9.2.5: The Well Control System (Blowout Prevention System)

The Well Control System, commonly known as the Blowout Prevention System, serves as a critical safeguard on drilling rigs to avert uncontrolled and potentially disastrous releases of high-pressure fluids—such as oil, gas, or saline water—emerging from subterranean layers. These hazardous fluid discharges are termed as Blowouts. Given the volatile characteristics of oil and gas, even a minor spark on the rig's surface can set off an explosion, leading to catastrophic consequences. One of the most notable incidents, the Mocondo Well disaster, exemplified this threat, as it resulted from an explosive blowout and the failure of the Well Control System. This tragedy claimed the lives of eleven crew members aboard the Deep Water Horizon Rig on April 20, leading to an alarming spill of 35,000 to 60,000 barrels of crude oil per day into the Gulf of Mexico, an episode we will explore further in this section.

For further insights, feel free to check out the Subsea Blowout Preventer Manufacturer.

The comprehensive rig diagram in Figure 9.02e demonstrates that the well control system consists of:

• the Accumulator (Item 18)
• the Blowout Preventer (not depicted in Figure 9.02e)

Figure 9.02e: Well Control System in a Modern Rotary Rig

Source: Serintel: Oil and Gas Portal Drilling Technologies

A depiction of a Blowout Preventer (abbreviated as BOP) is presented in Figure 9.11.

Figure 9.11: Blowout Preventer

Source: Gulf of Mexico Oil Spill Blog - Blowout Preventer Evidence

The blowout preventers constitute the primary component within the well control system, utilizing hydraulic operations; pressurized fluids are employed to activate pistons and cylinders that manage the opening or closing of the BOP valves. The Accumulators (Item 18 in Figure 9.02) function as storage units for pressurized, non-explosive gases and hydraulic fluids necessary for the hydraulic systems onboard the rig. They contain sufficient compressed energy to operate the blowout preventers even in the event of a power failure on the rig.

Essentially, a blowout preventer is an intricate system of valves, each designed to isolate the well's subsurface from the rig, thereby enabling effective well control. Typically, these valves are stacked in a configuration shown in Figure 9.11, located beneath the rig floor for onshore and some offshore wells, or placed on the seabed for other offshore installations.

A schematic illustration of a blowout preventer is presented in Figure 9.12.

Figure 9.12: Schematic Diagram of a Blowout Preventer

Source: OGES - Knowledge Market for Oil & Gas BOP Pressure Testing Procedure

Figure 9.12 features three types of valves (among others): Annular Preventer, Blind Rams, and Shear Rams. The Annular preventer, located atop the BOP in Figure 9.11, is designed to impede flow through the annular space between the drill string or casing and the annular preventer itself. Additionally, the annular preventer can accommodate non-cylindrical pipes such as the kelly or open holes. It consists of a doughnut-shaped bladder that permits rotation of the drill pipe when in the open position, while sealing the annulus in its closed position. Figure 9.13 illustrates the operation of the annular preventer.

In Figure 9.13, the blue zone signifies the doughnut-shaped bladder. As referenced, when the bladder is in the open (A) position, the drill pipe can rotate or be moved vertically; conversely, when in the closed (B) position, the bladder extends outward, sealing off the drill pipe, kelly, or open space. While the bladder-based sealing mechanism is not as effective as ram-type sealants, most blowout preventer assemblies will incorporate at least one annular preventer.

Schematics of ram-type preventers, including blind rams, shear rams, and pipe rams (the latter not detailed in Figure 9.12), are depicted in Figure 9.14.

Figure 9.14: Schematic Diagrams of Ram-Type Preventers

Source: Greg King © Penn State, licensed CC BY-NC-SA 4.0

This illustration indicates that:

• Blind rams isolate both the pipe and the annular space by crushing the pipe shut;
• Shear rams isolate both the pipe and the annular space by shearing off the pipe when engaged;
• Blind shear rams effectively isolate both the pipe and the annular space by cutting and crushing the pipe when closed;
• Pipe rams isolate the annular space by encircling the pipe when engaged.

A blowout initiates as a Kick (the ingression of formation fluids into the wellbore). The primary difference between a kick and a blowout lies in control; while a kick is manageable, a blowout is not. Previous discussions have introduced two means of defense against kicks, which were described in reference to drilling fluids, highlighting their objectives:

For more details, please refer to our site at BOP Control System.

• Control formation pore pressures to ensure desired well control (applying hydrostatic and hydrodynamic pressures that exceed formation pore pressures to prevent fluid ingress into the wellbore);
• Establish an impermeable filter cake on wellbore walls to further inhibit fluid migration from permeable formations into the wellbore.

In terms of the first quoted objective, if the pressure from the drilling mud remains greater than the pore pressure, we can be assured that the fluids will move towards the formation rather than into the well. However, this isn't always guaranteed. For instance, if we inadvertently drill through a natural fracture or if our mud density is excessively high, leading to formation fracture, we might lose significant amounts of drilling fluid into that fracture (Lost Circulation). In such situations, we may only apply a fraction of the oil column’s height, which will exert comparatively lower pressure on a secondary porous formation.

The second quoted objective points to the strategic application of an impermeable Drill Cake (filter cake) across a permeable formation. With a slightly Underbalanced Pressure (where drilling fluid pressure is lower than formation pressure), a seal connecting the wellbore and formation is created; however, this does not constitute a Failsafe System since higher formation pressures can dislocate the filter cake beyond certain underbalanced pressure thresholds.

While the previously discussed methods aim to mitigate the occurrence of kicks, their effectiveness can vary, meaning that kicks may still transpire. Common causes of a kick include:

• Insufficient mud weight (density): The hydrostatic pressure exerted by the mud column fails to surpass formation pore pressure;
• Erroneous mud replacement during tripping: During tripping out of the hole, mud volumes should be pumped into the wellbore to replace the drill pipe being extracted at adequate rates;
• Swabbing: Rapid removal of drill pipe from the wellbore can create negative pressure (suction);
• Cut mud: The entry of gas into the wellbore could reduce the wellbore pressure gradient;
• Lost circulation: Significant quantities of drilling fluid entering into the subsurface formations (due to high permeability, natural fractures, or drilling-induced fractures) can also lead to reduced weight and height of the mud column.

To identify potential kicks, look for these indicators:

• Increase in returns flow rate of drilling fluid at constant pump rates (primary indicator): A heightened flow rate suggests formation fluids entering the wellbore, thus signifying a likely kick. Furthermore, during gas kicks, the compressible nature of gas can cause bubbles to expand as they travel upwards, correlating to decreased hydrostatic pressures.
• Increase in mud volume in the mud pit without additional drilling fluid inputs (primary indicator): An unexpected increment signals formation fluids' entry into the wellbore, suggesting a kick.
• Continued drilling fluid returns despite pump shutdown (primary indicator): If drilling fluid keeps flowing after shutting off the mud pumps, it indicates that formation fluids are displacing the mud.
• Improper wellbore fill-up or volume balance during trips (primary indicator): If withdrawing the drill pipe alters the mud pit volume inadequately, it is a strong kick sign.
• Decrease in pump pressure and increase in pump output (secondary indicator): If lighter fluids replace heavier drilling fluid in the annulus, pump pressure will drop, leading to increased pump strokes.
• Apparent weight-on-bit fluctuations (secondary indicator): Unexplained variations in the weight-on-bit indicator may reflect the buoyancy shift caused by wellbore fluid density changes—occurring if lighter formation fluid displaces denser drilling fluid.
• Drill Break or Bit Drop occurrences (secondary indicator): Sudden shifts in drilling rates may indicate natural fracture systems in the drilled formations, recorded in drilling logs. For instance, in a previous field, I encountered a 12-meter (~36 ft) bit drop due to drilling through a naturally fractured reservoir causing cavern formation.
• Reduction in mud weight (secondary indicator): Observations of decreased mud density at the rig site by the Mud Man might signal a kick.

Once a kick is detected, the Operating and Drilling Companies implement specific, well-tailored protocols to prevent a controllable kick from evolving into an uncontrollable blowout. While the specifics vary, they typically comprise:

1. Ceasing drill pipe rotation.
2. Raising the drill bit off the bottom and Spacing Out (wherein the top of the drill string remains several feet above the rig floor to ensure the BP valves can close properly).
3. Halting mud pumps and checking for ongoing Mud Returns.
4. If returns persist:
   
   1. Shut in the well with the annular preventer or pipe rams:
      
      1. Hard shut-in (as shown by the closed choke in Figure 9.12)
      2. Soft shut-in (open choke in Figure 9.12)
   2. For hard shut-ins, reopen the choke.
   3. Weight Up (adding weighting agents) to achieve desired density—this is the Kill Fluid employed to Kill the Well).
   4. Circulate the kill fluid down the wellbore and out of the choke using established methods:
   1. The Driller's Method
   2. The Weight and Wait Method

Alternate procedures will apply if the kick happens during tripping. The details of handling hard or soft shut-ins and circulation methods, namely The Driller’s Method and The Weight and Wait Method, will be elaborated upon in subsequent drilling courses. It is essential to highlight that for each operation, there will be Daily Safety Meetings dedicated to discussing the well's status and crucial safety factors relevant to drilling activities.

Summarizing, the function of drilling fluids in exerting pressure on permeable formations and forming an impermeable filter cake to prevent kicks, alongside the blowout preventer's role and company protocols, form a robust strategy against blowouts. But how do these blowouts occur in the first place?

Consider the infamous Macondo Blowout incident aboard the Deep Water Horizon rig—this event marked the most extensive oil spill in the Gulf of Mexico. When tragedy struck, eleven crew members lost their lives due to a gas explosion.

Figure 9.15: Drill Pipe Spaced Out to Close Blow Out Preventers

Source: Greg King © Penn State, licensed CC BY-NC-SA 4.0

The YouTube video titled "Deepwater Horizon Blowout Animation" (duration 11:22) provides insights into the disaster and its causes.

After comprehending the essentials of offshore drilling rigs, crew operations, drilling rig components, kicks, and blowouts, I suggest watching the film "Deep Water Horizon." Use your knowledge of oil and gas drilling to analyze the movie’s technical elements and consider the following questions:

• What type of offshore drilling rig was represented in the Deep Water Horizon?
• What category of well was drilled (exploration, appraisal/delineation, or development well)?
• Who were the principal characters among the rig crew (both the 'good guys' and 'bad guys')?
• Which companies (operating, drilling, or service) employed these characters?
• What were the underlying causes of the disaster?
• Why were Cement Bond Logs and pressure-testing cement critical in avoiding this catastrophe?
• What elements were portrayed realistically, and which were dramatized for effect?