Manage Pressure Drilling Operation and Design Method

Managed Pressure Drilling with Constant Bottom Hole Pressure mode enables the development of an adaptive well design and safe operation(gas mud separator) by providing the following key points:

  1. Improved Kick Tolerance

Early Kick Detection by Coriolis Meter can reduce influx volume. Once MPD system detects the influx in “auto mode”, the system automatically increases back-pressure to stop the flow while drilling. Typical influx in MPD mode is less than 3 bbls.

  1. Improved Safety and Well Control

It mitigates the risk of exceeding MAASP with MPD because of smaller influx. Also it can enhance ability to safely circulate out gas in the riser.

  1. ECD Management

It enables to maintain the constant bottom hole pressure during drilling and connection. Adjusting MPD choke can manage the drilling safety margin.

MPD application with the adaptive CSG design will most likely eliminate at least one CSG, and has potential saving of two CSG strings, which represents significant cost saving.

The method introduced here is applicable to any deepwater well which has narrow drilling window. MPD application with Below Tension Ring (Rotating Control Device) on 6th generation dynamic positioning rig can develop real time CSG setting depth optimization with the management of bottom hole pressure in each hole section.


INPEX Offshore North West Sabah, LTD. operation team carried out 1st drilling campaign as operator for the first time in Malaysia from November 2014 until April 2015.

The drilled two exploration wells were located in the Block offshore Sabah state of Malaysia approximately 120km to 150km distant from northern coast line of Borneo Island. The Block expands to cover the area with water depth ranging from 200m to 1,800m, and our drilled two wells were located at points where water depth ranges from 960m to 1,250m. Because of deepwater condition and not many offset wells information, these wells could have the features of narrow drilling window and higher uncertainty of pore pressure – fracture pressure prediction. But the campaign recorded excellent health and safety statistics without experiences of any LTI, Medevac or formation hydrocarbon spill case on rig.

Decision to utilize MPD with CBHP mode

For this campaign, the semi-submersible Dynamic Positioning rig was secured by farming-in to the other Operator Company (hereinafter the Assigner)’s existing long term rig contract. The dedicated Rig Assignment Agreement was prepared and agreed between INPEX and the Assigner proceeding to the mobilization stage which enabled continuous back-to-back usage of rig between two companies also providing advantages of sharing common cost among parties and opportunities of sharing rig installed (or rig customized) third party service providers equipment subject to technical, economic advantage to each party. Besides that, the Assigner has already conducted study to modify the rig and held HAZOP as detailed engineering risk analysis for introducing MPD system to the rig.

Upon completing pore pressure – fracture gradient study by third party consultant, the opportunity to eliminate the intermediate drilling liner (i.e. 11-3/4″ liner) was considered significant if INPEX can successfully utilize MPD with CBHP mode for our drilling campaign to overcome some foreseen challenges. Comparing with the first case application of MPD to a particular rig by ourselves, such advantage that the Assigner had already conducted mechanical fittability engineering study and operation risk analysis together with those anticipated learning curve by MPD engineers and rig crew through the Assigner’s preceeding operation has encouraged our decision being made expeditely. Also, sharing the engineering study and customized subsea equipment (i.e. flow spool, adaptor spool for RCD components) manufacturing cost with them was also quite attractive to INPEX.

As INPEX desired to utilize MPD with CBHP mode, on the contrary to Pressurized Mud Cap Drilling mode to the Assigner applied to their wells, additional HAZOP was held focusing onto CBHP mode. Also specific MPD operational seminer and in-house training for rig crews, relevant third party engineers and INPEX personnel were conducted.

MPD with Constant Bottom Hole Pressure

In 2011, International Association of Drilling Contractors (IADC) declares that “MPD is an adaptive drilling process used to more precisely control the annular pressure profile throughout the wellbore”. IADC also defines its objectives as follows:

  • To ascertain the downhole pressure environment limits.
  • To manage the annular hydraulic pressure profile accordingly.

The term “MPD system” is commonly referred to the following 4 types of drilling support systems in the industry:

Returns Flow Control

  • Diverts flow away from rig floor, avoids closing the BOP.
  • Allows pipe movement while killing the well.

Constant Bottom Hole Pressure

  • Surface pressure applied to maintain bottom hole pressure.
  • Well closed-in on connections to compensate ECD.

Dual Gradient

  • Two fluid gradients used to control the well.
  • Mainly associated with deepwater.

Pressurized Mud Cap Drilling

  • Sacrificial fluid used to drill.
  • Cap fluid to maintain well control.

In conventional drilling, only two factors, that is, mud weight and friction force govern BHP namely by Equivalent Circulation Density with pumps on and Equivalent Static Density with pumps off within a mud window. MPD with CBHP mode can add one more factor of surface back pressure besides those two factors in the drilling system.

Generally, this MPD system is equipped with “Rotating Control Device (RCD)” and dedicated choke manifolds and these enable to change opened drilling fluid system (at flow line / mud return line) to semi-closed system with surface back pressure.

Advantages of MPD with CBHP mode

The followings are main advantages of MPD with CBHP mode:

  • Minimization of influx – MPD choke reacts to apply SBP automatically or manually once a kick is detected. If installed, Early Kick / Loss Detection system can also contribute to mitigate influx.
  • ECD/ESD management – MPD choke adjustment manages to maintain BHP within mud window (operation window).
  • Dynamic Leak-off test – Applying SBP enables to detect a weak point in open hole by causing leak-off of formation intentionally.
  • Reduction in reservoir damage – A control of BHP in minimum overbalance against pore pressure enables to minimize reservoir damage.

In addition to the above direct influence, if the requirement for kick tolerance can be relaxed by using Early Kick / Loss Detection system incorporated in this MPD system, there would be more room to deepen each CSG / liner setting depth (or even eliminate one or two CSG / liner string) compared with conventional CSG design.

Consequently, MPD with CBHP mode may enable the expansion of adaptable well design and safer operation by providing the features above.

MPD Equipment at the well-site

Piping and Instrument diagram of MPD with CBHP mode at the wellsite is shown in Figure 1. Coriolis flow meter was installed just after MPD choke as Early Kick / Loss Detection system. Rotating Control Device (RCD) was installed below the tension ring of the telescopic joint. Equipment layout at the wellsite is also shown in Figure 2.

Rotating Control Device

A RCD can seal the annulus around drill pipe during drilling and reciprocating by installing a bearing assembly. RCD together with MPD Manifold can contain mud flow under closed fluid loop with an additional function to apply surface back pressure (SBP). The type of RCD can be selected by a height clearance between BOP and rotary table for onshore rigs. If the RCD is installed above telescopic joint, that RCD does heave and the pressure ratings of the system shall be limited to the specifications of the rig’s telescopic joint. In order to apply more SBP by MPD with CBHP mode, RCD can be installed alternatively below riser tension ring.

The industry standard of RCD is defined in API SPEC 16RCD.

MPD Manifold

In order to apply or adjust SBP, a MPD Manifold contains an independent choke manifold. That choke manifold should consist of two chokes as redundancy and a bypass line in case of plugged choke situation. A Pressure Relief Valve (PRV) is also set up at immediate upstream of choke to release the pressure and divert return to Mud Gas Separator (MGS) or overboard line in case of abrupt pressure increase close to working pressure of surface system. If the bearing assembly is installed into RCD body, the return from the wellbore is diverted to shale shakers through this manifold, or directly to MGS in case of gas in riser situation by passing MPD Manifold. This manifold commonly has equipment as a faculty of Early Kick/ Loss Detection (i.e. Coriolis flow meter) which enables continuous monitoring the fluid flow inside closed loop and more importantly can minimize influx in a well control event.

Coriolis flow meter, also known as mass flow meter is a device that measures mass flow rate of a fluid traveling through a tube. The mass flow rate is the mass of the fluid traveling past a fixed point per unit time. The mass flow meter does not measure the volume per unit time (e.g., cubic meters per second) passing through the device; it measures the mass per unit time (e.g., kilograms per second) flowing through the device. Volumetric flow rate is the mass flow rate divided by the fluid density. If the density is constant, then the relationship is simple. If the fluid has varying density, then the relationship is not simple.

Drill String Isolation Tool / Wellbore Isolation Tool

Drill String Isolation Tool (DSIT) is unique to MPD system for subsea wells which have wellhead (or BOP) at mud-line. DSIT is similar to annular BOP by its mechanism, and made up below RCD body and above discharge line outlet. It enables isolating RCD from wellbore by closing DSIT. DSIT can be a short time back-up for RCD to apply SBP subject to no string rotation in case of RCD bearing assembly’s seal failure and is required to be changed out.

Feeding Pump (or Mud pump)

When SBP is applied by MPD choke, circulation of flow through that choke can be essential. While stopping standpipe flow, other circulation lines should be set up to keep MPD system active therefore an alternate flow source might be required. This source can be one of mud pumps, but a dedicated feeding pump and lines can be set up if it doesn’t allow so.

CSG Design with MPD system

Revised Kick Tolerance Requirement of MPD with CBHP mode

In original CSG design for our wells without MPD, it requires 11-3/4″ or 7″ drilling liner in both wells to reach planned well total depth full-filing the kick tolerance requirement. According to the technical records from MPD provider, MPD with CBHP mode with Early Kick / Loss Detection system enables to detect influx early and precisely then minimize the average influx volume to less than 3 bbls. For example in Indonesian field, the well could be shut-in within 1-2bbls of influx with SBP adjusted by MPD choke. With this advantage, the utilization of that MPD system can contribute in optimizing CSG setting depth, and even eliminating a CSG string for cost and time saving with safer operation. It can be interpretated that MPD with CBHP mode can reduce the kick tolerance requirement practically which will enable expanding the drillable depth with same numbers of CSG even with deepwater exploration wells.

The original CSG design and the revised CSG design sheets are shown in Figure 3 and Figure 4. In this case, the dispensation to our Corporate Standard was issued for approval to reduce the kick tolerance requirement with that MPD system down to 10bbls for all size of bore hole. And 11-3/4″ intermediate liner was considered as eliminatable in new CSG design to achieve well objectives.

Example of conventional CSG
Figure 3—Example of conventional CSG design under narrow drilling window
Example of new CSG design with revised kick tolerance requirement by MPD with CBHP mode under narrow drilling window
Figure 4—Example of new CSG design with revised kick tolerance
requirement by MPD with CBHP mode under narrow drilling window

Hydraulics and Kick Simulation

If there is a major concern of ECD at bottom hole or at any weak point in wellbore during circulation, borehole pressure simulation during circulation or at kick should be carefully conducted. The following key factors should be addressed through multiphase &thermos-dynamic flow simulation using MPD with CBHP mode:

  • Kick tolerance requirements
  • Kick intensity
  • Safety margin including choke margin for well control event and minimum surface pressure loss caused by MPD equipment and piping
  • Static mud weight for calculating kick tolerance
  • PVT model if OBM / SBM in use
  • Minimum overbalance requirement against pore pressure factored into mud weight (if mud hydrostatic is a temporary barrier requirement)

All assumptions should be agreed and cleary defined within operational organization and consistent throughout both planning and execution phase. Especially in those wells with long and deep open hole section with which MPD with CBHP mode is to be applied, geothermal effect may become critical in hydraulics simulation to check realistic ECD at CSG shoe or other weak point.

Operational Risk Management

In regards to installation of new system and its application, mitigations of new risks accompanied should be required. For this campaign, the following precautions were managed successfully:

  • MPD Procedures – To apply MPD, specific MPD related operation procedures were discussed among operational organization, drilling contractor, relevant third party engineers and MPD provider, and a manual to cover such procedures was issued by MPD provider customized for the campaign. Personnel roles and responsibilities for MPD operations were also detailed in the manual especially for any well control events which need immediate corrective actions.
  • Inhouse / On-site Training – The objectives of training are to understand the details of MPD and the procedures, to improve mutual communication on MPD operations at the rigsite. Inhouse training course for the personnel who will be involved in MPD operations was held prior to starting operations. Also on-site training course was arranged, this time along the course of MPD finger printing exercises where rig crew and MPD operator can practice the synchronization of pump rate and MPD choke control at various key operational situations together with conducting calibrattion of the MPD system pressure reading.
  • Risk Assessment – Separate risk registers were compiled and risk assessment was conducted for drilling (basis and details in well design) and logistics aspects upon conducting MPD dedicated HAZOP exercise.
3 sets Mud gas separator
Mud gas separators

Cost Analysis

Additional costs by introducing MPD system were estimated in planning phase, such as rig modification cost sharing with the Assigner and other consortium member, mobilization / demobilization and rental cost of MPD equipment including manpower fee. For cost saving side, if 11-3/4″ intermediate liner could be eliminated, total 4+ days of operation time reduction per well was expected in this campaign. From a potential hidden cost impact standpoint, it can also eliminate a few risks from unconventional operation with 11-3/4″ liner setting case, such as under-reaming 14-3/4″and 12-1/4″ hole, running and cementing 11-3/4″and 9-5/8″ liner with a narrow clearance etc.

Comparing the cost impact/saving as above, it seemed also attractive from economical standpoint to utilize MPD for our campaign and decision was made to adopt MPD by the operation team.

Operation Results with MPD system

This campaign was successfully completed without any personal injuries and in full compliance with local legislative HSE requirements. Although the narrower margin between actual pore pressure and LOT results than expected created difficult situation in management of wellbore pressure balance in intermediate and deeper hole sections, MPD with CBHP mode contributed a lot to extend drilling interval with minimizing influx and lost circulation events by adjusting SBP within a narrow margin to control BHP during drilling, connection and any other operation with RCD bearing seal activated.

The following points mentioned what was done successfully by MPD with CBHP mode in this campaign:

Minimizing influx – Coriolis flow meter proved its capacity to detect anomalies in flow even a small one in and out quickly and precisely, and that made MPD choke responded automatically to minimize influx as per original design. In most of kick events of both two wells, influx volume was less than 1 bbl. For the case that ballooning was suspected, influx was allowed to continue intentionally to check well behavior.

BHP management – Throughout operations, BHP was managed to maintain in narrow window. Especially in slim and deep hole, although the big difference between ECD and ESD was seen, appropriate SBP was successfully maintained during both drilling and connection.

Kick tolerance management – By utilizing MPD with CBHP mode, achieved the kick tolerance requirements to be relaxed to 10 bbls in all hole sizes upon a dispensation request was approved.

This also worked in decision to continue drilling with MPD installed when the actual LOT result in surface hole section was lower than expected.

Dynamic Leak-off test – MPD with CBHP mode enables dynamic LOT with increasing SBP temporality. It could be useful for drilling ahead to detect the weakest point which might cause down-hole losses in a drilled interval.

Improvement on MPD rig-up / rig-down time – Continuous improvement on MPD rigging up and down time could be seen. Total rig-up / rig-down time was estimated as 3+ days from the Assigner’s record, but in our campaign, it was actually +/- 2 days in each well. On the other hand, the following points described what could have been done better by MPD with CBHP mode in this campaign:

Real time CSG setting depth optimization – There could be an opportunity to manage CSG setting depth adjustment while drilling a section in a better way referring to a real time pore pressure estimation by third party consultant and dynamic LOT results. In actual situation, the real time pore pressure prediction accuracy was not good enough to raise a timely flag of marginal pressure envelope risk to the operation team which prevented CSG from being set at optimum depth in a few occasions. Dedicated plan to stop drilling ahead and to decide section TD should be established with hydraulics simulation.

Sensitive Coriolis flow meter – The sensitivity of Coriolis flow meter should be noted. For subsea wells, any crane activities, mud transfers, helicopter operations and any other weight balance movements should be communicated with MPD operator. Those could come out as any anomalies in the readings of that flow meter. A few times observed such false alarms could have been eliminated in the campaign if more stringent communication standard had been established between rig crews and MPD operators from the beginning.

Equipment failure / malfunction – Cement and formation cuttings blocked MPD choke line in larger hole section with high ROP. Potential mitigation measure would be slowing down ROP or reducing flow rate while drilling to avoid a lot of big cuttings or cement chunks coming up to surface at one time. And leakage through RCD bearing assembly was seen when in a few times immediately after assembly installation. The estimated cause was accidental ripping off of external surface O-rings of RCD bearing due to its tight clearance against rig’s telescopic joint or diverter flex joint. In addition, the lack of centralization of bearing assembly during its installation into RCD body. The detailed procedure was planned and established after try and error for installation and removal of RCD bearing assembly during operation, which could successfully improved the failure frequency onward.


INPEX Offshore North West Sabah, LTD. has utilized MPD with CBHP mode and drilled two deepwater exploration wells in offshore Sabah in East Malaysia. By that MPD system and review on technical records of MPD operation, the kick tolerance requirement was relaxed down and new CSG program was made which

could eliminate one CSG (liner) string based on the originally predicted pore pressure / fracture gradient envelope. In order to assure personnel competence in using MPD for well operations, MPD procedures, training courses and risk assessments were made in planning or execution phase. MPD with CBHP mode could detect kick and losses quickly and precisely with Coriolis flow meter and minimize influx volume by automated MPD choke adjustment. This feature combined with the SBP management during drilling and connection contributed in extending drilling depth in each hole section even under narrow pressure envelope condition. Consequently, introduction of MPD with CBHP mode could successfully achieve the target of exploration drilling in both two wells even under situation where actual pore pressure and fracture gradient envelope was revealed harsher than initially predicted.


BHP: Bottom Hole Pressure

BOP: Blow Out Preventer

CBHP: Constant Bottom Hole Pressure

CSG: Casing

DG: Dual Gradient

DP: Dynamic Positioning

DSIT: Drill String Isolation Tool

ECD: Equivalent Circulation Density

ESD: Equivalent Static Density

HAZOP: Hazard and Operability Study

IADC: International Association of Drilling Contractors

LOT: Leak Off Test

LTI: Lost Time Injury

MAASP: Maximum Allowable Annulus Surface Pressure

MGS: Mud Gas Separator

MPD: Managed Pressure Drilling

OBM: Oil Based Mud

PMCD: Pressurized Mud Cap Drilling

PRV: Pressure Relief Valve

RCD: Rotating Control Device

RFC: Returns Flow Control

ROP: Rate Of Penetration

SBM: Synthetic Based Mud

SBP: Surface Back Pressure

TD: Total Depth

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