Blow out Preventers

Subsea engineers are the crew that works with all the equipment and operations that are performed between the drill-floor and the seabed on floating offshore drilling rigs.?The “SUBSEA” crew is employed by the drilling contractor and is an integral part of the offshore operations.

Subsea Operations

The subsea crew is responsible for implementing and maintaining the structures, tools, and equipment used in the underwater components of offshore oil and gas drilling and production operations.

The underwater environment presents unique challenges to subsea engineers, particularly deepwater operations where temperature, pressure, and corrosion test the durability of submerged equipment and tools. Most subsea engineering operations depend on automation and remote procedures to construct, maintain and repair?components beneath the surface of the water.

To understand what tasks the subsea team is required to undertake we first need to explore the key structures between the seabed and the drill-floor that connect the drilling unit to the wellbore. There’s also a lot of technology hiding beneath the surface of the water. Starting from the seabed and working our way up to the drill-floor we’ll look at the subsea components that help us bring drill cuttings and potentially trapped hydrocarbons safely to surface.

With the deepest-water offshore well ever to be drilled lying in 3,400 m (11,155 ft) of water, it’s easy to see why a team of specialists needs to be employed to oversee the operations that happen beneath the waves.

Subsea Wellhead

The subsea wellhead system is a pressure-containing vessel that provides a means to hang off and seal off casing used in drilling the well. The wellhead also provides a profile to latch the subsea blowout preventer (BOP) stack and drilling riser back to the floating drilling rig. In this way, access to the wellbore is secure in a pressure-controlled environment. The subsea wellhead system is located on the ocean floor and must be installed remotely with running tools and drill-pipe

Figure 1 – Subsea wellhead

The subsea wellhead inside diameter (ID) is designed with a landing shoulder located in the bottom section of the wellhead body. Subsequent casing hangers land on the previous casing hanger installed. The casing is suspended from each casing-hanger top and accumulates on the primary landing shoulder located in the ID of the subsea wellhead. Each casing hanger is sealed off against the ID of the wellhead housing and the outside diameter (OD) of the hanger itself with a seal assembly that incorporates a true metal-to-metal seal. This seal assembly provides a pressure barrier between casing strings, which are suspended in the wellhead.

A standard subsea wellhead system will typically consist of the following:

·???????Drilling guide base.

·???????Low-pressure housing.

·???????High-pressure wellhead housing.

·???????Casing hangers (various sizes, depending on casing program).

·???????Metal-to-metal annulus sealing assembly.

·???????Bore protectors and wear bushings.

·???????Running and test tools.

The drilling guide base provides a means for guiding and aligning the BOP onto the wellhead. Guidewires from the rig are attached to the guideposts of the base, and the wires are run subsea with the base to provide guidance from the rig down to the wellhead system.

Subsea Blowout Preventer (BOP)?

There are two means to prevent an escape of high-pressure fluids or gases from the well when drilling for oil and gas.

The primary means is the hydrostatic pressure from the weighted up drilling mud and the second means is the blowout preventer. The BOP is literally the last line of defense in preventing a catastrophic event on the rig.

The BOP is an arrangement of valves, rams preventers, annular preventers, connectors, and control system that can be controlled from the surface to “shut-in” the well in the event of an impending blowout.

In addition to controlling the downhole pressure and the flow of oil and gas, blowout preventers are intended to prevent tubing, tools and drilling fluid from being blown out of the wellbore when a blowout threatens. Blowout preventers are critical to the safety of the crew, rig, and environment, and to the monitoring and maintenance of well integrity

Figure 2 – A Subsea BOP

With the wellhead just above the mudline on the seafloor, there are four primary ways by which a BOP can be controlled. The possible means are:

·???????Electrical Control Signal: sent from the surface through a control cable;

·???????Acoustical Control Signal: sent from the surface based on a modulated/encoded pulse of sound transmitted by an underwater transducer;

·???????ROV Intervention: remotely operated vehicles (ROVs) mechanically control valves and provide hydraulic pressure to the stack (via “hot stab” panels);

·???????Deadman Switch / Auto Shear: fail-safe activation of selected BOPs during an emergency, and if the control, power and hydraulic lines have been severed.

Two control pods are provided on the BOP for redundancy. Electrical signal control of the pods is primary. Acoustical, ROV intervention and dead-man controls are secondary.

An emergency disconnect system, or EDS, disconnects the rig from the well in case of an emergency. The EDS is also intended to automatically trigger the deadman switch, which closes the BOP, kill and choke valves. The EDS may be a subsystem of the BOP stack’s control pods or separate.

Pumps on the rig normally deliver pressure to the blowout preventer stack through hydraulic lines. Hydraulic accumulators on the BOP stack enable closure of blowout preventers even if the BOP stack is disconnected from the rig. It is also possible to trigger the closing of BOPs automatically based on too high pressure or excessive flow.

The subsea team

The subsea team is responsible for all maintenance and testing of the BOP and its ancillary equipment. Function tests are carried out frequently throughout the drilling program, especially prior to running “the stack” from the surface, and also prior to drilling through expected reservoir formations.

The drilling crew and subsea team run coordinated tests from both the drill-floor and the backup system’s control panel within the accommodation unit. Every rig must have a BOP control panel at the driller’s station as well as one in a safe location away from the drill floor.

Figure 3 – A BOP control panel

The members of a subsea team are generally recruited with an electrical or mechanical trade base or engineering degree and they then go through extensive training programs to familiarize themselves with the subsea operations. Because of the skills required to be able to competently do their job these crew members don’t start working offshore as an unskilled laborer like many of the drilling crew members generally do. Subsea operations are a highly specialized field and as such, highly specialized teams are required to perform the tasks involved.

It is also one of the most highly regulated areas in the offshore drilling industry due to the fact that failures in the system can result in catastrophic events, such as the Deepwater Horizon disaster. Being the last line of defense in the event of a blowout, it is critical that all the subsea equipment can be reliably called upon to shut the well in during a well control emergency situation.

Because the BOP is such a critical part of the process safety systems offshore, since the Macondo blowout there have been strict regulatory requirements imposed on the industry to ensure the operators have clear programs in place to identify potential hazards when they drill, clear protocol for addressing those hazards, and strong procedures and risk-reduction strategies for all phases of activity, from well design and construction to operation, maintenance, and decommissioning.

Adhering to these regulations requires certification of all subsea equipment from an independent third party regarding the condition, operability, and suitability of the BOP equipment for the intended use and the operator must have all casing designs and cementing program/procedures certified by a professional engineer, verifying the casing design is appropriate for the purpose for which it is intended under expected wellbore conditions.

Third-party verification and inspection organizations work with subsea equipment, specifically BOP and regulatory compliance audits, well-control, and drilling equipment inspections, to ensure the highest levels of integrity within the subsea well control system prior to it being deployed.

Adjoining the top of the BOP and connecting with the bottom of the marine riser is the lower marine riser package.

Lower Marine Riser Package (LMRP)

The LMRP – Lower Marine Riser Package – is the upper section of a two-section subsea BOP stack consisting of the hydraulic connector, annular BOP, ball/flex joint, riser adapter, jumper hoses for the choke, kill and auxiliary lines and subsea control modules. The LMRP interfaces with the BOP stack

Figure 4 – Subsea BOP control system

Blowout preventers must have completely redundant control systems on the BOP. These control systems are called pods and are designated Blue Pod and Yellow Pod in all systems, no matter which manufacturer. They can be found on the lower marine riser package and are extensively function tested prior to the deployment of the BOP.

There can be as many as six emergency systems in a BOP to operate critical functions in the case of the loss of the primary control system:

1.???Emergency Disconnect Sequence?(EDS) – In a case where a dynamically positioned rig has lost the station-keeping ability, the EDS is a one-button system that allows the wellbore to be secured by closing the shear rams. The hydraulic functions to the lower BOP are then vented and the LMRP is separated from the lower BOP by unlatching the connector. An over‐pull is preset on the riser tensioners and the LMRP lifts from the lower BOP. A riser recoil system prevents a slingshot effect. After the EDS button is activated, the sequence takes about 55 seconds maximum.

2.???Acoustic systems?– A limited number of emergency functions (typically shear rams and LMRP connector) can be operated from the rig using a hydrophone transmitting to transducers on the BOP. It is uncertain if these systems will work in a well-control situation where considerable noise is generated from flow in the wellbore.

3.???Remote operated vehicles?(ROVs) have pumps which can operate functions through a ‘hot stab’ plugged into a dedicated receptacle in the panel. The limitation of an ROV is the time to deploy from the rig to the seabed and the limited flow rate of their pumps.

4.???Deadman?systems?will close the shear rams in the event all hydraulic and electric control is lost on the BOP. This would typically only happen if the riser string parted. In deepwater if the riser is lost, then the hydrostatic pressure of the drilling mud, which is needed to contain wellbore pressure, would be reduced as it is replaced by seawater. Closing the shear rams secures the well.

5.???Automatic Disconnect System?(ADS) closes the shear rams when the lower flex joint reaches a preset angle.

6.???Autoshear?closes the shear rams in the event the LMRP is unintentionally disconnected.

The BOP and LMRP are run subsea using the “marine drilling riser” after the top part of the well has been drilled, the conductor casing has been cemented and the wellhead has been landed.

Marine Drilling Riser and Marine Riser Tensioner

A marine drilling riser is a conduit that provides a temporary extension of the subsea oil well to the drilling rig. The “riser” has a large diameter, low-pressure main tube with external auxiliary lines that include high-pressure choke and kill lines for circulating fluids to the subsea blowout preventer (BOP), and usually power and control lines for the BOP

Figure 5 – A drilling riser

When used in water depths greater than about 20 meters, the marine drilling riser has to be tensioned to maintain stability.

A marine riser tensioner located on the drilling platform provides a near-constant tension force adequate to maintain the stability of the riser in the offshore environment. The level of tension required is related to the weight of the riser equipment, the buoyancy of the riser, the forces from waves and currents, the weight of the internal fluids, and an adequate allowance for equipment failures.

The marine riser is kept in tension with large pistons operated with an air/oil system at pressures up to 3,000 psi. The riser may be connected via a tensioning ring to wire rope, which is reeved over sheaves on the pistons, or the pistons may be connected directly to the riser tensioner ring

Figure 6 – Riser Tensioner

Once the BOP stack has been successfully run to the seabed with the marine riser and latched onto the wellhead, it will undergo another series of function tests to determine its operability under water-depth conditions.

The density of water can cause problems that can increase dramatically with depth. The hydrostatic pressure at the surface is 14.6 psi (pounds per square inch) but this increases by this amount for every 10 meters of water depth. For a deepwater well that has the wellhead on the seabed in 2,000 meters of water, you would expect to find the hydrostatic pressure acting on the BOP to be around 3,000 psi.

When you also consider the water temperature to be close to 0° Celsius then you can imagine the type of hostile environment these safety-critical components have to function under. Making equipment that can operate under these conditions is the job of the manufacturer’s design engineers,?and making sure they work and keeping them well maintained is the responsibility of the subsea engineers onboard the rig.

Troubleshooting difficult BOP issues generally require collaboration between the design engineers onshore and the subsea engineers and the maintenance crew involved in the offshore operations. When subsea function tests fail then the entire BOP stack and riser string has to be pulled up to the surface so physical examination of the unit can take place.

This is a very time-consuming and costly exercise and therefore making sure everything is functioning 100% before running it down to the seabed is imperative. As anyone who has ever worked offshore knows, it’s all-too-common for BOP’s to fail function tests and this is why such strict regulatory conditions have been placed on the subsea components used for the drilling of offshore wells, especially in deepwater and ultra-deepwater wells. Once the BOP has been successfully tested it’s time to drill ahead!

Elon Chaves