Monitor Systems Engineering: Blow Out Preventer Control System (BOP)

Blow Out Preventer Control System (BOP)

 

Monitor System's BOP Blow Out Preventer Control System provides clients with a highly reliable interface to well control, comprising a unique slim-line panel design developed using the very latest in leading-edge technology for operating in hazardous areas. The panel unit provides easy front access for maintenance purposes and is specifically designed to enable straightforward integration into old or new pneumatic / hydraulic interfaces. The BOP Control System is custom designed to suit all individual requirements.

 

 

 

Case Study

 

Blow Out Preventer Control System (BOP)

 

Overview: The BOP Control System designed and installed for Transocean's 714 rig was developed to integrate with their existing onboard field equipment. The system included a Driller's BOP control panel, a Tool Pusher's mini control panel and an Interface Panel to the Koomy Unit. In addition, there were Control Stations fitted to the aft and forward lifeboat muster points. All control and alarm signals were also integrated to the rig's Data Management System.

 

By upgrading to Monitor's BOP Control System, the client incurred less cost as the integration utilised existing pneumatic control panels and most existing cabling. This critical piece of safety equipment also provides a high level of ongoing availability and essential reliability ensuring low levels of costly operational downtime. Customer: Transocean.

 

 

 

Further Reading

 

Overview: A blowout preventer control system (BOP) is a large, specialized valve used to seal, control and monitor oil and gas wells. Blowout preventer control systems (BOPs) were developed to cope with extreme erratic pressures and uncontrolled flow (formation kick) emanating from a well reservoir during drilling. Kicks can lead to a potentially catastrophic event known as a blowout. In addition to controlling the downhole (occurring in the drilled hole) pressure and the flow of oil and gas, blowout preventer control system (BOP) are intended to prevent tubing (e.g. drill pipe and well casing), tools and drilling fluid from being blown out of the wellbore (also known as bore hole, the hole leading to the reservoir) when a blowout threatens. Blowout preventer control systems (BOPs) are critical to the safety of crew, rig (the equipment system used to drill a wellbore) and environment, and to the monitoring and maintenance of well integrity; thus blowout preventer control systems (BOP's) are intended to be fail-safe devices.(Blow Out Preventer Control System BOP, oil and gas industry)

 

The term BOP (an initialism rather than a spoken acronym, i.e., pronounced B-O-P, not "bop") is used in oilfield vernacular to refer to blowout preventers.

The abbreviated term preventer, usually prefaced by a type (e.g. ram preventer), is used to refer to a single blowout preventer unit. A blowout preventer control systems (BOPs) may also simply be referred to by its type (e.g. ram).

 

The terms blowout preventer, blowout preventer stack and blowout preventer system are commonly used interchangeably and in a general manner to describe an assembly of several stacked blowout preventers of varying type and function, as well as auxiliary components. A typical subsea deepwater blowout preventer control systes (BOP) includes components such as electrical and hydraulic lines, control pods, hydraulic accumulators, test valve, kill and choke lines and valves, riser joint, hydraulic connectors, and a support frame. Two categories of blowout preventer are most prevalent: ram and annular. Blowout preventer control systems (BOPs) frequently utilize both types, typically with at least one annular BOP stacked above several ram BOPs.

(A related valve, called an inside blowout preventer, internal blowout preventer, or IBOP, is positioned within, and restricts flow up, the drillpipe. Blowout preventer control systems (BOPs) are used at land and offshore rigs, and subsea. Land and subsea BOPs are secured to the top of the wellbore, known as the wellhead. Blowout preventer control systems (BOPs) on offshore rigs are mounted below the rig deck. Subsea Blowout preventer control systems (BOPs) are connected to the offshore rig above by a drilling riser that provides a continuous pathway for the drill string and fluids emanating from the wellbore. In effect, a riser extends the wellbore to the rig. (Blow Out Preventer Control System BOP, oil and gas industry)

 

Use

 

The invention of Blowout preventer control systems (BOPs) was instrumental in reducing the incidence of oil gushers, blowouts, indicating that substantial improvement is needed. Blowout preventer control systems (BOPs) come in a variety of styles, sizes and pressure ratings. Several individual units serving various functions are combined to compose a blowout preventer stack. Multiple blowout preventers of the same type are frequently provided for redundancy, an important factor in the effectiveness of fail-safe devices.

 

The primary functions of a blowout preventer system are to:

Confine well fluid to the wellbore;

Provide means to add fluid to the wellbore;

Allow controlled volumes of fluid to be withdrawn from the wellbore.

Additionally, and in performing those primary functions, blowout preventer systems are used to:

Regulate and monitor wellbore pressure;

Center and hang off the drill string in the wellbore;

Shut in the well (e.g. seal the void, annulus, between drillpipe and casing);

“Kill” the well (prevent the flow of formation fluid, influx, from the reservoir into the wellbore) ;

Seal the wellhead (close off the wellbore);

Sever the casing or drill pipe (in case of emergencies).

 

In drilling a typical high-pressure well, drill strings are routed through a blowout preventer control system (BOP) stack toward the reservoir of oil and gas. As the well is drilled, drilling fluid, "mud", is fed through the drill string down to the drill bit, "blade", and returns up the wellbore in the ring-shaped void, annulus, between the outside of the drill pipe and the casing (piping that lines the wellbore). The column of drilling mud exerts downward hydrostatic pressure to counter opposing pressure from the formation being drilled, allowing drilling to proceed. When a kick (influx of formation fluid) occurs, rig operators or automatic systems close the blowout preventer control system (BOP) units, sealing the annulus to stop the flow of fluids out of the wellbore. Denser mud is then circulated into the wellbore down the drill string, up the annulus and out through the choke line at the base of the blowout preventer control system (BOP) stack through chokes (flow restrictors) until downhole pressure is overcome. Once “kill weight” mud extends from the bottom of the well to the top, the well has been “killed”. If the integrity of the well is intact drilling may be resumed. Alternatively, if circulation is not feasible it may be possible to kill the well by "bullheading", forcibly pumping, in the heavier mud from the top through the kill line connection at the base of the stack. This is less desirable because of the higher surface pressures likely needed and the fact that much of the mud originally in the annulus must be forced into receptive formations in the open hole section beneath the deepest casing shoe. (Blow Out Preventer Control System BOP, oil and gas industry)

 

If the blowout preventers and mud do not restrict the upward pressures of a kick, a blowout results, potentially shooting tubing, oil and gas up the wellbore, damaging the rig, and leaving well integrity in question. (Blow Out Preventer Control System BOP, oil and gas industry)

 

Since blowout preventer control systems (BOPs) are important for the safety of the crew and natural environment, as well as the drilling rig and the wellbore itself, authorities recommend, and regulations require, that blowout preventer control systems (BOPs) be regularly inspected, tested and refurbished. Tests vary from daily test of functions on critical wells to monthly or less frequent testing on wells with low likelihood of control problems. Exploitable reservoirs of oil and gas are increasingly rare and remote, leading to increased subsea deepwater well exploration and requiring BOPs to remain submerged for as long as a year in extreme conditions. As a result, blowout preventer control system (BOP) assemblies have grown larger and heavier (e.g. a single ram-type BOP unit can weigh in excess of 30,000 pounds), while the space allotted for blowout preventer control system (BOP) stacks on existing offshore rigs has not grown commensurately. Thus a key focus in the technological development of blowout preventer control systems (BOPs) over the last two decades has been limiting their footprint and weight while simultaneously increasing safe operating capacity. (Blow Out Preventer Control System BOP, oil and gas industry).

 

 

Types

 

Blowout preventer control systems (BOPs) come in two basic types, ram and annular. Both are often used together in drilling rig blowout preventer control system (BOP) stacks, typically with at least one annular BOP capping a stack of several ram BOPs.

 

 

Ram Blowout Preventer

 

The ram blowout preventer control system (BOP) was invented by James Smither Abercrombie and Harry S. Cameron in 1922, and was brought to market in 1924 by Cameron Iron Works. A ram-type BOP is similar in operation to a gate valve, but uses a pair of opposing steel plungers, rams. The rams extend toward the center of the wellbore to restrict flow or retract open in order to permit flow. The inner and top faces of the rams are fitted with packers (elastomeric seals) that press against each other, against the wellbore, and around tubing running through the wellbore. Outlets at the sides of the blowout preventer control system (BOP) housing (body) are used for connection to choke and kill lines or valves. Rams, or ram blocks, are of four common types: pipe, blind, shear, and blind shear. (Blow Out Preventer Control System BOP, oil and gas industry)

 

Pipe rams close around a drill pipe, restricting flow in the annulus (ring-shaped space between concentric objects) between the outside of the drill pipe and the wellbore, but do not obstruct flow within the drill pipe. Variable-bore pipe rams can accommodate tubing in a wider range of outside diameters than standard pipe rams, but typically with some loss of pressure capacity and longevity.

 

Blind rams (also known as sealing rams), which have no openings for tubing, can close off the well when the well does not contain a drill string or other tubing, and seal it.

 

Blind shear rams (also known as shear seal rams, or sealing shear rams) are intended to seal a wellbore, even when the bore is occupied by a drill string, by cutting through the drill string as the rams close off the well. The upper portion of the severed drill string is freed from the ram, while the lower portion may be crimped and the “fish tail” captured to hang the drill string off the blowout preventer control system (BOP).

 

In addition to the standard ram functions, variable-bore pipe rams are frequently used as test rams in a modified blowout preventer device known as a stack test valve. Stack test valves are positioned at the bottom of a BOP stack and resist downward pressure (unlike BOPs, which resist upward pressures). By closing the test ram and a blowout preventer control system (BOP) ram about the drillstring and pressurizing the annulus, the BOP is pressure-tested for proper function. (Blow Out Preventer Control System BOP, oil and gas industry)

 

The original ram blowout preventer control systems (BOPs) of the 1920s were simple and rugged manual devices with minimal parts. The BOP housing (body) had a vertical well bore and horizontal ram cavity (ram guide chamber). Opposing rams (plungers) in the ram cavity translated horizontally, actuated by threaded ram shafts (piston rods) in the manner of a screw jack. Torque from turning the ram shafts by wrench or hand wheel was converted to linear motion and the rams, coupled to the inner ends of the ram shafts, opened and closed the well bore. Such screw jack type operation provided enough mechanical advantage for rams to overcome downhole pressures and seal the wellbore annulus. (Blow Out Preventer Control System BOP, oil and gas industry)

 

Hydraulic rams blowout preventer control systems (BOPs) were in use by the 1940s. Hydraulically actuated blowout preventers had many potential advantages. The pressure could be equalized in the opposing hydraulic cylinders causing the rams to operate in unison. Relatively rapid actuation and remote control were facilitated, and hydraulic rams were well-suited to high pressure wells. Because blowout preventer control systems (BOPs) are fail-safe devices, efforts to minimize the complexity of the devices are still employed to ensure ram blowout preventer control system (BOP) reliability and longevity. As a result, despite the ever-increasing demands placed on them, state of the art ram BOPs are conceptually the same as the first effective models, and resemble those units in many ways.

 

Ram BOPs for use in deepwater applications universally employ hydraulic actuation. Threaded shafts are often still incorporated into hydraulic ram BOPs as lock rods that hold the ram in position after hydraulic actuation. By using a mechanical ram locking mechanism, constant hydraulic pressure need not be maintained. Lock rods may be coupled to ram shafts or not, depending on manufacturer. Other types of ram locks, such as wedge locks, are also used.

Typical ram actuator assemblies (operator systems) are secured to the blowout preventer control system (BOP) housing by removable bonnets. Unbolting the bonnets from the housing allows BOP maintenance and facilitates the substitution of rams. In that way, for example, a pipe ram blowout preventer control system (BOP) can be converted to a blind shear ram BOP. (Blow Out Preventer Control System BOP, oil and gas industry)

 

Shear-type ram BOPs require the greatest closing force in order to cut through tubing occupying the wellbore. Boosters (auxiliary hydraulic actuators) are frequently mounted to the outer ends of a blowout preventer control systems (BOPs) hydraulic actuators to provide additional shearing force for shear rams.

Ram BOPs are typically designed so that well pressure will help maintain the rams in their closed, sealing position. That is achieved by allowing fluid to pass to pass through a channel in the ram and exert pressure at the ram’s rear and toward the center of the wellbore. Providing a channel in the ram also limits the thrust required to overcome well bore pressure.

 

Single ram and double ram blowout preventer control systems (BOPs) are commonly available. The names refer to the quantity of ram cavities (equivalent to the effective quantity of valves) contained in the unit. A double ram BOP is more compact and lighter than a stack of two single ram blowout preventer control systems (BOPs) while providing the same functionality, and is thus desirable in many applications. Triple ram BOPs are also manufactured, but not as common. (Blow Out Preventer Control System BOP, oil and gas industry)

 

Technological development of ram BOPs has been directed towards deeper and higher pressure wells, greater reliability, reduced maintenance, facilitated replacement of components, facilitated ROV intervention, reduced hydraulic fluid consumption, and improved connectors, packers, seals, locks and rams. In addition, limiting BOP weight and footprint are significant concerns to account for the limitations of existing rigs.

 

The highest-capacity large-bore ram blowout preventer on the market, as of July 2010, Cameron’s EVO 20K blowout preventer control system (BOP), has a hold-pressure rating of 20,000 psi, ram force in excess of 1,000,000 pounds, and a well bore diameter of 18.75 inches. (Blow Out Preventer Control System BOP, oil and gas industry)

Done