Well integrity/control

Managed-Pressure-Drilling Equipment Augments Deepwater Well Control

This paper describes how a technique known as applied-surface-backpressure managed-pressure drilling (ASBP-MPD) can alleviate the limitations of conventional deepwater well control.


This paper describes how a technique known as applied-surface-backpressure managed-pressure drilling (ASBP-MPD) can alleviate the limitations of conventional deepwater well control. The paper discusses equipment design and operating philosophy, outlining actions that can be taken to respond to an influx while remaining within the primary well barrier.

Conventional Well Control: Background and Limitations

Industry personnel are trained to follow conventional well-control-response steps when securing a well and closing a subsea blowout preventer (SSBOP) once an influx is detected. The steps are logical from the perspective of adhering to the operating requirements of existing well-control equipment. While variations in procedures exist between companies, the logic behind these steps remains consistent across the industry. The conventional steps are as follows:

  1. Stop rotating; pick up off bottom and space out
  2. Stop the mud pumps
  3. Conduct a static flow check
  4. Close the SSBOP

Conventional well-control response is limited by the design and operating philosophy of conventional well-control technology. The challenges associated with these constraints include a significant drop in bottomhole pressure (BHP), increased influx volume before the well is finally secured, and the amount of time needed to detect an influx. The initial confirmation of an influx can take a substantial period of time because of a variety of factors that can influence the return flow rate and mud-pit volumes.
On a deepwater rig, the interpretation of pit-volume and flow-rate changes can be subjective. To complicate matters further, conventional drilling rigs often are equipped only with inaccurate paddle flowmeters on the main flowline to measure flow out of the well; these do not offer a precise flow measurement.

The conventional well-control-response procedure does not seem adequate for the deepwater drilling environment when evaluated in terms of influx detection and response time, total influx volume, and reservoir drawdown. Furthermore, after the SSBOP is closed, the conventional well-control response is subject to significant residual risks in the form of stuck pipe, lost circulation from choke-line friction, and the exceeding of kick tolerance. Finally, closing the SSBOP does not address an influx that has been circulated into the riser undetected.

Circulating an Influx Past the SSBOP Undetected

Drilling into deeper water has resulted in an increase in riser lengths and the amount of hydrostatic pressure in the riser. A hydrocarbon influx taken at reservoir depths that has dissolved in oil- or synthetic-oil-based drilling mud may not break out of solution until it has been circulated up past the SSBOP. This scenario is different from a ­shallow-water drilling operation, wherein the bubblepoint of an influx is expected to be below the SSBOP. When such circumstances occur, an influx may be circulated up through the wellbore and into the riser without demonstrating the expansion behavior that would be expected from free gas in the wellbore. In this case, a gas influx is able to escape past the SSBOP without being detected.

An influx that breaks out of solution at shallow water depths and at high enough concentrations can result in a riser-unloading event in which a significant volume of drilling mud and gas is discharged through the rotary table in seconds with very little indication that the event is about to occur.

For lower-intensity gas-in-riser events in which the diverter packer may be closed in time, the end result is to divert drilling mud and hydrocarbons overboard, which can cause an environmental issue. Lining up the diverter to the rig’s separator is often no longer permitted by local regulators following the Macondo accident.

ASBP-MPD Equipment Overview

The limitations previously described can be addressed with ASBP-MPD equipment. The key components of an ASBP-MPD system are as follows and are described in detail in the complete paper:

  • Subsea (installed below the telescopic slip joint)
    • MPD riser-sealing system
    • MPD annular
    • Flow spool
    • Mud-return hoses
  • Topside
    • Distribution manifold
    • Choke and flow-out metering manifold
    • Flow-in metering
    • Control and data-acquisition system
    • Mud/gas separator (MGS) (optional)
  • Drillstring
    • Drillstring nonreturn valves (NRVs)

In an ASBP-MPD system, the capability of the primary barrier is enhanced to include rapid and accurate wellbore-pressure control with drilling chokes, accurate flow-in- and flow-out-rate measurement, and the security of a continuously sealed wellbore and riser during drilling.
When the subsea MPD riser seal or MPD annular is activated, flow is diverted to the topside MPD equipment through the subsea flow spool (Fig. 1) and mud-return hoses. At surface, a distribution manifold directs the riser flow to an MPD choke and a Coriolis-metering manifold. Following the MPD choke, returns are normally processed through a dedicated MPD MGS or the rig’s MGS and ultimately routed back to the shakers. Coriolis meters also are installed upstream of the rig pumps to measure mud density and flow rate into the well. Finally, drillstring NRVs prevent backpressure applied to the annulus from escaping through an open drillstring when the topdrive is disengaged.

Fig. 1—MPD annular and flow spool deployed in the moon pool (left); MPD annular general assembly (center) and flow-spool general assembly (right).

Improved Kick Detection With an ASBP-MPD System

With an ASBP-MPD system installed on a rig, the ability to detect kicks rapidly and confidently is improved when compared with conventional kick-detection systems and procedures. This is achieved by accurately measuring flow in and flow out by isolating the flow-out measurement from vessel heave. This results in both smaller influx sizes and a reduced reliance on a static flow check to reconfirm that an influx has occurred.

The placement of the MPD riser-sealing system below the slip joint isolates the flow-out measurement from changes in flow rate induced by vessel heave, which further enhances the speed at which the rig crew can identify and confirm that a formation-fluid influx has occurred. The use of Coriolis flowmetering also improves kick-detection speed.

Given the ability of the MPD kick-­detection system to distinguish between a change in flow out caused by a formation-fluid influx vs. wellbore ballooning or other operational factors, the rig crew has more confidence in overall event-detection capabilities. As a result, a conventional static flow check becomes obsolete.

Once an influx has been detected, an MPD-assisted shut-in can be implemented to reduce influx volumes while preparing to close the SSBOP.

MPD-enhanced kick detection and assisted shut-in offers several benefits.

  • Rapid and accurate kick detection eliminates static flow check and reduces influx volumes.
  • Rapid increase in wellbore pressure means influx volumes are reduced.
  • Drops in BHP before closing the SSBOP are eliminated.
  • Continuous seal-in of riser system offers protection from riser-gas events.

ASBP-MPD Influx Circulation Within the Primary Well Barrier

The use of ASBP-MPD equipment redefines the primary well barrier to include a closed circulating system with the ability to control wellbore pressure dynamically and rapidly. The operational limits of the primary well barrier, including the MPD system, are defined using an MPD operations matrix that details the maximum allowable surface pressure and influx volumes that can be circulated through the riser and MPD system before an event must be controlled by the secondary well-control system. With the ASBP-MPD system active, an influx that can be controlled within the primary well barrier may be removed from the well by using the MPD system, as opposed to prematurely resorting to the secondary well-control system.

Circulating the influx out of the well within the primary well barrier provides several advantages. First, excessive choke-line friction can be avoided, given that circulation is through the riser bore. Next, the risk of stuck pipe is reduced significantly because cuttings are circulated out of the wellbore continuously at higher flow rates than in conventional well-control techniques. Furthermore, the drillpipe can be rotated and reciprocated. Finally, the SSBOP is not worn from unnecessary closures.

If the primary well-barrier limits are exceeded at any time, the event is immediately turned over to secondary well control.

Performing an MPD influx circulation provides a significant opportunity to improve upon conventional well-control limitations.

  • Rapid and accurate kick detection eliminates static flow check and reduces influx volumes.
  • Rapid increase in wellbore pressure means influx volumes are reduced.
  • Continuous seal-in of riser system offers protection from riser-gas events.
  • Wear on SSBOP from unnecessary closure is avoided.
  • Excessive choke-line friction is eliminated because of circulation through the main riser bore.
  • The drillstring can be rotated and reciprocated while circulation is maintained, further reducing the risk of stuck pipe upon SSBOP closure.

Benefits of Deepwater Well Control With MPD Annular

The MPD annular enhances deepwater well control with the following benefits:

  • Once the MPD annular is closed, an MPD-assisted shut-in and dynamic MPD kick circulation may be performed.
  • During MPD riser-seal-assembly changeout, closing the MPD annular ensures a continuous wellbore seal, enabling MPD pressurized conditions and advanced kick detection.

The MPD annular is not intended to be closed in time to protect against a sudden riser-unloading event. Such events can occur in a very short period of time without notice. The most secure means of protecting against riser unloading is MPD with a continuously sealed wellbore using the MPD sealing system.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 186331, “Augmenting Deepwater Well Control With Managed-Pressure-Drilling Equipment,” by Austin Johnson, SPE, Brian Piccolo, Henry Pinkstone, SPE, Bo Anderson, and Justin Fraczek, SPE, AFGlobal, prepared for the 2017 SPE/IATMI Asia Pacific Oil and Gas Conference and Exhibition, Bali, Indonesia, 17–19 October. The paper has not been peer reviewed.