Patent Description:
MPD is an adaptive drilling process used to precisely control the fluid pressure throughout the wellbore in the annular space between the drill string and the wellbore wall during drilling operations. The objective of MPD is to ascertain the downhole pressure environment limits and to manage the annular hydraulic pressure profile accordingly. The general categories of MPD known in the oil and gas industry include Dual Gradient Drilling (DGD), Constant Bottom Hole Pressure Drilling, Pressurized Mud Cap Drilling, Returns Flow Control drilling and Controlled Mud Level Drilling.

<CIT> issued to Maus discloses a method for controlling the liquid level of mud in a marine drilling riser. One or more flow lines are used to withdraw drilling fluid from the upper portion of the riser pipe. Gas is injected into the flow line/s to reduce drilling fluid density to provide lift. No mud return pumping system is used in this disclosure.

Howells, <CIT>, discloses another method for controlling the liquid level of mud in a marine drilling riser. A fluid return pump is installed in the lower part of a marine drilling riser system. Return fluid from the well may be pumped back to the surface through a conduit or discharged to the ocean through an opening valve. The valve or the returns pump controls the fluid level in the riser. The disclosed system also may detect the pressure inside the riser and send an electrical signal in response.

<CIT> issued to Fossli discloses another method for controlling the liquid level of mud in a marine drilling riser. The arrangement described includes a surface blowout preventer (BOP) and a gas bleeding outlet at the upper end of the drilling riser, a lower BOP with a by-pass line, and an outlet at a chosen depth below the water surface that is connected to a pumping system with a flow return conduit running back to a drilling vessel. Managed pressure drilling systems such as those disclosed in <CIT> require electrical signals and electrical power to be transmitted to a subsea pumping system. Such systems may be complex and expensive. It would be more desirable to have a system where such complicated controls could be avoided and existing equipment on the drilling vessel used.

In Reitsma, International Patent Application Publication No. <CIT>, another method and apparatus are described for controlling the liquid level of mud in riser. The apparatus described includes a fluid outlet in a marine drilling riser which is connected to the inlet of an ejector assembly to return drilling fluid to a drilling platform on the water surface. The method includes pumping drilling fluid into a drill string extending from the drilling platform into the wellbore and at least one of, (i) introducing fluid into a power fluid inlet of the ejector assembly at a rate selected to remove fluid from the wellbore fluid outlet at a selected rate and (ii) operating a controllable flow restriction in a flow path from the wellbore fluid outlet to the working fluid inlet of the ejector assembly, in order to maintain a selected wellbore pressure.

In Controlled Mud Level drilling, a subsea mud lift pump is coupled to the interior of the riser at a chosen level above the water bottom but below the water surface, and a mud return line is used to circulate the drilling mud back to the surface. This allows the fluid level in the riser to be controlled at any elevation above the location of the connection to the subsea mud lift pump. A commercially available example of such a Controlled Mud Level Drilling system is sold under the trademark EC-Drill, which is a trademark of Enhanced Drilling, AS, Straume, Norway. While such systems offer many benefits such as the ability to manage bottom hole pressure and reduced ECD (Equivalent Circulating Density) effects, these systems require significant modifications to drilling vessels and drilling operating procedures before they can be used. Such modifications can be prohibitively expensive and often cannot be accomplished while the drilling vessel is working. In addition, these systems require power and control input for subsea pumps, adding to the expense and complexity of the system. Most drilling vessels are therefore unable to support MPD activities without a major retrofit. It is desirable to have an MPD system that requires little to no vessel modifications and does not require subsea electrical power and control to be supplied to a subsea pump.

According to a first aspect of the invention, there is provided a method of controlling pressure in a well as set out in claim <NUM> of the appended claims.

Some embodiments further comprise adjusting a setting of an iris type annular pressure control device disposed in the riser in an annular space between the riser and a drill string disposed in the riser to increase back pressure on the well.

Some embodiments further comprise filtering cuttings exceeding a selected size from fluid entering a working fluid inlet of the first jet pump.

According to a second aspect of the invention, there is provided a managed pressure drilling system as set out in claim <NUM> of the appended claims.

Some embodiments further comprise a fluid level sensor in the riser.

In some embodiments, the fluid level sensor comprises a pressure sensor.

Some embodiments further comprise a controller in signal communication with the fluid level sensor. The controller provides control output to operate the power fluid pump and the gas source in response to signals from the fluid level sensor to maintain the fluid level at the selected elevation.

Some embodiments further comprise a drilling fluid pump disposed on the platform and connected at an outlet to a drill string extending into the riser.

Some embodiments further comprise valves connected to the power fluid inlet, the working fluid inlet and the fluid outlet of the first jet pump. The valves are operable to cause fluid to flow into the fluid outlet of the first jet pump. The valves are operable to bypass the first jet pump, and the valves are operable to direct fluid flow from the port to the working fluid inlet of the first jet pump and fluid flow from the fluid outlet of the first jet pump to the working fluid inlet of the second jet pump.

Some embodiments further comprise at least one valve connected between a riser kill line and the power fluid inlet of the first jet pump wherein power fluid to operate the first jet pump is moved through the kill line.

Some embodiments further comprise at least one valve disposed in a choke line extending from the subsea well to the fluid outlet of the first jet pump, and at least one valve disposed in a return line extending from the fluid outlet of the first jet pump to the working fluid inlet of the second jet pump, wherein the choke line is operable as a drilling fluid return line from the riser port to the platform.

Some embodiments further comprise a rock catcher and separator disposed in a fluid line connecting the port and the working fluid inlet of the first jet pump.

Some embodiments further comprise an annular control device operable to close an annular space in the riser between the riser and a pipe string disposed in the riser, wherein the power fluid pump is operable to maintain a selected pressure in the subsea well when a drilling fluid pump in pressure communication with a pipe disposed in the riser is switched off.

Other aspects and possible advantages will be apparent from the description and claims that follow.

Illustrative embodiments are disclosed herein. In the interest of clarity, not all features of an actual implementation are described. In the development of any such actual implementation, numerous implementation-specific decisions may need to be made to obtain design-specific goals, which may vary from one implementation to another. It will be appreciated that such a development effort, while possibly complex and time-consuming, would nevertheless be a routine undertaking for persons of ordinary skill in the art having the benefit of this disclosure. The disclosed embodiments are not to be limited to the precise arrangements and configurations shown in the figures, in which like reference numerals may identify like elements. Also, the figures are not necessarily drawn to scale, and certain features may be shown exaggerated in scale or in generalized or schematic form, in the interest of clarity and conciseness.

Example embodiments of a managed pressure control system according to the present disclosure may include the following components shown schematically in <FIG>. A first jet pump <NUM>, which may use liquid as a power fluid, has a power fluid inlet, a working fluid inlet and a working fluid outlet. The first jet pump <NUM> may take its power fluid input from an auxiliary line such as a kill line <NUM>, which may be one of the auxiliary lines ordinarily associated with a drilling riser <NUM> (or other conduit). The working fluid inlet is connected to the riser <NUM> main tube. Varying the power fluid flow rate allows the amount of fluid that is drawn from the riser <NUM> and discharged to a return line <NUM> that extends to a drilling platform <NUM> disposed on or above the surface of a body of water. By either increasing or decreasing the power fluid flow, a level of liquid in the riser <NUM> main tube can be adjusted and controlled.

A second jet pump 40A, which uses gas as a power fluid has its power fluid inlet connected to a gas injection line <NUM> extending to a gas source, e.g., a gas injection system <NUM>, disposed on the platform <NUM>. The working fluid inlet is connected to the working fluid outlet (i.e., the discharge) of the first jet pump <NUM>. Varying the working fluid (gas) flow rate affects the working fluid inlet pressure of the second jet pump 40A. Changing the working fluid inlet pressure of the second jet pump 40A changes the performance characteristics of the first jet pump <NUM>.

The kill line <NUM> may be an existing external conduit that is present on most offshore drilling vessels using a drilling riser. The kill line <NUM> in the present embodiment can be used to provide power fluid for the first jet pump <NUM>. In some embodiments, a separate conduit may be used in place of or in addition to the kill line <NUM>. A bypass arrangement around the first jet pump <NUM>, for example using valves 48A as shown in <FIG>, allows the kill line <NUM> to be used in a known manner, e.g., during well pressure control operations in addition to being used as the power fluid conduit for the first jet pump <NUM>.

An auxiliary line such as a choke line <NUM> (shown connected between a BOP stack <NUM> and the outlet or discharge of the second jet pump 40A) may be an existing riser external line that is present on offshore drilling vessels using a drilling riser. The choke line <NUM> can be used to provide a mud return flow conduit, e.g., through a return line <NUM>, from the outlet of the second jet pump 40A to a mud return inlet of a drilling mud system <NUM> located on the platform <NUM>. In some embodiments, a separate conduit (not shown) may be used in substitution of or in addition to the choke line <NUM> and return line <NUM>. Bypass arrangement around the second jet pump 40A may be provided, such as by valves including valve <NUM>, 42A and <NUM> to enable ordinary use of the choke line <NUM> during well control operations.

The subsea blowout preventer (BOP) stack <NUM> may be an existing subsea BOP stack comprised of pipe rams, shear rams and annular well closure devices. The BOP stack <NUM> may contain one or more wellbore pressure sensors.

An iris type annular pressure control device <NUM> may be used to control fluid pressure in the riser <NUM> in the annular space between the riser <NUM> and a drill string <NUM>. The annular pressure control device may be similar to a device described in <CIT>.

The drilling mud system <NUM> may be any mud system known in the art to be used on marine drilling vessels and may comprise solids and gas separators, mud pits, pump(s) <NUM>, pressure sensor(s), a flow meter <NUM>, level sensors and mud conditioning equipment.

The gas injection system <NUM> may provide gas under pressure (e.g., <NUM>,<NUM> KPascal [<NUM>,<NUM> psi]but in some embodiments as much as <NUM>,<NUM> KPascal {<NUM>,<NUM> psi} ), for example, nitrogen gas, and may comprise gas storage bottles and pressure regulation equipment (none shown separately). Some embodiments may include gas compression and nitrogen generator(s).

The riser <NUM> is a conduit known in the art that connects the subsea BOP stack <NUM> to the platform <NUM> and may be used to assist with mud return from the well <NUM> to the platform <NUM>.

A surface BOP and riser gas handler as shown in <FIG> may be used in some embodiments to provide well pressure control for situations involving severe fluid influx (kicks) or to handle continuous gas generation which can occur with under balanced drilling.

Flow meters <NUM>, <NUM>, <NUM> and <NUM> may be used to measure the flow of fluid (mud) into and out of the well <NUM> as shown as they are respectively connected in <FIG>. The flow meters may measure volumetric flow and/or mass flow.

Pumps disposed on the drilling platform <NUM> may comprise mud pump(s) <NUM> of any known type that are installed on drilling vessels. The pumps may be positive displacement type pumps or centrifugal pumps. A fill pump <NUM> provides a flow of fluid, e.g., drilling mud to cool a riser slip joint and ensures liquid level in the riser <NUM> remains above the riser connection 12A to the second jet pump 40A inlet. A riser boost pump <NUM> may be used to provide additional liquid flow into the riser <NUM> at a selected position through a riser boost line <NUM>, generally proximate the bottom of the riser <NUM> to assist in lifting drill cuttings to the platform <NUM>. A jet pump power fluid pump <NUM> (feed pump) may provide power fluid to the first jet pump <NUM>, e.g., through the kill line <NUM>.

A well head <NUM> provides a structural and pressure-containing interface for the drilling operations and may be connected to the bottom of the BOP stack <NUM> and to the top of a well casing <NUM>.

A rock catcher and separator <NUM> (rock catcher) may be provided to ensure that drill cuttings that are larger than the throat clearance in the first jet pump <NUM> do not enter the first jet pump <NUM>. The rock catcher and separator may have inlet <NUM> and outlet <NUM> pressure sensors which enable detecting blockage (as a result of increased pressure difference across the rock catcher <NUM>). The rock catcher <NUM> may also have an additional sensor (not shown) for determining if it is full of cuttings, such as a density sensor (not shown). Embodiments of the rock catcher <NUM> may include:.

A valve <NUM> on the outlet of the first jet pump <NUM> can be selectively closed so that the power fluid is forced back through the working fluid inlet of the first jet pump <NUM>. This allows for debris and blockages to be cleared from the first jet pump <NUM>.

Because jet pumps have no moving parts to experience mechanical wear, they can operate for several years at a low risk of failure and with minimal maintenance requirements. They also tend to be more rugged and tolerant of corrosive and abrasive well fluids. Jet pumps can handle significant volumes of free gas.

An example jet pump D, such as may be used for the first jet pump (<NUM> in <FIG>) and the second jet pump (40A in <FIG>) is shown in more detail in <FIG>. The jet pump D may comprise a diffuser having a converging inlet diffuser D3 and a diverging outlet diffuser D4. An outlet of the converging outlet diffuser D4 may be coupled through a return line to the mud system (<NUM> in <FIG>). A working fluid inlet <NUM> to the jet pump D may be in fluid communication with the wellbore fluid outlet (e.g., through a check or non-return valve <NUM> in <FIG>). Power or motive fluid may enter the jet pump D through a power fluid inlet. The power fluid may be supplied by pump <NUM> in <FIG> for the first jet pump (<NUM> in <FIG>) or from the gas source (<NUM> in <FIG>) for the second jet pump (40A in <FIG>). The power fluid is discharged in the interior of the ejector assembly D upstream of the converging diffuser D3 through a nozzle D2. The nozzle D2 serves to increase velocity of the power fluid so as to reduce fluid pressure at the working fluid inlet D1. A combination of the power fluid and the working fluid, e.g., the drilling fluid, maybe returned to the drilling platform (<NUM> in <FIG>) through a fluid return line.

The pressure at a diffuser outlet <NUM> (discharge) is related to the discharge static head and the discharge friction head. The discharge static head is related to fluid density. The fluid density can be reduced, for example, by injecting lower density fluids or gases into the fluid present at the discharge <NUM>. If a gas, such as nitrogen, is injected into the discharge line (e.g., <NUM> in <FIG>) the operating point of the jet pump will be changed. Thus adding gas into the jet pump discharge allows for the performance of the jet pump to be controlled, and such principle is used according to the present disclosure for the second jet pump (40A in <FIG>).

Managed pressure drilling systems and methods known in the art such as are disclosed in International Application Publication No. <CIT> include using a jet pump for controlling the level of mud in a drilling riser. However, the foregoing application publication does not disclose an apparatus or method for handling large drill cuttings and/or high volume of drill cuttings. Large drill cuttings can introduce operating difficulties in a jet pump as they rely on small nozzle and annular throat diameters (e.g., approximately <NUM> {<NUM> inch} for deep water drilling applications). It is likely that that drill cuttings exceeding this size may be present during drilling operations; without an effective means of dealing with such drill cuttings the jet pump will fail in its purpose of controlling mud level in the riser. The present disclosure provides a system able to handle large cuttings through the use of the rock catcher and separator (<NUM> in <FIG>) on the inlet from the riser (<NUM> in <FIG>) into the working fluid inlet of the first jet pump (<NUM> in <FIG>).

Referring once again to <FIG>, the performance of the first jet pump 40in improved by operating the second jet pump 40A such that the working fluid inlet of the second jet pump 40A is coupled to the working fluid outlet of the first jet pump <NUM>. Having the second, gas-operated jet pump 40A coupled to the working fluid outlet of first jet pump <NUM> reduces back pressure at the working fluid outlet of the first jet pump <NUM>. Reduced back pressure allows increased performance of the first jet pump <NUM> to be obtained utilizing the mud pump(s) <NUM> on the drilling vessel or platform <NUM>. Adding additional mud pumps to a drilling vessel may be cost prohibitive, and by using jet pumps as explained herein, a MPD system may provide capability to obtain extra performance out of existing drilling vessel equipment.

In some embodiments, and referring now to <FIG>, methods according to the present disclosure may be implemented automatically. Sensors for measuring certain parameters may be in signal communication with a controller or processor <NUM>. The processor <NUM> may be, for example, a microprocessor, microcontroller, programmable logic controller or any other device capable of controlling operation of one or more output devices in response to measurements made by one or more sensors. The sensors may comprise one or more pressure sensors <NUM> in fluid communication with the riser (<NUM> in <FIG>) to provide measurements related to pressure in the wellbore and fluid level in the riser. Flow and/or pump operating rate sensors <NUM> may be provided for the riser boost pump(s) (<NUM> in <FIG>), for the rig mud pump(s) (<NUM> in <FIG>) at <NUM>, for the riser fill pump (<NUM> in <FIG>) at <NUM>, for riser fluid level at <NUM>, for flow rate at <NUM> and for drill string segment connection and disconnection at <NUM>. The controller <NUM> may comprise programming and/or embedded instructions to control operation of the riser boost pump at <NUM>, the riser fill pump at <NUM>, the rig mud pump(s) at <NUM>, the annular pressure control device at <NUM> and a control rate signal for the gas injection system at <NUM>. Control of the foregoing components of the system may be performed according to various methods described below.

Methods according to the present disclosure for operating a MPD system may comprise the following. Particular components of the drilling system referred to by number in the following description may be observed in <FIG>.

Method <NUM>: Maintaining constant bottom hole pressure (CBHP) during "drilling ahead" (lengthening the well <NUM>) whether drilling over balanced, balanced or under balanced. Over balanced means the fluid pressure in the well exceeds fluid pressure of exposed formations penetrated by the well <NUM>. Balanced means that the well fluid pressure is the same as the formation fluid pressure, and under balanced means that the well fluid pressure is less than the formation fluid pressure.

Method <NUM>: Maintaining constant bottom hole pressure (CBHP) and ECD during tool joint (drill string segment) connections. During drilling operations, it is necessary from time to time to lengthen the drill string <NUM> by coupling therein one or more additional segments of drill pipe and/or drilling tools. During operations to retrieve the drill bit <NUM> for service or replacement, the entire drill string <NUM> may be removed from the well <NUM>. During such "making or breaking connections" operations, the rig mud pump(s) <NUM> are switched off and hydraulic connection between the mud pump(s) <NUM> and the drill string <NUM> are temporarily broken.

Method <NUM>: Isolate the first jet pump during well control operations.

Using the choke line <NUM> and the kill line <NUM> for the primary input fluid injection and output return line to the drilling vessel <NUM> means that these lines are unavailable to support well control operations while the first jet pump <NUM> is in use. To address this limitation, isolation valves are provided around the first jet pump <NUM> as shown in <FIG>. Once the isolation valves are closed, the first jet pump <NUM> is isolated from the choke line <NUM>, and the choke line <NUM> becomes available for well control operations. In addition, to make the kill line <NUM> available for well control operations, a valve on the inlet to the first jet pump <NUM> can be closed and an in line valve opened to make the kill line <NUM> available for well control operations.

Method <NUM>: Clear blockages and debris from the first jet pump.

Claim 1:
A method of controlling pressure in a well (<NUM>), comprising:
pumping fluid into a riser (<NUM>) extending between a drilling vessel (<NUM>) and a wellhead (<NUM>); and
pumping fluid out of the riser to the drilling vessel by operating a first jet pump (<NUM>) disposed in a conduit extending from the riser to the drilling vessel,
providing a second jet pump (40a) having a working fluid inlet in communication with a working fluid outlet of the first jet pump (<NUM>), and a working fluid outlet in fluid communication with the conduit;
supplying power fluid to the first jet pump by means of a power fluid pump (<NUM>) in fluid communication with a power fluid inlet of the first jet pump (<NUM>);
supplying power fluid to the second jet pump (40A) by means of a gas source (<NUM>) in fluid communication with a power fluid inlet of the second jet pump (40A); and
controlling the gas source (<NUM>) and the power fluid pump (<NUM>) to maintain a fluid level in the riser (<NUM>) at a selected elevation.