The invention relates generally to offshore drilling systems. More particularly, the invention relates to a dual-gradient offshore drilling system using low-density liquid lift for drilling risers.
The search for crude oil and natural gas in deep and ultra-deep water has resulted in greater use of floating drilling vessels. These vessels may be moored or dynamically-positioned at the drill site. Deep water drilling typically involves the use of marine risers. A riser is formed by joining sections of casing or pipe. The riser is deployed between the drilling vessel and wellhead equipment located on the sea floor and it is used to guide drill pipe and tubing to the wellhead and to conduct a drilling fluid and earth-cuttings from a subsea wellbore back to the floating vessel. A drill string is enclosed within the riser pipe. The drill string includes a drilling assembly that carries a drill bit.
A suitable drilling fluid (commonly called “drilling mud” or “mud”) is supplied or pumped under pressure from the drilling vessel. This drilling mud discharges at the bottom of the drill bit. Mud lubricates and cools the bit, and lifts drill 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 mudline (sea floor), and from the mudline to the surface through the riser/drill string annulus.
Drilling mud is very important in the drilling process. It serves as: (1) a lubrication and heat transfer agent; (2) a medium to carry away and dislodge pieces of the formation cut by the drill bit; and (3) a fluid seal for crucial well control purposes. To maintain well control, drilling operators attempt to carefully control the mud density at the surface of the well to avoid many potential problems. One potential problem is “lost circulation” when a column of drilling mud exerts excess hydrostatic pressure, which propagates a fracture in the formation. Formation fluids may enter the wellbore unexpectedly when the hydrostatic pressure falls below the formation pressure. Such an event is called “taking a kick.” A blowout occurs when the formation fluid enters the wellbore in an uncontrolled manner. Both of these problems become even more difficult to overcome in deep water. In a conventional drilling system, the relative density of the drilling mud over that of the seawater, along the length of the riser in deep water, combined with a low overburden pressure, results in excess hydrostatic pressure in the riser/drill string annulus and the wellbore/drill string annulus.
Because of the narrow margins between pore pressure (formation fluid pressure) and fracture pressures (leak-off/lost circulation pressures), equivalent circulating density (ECD) is tightly controlled by balancing hole cleaning requirements and circulation rates. The wellbore is also cased off at frequent intervals to maintain well control.
One 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 narrow pore pressure/fracture gradient margins found in abnormally pressured, ultra-deepwater wells. As an enabling technology, dual-gradient drilling permits drilling in deep and ultra deep water using fewer casing strings than possible using conventional drilling systems. Because there are fewer casing strings used, there is potential for drilling dual-gradient wells faster than conventionally drilled wells. Dual-gradient drilling can also enhance extended-reach drilling by reducing the influence of circulating pressure losses on bottom-hole pressure. Dual-gradient drilling can be used to drill a wellbore with a larger diameter hole at the bottom of the wellbore, resulting in lower pressure drop per unit length than a smaller diameter wellbore.
Forms of dual-gradient drilling technology being developed include pump-lifted and gas-lifted drilling risers. Pump-lift systems use pumps positioned near the sea floor to pump the heavy mud/drilling returns from the mud line to the drilling vessel to reduce the hydrostatic pressure at the mud line, generally to that which would result from a sea water gradient. Illustrative of the pump-lift systems is U.S. Pat. No. 4,813,495 to Leach that discloses a method and apparatus for drilling subsea wells in water depths exceeding 3000 feet (915 meters) (preferably exceeding 4000 feet (1220 meters)) where drilling mud returns are taken at the seafloor and pumped to the surface by a centrifugal pump that is powered by a seawater driven turbine. See also U.S. Pat. No. 4,149,603 to Arnold and published PCT application WO9915758. Limitations with the pump-lift systems include wear and equipment reliability for the subsea pumps and motors. Also, the ability of the pump-lift system to handle dissolved and entrained gas is potentially very poor.
Gas-lift systems use air or nitrogen to “lift” the drilling returns, effectively lowering the riser hydrostatic pressure to a seawater pressure gradient. For example, U.S. Pat. No. 4,099,583 to Maus discloses an offshore drilling method and apparatus which are useful in preventing formation fracture caused by excessive hydrostatic pressure of the drilling fluid in a drilling riser. One or more flow lines are used to withdraw drilling fluid from the upper portion of the riser pipe. Gas injected into the flow lines substantially 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 of the drilling fluid remaining in the riser and wellbore below the fracture pressure of the formation. See also U.S. Pat. No. 3,815,673 to Bruce, et al., U.S. Pat. No. 4,063,602 to Howell, et al. and U.S. Pat. No. 4,091,881 to Maus. Limitations with the gas-lift system include inefficient or ineffective cuttings transport, dealing with pressurized equipment on the drilling vessel, and detection of fluid influx from the formation to the well bore (kick detection).
Generally, the invention is a method of drilling a well below a body of water using a drill string that starts by injecting into the well, at a depth below the water surface, a liquid having a lower density than a density of a drilling mud. This produces a mixture of drilling mud and low-density liquid in the well. The low-density liquid may be miscible or immiscible with the drilling mud. The mixture of drilling mud and low-density liquid is withdrawn from an upper end of the well. At least a portion of the low-density liquid is separated from the mixture of drilling mud and low-density liquid, with at least a portion of the separated low-density liquid returned to the depth below the water surface and at least a portion of the drilling mud depleted of low-density liquid being returned to an upper end of the drill string.
An embodiment of the invention includes controlling the injection rate of the liquid. First, the rate of the liquid injected can be selected so the cuttings within the riser pipe have an upward velocity in excess of the settling rate of the cuttings in the riser pipe. Secondly, the rate of the liquid injected can be selected so the liquid lift maintains a bottom-hole pressure that is below the fracture pressure of the earth 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.
Specific embodiments of the invention will now be described in detail with reference to the accompanying figures. Like elements in the various figures are denoted by like reference numerals for consistency.
A riser system like the one depicted in
A drill string 60 extends from a derrick 62 on the drilling rig 20 into the wellbore 30 through a riser 52 which extends generally from the blowout preventor 38 back to the drilling vessel 12. Attached to the end of the drill string 60 is a bottom hole assembly 63, which typically includes a drill bit 64 and one or more drill collars 65. The bottom hole assembly 63 may also include stabilizers, mud motor, and other elected components required to drill a wellbore 30 along a planned trajectory, as is well known in the art. The end result is the creation of a well that extends from above the water surface to below the mudline 17 into the earth formation 17A. During conventional drilling operations, drilling mud is pumped down the bore of the drill string 60 by a surface pump (not shown) and is forced out of the nozzles (not shown) of the drill bit 64 into the bottom of the wellbore 30. Cuttings resulting from the drilling become entrained in the mud at the bottom of the wellbore 30 and the mud laden with cuttings rises up the wellbore annulus 66 and into the riser/drill string annulus (54 in
The present invention is not limited to any particular return flow system. In one embodiment, the return flow system may comprise a first annular space between the drill string 60 and the wall of the wellbore 30, and a second annular space between the drill string 60 and the inner surface of casing 36 positioned in the wellbore, and a third annular space between the drill string 60 and the riser 52 extending between the cased wellbore and the surface of the body of water 14.
A liquid-lift drilling riser system, as shown in
In one embodiment, a miscible liquid-lift system uses a miscible liquid such as seawater to be injected into a water-based mud. For lifting a water-based drilling mud, seawater is injected into the riser boost line 68 to dilute the mud, effectively reducing mud density (weight). A portion of a return fluid is discarded at surface, and the water-based drilling mud is rebuilt with necessary additives needed to regain the desired mud weight.
For lifting a weighted mud, or if drilling with a synthetic or an oil-based mud, it may not be economical or environmentally acceptable to discard diluted drilling mud at surface. In such a case, the miscible liquid-lift system can comprise a base fluid common to both the low-density liquid 74 and the high-density mud 76. The high-density mud 76 generally contains barite, hematite and/or other suitable weighting agents and is directed down the drill string 60 as previously explained. The low-density liquid 74 may contain one or more density-reducing agents, such as low-density particulate materials, including, for example, hollow glass beads/microspheres or other density-reducing additive. As previously explained, the low-density liquid 74 is directed to the riser 52 at the mud line 17 via the riser boost line (68 in
Referring to
Another embodiment is an immiscible liquid-lift system. Referring to
Another embodiment of the liquid lift system uses a combination fluid, such as low-density glass beads (or a density-reducing agent) in a miscible low-density liquid slurry. By using miscible low-density liquid slurry instead of the low-density mud without the slurry, the volume of low-density liquid needed for producing a significant mud weight change in the riser (52 in
Referring to
The liquid-lift system has several advantages over pump-lift and gas-lift systems. The liquid-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 adverse consequences, and there is little or no additional subsea equipment to break down, thereby creating a need for a riser trip to repair.
The liquid-lift system also allows the switching of drilling from dual-gradient to conventional, single-gradient merely by ceasing the injection of the low-density boost fluid to the riser (52 in
While the invention has been described with respect to a limited number of embodiments, those skilled in the art will appreciate that other embodiments can be devised which do not depart from the scope of the invention as disclosed herein. Accordingly, the scope of the invention should be limited only by the attached claims.
This application is a continuation of application Ser. No. 10/081,054, filed on Feb. 21, 2002 which claims the benefit of U.S. Provisional Application No. 60/271,304 filed on Feb. 23, 2001.
Number | Date | Country | |
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60271304 | Feb 2001 | US |
Number | Date | Country | |
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Parent | 10081054 | Feb 2002 | US |
Child | 10912467 | Aug 2004 | US |