This disclosure relates to the field of drilling extended reach lateral wellbores in formations below the bottom of a body of water. More specifically, the invention relates to drilling such wellbores where a sub-bottom depth of a target formation is too shallow for conventional directional drilling techniques to orient the wellbore trajectory laterally in the target formation.
Lateral wellbores are drilled through certain subsurface formations for the purpose of exposing a relatively large area of such formations to a well for extracting fluid therefrom, while at the same time reducing the number of wellbores needed to obtain a certain amount of produced fluid from the formation and reducing the surface area needed to drill wellbores to such subsurface formations.
Lateral wellbore drilling apparatus known in the art include, for example and without limitation, conventional drilling using segmented drill pipe supported by a drilling unit or “rig”, coiled tubing having a drilling motor at an end thereof and various forms of directional drilling apparatus including rotary steerable directional drilling systems and so called “steerable” drilling motors. In drilling such lateral wellbores, a substantially vertical “pilot” wellbore may be drilled at a selected geodetic position proximate the formation of interest, and any known directional drilling method and/or apparatus may be used to change the trajectory of the wellbore to approximately the geologic structural direction of the formation. When the wellbore trajectory is so adjusted, drilling along the geologic structural direction of the formation may continue either for a selected lateral distance from the pilot wellbore or until the functional limit of the drilling apparatus and/or method is reached. It is known in the art to drill multiple lateral wellbores from a single pilot wellbore to reduce the number of and the cost of the pilot wellbores and to reduce the surface area needed for pilot wellbores so as to reduce environmental impact of wellbore drilling on the surface.
Some formations requiring lateral wellbores are at relatively shallow depth below the ground surface or the bottom of a body of water. In such cases using conventional directional drilling techniques may be inadequate to drill a lateral wellbore because of the relatively limited depth range through which the wellbore trajectory may be turned from vertical to the dip (horizontal or nearly so) of the formation of interest.
Example methods and apparatus described herein are related to drilling wells below the bottom of a body of water such as a lake or the ocean, using a water-bottom located template onto which a wellhead and injector assembly is mounted at an angle inclined from vertical. An inclined wellhead and injector assembly enables reaching a horizontal (lateral) trajectory at relatively shallow sub-bottom depths, for example, for exploiting hydrocarbon reservoirs that are located very shallow below the seafloor. There are a number of geographic locations worldwide where such drilling technique is relevant, where ordinary vertical entry drilling methods are inadequate to drill a horizontal wellbore due to the need for longer distance to reorient the wellbore from vertical to horizontal. In addition, the deployment of wellbore devices, for example, electrical submersible pumps that have a substantial length and outer diameter to achieve required fluid lift rates can be impractical if a wellbore build angle is too steep. invention system and method as described herein alleviates that problem by substantially reducing the wellbore deviation build rate (or “dog leg severity”).
Also described herein is a dual injector head system, where the lower injector is primarily for inserting a drill string into the wellbore, while the upper injector is primarily for retrieving a drill string from the wellbore. The drill string can be based on jointed drill pipe, a spoolable rod, a spoolable tube (like for example coiled tubing) or similar.
The upper injector assembly 14 may comprise a housing 24 having a suitably shaped entry guide 24A to facilitate entry of a well intervention assembly 20 into the wellbore. The housing 24 may comprise internally an upper pipe injector 28 of types well known in the art. A wiper 26 may be disposed above the upper pipe injector 28 so that any contamination on the exterior of the well intervention assembly 20 is removed before the well intervention assembly leaves the upper injector assembly 14 and is exposed to the surrounding water. Upper 30 and lower 32 stuffing box seals may be provided below the upper pipe injector 28 so that wellbore fluids cannot escape as the well intervention assembly is moved into and out of the wellbore 63. A lower wiper 26 may be disposed below the lower stuffing box seal 32 to prevent contaminants from entering the wellbore 63 as the wellbore intervention assembly 20 is moved into the wellbore 63.
The lower injector assembly 12 may also be supported by the frame 14A. The lower injector assembly 12 may include a lower pipe injector 17, a lower wiper 18 below the lower pipe injector 17 and blowout preventer elements, e.g., pipe rams 16A, shear rams 16B and blind rams 16C as may be found in conventional blowout preventers (BOPs). Operation of the lower pipe injector 17 and the respective rams 16A, 16B, 16C may be performed by a control module 17A. The control module 17A may comprise any form of BOP operating telemetry system known in the art, or may be connected to a vessel on the surface (
The upper 28 and lower 17 pipe injectors may be activated individually or simultaneously to push or pull, as the case may be, an umbilical cable, semi-stiff spoolable rod, coiled tubing or jointed pipe. Two simultaneously operated pipe injectors 28, 17 may be integrated for deployment into, and retrieval of a well intervention tool assembly from the wellbore 63.
The pipe injectors 28, 17 in the present embodiment may be integrated into a lubricator and BOP system, in contrast with coiled tubing injector apparatus known in the art where there would be one only pipe injector located externally of the lubricator. Having the injector located “externally” in the present context means that the intervention umbilical, rod, coiled tubing and the like must be pushed through seals that are normally exposed to a much higher pressure within the wellbore than the ambient pressure outside the wellbore. The differential pressure may result in more wear on seals and the intervention umbilical, rod or coiled tubing. More clamping force may also be required by the injector not to slip on the intervention umbilical, rod or coiled tubing. Thus, placement of the injectors inside the wellbore pressure containment system may reduce clamping forces required by the injectors and may reduce wear on the tubing and seals.
The principle of operation of the system 10 is based on placing the upper pipe injector 28 that is used for pulling the wellbore intervention tool assembly out of the wellbore 63 at a location above the wellbore pressure seals, i.e., the stuffing box seals 30, 32 and the BOP rams 16A, 16B, 16C. The lower pipe injector 17 may be used to urge the wellbore intervention tool assembly into the well and may be located below the above described wellbore pressure seals, where the lower pipe injector 17 pulls the umbilical, rod or coiled tubing through the wellbore pressure seals and pushes the umbilical, rod or tubing into the wellbore with no friction increasing seals located below the lower pipe injector 17. Both the upper 28 and lower 17 pipe injectors can be used simultaneously for increased efficiency and speed, if required.
Although the above description is made in terms of a drilling method based on a spoolable umbilical, rod or coiled tubing, it should be understood that also jointed pipes or tubing may be utilized in other embodiments.
Wellheads of types known in the art can be utilized, but will be installed on the subsea template at an angle as illustrated in
For those skilled in the art of offshore drilling, it will be appreciated that an alternative to jetting the conductor pipe 60 as illustrated, is that the conductor pipe 60 can be drilled into the seabed with a motor placed on top of the conductor or coupled to the exterior of the conductor. Also a jet drilling system can be deployed into the lower end of the conductor pipe 60, where such jet drilling system is retrieved after conductor has been placed to the required depth.
Another method for setting the conductor pipe 60 is to hammer the conductor pipe 60 into the sub-bottom, which is common for vertical conductor installations. For both the latter methods, the support system 50 may hold the conductor pipe 60 at the required angle during the hammering procedure.
1.
The wellhead will be mounted on the upper end of the surface casing. The wellhead may be landed onto the conductor pipe, whereafter the BOP can be connected to the wellhead when required.
Using a system as shown in
Possible benefits of a system and method according to the present disclosure may include any one or more of the following:
a) placing a wellhead at an angle under water to enable drilling horizontal wells in shallow sub-bottom formations;
b) placing a BOP and/or lubricator and seal stack system at an angle deviating from vertical on a subsea template;
c) jetting in a conductor pipe at an angle. Alternatively, drilling the conductor in by a motor connector to the conductor;
d) placing a lubricator and a seal stack system deviating from vertical on a subsea wellhead;
e) using an injector built into a pressure containing housing, where injector will be exposed to wellbore fluids and pressure;
f) using an injector located on the elevated pressure side of a sealing system preventing wellbore fluids from escaping to the outside environment;
g) combining two injectors, where one is primarily for inserting a drill string into the wellbore, while the other is primarily for retrieving a drill string from a wellbore.
h) combining two injectors, where both can be simultaneously operated at same speed to insert or retrieve a drill string from a wellbore;
i) combining two injectors, where each of these can be adjusted according to the outer diameter (OD) of an object passing through the injectors, so that a tool system can be inserted or retrieved from the lubricator while pushing in or pulling out by the injectors. An example can be that a bottom hole tool assembly is pushed in by the upper injector against the drilling umbilical, coil or drill pile with the lower injector not engaging the bottom hole tool assembly. Thereafter, as soon as the bottom hole assembly has passed through the lower injector, the lower injector is engaged towards the drill string (coil, umbilical or drill pipe) driving this string into the wellbore, while the upper injector are no longer responsible for pushing the string into the wellbore;
j) using a wiper seal to remove wellbore clay and the like from the drill string, before the drill string protrudes through the main seals in a BOP system.
k) using a wiper seal to remove wellbore clay and the like from the drill string, before the drill string protrude through the main seals in a lubricator stuffing box system;
l) providing capability to change out wellbore fluids with clean sea water in a lubricator prior to opening an upper stuffing box to insert or retrieve wellbore intervention tools or tool strings. This can be achieved by pumping in seawater and taking discharge to the surface for cleaning;
m) using an adjustable support system to guide and support weight of components engaging onto and landing into a seabed template;
n) using a sea bed lubricator system with a sealing system on a top end thereof, where a well intervention tool assembly on a pipe or pipe string can be inserted or retrieved in a safe manner without the need for a riser to surface. The foregoing is performed by individually closing and opening the upper or lower sealing system as well as displacing wellbore fluids with clean seawater prior to retrieval of the wellbore intervention tool assembly through the upper seal system;
o) mounting a drillable (for example manufactured in a material easy to drill out after use, or a material that will gradually dissolve by time by being exposed to certain fluids, like for example sea water) drilling system on the lower end of a conductor, where the drilling system is powered by fluid pumped from the surface or from a subsurface located pumping system;
p) deploying a drill string from a surface semisubmersible drilling rig or vessel, where the drill string enters a sea bed wellbore at an angle higher than 10 degrees from vertical;
q) increasing axial force (“weight on bit”) on a subsurface drill string, by using one or two injectors integrated in a sea bed located BOP and/or lubricator system.
r) replaceable modules that can be mounted on hydraulic jacks, where such modules can perform tasks as lifting, guiding, rotating, etc.
s) increasing length of external sealing, by e.g. cement, of casing strings by placing wellbore at an angle instead of vertical, which is critical with respect to very shallow reservoirs
t) introducing a submerged “goose neck” system to support and guide a drill string deployed from a surface vessel or drilling rig
While the invention has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, 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.
Filing Document | Filing Date | Country | Kind |
---|---|---|---|
PCT/US2015/059804 | 11/10/2015 | WO | 00 |
Number | Date | Country | |
---|---|---|---|
62081195 | Nov 2014 | US |