Systems and processes for subsea marine managed pressure operations. One system includes a modified riser joint configured to fluidly connect inline with one or more riser joints. The modified riser joint and the one or more riser joints are connected to form a riser connecting a floating vessel with a wellhead. The system further includes a subsea pressure management sub-system configured to be operatively and fluidly connected to the modified riser joint at a subsea location.

The present invention relates to a riser system in the form of a pumped riser (1), i.e. a riser (1) having an outlet (6) from the riser (1) at a depth below the surface (S) of a body of water, where the outlet (6) is coupled to a return pump (7) to return fluid from the riser (1) to the surface (S), and various operational methods to facilitate greater versatility when performing hydrocarbon drilling related operations. The arrangement also comprises a sealing element (15, 16) to seal an annulus (5) of the riser (1), and a by-pass (17) around the sealing element (15, 16). Various methods makes it possible to switch between open mode and closed mode, and vice versa, monitoring leakage across the sealing element (15, 16), as well as performing other operations exploiting the advantages of the two different modes.

In a method for quantifying a volumetric flow rate of a flow of drilling mud in a floating structure for subsoil drilling, a flowmeter and a detection device are provided on a floating structure for subsoil drilling. The flowmeter generates a flow signal. The detection device generates a heave signal representative of a vertical heave of the floating structure. A processor transforms the flow signal into a first spectrum in the frequency domain and the heave signal into a second spectrum in the frequency domain. The processor compares the first spectrum with the second spectrum, obtaining a resultant spectrum. The processor transforms the resultant spectrum into a resultant signal in the time domain. The processor determines a mean value of the flow signal, adds the resultant signal to the mean value, obtaining a quantification of a flow of drilling mud in the floating structure.

A downhole tool for cleaning and sealing a wellbore includes a wash tool configured at a downhole end of the downhole tool to generate pulses of a first fluid at a first frequency and a first pressure for washing a target interval of a wellbore. The downhole tool further includes a plugging tool configured uphole or downhole from the wash tool to generate pulses of a second fluid at a second frequency and a second pressure for depositing a sealing plug at the target interval of the wellbore. The second fluid has a higher viscosity than the first fluid, the second frequency is lower than the first frequency, and the second pressure is higher than the first pressure.

A double-layer coiled tubing double-gradient drilling system, on the basis of conventional drilling equipment, includes a double-layer coiled tubing system, spacer fluid, a downhole lifting pump system, throttling control systems and a data monitoring system. Power fluid enters an annular space of the tubing through an adapter, passes through a downhole lifting pump, enters an inner pipe through a bridge channel, and enters the bottom hole through the drill bit. Return fluid enters an annular channel of the tubing through a recovery hole, then enters the inner pipe through the bridge channel and enters the lifting pump, and then enters a solid control system through the adapter and the control systems in sequence. Gradient control of the bottom hole pressure is realized through monitoring of the spacer fluid and control of the drilling pump unit and throttling control systems. The problem of narrow safe drilling density window is solved.

The equivalent circulating density (“ECD”) in a wellbore may be managed during a wellbore operation using ECD models that take into account the rheology of the wellbore fluid and the rotational speed of tubulars in the wellbore. For example, a method may include rotating a rotating tubular in a stationary conduit while flowing a fluid through an annulus between the rotating tubular and the stationary conduit; calculating an equivalent circulating density (“ECD”) of the fluid where a calculated viscosity of the fluid is based on an ECD model ?_eff=f(? ?_eff)*h(Re), wherein ?_eff is the viscosity of the fluid, ? ?_eff is an effective shear rate of the fluid, and Re is a Reynold's number for the fluid for the rotational speed of the rotating tubular; and changing an operational parameter of the wellbore operation to maintain or change the ECD of the fluid.

Systems and processes for subsea marine managed pressure operations. One system includes a modified riser joint configured to fluidly connect inline with one or more riser joints. The modified riser joint and the one or more riser joints are connected to form a riser connecting a floating vessel with a wellhead. The system further includes a subsea pressure management sub-system configured to be operatively and fluidly connected to the modified riser joint at a subsea location.

A method comprises measuring a first external pressure within an annulus formed between a wellbore and a drill string disposed therein, where the first external pressure is measured by a first external pressure sensor. A fluid is pumped through the drill string into the annulus so as to move any cuttings in the annulus above the first external pressure sensor. A first internal pressure is measured within the drill string by a first internal pressure sensor. The first external pressure sensor is disposed between the first internal pressure sensor and a bottom of the wellbore.

A method for modifying a return fluid in a wellbore comprising disposing at least one valve along a drill pipe section of a drill string in the wellbore. At least one parameter of interest is determined at at least one location along the wellbore. At least one valve is controllably actuated to discharge at least a portion of at least one fluid from inside the drill string to an annulus in the wellbore to modify a local property of the return fluid in the annulus based at least in part on the measured parameter of interest.

The present invention provides a method and equipment for optimizing hydraulic parameters of deepwater managed pressure drilling in real time. The method comprises: acquiring overflow parameters in the current drilling process, performing preprocessing and feature extraction on the overflow parameters, and inputting the overflow parameters into trained support vector machine identification models for overflow judgment. If overflow occurs at the current drilling depth, reducing an opening of a throttle valve and increasing a displacement of a submarine pump, measuring a wellhead back pressure and calculating a bottom hole pressure, and judging whether overflow continues is performed. If overflow continues, mixing high-density drilling fluid with the original drilling fluid, pumping the mixture into a wellbore annulus, and performing the above operations of reducing the throttle valve opening, increasing the displacement of the submarine pump, calculating the bottom hole pressure and judging whether overflow continues is performed until overflow no longer occurs.