This can be done to workover, clean out and stimulate the well to increase production or to drill one or more side tracks or extensions from below the tubing to access isolated pockets of hydrocarbons.

This can be done on land with small workover rigs. However, the mobilisation of workover rigs offshore is expensive and, in many cases is impractical due to lack of deck space and/or crane lifting capacity on the offshore platform.

In most depleted fields the reservoir pressure has declined to below overburden pressure. Re-entering an old well and drilling from it is difficult and time consuming due to the sensitivity of the formation to fluctuations in circulating drilling fluid pressure. This is particularly so in unconsolidated strata. Such fluctuations in pressure occur when the circulation of drilling fluid is stopped and started, as when making drill pipe connections under normal conditions.

In drilling, the pressure of the drilling fluid, such as drilling mud, at the bottom of the well has basically two components, a static head which is the pressure due to the depth of the well and a dynamic head due to the circulation pressure. When the pumping of the mud down the well is stopped there is only the static head, so the pressure drops; when circulation is re-started there is a pressure surge or kick. The static mud pressure must be high enough to hold the well open when the circulation stops, but not so high that when circulation is re-started the mud penetrates or fractures the structure.

In the previously used teclmique of Through Tubing Rotary Drilling (TTRD) these pressure fluctuations are accentuated by the small annular cross section between the hole and the drill string. The dynamic pressure drop, or friction loss, through the annulus is high and, as a consequence, the associated Equivalent Circulating Density (ECD) is high. When circulation stops, the dynamic pressure component is removed and the bottom hole pressure drops considerably. When circulation is restarted the dynamic pressure reappears and a similar positive pressure surge occurs.

Coiled tubing drilling avoids this frequent stop/starting of the mud circulation but it will occur each time an additional coil has to be added to the system. Coiled tubing is also less effective than a jointed drill pipe for drilling long horizontal or lateral extensions to wells.

Slim-hole TTRD with casing will reduce the number of trips required and facilitate casing off of fragile formations but stop/starting the circulation of drilling fluid will still be necessary when adding joints of casing.

Particularly with offshore, the cost of re-activating the old platform drilling rig or installing a new small workover rig, plus the inability to avoid significant pressure fluctuations, makes many, if not most, old wells too expensive and difficult to re- enter through the completion.

We have now devised an improved drilling system with jointed drill pipe/casing which incorporates the means of controlling the pressure of the drilling fluid in the annulus and which reduces these problems.

According to the invention there is provided a method for drilling through an existing well which comprises (i) inserting a drill string down the well bore of the well, (ii)

circulating drilling fluid down the drill string, (iii) controlling the drilling fluid pressure in the annulus formed between the drill string and the walls of the well by at least one choke, and (iv) adding tubulars to the drill string whilst maintaining continuous circulation of drilling fluid though the drill string.

The invention also provides apparatus for drilling through an existing well which apparatus comprises (i) an insertion means able to insert a drill string down an existing well bore, (ii) a rotation means for rotating the drill string, (iii) at least one choke able to be located in the annulus between the drill string and the walls of the well and (iv) a coupler which enables tubulars to be added to the drill string whilst continuously circulating drilling fluid down the drill string.

The apparatus can be located directly onto the wellhead or Christmas Tree for small bore Through Tubing Rotary Drilling (TTRD). The Christmas Tree is the assembly of fittings and valves on the top of the casing which control the production rate of oil.

In use, the choke or chokes, which are preferably integral chokes, provide the capability of continuous and steady annulus pressure and Equivalent Circulating Density (ECD) control.

The coupler is preferably a coupler of the type described in our Patent Applications WO 98/16716 and WO 00/22278, the contents of which are hereby incorporated by reference, which also describe the making and breaking of tool joint connections under pressure inside a coupler, so that mud circulation can continue uninterrupted.

Patent Application WO 98/16716 describes a method for drilling wells in which a drill bit is rotated at the end of a drill string comprising tubular members joined together and mud is circulated through the tubular drill string, in which method

tubular members are added to or removed from the drill string whilst the circulation of mud continues.

The method supplies mud, at the appropriate pressure, in the immediate vicinity of the tubular connection that is about to be broken such that the flow of mud so provided overlaps with flow of mud from the top drive; as the tubular separates from the drill string the flow of mud to the separated tubular is stopped e. g. by the action of a closing device such as a gate valve.

The separated tubular can then be flushed out e. g. with air or water (if under water) depressured, withdrawn, disconnected from the top drive and removed.

The application describes a coupler for connecting and disconnecting tubulars to and from a drill string while continuously recirculating drilling fluid through the drill string which comprises a pressure chamber which has a divider which divides the chamber into upper and lower sections and, when the divider is in its closed position, prevents the passage of drilling fluid between the two sections and when the divider is open, the end of a tubular and the top of the drill string can be brought into and out of contact and in which the chamber has an inlet for entry of drilling fluid into the lower section of the chamber, there being an upper gripping means for gripping the tubular and a lower gripping means for gripping the drill string and the upper and lower gripping means being moveable into and out of engagement with the tubulars and drill string respectively and which can rotate the said tubular and said drill string relative to each other to make and break connections therebetween for connecting and disconnecting said tubulars whilst drilling fluid is continuously circulated down the drill string.

Preferably there is an outlet in the upper section of the chamber so that drilling fluid can be recirculated into and out of the chamber. Optionally at least one of the upper

and lower gripping means are positioned inside the chamber and preferably there is an annular preventer which seals the chamber from the environment.

The action of the divider, which can be a blind ram, is to divide the coupler into two parts e. g. by dividing the pressure chamber of the coupler connecting the tubular to the drill string. The drill string continues to be circulated with mud at the required pressure from an annulus connection below the blind ram.

In a preferred embodiment of the invention a tubular can be added using a gripping means which comprises a snubber, and the top end of the drill string is enclosed in and gripped by the lower section of the coupler, the tubular is then added to the upper section of the coupler and is sealed by pipe rams and the blind rams are opened and the lower end of the tubular and upper end of the drill string are joined together.

The tubular can be added to the drill string to which the lower section of the coupler is attached to the top of the suspended drill string with the blind rams in the closed position preventing escape of circulating drilling fluid. The tubular is lowered from substantially vertically above into the upper section of the coupler and is then sealed in by a seal so that all the drilling fluid is contained, the blind rams are then opened and the tubular and the suspended drill string brought into contact and joined together with the gripping means bringing the tubular and drill string to the correct torque.

The lower end of the tubular and the upper end of the drill string are separated by the blind rams such that the tubular can be sealed in by upper pipe rams so that, when the blind rams are opened, there is substantially no escape of drilling fluid and the tubular and drill string can then be brought together and made up to the required torque.

To remove another tubular from the drill string an extension/saver sub under the top drive penetrates the upper part of the pressure chamber, is flushed out with mud and pressured up; the blind rams open allowing the top drive to provide circulating fluid

and the extension/saver sub to connect to and to torque up into the drill string. The pressure vessel can then be depressured, flushed with air (or water if under water) and the drill string raised until the next join is within the pressure chamber, the'slips and grips'ram closed, the pressure chamber charged with drilling fluid and pressured up and the cycle repeated.

Preferably the coupler includes rotating slips which support the drill string while the top drive is raised up to accept and connect another tubular.

In patent application WO 00/22278 the upper grips and slips are able to pass through the blind rams when the blind rams are in the open position.

The addition or removal of a tubular can take place with continuous rotation of the drill string. For continuous rotation the gripping mechanism within the snubbing unit applies high torque at drilling rotation speed and a similar unit is installed upside down and grips the top of the drill string ; these two units are connected via differential gearing to provide the required torque to make or break the tool joint connections.

In the present invention a tubular can be added using gripping means which comprises a snubber. The coupler snubber can be modified to rotate the drill string and provide drilling torque instead of using a Top Drive; the coupler snubber can then be stroked over a longer vertical distance to move the drill pipe/casing into/out of the well.

There can be two short stroke snubbers as a split snubbing arrangement arranged vertically above the coupler so that they can be used to work hand to hand for continuous movement of long drill pipe/casing into the apparatus when drilling and a Rotary Blow Out Preventer (RBOP) or Pipe Ram with'rotary seal'can be used as the

top seal in the coupler. Such an arrangement permits continuous snubbing and allows a long-stroke arrangement to be used (1. 8m-5m). This is instead of the short stroke (1. 5m) of the integrated snubber design for the coupler.

For connecting the tubulars, any method for raising and connecting each tubular to the circulating swivel of a conventional drilling rig can be used and tubulars and tubular assemblies of 30ft, 20ft or even 15ft nominal lengths can be used.

For transportation and storing it is convenient to limit the tubulars and tubular assemblies to 19 1/2 fut for storage in 20ft ISO containers and for ease of transport and assembly with site cranes or lifting gear the components can be segregated into convenient groups.

Preferably the apparatus of the present invention integrates a snubbing unit and rotation device, a continuous circulation coupler, automated slips, (Rotary Blow Out Preventer) RBOP and Blow Out Preventer (BOP) s and adjustable annulus chokes with a central power and control system, designed to re-enter existing wells through the production tubing and preferably drill sidetrack extensions to new sections of the reservoir.

In use, apparatus of the present invention is mounted on the top of the wellhead or Christmas Tree. The drill string is assembled and inserted down the well bore, with the drilling fluid circulating down the drill string, either from a swivel or from the coupler and the returning drilling fluid leaving the annulus beneath the RBOP and through the annulus chokes. The down hole pressure can be maintained throughout the drilling or workover operation at the optimum for the exposed formation.

The invention provides the technical advance that it is able to re-enter existing wells and drill extensions, without pulling the completion tubing in conditions that would otherwise be uneconomic, due to reasons such as being so pressure depleted that drilling fluids would invade and damage the formation, being unconsolidated such that any step change in ECD would collapse the borehole or being so marginal in production potential that the cost of a full size rig is unjustified.

Preferably the means for inserting a drill string into an existing well incorporates a snubbing unit and/or rotating device and preferably the coupler's snubber referred to above is upgraded to stroke further in the vertical and so make a reasonable number of relocations to grip the tubular while inserting it into the well. This will avoid possible buckling of a thin wall tubular at high snubbing forces. The coupler's snubber can be further modified to transmit full drilling torque at the required drilling rotation speed and the maximum rotary and maximum axial forces do not coincide.

In the present invention, the continuous circulation coupler preferably should be able to handle pipe from 4-1/2"outside diameter to 2-3/8"outside diameter. This may require changing out ram seals and the shoes or inserts of the 90° slips from presently used couplers.

In use the coupler can be mounted on the BOP stack, with a'wet slips'unit in between, so that the drilling fluid will not be drained out after every connection.

Furthermore the upper pipe ram can be replaced by an RBOP, which should allow a longer seal life and also act as a back up should the lower RBOP seal begin to fail.

The lower pipe ram can be adapted to grip the string sufficiently to support the string weight. This will be aided as the coupler is mounted directly onto the BOP stack and the need to seal will be reduced.

The slips unit is preferably an assembly comprising two pipe ram blow out preventers above an RBOP, but alternative slips can be used.

The pipe rams incorporate the slips which support the drill string during connections.

With two sets of rams, two sizes of pipe can be accommodated.

The main BOP stack preferably contains two pairs of pipe rams and a pair of sheer/blind rams. The assembly of the coupler, slips unit and BOP stack is connected to provide a continuous pressure hull, hence the rams in the coupler and optionally the slips unit also serve as back-up for the BOP stack.

There is preferably an annulus pressure control system which is preferably a computer controlled choke system for controlling the flow of returning mud and cuttings from the annulus. Preferably an adjustable choke for this purpose should be downstream of a knock-out pot for cuttings and debris. The choke aperture should be varied to maintain a back pressure on the annulus, set in accordance with a real time model of the pressure circuit from the mud pump, down the drill string, through the bit and up the annulus to the knockout pot and the adjustable choke. In use, this real time model is continuously adjusted to accord with the reality of the changing well drilling conditions and drill string configuration. Given the desired BHP and circulation flow rate range, the model can set the required pressure upstream of the choke and adjust the choke to achieve it.

This choke and pressure control system completes an integrated, stand alone Pressure Controlled Drilling System (PCDS).

The present invention provides the ability to contain the well pressure, while extracting the bottom hole assembly by alternately closing the RBOPs to allow the passage of rough or irregular external profiles such as centralisers, MWD components and steering components, there being, by diligent design of the BHA, no pair of inconvenient profiles, at the same separation distance as the two RBOPs.

The integrated assembly can comprise one or more near standard preventers, connectors and snubbers, modified to seal and/or grip, by which assembly the normal mud pump pressures may be safely contained and the axial forces and/or torque to the string transmitted for making or breaking tool joint connections and drilling, all without a derrick or mast or any other structure conventionally used to support a top drive, swivel or crown block or a drill floor containing a rotary table.

For use on the seabed, the PCDS assembly may be split with the snubber, coupler and slips components being on the surface vessel, mounted above the marine riser and the BOP stack being on the subsea wellhead.

For use offshore with a tensioned, slim, pressured riser, the PCDS can be mounted directly onto the top of the riser and, being relatively compact and independent from any drilling rig on the vessel, it can be more easily supported during workover and/or drilling operations, as the vessel heaves around it in rough weather.

The invention provides the ability to connect or disconnect and install or retrieve all suitably sized tubulars, including but not limited to, drill pipe, casing, liners, production tubing, expandable casing, macaroni, coiled tubing, and tubular assemblies, including but not limited to, bit assemblies, bottom hole assemblies, MWD assemblies, production assemblies and can handle any tubular inserted into the top of the snubber, by any means available on site.

Preferably the whole assembly is designed to be transported to site by road, rail or sea and erected by crane or forklift on site or by self erection where appropriate. The present apparatus requires only to be mounted on the wellhead or Christmas Tree and connected to the control system, hydraulic power supply and mud circulation system (circulating pumps, mud storage and treatment tanks).

The whole PCDS assembly can be separated into convenient sub-assemblies that can be limited to 10 ton, or even 5 ton, maximum loads and, can conveniently conform to the exterior dimensions of standard 20ft or 10 ft ISO containers. The drill pipe and all other tubulars and tubular assemblies could also be made up to fit into 20ft ISO containers.

The present invention can be operated remotely, such that the method may be carried out unmanned and with manned intervention capable of being confined to inspection, maintenance and repairs with the assembly shut down and can perform relatively long sequences of operations under programmed computerised control, with manual override by the supervising operator available if intervention is required.

It is a feature of the invention that it is an inexpensive, compact well intervention system for TTRD with jointed drill pipe or casing. It is integrated and self contained and does not require any support from existing platform facilities. With its capability of drilling with continuous circulation and dynamic annulus pressure control, a steady down hole pressure at the desired circulation rate can be maintained and pressure fluctuations minimised.

The invention is described in the accompanying drawings in which

Figure 1 shows two alternative mountings on a well; Figure 2 shows schematically an installed equipment; Figure 3 shows the components of the apparatus in more detail and Figure 4 shows a more compact embodiment.

Referring to fig. 1, this shows the mounting on an existing well (1) drilled on an off shore platform which is to be drilled through the platform which has a main deck (9), well deck (20) and cellar deck (21). In fig. 1A the apparatus of the invention (3) is mounted on a Christmas Tree (7) and in fig. 1B it is mounted directly on a well head.

The decommissioned drilling rig (2) is skidded to one side to (8) and the apparatus (3) is mounted in the well slot (6). The chokes (4) and the mud circulation ports (5a) and (5b) are indicated. The apparatus is described in detail in figs 2 to 4.

Referring to fig. 2 the equipment is mounted on well head or Christmas tree by a connector (10), and for convenience the equipment can be considered as comprising four units or packages. Unit 1 is the drilling package, Unit 2 is the coupler package, Unit 3 is the grip and sealing unit and Unit 4 is the blow out preventer (BOP). There is a snubber/drilling make/break device at (15) and top swivel (18). There is mud storage and a treatment unit (16) which is connected via mud pumps (17) to diverter manifold (27). The flow of drilling mud is in through the swivel (18) and out through the choke annulus pressure control (28). There is also mud circulation through the coupler unit (29). The electro hydraulic power unit is shown at (30) and the control centre at (31). The heavy connecting lines are the mud flow connections and the thinner connecting lines are control circuit.

Referring to figs. 3 and 4 there is a connector (10) which connects to the well head or Christmas Tree. Unit 4 (the BOP unit) typically comprises two pipe rams (29 and 30)

and sheer/blind rams (31). Unit 4 is connected by connector (32) to Unit 3 (the slips unit) which typically comprises a rotary BOP (33), and two slip rams (34 and 35).

Unit 3 is connected by connector (36) to Unit 2 (the coupler unit) which comprises pipe rams (37), blind rams (38) and a rotary BOP (39). The coupler unit has a pressure chamber which has a divider which divides the chamber into upper and lower sections and, when the divider is in its closed position, prevents the passage of drilling fluid between the two sections and when the divider is open, the end of a tubular and the top of the drill string can be brought into and out of contact and in which the chamber has an inlet for entry of drilling fluid into the lower section of the chamber, there being an upper gripping means for gripping the tubular and a lower gripping means for gripping the drill string and the upper and lower gripping means being moveable into and out of engagement with the tubulars and drill string respectively and which can rotate the said tubular and said drill string relative to each other to make and break connections therebetween for connecting and disconnecting said tubulars whilst drilling fluid is continuously circulated down the drill string.

Unit 1 (the drilling unit) in which there are grips and snubber at (41) is mounted on Unit 2 and supported on and moved vertically by a mechanism, which is preferably hydraulic, at (40).

Further integration of Units 1 to 4, to reduce height and weight can be achieved by eliminating components such as a pair of pipe rams (29 or 30), and/or a pair of slip rams (34 or 35), subject to there being either a reduction in the diameters to be handled, or the jaws of the pipe rams being capable of sealing against different diameters. Further reduction in height and weight may be achieved by adding a sealing function to the slip rams at (34 and/or 35) and eliminating the pipe rams at (37) and/or adding a slips function to the pipe rams at (37) and eliminating one or

both of the slip rams at (34 and 35). Hence, the PCDS may be reduced considerably in height, for example as shown in Fig 4.

In use, when an existing well is to be drilled through, the equipment is connected at (10) onto the existing well bore, either directly to the well head (1) or on top of the Christmas tree (7). The drill pipe is fed from swivel (18) and rotated as in conventional drilling. When a new tubular is to be added, it is gripped by the snubber in Unit 1 and connected by the coupler Unit 2 whilst the drilling fluid is circulated continuously. The tubular is lowered from substantially vertically above into the upper section of the coupler and is then sealed in by a seal so that all the drilling fluid is contained; the blind rams are then opened and the tubular and the suspended drill string brought into contact and joined together with the gripping means bringing the tubular and drill string to the correct torque.

The lower end of the tubular and the upper end of the drill string are separated by the blind rams such that the tubular can be sealed in by upper pipe rams so that, when the blind rams are opened, there is substantially no escape of drilling fluid and the tubular and drill string can then be brought together and made up to the required torque.

As the drill pipe passes down the well bore there is an annulus between the drill pipe and the tubing or walls of the well bore and the drilling fluid is pumped down the drill string and back up this annulus. The chokes (28) maintain continuous and steady annulus pressure and Equivalent Circulating Density control.

For continuous rotation as well as continuous circulation, the gripping mechanism within the snubbing unit (41) is upgraded to apply high torque at drilling rotation speed and a similar gripping mechanism is installed upside down instead of one or both of the slip rams (34 and/or 35), these two gripping mechanisms being connected via differential gearing to provide the required torque to make or break tool joint

connections. Additionally the'upside down'pipe rams at (37) would preferably be replaced by an'upside down'RBOP to accommodate extensive rotation under full mud pump pressure.

For use offshore the assembly of fig. 3 can be split into two components with the snubber, coupler and slips components (34 to 41) being on the surface vessel, above the marine riser and the BOP stack (33 back to 29) being on the subsea wellhead.