BOP Accumulator Units
Sara's BOP Accumulator Units meet or exceed the design specification as specified in API
16D. Each control system is specifically engineered to assure reliable control of the BOP
stack with adequate reserve for continuous operation under emergency conditions. Sara
welcomes the opportunity to assist you in the proper selection of standard equipment or
custom design to meet your application and certification requirements.
This system shown here is for Air Remote Control Panel operation. Sara systems that are
designed to meet API 16D must have Air-Electric Remote Control Panels if they are used
on Offshore Drilling Rigs.
Remote Panel
PLC Based, Touchscreen Driven, Remote Panel System
for BOP Accumulator Unit
Background
Handles high temperatures up to 60 C
The display panels currently used in the accumulator system were first designed in the
1980’s. Due to the level of technology available, the panels were controlled by pneumatic,
electrical or both power sources.
On pneumatic panels, control was received via valve operation of the cylinders on the
Accumulator Unit. Electric lights in the panels functioned as valve indicators.
Electrical panels used a system of relays and contacts that were configured to establish the
valve operation logic.
Easy rig up and rig down
These panels functioned well for some time, but contained various intrinsic flaws. As
Accumulator Unit safety became increasingly important, the remote panels required
quicker response time and the ability to log and diagnose problems before they occurred.
Accordingly, a new panel design with faster and smarter control capability was needed.
NOV Sara’s control keeps the best features and reliability of its predecessors, while
overcoming the flaws that inherent in the older panels.
Features
Explosion proof for Class I Div. I or Class I Div.
II
Air cooler for higher temperatures
Logging of functions and alarms
Air and battery back up
Minimum rig-up time; no air hose
System can be retrofitted on existing units
System can set secondly pressure units
System can set minimum and maximum gauge
readings
Time zones can be set for accurate logging
Impact resistant IR touchscreen
Help Screen included for diagnostics without
opening the panel
Functions
Visual indications of valve position
Audible and visual alarm for low accumulator
pressure, low manifold pressure, low rig air
pressure and low reservoir fluid level
Push buttons from open/close function with
master push button for two hand operation
Push buttons for high/low function of bypass
valve
Push buttons for raise/lower annular regulator
pressure setting
Push button for lamp test
Options
Wireless capability for remote communications
Permits remote monitoring of Unit Status
Communications via Optical fiber Cable
Screen displays with reduced sun glare
Communication via Co-axial Cable
Communication via Ethernet touchscreen or
Gauges.
The second line of defense for the
workers and the well to prevent a
blowout is the group of equipment called
blowout preventers (BOPs)
. BOPs and
associated valves are installed on top of
the
casing head
before drilling ahead
after rigging up. These high-pressure
safety valves and associated equipment
are designed to shut off the well hole and
prevent the escape of the underground
fluids and prevent a blowout from
occurring.
After installation, the BOP and
associated valves are pressure tested to
insure integrity and proper operations.
The BOP and associated equipment
consists of:
BOP Stack
Annular BOP
Ram-Type BOP
Choke Manifold
Accumulator
BOP Stack
A BOP installation could consist of both
annular
and
ram-type
BOPs assembled
into a stack. Also, there can be a kill line
valve and a choke line valve.
The choke line valve is used to redirect the
mud from the well bore to the
choke
manifold
during a kick.
The kill line valve is used to direct drilling
fluid to the BOP during a kick.
Fig. 2. A blowout preventer (BOP) with
one
annular BOP on top and two ram type
BOPs
are stacked together with a kill line
valve and a choke line valve.
Annular BOP
Fig. 3. Annular blowout preventer cutaway
diagram showing the head, piston, wear
Annular BOPs
are designed to form a seal
in the
annular space
between the
drill pipe
and the wellbore and are usually mounted
at the top of the BOP stack.
packing unit, opening chamber, and closing
chamber.
Ram-Type BOP
Ram-type BOPs
have rubber faced steel
rams that come together with great force
to seal the wellbore. Usually two or more
ram-type BOP's are mounted in the BOP
stack.
Fig. 4. Ram-type blowout preventer
Choke Manifold
A
choke manifold
is a system of valves
used to circulate out a kick and to
circulate mud in of the proper weight.
This device responds automatically to
a kick and can prevent a blowout if
properly installed and maintained.
Fig. 5. Choke manifold
The BOP control system, called
an
accumulator
, provides the
energy to operate the blowout
preventers.
This system of consists of:
Compressed gas bottles,
Regulator valves,
Pumps,
Hydraulic reservoir,
Control manifold, and
Control valves.
Fig. 6. The blowout preventer control systems
accumulator showing regulator valves, accumulator
bottles, back-up pump (pneumatic), hydraulic
reservoir, control manifold, control valves, and
Blowout preventer
The blow-out preventer is a large, specialized valve used to seal, control & monitor oil and gas wells. Blow-out preventers were developed for coping 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 blow-out. In addition to controlling the down-hole (occurring in the drilled hole) pressure and the flow of oil and gas, blow-out preventers 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 blow-out threatens. blow-out preventers 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 blow-out preventers are intended to be fail-safe devices.
That term BOP (an initialism rather than spoken as a word, i.e.- pronounced 'B' 'O' 'P') is used in oilfield vernacular to refer to blow-out preventers.
The abbreviated term preventer, usually prefaced by a type (e.g. ram preventer), is used to refer to a single blow-out preventer unit. A blow-out preventer may also simply be referred to by its type (e.g. ram).
The terms blow-out preventer, blow-out preventer stack and blow-out preventer system are
commonly used interchangeably and in a general manner to describe an assembly of several stacked blow-out preventers of varying type and function, as well as auxiliary components. A typical subsea deepwater blow-out preventer system 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 blow-out preventer are most prevalent: ram and annular. BOP stacks frequently utilize both types, typically with at least one annular BOP stacked above several ram BOPs. (A related valve, called an inside blow-out preventer, internal blow-out preventer, or IBOP, is positioned within, and restricts flow up, the drillpipe. This article does not address inside blow-out preventer use.)
blow-out preventers 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. BOPs on offshore rigs are mounted below the rig deck. Subsea 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.
Use of blow-out preventer:-
The invention of out preventers was instrumental in reducing the incidence of oil gushers, blow-outs, which are dangerous and costly.
blow-out preventers come in a variety of styles, sizes and pressure ratings. Several individual units serving various functions are combined to compose a blow-out preventer stack. Multiple blow-out preventers of the same type are frequently provided for redundancy, an important factor in the effectiveness of fail-safe devices.
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, blow-out 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 blow-out preventer 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 blow-out preventer 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 BOP stack through chokes (flow restrictors) until down-hole 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.
If the blow-out preventers and mud do not restrict the upward pressures of a kick, a blow-out results, potentially shooting tubing, oil and gas up the wellbore, damaging the rig, and leaving well integrity in question.
Since 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 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, 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 BOP stacks on existing offshore rigs has not grown commensurately. Thus a key focus in the technological development of BOPs over the last two decades has been limiting their footprint and weight while simultaneously increasing safe operating capacity.
