portion of the separated low density fluid returned to the depth below the water surface and at least a portion of the drilling mud where the low density fluid has been removed is returned to an upper end of the drill string. The invention is further defined in claim 1.

An embodiment of the invention comprises controlling the injection rate of the liquid. First, the rate of fluid injection can be chosen so that the cuttings in the riser have an upward velocity that is greater than the sink rate of the cuttings in the riser. Second, the rate of fluid injected can be selected so that the fluid lift maintains a bottomhole pressure that is below the fractional pressure of the soil formation and above the pore pressure of the formation.

Other aspects and advantages of the invention will be apparent from the following description and the appended claims.

Brief description of the drawings

Figure 1 shows an offshore drilling system configured for dual-gradient riser drilling.

Figure 2 shows a liquid lifting system for drill risers according to an embodiment of the present invention. Figure 3 shows a mud processing in a liquid lifting system for drill risers according to an embodiment of the present invention. Figure 4 shows a flow diagram of miscible liquid lift in accordance with an embodiment of the present invention. Figure 5 shows a flow chart with immiscible liquid lift in accordance with an embodiment of the present invention.

Detailed description of the invention

Certain embodiments of the invention will now be described in detail with reference to the attached figures. Like elements in the different figures are designated by like reference numbers for the sake of consistency.

Figure 1 shows a type of offshore drilling system (10) where a drilling vessel (12) floats on a body of water (14) which lies above a predetermined soil formation (17A). A drilling rig (20) is positioned in the middle of the drilling vessel (12) above a moon pool (22). The Moon Pool

(22) is an opening with walls that extend through the drilling vessel (12) and through which drilling tools are lowered from the drilling vessel (12) to the seabed or mud line (17). At the mud line (17), a guide pipe (32) extends into the wellbore (30). A casing (33) is attached to the upper end of the casing (32). A guide structure (34) is installed around the casing (33) and next to a blowout preventer (38) before the casing (33) is fed to the mud line (17). A wellhead (35) is attached to the upper end of a casing (36) which extends through the guide pipe (32) and into the wellbore (30). The wellhead (35) has a conventional design and provides a device for hanging additional casing in the wellbore (30).

A riser system as shown in Figure 1 typically comprises one or more additional lines (well control lines 53 and boost line 68) on the outside of a riser (52). Well control lines (53) provide a high pressure conduit for fluid flow between a BOP (38) and a drilling rig (20). A boost line (68) supplies drilling fluid to the bottom of a riser (52) to improve cuttings removal.

A drill string (60) extends from a derrick (62) on the drilling rig (20) into the wellbore (30) through a riser (52) extending generally from the blowout preventer (38) back to the drilling vessel (12). A bottom hole assembly (63) is attached to the end of the drill string, which typically comprises a drill bit (64) and one or more drill collars (65). The downhole assembly (63) may also include stabilizers, mud motor and other selected components necessary to drill a wellbore (30) along a planned path, which is well known in the art. The end result is the formation of a well that extends from above the water surface to below the mudline (17) into the soil formation (17A). During conventional drilling operations, drilling mud is pumped down the bore to the drill string (60) by means of a surface pump (not shown) and is forced out of the nozzles (not shown) the drill bit (64) into the bottom of the wellbore (30). Drilling cuttings resulting from the drilling are swept into the mud at the bottom of the wellbore (30), and the drilling mud filled with drilling cuttings rises through the wellbore annulus (66) and into the riser/drill string annulus (54 in figure 3), and to the surface for treatment in the sludge treatment plant (not shown). The passage of the mud from the bottom of the wellbore to the surface of the water body can be referred to as the return flow system.

The present invention is not limited to a particular return flow system. In one embodiment, the return flow system may comprise a first annulus between the drill string (60) and the wall of the well bore (30), and a second annulus between the drill string (60) and the inner surface of the liner (36) positioned in the well bore, and a third annulus between the drill string (60) and the riser (52) extending between the lined wellbore and the surface of the body of water (14).

A fluid lift drill riser system, as shown in Figure 2, uses a lightweight, miscible or immiscible fluid to reduce the density of the drilling mud to as low as that of seawater. A surface pump (not shown) pumps a low density fluid (74) through a riser boost line (68). The low-density liquid (74) is led to the riser (52) approximately at the sludge line (17) via the riser boost line (68). During normal drilling, the low-density fluid (74) will mix with the high-density mud (76) that returns from the bottom of the well. This mixture (80) will return to the surface and flow over vibrating screens (not shown). Once through the vibrating screens (not shown), the mixture (80) will be separated and processed into its original low density liquid (74) and high density slurry (76). The high density mud (76, preferably substantially all high density mud that has been cleaned of low density fluid (21)) will again be pumped down the drill string (60) and the low density fluid (74, preferably substantially all of the separated low density fluid (74)) will again be pumped down the riser boost line (68) back to the bottom of the riser (52). Adequate separation provides a closed circuit system with low fluid losses.

Fig. 3 shows an alternative structure for a liquid lift drilling system. A lightweight, miscible or immiscible fluid is used to reduce the density of drilling mud to as low as that of seawater. A surface pump (not shown) pumps a low density fluid (74) through a fluid injection line (72). The low density fluid (74) is directed to a position below the mud line (17) via a parasitic string (71) installed in the lined wellbore (37). The parasite string thus places the low density fluid (74) in an annulus between the drill string (60) and the inner wall of the casing (36). During normal drilling, the low-density fluid (74) will mix with the high-density mud (76) that returns from the bottom of the well. This mixture (80) will return to the surface and flow over vibrating screens (not shown). Once through the vibrating screens (not shown), the mixture (80) will be substantially separated and processed into its original low density liquid (74) and high density slurry (76). The high-density mud (76) will again be pumped down the drill string and the low-density fluid will again be pumped down the fluid injection line (72) through the parasitic string (71) to the lined wellbore (37).

In one embodiment, a miscible fluid lift system uses a miscible fluid such as seawater to be injected into water-based sludge. To lift a water-based drilling mud, seawater is injected into the riser boost line (68) to thin the mud, effectively reducing mud density (weight). Part of the return fluid is removed at the surface, and the water-based drilling mud is rebuilt with additives necessary to restore the desired mud weight.

To lift a heavy mud, or if the drilling is done with a synthetic or oil-based mud, it does not have to be economically or environmentally acceptable to dispose of diluted mud at the surface. In such a case, the miscible liquid lift system may comprise a base fluid common to both low density liquid (74) and high density slurry (76). The high-density mud (76) generally comprises barite, hematite and/or other suitable weighting components, and is led down the drill string (60) as previously explained. The low-density liquid (74) may comprise one or more density-reducing additives such as low-density particulate materials, including, for example, hollow glass beads/microspheres or other density-reducing additives. As previously explained, the low-density fluid (74) is led to the riser (52) at the mudline (17) via the riser boost line (68) in Figure 2, or is led into the wellbore (37) in Figure 3 via a parasitic string (71) in Figure 3. The fluid mixture ( 80) which is returned up to the riser (52) contains both weighting additives and weight-reducing additives if they are present.

With reference to Figure 4, drill cuttings are removed from the return fluid mixture (80) using one or more standard cuttings management devices (116). The resulting fluid (82) is then transported to one or more separation devices (112) such as mechanical separators, gravity separators, centrifuges or similar equipment. The one or more separation devices (112) separate the fluid (82) into low-density liquid (74) and heavy additives (114). The low-density fluid (74) is transferred to mud storage (110) before being directed into the riser annulus (54) in Figure 2 above the BOP (38 in Figure 2) or into the wellbore annulus (37 in Figure 3) below the mud line (17 in Figure 3) . The high-density sludge (76) is reformulated at (106) by combining the heavier additives (114) and a portion (83) of untreated fluid (82). The reformulated high-density mud (76) can then be moved to the mud storage (111) for temporary storage before it is led into the wellbore (30, figure 2). The miscible fluid lifting system can be used for any type of drilling fluid, and this embodiment of the fluid lifting system can be used to drill part or all of the well.

Another embodiment is an immiscible liquid foam system. With reference to Figure 5, an immiscible system uses a low density boost fluid (74) which is substantially immiscible with the high density mud (76) to facilitate the returning drilling fluid. An example of this is drilling with a weighted water-based mud and boosting with a lightweight, immiscible synthetic fluid such as ester, olefin or glycol. The low-density fluid (74) is introduced into the return drilling fluid at the base of the riser (52 in figure 2) or down the fluid injection string (72 in figure 3) or both at the base of the riser (52 in figure 2) and down the injection string (72 in figure 3) at the same time. The resulting fluid (80) is a stable two-phase fluid with a lower density than the sludge (76). With reference to Figure 5, one or more conventional separation devices (81), such as a three-phase centrifuge, can be used to separate the fluid mixture (80) on the drilling vessel (12 in Figure 1), where the fluids (74, 76) can be recycled. First, the fluid mixture (80) may be processed using standard solids control equipment (120), such as vibrating screens, to remove some or substantially all of the drill solids. Next, the resulting fluid (82) is separated in an oil-water separator (81), such as a three-phase centrifuge, to produce drilling solids (86), low-density fluid (74), and drilling fluid (122). The drilling solids (86) can be removed in any environmentally friendly way. The low-density liquid (74) can be removed to sludge storage

(110) for temporary storage. The drilling fluid (122) in this embodiment may pass through additional standard solids control devices (116) and then be transferred to the mud storages (111) for temporary storage as high density mud (76).

Another embodiment of the liquid lift system uses a combination of fluid such as low density glass droplets (or a density reducing agent) in a miscible low density liquid slurry. By using miscible low-density fluid slurries instead of non-slurry low-density fluid, the volume of low-density fluid required to produce a significant sludge weight change in the riser (52 in Figure 2) can be reduced. The density reducing agent can be recovered at the surface before the excess fluid volume is disposed of. The result is a stable homogeneous fluid with a lower density than the mud that is pumped down the drill string (60 Figure 1).

With reference to Figure 2, controlling the rate of the low density fluid (74) which is injected into the riser (52) at or near the mud line (17) via the riser boost line (68), or directed into the lined wellbore (37 in Figure 3) via the fluid injection string (72 in Figure 3) serves two primary purposes in the fluid lift system. First, the rate of injected fluid can be controlled so that the cuttings in the riser annulus space (54) have an upward velocity beyond the sink rate of the drill cuttings in the riser (52). Second, the rate of low density fluid (74) injected can be controlled to maintain a bottom hole pressure that is below the fractional pressure of the soil formation and above the pore pressure of the formation.

The liquid lift system has several advantages compared to pump lift and gas lift systems. The fluid lift system can use conventional solids control equipment and rig pumps to produce a simpler, more reliable dual gradient drilling system than a pump lift system. Cuttings transport is conventional. Kick detection is conventional, circulation can be stopped (remain static) without further consequences and there is little or no additional subsea equipment to break down, thus not requiring a riser trip to repair.

The fluid lift system also allows the well to change from dual gradient to conventional single gradient simply by stopping injection of the low density boost fluid to the riser (52 in Figure 2). The liquid lift system also allows for additional injection/lift points beyond just the mud line. The use of a parasitic string (71 in Figure 3) to inject lift fluid (17 in Figure 3) increases the efficiency of the fluid lift system and makes it possible to use dual gradient drilling in shallow water or on land. In addition, the volume of lift fluid required to create lift in the riser (52 in Figure 3) can be reduced by using the parasitic string to inject the lift fluid below the mudline (17 in Figure 3).

Because the invention has been described with respect to a limited number of embodiments, one skilled in the art will recognize that other embodiments may be provided which do not depart from the intent of the invention as shown. Accordingly, the scope of the invention should be limited only by the appended claims.

Claims (19)

1. Method for treating a drilling fluid (76) used when drilling a well bore (30) in a soil formation (17) under a body of water, where a drill string (60) extends from a drilling facility (12) on the water surface (14) into in the well bore (30), and the drilling fluid (76) passes through the drill string (60) and flows from the drill string into the well bore (30), whereby cuttings from the drilling are swept along in the drilling fluid and the drilling fluid with the entrained cuttings is returned to the surface (14) of the water body by means of a return flow system (54), comprising the steps of separate at least a part of the entrained cuttings from the drilling fluid to give a drilling fluid with a greatly reduced cuttings content, and return at least a part of the drilling fluid with a reduced cuttings content to the drill string (60) for reuse when drilling the wellbore, characterized by the step of : a) injecting a fluid (74) with a density less than the density of the drilling fluid (76) into the return flow system (54) at a depth below the surface of the water body, thereby producing a mixture (80) of drilling fluid and low density fluid in a return flow system, b) withdrawing the mixture of drilling fluid (76) and low density fluid (74) from an upper end of the return flow system (54), c) separating at least a portion of the low density fluid (74) from the mixture of drilling fluid and low density fluid, and d) returning at least a portion of the separated low density fluid (74) to the return flow system (54) to the depth below the water surface. 2. Method according to claim 1, where the low-density liquid (74) is not miscible with the drilling fluid (76). 3. Method according to claim 2, where the drilling fluid (76) is water-based and the low-density fluid (74) is at least one of an oil-based, synthetic or non-aqueous fluid. 4. Method according to claim 2, where the low-density liquid (74) comprises density-reducing particulate material. 5. Method according to claim 1, where the low-density liquid (74) is miscible with the drilling fluid (76). 6. Method according to claim 1, where the separation comprises: at least one of the processes mechanical separation, gravitational separation and centrifugal separation. 7. Method according to claim 1, further comprising: control of a rate of the liquid injection so that a bottomhole pressure in the well (30) is below a fractional pressure of the soil formation, and above a pore pressure in the formation. 8. Method according to claim 1, further comprising: control of a rate of liquid injection into the lower end of the riser so that the cuttings in the return flow system (54) have an upward velocity beyond the sink rate of the cuttings in the system (54). 9. Method according to claim 1, where the low-density liquid (74) comprises density-reducing particulate material. 10. Method according to claim 1, further comprising: stopping the injection of the low-density fluid (74) into the well (30) at a depth below the water surface (14) to switch from dual-gradient drilling to conventional drilling. 11. Method according to claim 1, where substantially all separated low density fluid (74) is returned to the depth below the water surface (14), and substantially all separated drilling fluid (76) is returned to the upper end of the drill string (60) in a closed system (54) . 12. Method according to claim 1, where the depth below the water surface is between the drill string and the wellbore at a position below a wellhead. 13. Method according to claim 1, where the depth below the water surface is at a lower end of a riser (52) which extends from the drilling facility (12) on the surface (14) of the sea down to the wellhead (38) on the seabed (17). 14. Method according to claim 1, where the low-density fluid (74) is injected via a parasitic string (72) into an annulus between the drill string (60) and a casing inner wall (37) at a position below a wellhead (38). 15. Method according to claim 1, where the low density fluid (74) is injected into a lower end of a riser (52) which extends from a drilling vessel (12) on the surface (14) of the body of water down to a wellhead (38) on the bottom of the water body. 16. Method according to claim 9, where the particulate material comprises low-density glass droplets. 17. Method according to claim 9, where the particulate material comprises low-density microspheres. 18. Method according to claim 1, where the return flow system comprises a first annulus between the drill string (60) and the wall of the well bore (30), and a second annulus (54) between the drill string (60) and the inner wall of a liner (37) positioned in the well bore , and a third annulus (54) between the drill string (60) and a riser (52) extending between the lined wellbore and the surface (14) of the body of water, where the return of the separated low density fluid (74) in step (d) is to the annulus at the lower end of the third annulus. 19. Method according to claim 1, where the return flow system comprises a first annulus between the drill string (60) and the wall of the well bore (30), a second annulus between the drill string (60) and the inner wall of a liner (37) positioned in the well bore, and a third annulus (54) between the drill string (60) and a riser (52) extending between the lined wellbore and the surface (14) of the body of water, where the return of the separated low density fluid (74) in step (d) is to the second ring room.