1. MPD system architecture and common layouts

1.1 Minimal / Basic MPD package

A basic MPD package includes a Rotating Control Device (RCD), a choke (often manually operated), flow metering, an enclosed flowline routed to a separator or approved diversion point, and basic pressure-relief arrangements.
The minimal package commonly also installs a non-return/float valve or retention trap where required and a safe, routed path for flaring or venting to meet site HSE plans.
This configuration is suitable for limited surface back-pressure control or to convert a conventional rig to basic closed-loop capability. Still, it lacks automation, redundant safety devices, and advanced gas-handling required for higher-risk wells.

1.2 Standard MPD package (typical industry configuration)

The standard package adds an automated choke manifold with actuators and both local and remote controls, calibrated flow meters, a separator, gas handling equipment, and an MPD Programmable Logic Controller (PLC)) / Human-Machine Interface (HMI) or control workstation.
Safety items must be explicitly defined and implemented, including pressure relief valves (PRVs) or relief routing, actuator fail-safe logic, emergency shutdown (ESD) interlocks, and documented testing and maintenance procedures formed from a HAZOP/FMEA study.
Standard packages should include documented calibration, instrument traceability, and procedures for commissioning, periodic functional testing, and operator competency verification.

1.3 Full / Integrated MPD (rig-integrated / advanced)

Fully integrated MPD systems are engineered to interface with the rig’s automation and control network (driller’s console/Cyberbase/rig SCADA), provide redundant choke and PRV control, and include diagnostics and formal acceptance testing before use.
These systems regularly implement closed-loop control modes, real-time predictive hydraulics or model-predictive controllers, and additional redundancy when MPD is credited as a primary or co-primary well barrier.
Integrated installations require a documented integration plan, a cyber/controls interface specification, and formal verification (HAZOP/FMEA) demonstrating safe operation with BOP and rig control systems.

2. Software, automation, modeling, and control logic

2.1 Integration and control platforms

MPD control software commonly integrates with rig automation and SCADA platforms using PLCs, OPC-UA, or similar industrial interfaces to share pump, choke, and sensor data and to provide an HMI at the driller’s console.
System integration should be scoped and tested during planning to ensure deterministic data exchange, correct command authority (who can move the choke), and safe handover procedures between the MPD operator and the driller.

2.3 Typical real-time inputs (required signals)

Field MPD systems should capture, time-synchronize and record: pump flow and stroke counts, pump pressures and standpipe pressure, choke line/annular pressure, separator/flare pressure, flow-out, calibrated flow-meter outputs, choke position and actuator health, PRV state, mud density and rheology parameters, gas detectors/riser gas readings, measured string displacement/hookload and ROP, and computed ECD/ESD channels.
All channels must include synchronized timestamps and adequate sampling frequency so transient events (for example, short kicks or rapid gas influx) can be detected and analyzed.

2.4 Control modes and algorithm types

MPD controllers typically support multiple modes such as CBHP (Constant Bottom-Hole Pressure), ESD/Equivalent Static Density control, manual mode, and operator-assisted modes; the selected mode must be recorded and displayed on the HMI.
Automatic CBHP and ESD modes calculate the required surface backpressure using real-time hydraulics (pump rate, fluid properties, annular geometry), along with control algorithms such as PID or more advanced model-predictive / feed-forward, and feedback controllers.
Advanced systems combine real-time measurements with predictive transient hydraulics to compensate for dynamic effects such as pipe movement (heave), changes in friction factor, non-Newtonian mud rheology, and varying gas content.

2.5 Compensation and modeling requirements

For floating rigs and riser operations, MPD designs must accept heave/position inputs and use transient-aware models to avoid incorrect BHP setpoint responses during riser motion.
When drilling fluids are non-Newtonian, the MPD control system must include appropriate rheology models (yield stress, shear-thinning) to ensure ECD calculations used by the controller are representative of downhole conditions.

3. Alarm, safety logic, and functional assurance

3.1 Alarming and safe states

MPD systems must implement multi-level alarm logic (pre-alarm and trip alarms) with clearly defined operator actions and documented automatic safe states that the system moves to on loss of control or communication.
Safety functions should include manual overrides for the choke actuator, PRV fallback paths, instrument redundancy, and watchdogs to detect and respond to control or sensor failures.

3.2 Safety lifecycle and verification

The design, acceptance testing, and operational use of MPD must be supported by formal safety studies (HAZOP or equivalent), FMEA, documented operational limits, and a verification/testing schedule that includes commissioning and periodic functional testing.
Where MPD is credited as a primary barrier, additional redundancy, traceability, PRV discharge routing, and certification requirements apply and must be satisfied before operations begin.

4. Data logging, post-job analysis, and continuous improvement

4.1 Data quality and retention

MPD operations require time-synchronized, high-frequency recording of raw and derived channels (pressure, flow, choke position, pump strokes, gas readings, and mud properties) with calibration and instrument-traceability records.
Data retention and secure archival must comply with operator and regulatory requirements to ensure logs are available for incident investigation, regulatory reporting, and lessons-learned activities.

4.2 Uses of MPD logs

MPD logs are used for forensic analysis of kicks and losses, validation and tuning of predictive hydraulic models, reservoir/formation evaluation, and to improve future well designs and MPD procedures.

5. Practical operational recommendations (field checklist)

Carry out a HAZOP or equivalent risk assessment specifically for the planned MPD mode and obtain documented acceptance before mobilizing equipment.
Confirm control authority and handover procedures between the driller and MPD operator in writing and display the active control mode clearly at the driller’s console.
Verify instrument calibration, choke actuator local/remote switching, PRV setpoints, and relief routing during pre-job checks and again after commissioning.
Ensure that all relevant signals are time-synchronized, that sampling rates capture transients, and that a secure copy of raw data and derived channels will be archived.
Train personnel on MPD modes, alarm responses, and emergency procedures, and rehearse handover and failure-mode drills during mobilization.

References

API RP 92M — Managed Pressure Drilling Operations with Surface Backpressure (API recommended practices).
IADC Guidance for UBO and MPD Techniques for Land Operations (IADC guidance aligned to API RP-92).
American Bureau of Shipping (ABS) — Managed Pressure Drilling Guide (classification & certification guidance).
NOV — MPD products, and NOVOS rig integration materials describing MPD-to-rig automation practices.
BSEE and SPE / OnePetro technical case studies and papers on MPD modes, data uses, and forensic analysis.