WO2014176601A1

WO2014176601A1 - Offshore drilling unit having drill cuttings storage for an entire wellbore

Info

Publication number: WO2014176601A1
Application number: PCT/US2014/035738
Authority: WO
Inventors: Joe M. SHERWOOD
Original assignee: MI LLC
Current assignee: MI LLC
Priority date: 2013-04-26
Filing date: 2014-04-28
Publication date: 2014-10-30
Anticipated expiration: 2015-10-26

Abstract

A method for processing drill cuttings returned to a mobile offshore drilling unit wherein the cuttings are disposed in drilling mud pumped through a drill string used to drill a wellbore includes separating the drill cuttings from the returned drilling mud. The method includes moving the separated cuttings to a storage area having sufficient capacity to hold separated cuttings resulting from drilling the entire wellbore.

Description

OFFSHORE DRILLING UNIT HAVING DRILL CUTTINGS STORAGE FOR

AN ENTIRE WELLBORE

Background

[0001] This application claims the benefit of U.S. Provisional Application No. 61/816555 filed on April 26, 2013, which is incorporated by reference herein in their entirety.

[0002] This disclosure relates generally to the field of mobile offshore drilling units.

More specifically, the disclosure relates to processing of drill cuttings returned from a well during the drilling process.

[0003] Offshore drilling units are used to drill wells through formations below the bottom of a body of water such as a lake or ocean. Several configurations of offshore drilling units are known in the art, including floating drilling units such as drillships and semisubmersible drilling units, and bottom supported drilling units such as "jackups." See, for example, U.S. Patent No. 7,886,845 issued to King et al.

[0004] Drilling operations from offshore drilling units may include extending a conduit called a "riser" from the drilling unit to a lower marine riser package (LMRP) coupled to a pressure control system (blowout preventer - "BOP" stack) coupled proximate the water bottom to the first full wellbore casing cemented in place in the wellbore. Drilling fluid ("drilling mud") is pumped through a drill string extended into a wellbore and exits through courses or nozzles in the drill bit at the bottom of the wellbore. The exiting drilling mud cools and lubricates the drill bit, facilitates drilling the formations and lifts drill cuttings up the riser or other return line (e.g., in subsea mudlift drilling systems; see., e.g., U.S. Patent No. 6,415,877 issued to Fincher et al) to the offshore drilling unit

[0005] When the drilling mud with entrained drill cuttings is returned to the offshore drilling unit, the cuttings and gas may be removed by treatment equipment known in the art. To reduce the environmental impact of drilling operations, it is desirable to have the drill cuttings removed from the drilling location for processing to remove any residual components of the drilling mud therefrom for safe disposal. Brief Description of the Drawings

[0006] FIG. 1 shows an example of drilling a wellbore through subsurface formations and an apparatus therefor.

[0007] FIG. 2 shows an example floating drilling platform that may be used for the apparatus shown in FIG. 1 to drill formations below the bottom of a body of water.

[0008] FIG. 3 shows an example return fluid processing system according to one example.

[0009] FIG. 4 shows an example cuttings storage room including a selected number of

ISO pumps for cuttings storage.

[0010] FIG. 5 shows a sectional view of a drill ship including a storage cuttings room as in FIG. 2.

[0011] FIG. 6 shows an example shaker system for solids removal from the returned drilling fluid.

[0012] FIG. 7 shows an example drain used with the shaker system of FIG. 4.

Detailed Description

[0013] An example of a drilling system drilling a wellbore through subsurface rock formations is shown schematically in FIG. 1. The drilling system shown in FIG. 1 is only meant to serve as an example of a drilling system for purposes of explaining devices that may ultimately be placed on a mobile offshore drilling unit for processing drilling fluid returning from such a wellbore as a result of drilling and related operations as will be explained with reference to FIGS. 3 through 7. The example drilling system shown in FIG. 1 is not a limit on the scope of the present disclosure.

[0014] The drilling system 100 may include a hoisting device known as a drilling rig 102 that is used to support drilling operations through subsurface rock formations such as shown at 104. Many of the components used on the drilling rig 102, such as a Kelly (or top drive), power tongs, slips, draw works and other equipment are not shown for clarity of the illustration. A wellbore 106 is shown being drilled through the rock formations 104. As will be further explained below, such formations may be below the bottom of a body of water. A drill string 112 is suspended from the drilling rig 102 and extends into a wellbore 106, thereby forming an annular space (annulus) 115 between the wellbore wall and the drill string 112, and/or between a casing 101 (when included in the wellbore 106) and the drill string 112. One of the functions of the drill string 112 is to convey a drilling fluid 150 (shown in a storage tank or pit 136) to the bottom of the wellbore 106 and into the wellbore annulus 115.

[0015] The drill string 112 may support a bottom hole assembly ("BHA") 113 proximate the lower end thereof that includes a drill bit 120, and may include an hydraulically operated "mud" motor 118, a sensor package 119, and a check valve (not shown) to prevent backflow of drilling fluid from the annulus 115 into the drill string 112. The sensor package 119 may be, for example, a measurement while drilling and logging while drilling (MWD/LWD) sensor system. The BHA 113 shown in FIG. 1 may also include a telemetry transmitter 122 that can be used to transmit pressure measurements made by the transducer 116, MWD/LWD measurements as well as drilling information to be received at the surface. A data memory including a pressure data memory may be provided at a convenient place in the BHA 113 for temporary storage of measured pressure and other data (e.g., MWD/LWD data) before transmission of the data using the telemetry transmitter 122. The telemetry transmitter 122 may be, for example, a controllable valve that modulates flow of the drilling fluid through the drill string 112 to create pressure variations detectable at the surface. The pressure variations may be coded to represent signals from the MWD/LWD system and the pressure transducer 116.

[0016] The drilling fluid 150 may be stored in a reservoir 136, which is shown in the form of a mud tank or pit. The reservoir 136 is in fluid communications with the intake of one or more mud pumps 138 that in operation pump the drilling fluid 150 through a conduit 140. An optional flow meter 152 may be provided in series with one or more mud pumps 138, either upstream or downstream thereof. The conduit 140 is connected to suitable pressure sealed swivels (not shown) coupled to the uppermost segment ("joint") of the drill string 112. During operation, the drilling fluid 150 is lifted from the reservoir 136 by the pumps 138, is pumped through the drill string 112 and the BHA 113 and exits the through nozzles or courses (not shown) in the drill bit 120, where it circulates the cuttings away from the bit 120 and returns them to the surface through the annulus 115. The drilling fluid 150 returns to the surface and goes through a drilling fluid discharge conduit 124 and optionally through various surge tanks and telemetry systems (not shown) to be returned, ultimately, to the reservoir 136.

[0017] A pressure isolating seal for the annulus 115 may be provided in the form of a rotating control head forming part of a blowout preventer ("BOP") 142. The drill string 112 passes through the BOP 142 and its associated rotating control head. When actuated, the rotating control head on the BOP 142 seals around the drill string 112, isolating the fluid pressure therebelow, but still enables drill string rotation and longitudinal movement. Alternatively a rotating BOP (not shown) may be used for essentially the same purpose.

[0018] As the drilling fluid returns to the surface it goes through a side outlet below the pressure isolating seal (rotating control head or BOP 142) to the fluid discharge conduit 124. The drilling fluid 150 exits the fluid discharge conduit and may be directed through an optional degasser 17 (explained further below) and solids separation equipment 129. The degasser 17 and solids separation equipment 129 are designed to remove excess gas and other contaminants, including drill cuttings, from the drilling fluid 150. After passing through the solids separation equipment 129, the drilling fluid 150 is returned to reservoir 136. Treatment and storage of the drill cuttings and the solids separation equipment will be further explained below with reference to FIGS. 3 through 7.

[0019] FIG. 2 shows an example mobile offshore drilling unit (MODU) which may include a drilling system 100 similar in configuration to that shown in FIG. 1 for drilling formations below the bottom B of a body of water W. The present example MODU may be a drill ship S with a deck K disposed on an upper part of a hull H. One or more cranes C may be on the deck K. A derrick D, which may be part of the drilling rig (102 in FIG. 1), may be mounted on the deck K. The drill ship S is only one example of a mobile offshore drilling unit (MODU). Other examples may include, without limitation, semisubmersible platforms and bottom supported drilling platforms such as jackups or barges. Other example embodiments may include two drilling systems 100 on the same MODU, for example, a drill ship. See, for example, U.S. Patent No. 6,047,781 issued to Scot et al.

[0020] The drilling system 100 may be modified to be used with a MODU such as the drillship S by having the BOP 142 (or related pressure control devices) disposed on the bottom B of a body of water. The drilling system 100 may have a fluid connection from the BOP 142 through a riser 101A so that part of the function of the fluid discharge conduit (124 in FIG. 1) may be performed by the riser 101A. Thus, cuttings transported out of the wellbore (106 in FIG. 1) by the drilling fluid (150 in FIG. 1) may be conducted to the drill ship S by the riser 101 A.

[0021] An offshore drilling unit according to the present disclosure enables the drilling system 100 thereon to drill an entire wellbore without the need for any work boat or other auxiliary vessel to accept any drill cutting for transport when operating, e.g., in a "zero-discharge" area or region (i.e., where no substances are permitted to be disposed of from the drilling system 100 such as drill cuttings). Using offshore drilling units known in the art, the drill cuttings that are discharged from the wellbore (as explained with reference to FIG. 1) must be either processed to remove harmful substances and then dumped, or must be removed from the wellbore location for safe disposal. In cases where the base fluid of the drilling fluid (150 in FIG. 1) is a hydrocarbon liquid ("oil based mud"), extensive onboard equipment would be required on the offshore drilling unit to reduce the amount of oil on cuttings (OOC) to less than 5.9% (e.g., dryer technology) or even less than 1.0% OOC (e.g., thermal technology) in order to dump the cuttings in the water W locally. Typically cuttings leaving the wellbore (106 in FIG. 1) when using oil based mud exceed 25% OOC by volume.

[0022] However, even if drill cuttings treated to such a degree were disposable by dumping from the offshore drilling unit overboard, an offshore drilling unit according to the present disclosure is designed for zero OOC discharge, because no cuttings are discharged from such offshore drilling unit. An offshore drilling unit configuration and process according to the present disclosure may eliminate the need for the above mentioned processing of the drill cuttings by providing on-board storage capacity for the drill cuttings for the entire wellbore (e.g., in the form of a selected number of storage containers called pneumatic storage tanks).

[0023] A process according to the present disclosure may use blower technology to transport cuttings from a "shaker pit" (explained below) to a storage area, and it has been determined to be possible to insert enough pneumatic storage tanks on a drill ship form of offshore drilling unit, at least, to cover any one wellbore 's volume of cuttings from drilling the entire wellbore. Within the disclosed process, shakers (e.g., such as the solids separation equipment shown schematically at 129 in FIG. 1) recover the base drilling fluid (which may be oil) from the cuttings so that in their as discharged form having in excess of 25% OOC, the OOC may be reduced to about 15% OOC. Centrifuges may be used to remove more of the drilling fluid from the cuttings, reducing OOC further to about 10%>. Additional reduction in OOC to below about 10%> would require the use of secondary processing, i.e., driers and heaters, mentioned above. A lot of cost, energy and logistics are involved to obtain such results. And the best obtainable result is still on the order of 1.0% OOC from a thermal process. In the present example embodiment, because the cuttings are stored onboard the offshore drilling unit, such processing is not required.

[0024] An example offshore drilling unit design according to the present disclosure allows the capability to drill wellbores in zero-discharge regions with no cuttings transport support capabilities. Once the wellbore has been drilled and the internal cuttings storage facilities are loaded with all the wellbore drill cuttings, the offshore drilling unit may return to a port or other service facility to offload the stored drill cuttings for processing and disposal.

[0025] FIG. 3 shows an example drilling fluid return processing system according to the present disclosure. The drilling fluid return processing system may include having two separate flow lines 19 connected at one end to the fluid discharge conduit (124 in FIG. 1, or the riser 101 A in FIG. 2) each passing through a flow distribution system. The returned drilling fluid may be conducted through appropriate manifolds (not shown in FIG. 3) to corresponding sets of shakers 14 (in combination corresponding to the solids separation equipment shown at 129 in FIG. 1). As will be appreciated by those skilled in the art, the shakers 14 may be single deck, double deck, triple deck or any other shaker system. The shakers 14 may be disposed over shaker pits 16 (shown in more detail in in FIG. 7) to collect liquid separated from the returned drilling fluid and cuttings. One or more degasser(s) 17 may be provided remove any gas that may be present, e.g., in solution, in the retuned drilling fluid once it has passed through the shakers 14. Degassers may be one of two general types. A vacuum type is the most common form of degasser. It can be disposed in a horizontal, vertical or round vessel. A vacuum action is created to pull in drilling fluid having gas dissolved or entrained therein. When the drilling fluid enters the vessel it is distributed to a layer of internal baffle plates designed for the drilling fluid to flow in thin laminar films and is exposed to a vacuum that causes the gas to escape and break out of the drilling fluid. A vacuum pump moves the escaping gas from the vessel and discharges it to a flare or environmental control system. An atmospheric degasser processes drilling fluid by accelerating fluid through a submerged pump impeller and impinging the drilling fluid on a stationary baffles to maximize surface and thus enable escaping gas vent to the atmosphere.

[0026] Liquid discharged from the shaker pits 16 may be conducted to corresponding centrifuges 18 (e.g., one centrifuge may be provided for each shaker pit) to remove certain solids not previously removed by the shakers 14. The solids discharged from the shakers 14 and the centrifuges 18 may be conducted to a cuttings storage area 10A having a selected number of storage pits such as pneumatic pressure tanks 10 therein. The cuttings storage 10A area may be disposed in a convenient place in the hull (H in FIG. 2).

[0027] As shown in FIG. 4, the cuttings storage 10A area may include, in the present example a selected number, e.g., thirty, 10.4 cubic meter pneumatic pressure tanks 10 for holding cuttings during drilling operations and until the offshore drilling unit can be moved to a location for cleanout of the pneumatic pressure tanks 10, and subsequent treatment and disposal of the cuttings and associated solids.

[0028] FIG. 5 shows a sectional view of the drill ship hull H to illustrate a possible location of the cuttings storage room 10A and pneumatic pressure tanks 10.

[0029] FIG. 6 shows an oblique view of the shaker system shown in FIG. 3 to illustrate the relative positioning of returned drilling fluid delivery manifolds 21 and the shaker pits 16 with respect to the shakers 14. An example of the shaker pits 16 will be explained in more detail with reference to FIG. 7.

[0030] Having described in general terms components of an example drilling fluid return processing and cuttings storage system, such system will now be explained in more detail. The two flow lines 19 provide initial distribution of the drilling fluid returned from the wellbore. The two flow lines 19 entering the shaker area (10A in FIG. 4) may also be coupled together by a manifold 21 to allow returned drilling fluid to flow to either or both sets of shakers (14 in FIG. 6) or the shaker pits (16 in FIG. 6).

[0031] The number of shakers selected in the present example for dual, simultaneous operations may be four for each flow line (19 in FIG. 3) providing a total of eight shakers accessible as required during drilling operations. One set of four shakers may be made up of three 'parallel' models and one 'series' model. The series model allows for additional offline processing capabilities such as lost circulation material (LCM) recovery, mud weight cut-back (i.e., removing density increasing materials such as barite), completions ready assignment and offline processing. It may also be possible to configure the shakers so that one set of shakers may be cleaned while the other is being used to separate solids from the drilling fluid during wellbore drilling.

[0032] The shaker pits may be designed to decrease common non-productive time associated with shaker pit cleaning. To reduce cleaning time, the shaker pits (16 in FIG. 7) may include two or more sets of multiple pits (three each in the present embodiment) assembled into a single shaker pit system with the capability of all shaker pits being aligned into separate groups or a single group, as shown in FIG. 7. To help promote self-cleaning, the shaker pits 16 may have few if any corners, as high angle slopes on the bottom of the shaker pits as possible within the confines of the space available within the drilling unit hull structure and low elevation (i.e., at the lowermost elevation on each shaper pit) drain/suction points 16B to make the shaker pits 16 more efficient. The present example may not require agitation of the shaker pits 16 as the proposed shaker pit structure may promote settling of solids to the bottom thereof. If more than one drilling system (100 in FIG. 1) is used on an offshore drilling unit, one set of shakers 14 and associated shaker pits 16 may be used for each of the drilling systems

[0033] Associated with the shaker pits 16 may be a separate tank (not shown in the drawings) used for drained fluid collection and segregation. This separate tank (not shown) may be designed to make the shakers 14, and mud mix areas (not shown in the Figures) self-supporting by segregating their respective drain systems before entering any onboard water clarifier. This tank (not shown) may be used as a drains segregation pit and may provide that any downstream water clarification unit will run more efficiently and for longer durations as the segregated drains may separate dense phases, e.g., densifiers and fine grained suspended solids from free oil in the drains flow from the shaker pits 16.

[0034] As explained above, degassers (17 in FIG. 1) may include one or more model atmospheric degassers or a vacuum degasser system in fluid communication with each shaker pit system (16A in FIG. 7) with the capability of the operator lining up both degassers on one of either shaker systems during high rate of flow wellbore sections.

[0035] Two pumps may be used to supply liquid feed to the centrifuges (18 in FIG. 1).

The centrifuges (18 in FIG. 3) may be configured for either low gravity solids (LGS) removal or high gravity solids (HGS) removal system if corresponding drilling fluid densities are used. Such densities may be obtained, for example, by mixing the drilling fluid with barium sulfate (barite) powder in concentrations required to obtain a selected drilling fluid density.

[0036] To facilitate cleaning of the shaker pits (16 in FIG. 7) an automated tank cleaning system may be used. The automated tank cleaning system may operate to clean one set of shakers and associated pits at least partially contemporaneously while the other shakers and pits are being used during wellbore drilling With shaker pit tank design as described herein, the automated tank cleaning system can clean all the shaker pits 16 to the necessary degree of cleanliness in about two hours as contrasted with 12 hours for conventional shaker pit cleaning systems.

[0037] A pneumatic conveyance system may be designed into the drilling fluid return processing system for several reasons, safety and containment being foremost. Each shaker 14 may have all of its cuttings removed using a screw or auger type conveyor (not shown), gravity or vacuum applied to a connecting line (15 in FIG. 3) at the end of the interconnected shakers 14. An end of each connecting line may be positioned over a respective cuttings containment blower valve. The cuttings thus will drop straight down into one or more of the cuttings containment blower(s) (CCB) valve(s) (12 in FIG. 4) which starts a pneumatic conveyance process. The CCB valves (12 in FIG. 4) capture pre-set amounts of solid material (adjusted by cycle time) and pulse it into a piping system for transport of the separated cuttings. From the CCB valve (12 in FIG. 4) the cuttings may be sent to the pneumatic storage tanks (10 in FIG. 4) via specifically configured piping and directional control valves shown collectively at 12A in FIG. 3.

[0038] In the present example drill ship type offshore drilling unit, the cuttings containment room may be configured to have enough capacity for thirty of these modified pneumatic pressure tanks which each can store 10.4 m³ giving this room a total storage capacity of 312 m³. A non- limiting example of pneumatic pressure tanks that may be used in some embodiments forms part of a drill cuttings handling system sold under the trademark CLEANCUT, which is a trademark of M-I SWACO.

[0039] An offshore drilling unit having full wellbore cuttings storage capability may enable fully self-contained drilling operations in remote areas where the use of service vessels to supply materials and to remove stored drill cuttings is impractical.

[0040] 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.

Claims

Claims What is claimed is:

1. A method comprising:

separating drill cuttings from drilling fiuid returned from a wellbore during the drilling thereof; and

moving the separated cuttings to a storage area having sufficient capacity to hold separated cuttings resulting from drilling the entire wellbore.

2. The method of claim 1 wherein the separating the drill cuttings comprises moving the returned drilling fiuid over at least one shaker.

3. The method of claim 2 wherein the at least one shaker comprises at least two shaker systems, and wherein the drilling fluid is passed over one of the at least two shaker systems while a second one of the at least two shaker systems is cleaned.

4. The method of claim 2 further comprising discharging separated drilling fluid from the at least one shaker to a shaker pit disposed below the at least one shaker, the shaper pit shaped to further separate solids from the returned drilling fluid after passing through the at least one shaker.

5. The method of claim 2 wherein solids separated by the at least one shaker are moved to at least one pneumatic pressure tank disposed in the storage area.

6. The method of claim 2 wherein the solids separated by the at least one shaker are moved to the storage area using a screw conveyor.

7. The method of claim 6 further comprising moving the cuttings from the screw conveyor pneumatically to the storage area.

8. The method of claim 7 wherein the pneumatic movement is performed by a cuttings containment blower.

9. The method of claim 1 further comprising moving the returned drilling fluid having the separated cuttings removed therefrom through a centrifuge to further remove solid material from the returned drilling fluid.

10. The method of claim 1 further comprising removing gas from the returned drilling fluid after separating the drill cuttings therefrom.

11. The method of claim 1 wherein the storage area is disposed in a selected portion of a hull of a mobile offshore drilling unit.

12. An apparatus, comprising:

a drilling fluid discharge line coupled to a fiuid discharge of a wellbore;

at least one shaker in a flow path of the drilling fiuid discharge line; and

a conveyor to move solids separated from the at least one shaker to a storage area, wherein a storage volume of the storage area is sufficient to hold all drill cuttings from an entire drilled wellbore.

13. The apparatus of claim 12 further comprising at least one shaker pit disposed beneath the at least one shaker, the at least one shaker pit having a shape to enable further separation of solids from liquid passing through the at least one shaker.

14. The apparatus of claim 12 wherein the at least one shaker comprises at least two shakers in fluid communication with a fluid manifold, the manifold controllable to enable fluid from the fluid discharge line to flow over a first one of the at least two shakers and a second one of the at least two shakers to be substantially simultaneously cleaned.

15. The apparatus of claim 12 wherein the storage area comprises at least one pneumatic pressure tank.

16. The apparatus of claim 12 further comprising a screw type conveyor to move solids collected by the at least one shaker.

17. The apparatus of claim 15 further comprising a cuttings containment blower coupled at an inlet thereof to an outlet of the screw type conveyor, the cutting containment blower coupled at an outlet thereof to the storage area.

18. The apparatus of claim 12 further comprising a degasser in fluid communication with a fluid outlet of the at least one shaker.

19. The apparatus of claim 12 further comprising at least one centrifuge in fluid communication with a fluid outlet of the at least one shaker.

20. A method, comprising:

drilling a wellbore by turning a first drill bit at a bottom of a first drill string in the wellbore;

pumping drilling fluid through the drill string;

passing drilling fluid returning from the wellbore to at least a first shaker in selective fluid communication with a fluid discharge outlet of the wellbore;

moving solids extracted from the fluid returning from the wellbore to a storage area, the storage area having sufficient volume to store all the extracted solids obtained by drilling the entire wellbore.

21. The method of claim 20 further comprising passing the fluid after extraction of the solids therefrom through a centrifuge to remove additional solids from the drilling fluid returning from the wellbore.

22. The method of claim 20 further comprising cleaning at least a second shaker in selective fluid communication with the fluid discharge outlet at least partially contemporaneously with passing drilling fluid over the at least a first shaker.