Well Control Equip

8/10/2019 Well Control Equip

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(1) WELL CONTROL EQUIP.

7/15/2007 M A-Mohsen

Introduction

Well control equipment is the second and last line of defense. Although there are many factors which m

contribute to a blow-out, faulty equipment and equipment control have statistically been predominant causesthese events.

Selecting the appropriate equipment (capacity, pressure rating etc.) and maintaining its integrity

prerequisites in preventing such a calamity. Drilling contractor personnel and operator personnel alike shouldfully familiar with well control equipment, with respect to function, limitation, and how to operate it, sho

there be a kick situation.

5.1.1 FUNCTION

The function of well control equipment is to close off the well bore and stop a well flow in case of loss

primary control, and to be able to keep the bottom hole pressure equal to the formation pressure while preparfor and restoring primary control.

Well control equipment includes: the preventer stack, the last set casing string, the well headand auxili

equipment such as the choke and kill manifoldand the control unitas well as some srill string components.

Well control equipment can provide proper protection only if the pressure rating is adequate. For this reaso

working pressure classification has been introduced for all well control equipment.

5.1.2 WORKING PRESSURE CLASSIFICATION

Well control equipment is divided into several working pressure (WP) classifications. The choice of equipmdepends on the maximum expected surface pressure that could be encountered during drilling and worko

operations.

The most common pressure ratings are:

13,800 kPa (2,000 psi) WP. / 20,700 kPa (3,000 psi) WP. / 34,500 kPa (5,000 psi) WP.

69,000 kPa (10,000 psi) WP. / 103,500 kPa (15,000 psi) WP.

Although the minimum requirements for each WP classification are well and area specific, some of the geneconsiderations follow below:

5.1.3 GENERAL CONSIDERATIONS

The following considerations should be taken into account when selecting well control equipment:

The equipment should be selected to withstand the maximum anticipated surface pressures and mgovernmental regulations.

On offshore wells the specifications will generally fall into the 34,500 kPa (5,000 psi) WP and higwith a trend to the 69,000 kPa (10,000 psi) WP classification.


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The blow-out preventer stack should consist of remote controlled equipment capable of closing in well with or without the pipe in the hole.

Welded, flanged or hub connections are mandatory on high pressure systems above 13,800 kPa (2,0psi).

In some areas well control equipment suitable for sour service may be required; in such cases complete high pressure BOP system should be fabricated of materials resistant to sulphide str

cracking. The response time of surface BOPs should be as specified in API RP53, i.e. the closing system sho

be capable of closing each ram preventer within 30 seconds; the closing time should not exceedseconds for annular preventers smaller than 508 mm (20 in) and 45 seconds for annular preventers

508 mm (20 in) and larger.

Although pressure rating of the equipment is the first concern, the layout of the stack is also critical.

5.1.4 MINIMUM REQUIREMENTS

Depending on the working pressure the surface blow-out prevention equipment must also comply w

minimum compositional requirements.

The number and type of BOPs to be used, apart from size, depends on expected formation pressure and probability of these pressures (i.e. are we drilling in a known area or wild-catting). The higher the expec

pressures, the greater the precaution needs to be (i.e. more BOPs to provide redundancy).

Well killing system

5.2.1 INTRODUCTION

When primary control has been lost and formation fluids enter the well bore, a hydrostatic overbalance is longer maintained. Instead we have a pressure balance in the annulus between the formation pressure and

sum of the hydrostatic heads of the fluids in the annulus plus viscous friction losses due to flow plus the bapressure applied at the surface. If no, or insufficient, back pressure is applied the rate of flow from formation

well will increase until the friction losses in the annulus enable equilibrium to be reached. The result is a blout.

This pressure balance is maintained in static conditions by closing off the annulus at the surface by means of

BOPs. Flow will then only continue until the well head pressure has increased to the difference between formation pressure and the hydrostatic pressure of the fluid column in the annulus.

Under dynamic conditions (i.e. during well killing operations) the balance is maintained and additional inflowprevented by applying a calculated back pressure which is equal to the formation pressure minus the hydrost

head in the annulus minus the friction losses plus a safety factor. Given that the hydrostatic head in the annuwill vary as the initial volume of formation fluid flows up the well, especially if it is gas, and as kill mud

pumped down the drill pipe and enters the annulus, it is necessary to vary the applied back pressure. Thidone by passing the flow through a restriction whose size can be changed in a quantifiable manner. Suc

restriction is called an adjustable choke.


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Gate valves, e.g. Cameronand WKM, are commonly used in rig manifolds. It is however possible that in socases plug valves, e.g. Halliburton Lo-Torc valves, have been installed. Such valves are normally prohibited

this application.

CHOKE AND KILL LINE OUTLET VALVES

Owing to area and contractor specific requirements, it is not feasible to specify a standard layout, but following minimum requirements should be adhered to:

The choke line must have a minimum ID of 76.2 mm (3"), the kill line may be as small as 50.8 mm (2albeit that this might restrain operational flexibility should immediate substitution of a choke line

required. During normal operation, the inner (usually manual) choke and kill line valves should remopen and the outer (hydraulically operated) valves closed such as to prevent excessive solids build-up

these lines. Wellhead outlets should, under normal operating conditions, not be used for a choke and kill line tie-i

If the kill line is not meant to ultimately replace or augment the choke line, it is highly desirableinstall a check valve upstream of the stack valves.

HYDRAULICALLY OPERATED CHOKE LINE VALVE

This type of valve is an adapted gate valve, e.g. Cameron type LSF,

provided with a double acting hydraulic cylinder mounted on the bonnetcap.

The stem of the valve is connected to the piston in the cylinder. Whenhydraulic pressure is applied to the bottom of the cylinder, the piston and

gate move upwards and the valve opens. When the hydraulic pressure is onthe top of the cylinder the valve will close.

A handwheel and locking screw are provided to close the valve manually if

required.

The lower stuffing box and tail rod on the stem have a three-fold function:

To act as a pressure balance for the stem which connects the gate to

the operating piston. To keep the grease packed in the gate cavity of the valve body.

To serve as an indicator whether the valve is "open" or "closed". Figure 3.5.5 : Hydraulically opergate valve

"HCR" PRESSURE OPERATED GATE VALVE

On several rigs an older type remote control gate valve may be found, the "HCR valve" (see Figure 3.5.6). Tpressure operated gate valve is a flow line valve requiring relatively low operating pressures. The closing ra

of well pressure to hydraulic operating pressure is approximately 8 to 1. The gate is packed with elemesimilar to the "QRC" ram assembly. These valves are made to hold pressure from one side only. It is theref

of crucial importance that during installation the correct side will face the BOP stack. The flow directionusually indicated by an arrow on the body of the valve.


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"HCR" pressure operated gate valves are available in 4" or 6" sizes, either 3,000 psi or 5,000 psi WP, and hstandard API flanges. Figure 3.5.6 :HCR pressure operated gate valve

WKM GATE VALVE

The WKM gate valve has parallel expanding gates which

produce an extraordinarily high seating force against both theupstream and downstream seats simultaneously. This seating

force is entirely mechanical and unaffected by line pressurefluctuations or vibration (see Figure 3.5.4).

During opening or closing, the gate and segment match at all four surfaces. The face-to-face width of the gasegment assembly is less than the distance between the

upstream and downstream seats, thus the gates move freelybetween the seats.

In the closed position, the upper matching surfaces of gate and

segment are in solid contact. The gate wedges against thesegment, expanding the gate-segment assembly outward

against the seats. This expansion is controlled by thedownward movement of the gate, so that an extremely high

seating pres-sure is obtained.

In the open position, the two bottom angles are in contact and

the gate-segment assembly expands, sealing off against theseats. Expansion is controlled by the upward movement of the

gate. Flow is isolated from the valve body when the valve isfully opened.

CAMERON TYPE F GATE VALVE

This valve has a stationary stem. The non rising stem is

provided with a back seat which separates the stuffing boxfrom the bonnet flange. To prevent damage to the internal

parts, in case excessive torque is applied, the handwheel,connected to the spindle, is equipped with a safety pin (shear pin).

These valves use the floating gate design, in which the line pressure forces the gate into sealing contact witmetal seal ring, creating a metal to metal seal. The seat ring and its seal ring are in turn forced against the bo

sealing surface to complete the sealing process.

On early valves the seat rings had 24 teeth cut into the outer circumference which aligned with a dmechanism on the gate. Each time the valve was opened the seat ring was rotated 15 degrees. This provid

even wear on the seat rings and extended seat ring life. However, the seat rings tended to seize in the retaiplates which were used and invariably were cracked by the dog mechanism. For this reason the rotating se

were phased out.


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The current version of the type F gate valve is the FL as shown in Figure 3.5.3, plus its variant the FLS valThe FLS variant has an improved seat-to-body seal and is the one most commonly used in Group operations.

Because the gate floats differential pressure will cause excessive friction. It is often therefore a problem

operate these valves under pressure; sometimes cheaters have to be used to turn the handwheel. If differential pressure over the valve is too great this pressure

should be equalised before opening.

5.2.4 CHOKES

The choke is normally an adjustable orifice installed in the

return line. It is used to restrict the flow area so that thepressure drop of the returns through this line can be regulated

while a kick is circulated out.

Three types of chokes may be encountered in chokemanifolds:

The manual adjustable choke.

The replaceable fixed choke. The remote controlled choke.

MANUAL ADJUSTABLE CHOKE Figure 3.5.3 : The Cameron type FL gate valve

Figure 3.5.7 shows a typical needle valve type manual adjustable choke. The stem and seat area are of tungscarbide to make them more wear resistant; it must be understood that a

choke is not meant to be used as a valve. The tool is designed to create aflow restriction and not to provide a high-pressure seal. Washed out

sealing areas are also common. Therefore the choke must be used forinitial closing in only and should immediately be backed up by closing the

upstream valve. This type of choke should not be left "closed" for longperiods of time. Temperature expansion of the needle can damage the seat

and the needle may "freeze" in the seat.

FIXED CHOKE

Instead of using an adjustable spindle valve, the seat can be replaced by

different sizes of "beans". Such chokes are used only if the well returnswill have to be produced at a constant rate over a considerable period of

time, such as is common during production tests. Fixed chokes aresometimes referred to as positive chokes.

The choke body in such a set-up is provided with a cap instead of a needle

assembly. Figure 3.5.7 : Manually operated choke


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REMOTE CONTROLLED CHOKE

Remote controlled chokes are operated from a panel, usually on the rig floor (see Figure 3.5.8). This operatpanel should include:

a drill pipe pressure gauge

an annulus pressure gauge a pump stroke counter

a choke selection switch a maximum allowable annulus

pressure setting regulator(optional)

a choke control lever and throttles for the pumps

(optional)

There are different remote controlled

chokes, some of which have specificoperating characteristics that may

affect the well killing operation. It istherefore important to check details of

the unit installed. Some examples aregiven overleaf.

CAMERON AX CHOKE

The Cameron AX choke(Figure 3.5.9)

is a choke which uses a sleeve that Figure 3.5.8 : Choke control console

moves in and out of a tapered seat. It is available for pressures from 34,500 kPa (5,000 psi) to 140,000 k

(20,000 psi). The movement is controlled by a double acting hydraulic cylinder. The choking action starts whthe sleeve approaches and then enters the tapered seat. Here again the wear areas are of tungsten carbide.

The choke in this case does not form a positive seal, and thus an upstream valve must be closed after the ch

is "closed".

Figure 3.5.9 :Cameron drilling choke (5000 - 15000 psi WP)


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SWACO SUPER CHOKE

The Swaco Super Choke (Figure 3.5.10) is a hydraulicallyoperated valve available in working pressures of up to

138,000 kPa (20,000 psi) . The size of the orifice isdetermined by the overlapping portions of half moon

openings in two flat, highly polished tungsten carbide discswhich rotate with respect to each other. The downstream

disc is fixed while the upstream disc may be rotated up to180 degrees by a hydraulically driven rotary actuator. The

power required to rotate the plates is minimal. One mainadvantage of this choke is that it provides metal to metal

shut off and, when closed, it will holdpressure and can therefore be used to

shut the well in. It is capable ofmanual as well as hydraulic operation.

To replace the tungsten carbide orificeplates it is necessary to break the lineon the downstream side of the choke to

gain access.

Figure 3.5.10 : Swaco super choke

5.2.5 HIGH-PRESSURE (HP) LINES AND HOSES

HAMMER UNIONS

The connection between HP equipment is normally a fixed set-up consisting ofsteel pipes. Only in tempor

hook-ups are steel swings used. These swings are provided with hammer unions.

A union mostly consists of four parts:

A male sub with convex sealing face.

A female sub with a concave sealing face, an external square thread and an inner recess for a seal ring A hammer nut with square threads and two or three lugs.

A rubber seal ring.

The convex shape of the sub serves for self alignment when making up the union; this improves make up spand ensures proper seating of the sealing surfaces.

It is important that rig site personnel should inspect both sealing surfaces as well as the rubber seal whmaking up the connections.

It is also important that the individual parts of the union should be checked for the correct pressure rating (ty

before making up. Some of the pressure classes have nuts and female subs which differ only slightly


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dimensions e.g. a WECO union type 1502 nut fits a type 1002 female sub, but the threads engage over a smarea only. When high pressure is applied the union expands and comes apart. When large volumes are involv

this can cause severe accidents. It is a good practice to secure the union connection with a safety chainproperly clamped steel wire. Figure 3.5.11 : Hammer union

CHIKSAN SWIVEL JOINT

Relatively short sections of jointed pipe called "swings"

are used to hook up a temporary line, for example.between cementing pump and cementing head.

Figure 3.5.12 : Swing in folded position

The flexibility of a swing is achieved by a number of

swivel joints installed in between the straight pipe sections.

A swivel joint (Figure 3.5.13) consists of a sealed ball bearing construction. The balls act as a retainer a

bearing which is packed with grease. In addition the construction is such that it prevents the swivel joint frcoming apart at the applied pressure.

These swivel joints, often calledchicksans, are supplied in long or short

sweep bends.

In confined spaces and for staticpressure, e.g. the hydraulic operating

lines for the BOPs, short sweepchicksans are used. Long sweeps are

preferred in circulating lines, to reducethe frictional pressure drop.

HIGH-PRESSURE HOSES Figure 3.5.13 : Chiksan swivel joint

Construction

High pressure hoses are basically built up of three mainparts: An inner hose, a carcass, and an outer hose. The

inner hose is internally flush and its material should beresistant to the fluids it has to convey.

Generally braided steel wires are vulcanised in the

rubber. Figure 3.5.14 : HP hose (Stena-Coflexip design)

The outer layer of the hose or sheath is intended to protect the reinforcement against corrosion and wear.


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(10) WELL CONTROL EQUIP


Hose connections

The hose connections should at least have the same strength as the hose. The weakest point of a hose is alwjust behind the connection, as the hose has the tendency to kink at that point.

Handling

Each hose has a minimum bending radius (MBR) which is specified by its manufacturer. This should alwaysrespected in order to avoid damage to the hose. If the manufacturers specification is unavailable a rule of thu

is that the MBR is twelve times the ID.

Bending the hose close to the end fittings should be avoided - as a rule of thumb the bend should not commecloser than twice the OD from the fitting.

Twisting the hose should also be avoided - the rule of thumb in this case is that the maximum twist is 1

three feet or metre.

These handling rules apply not only to hoses but also to flexible steel pipes

The sketchesshow the right and wrong ways of handling hoses in various situations

BOP stack equipment

Blow-out control equipment must be simple and reliable but still sophisticated enough to suit a broad range

applications.

A BOP stack should have a large enough internal diameter to pass the drilling tools. For the shallow part of

hole a large diameter stack or diverter set-up with low working pressure ratings is required, while for the deesections smaller inside diameters, but high working pressure rating are needed.

When all of these qualifications plus the operational characteristics, such as quick operation and reliasealing, have been incorporated, a blow-out preventer stack has become a heavy, massive piece of equipment

Although all these items look indestructible, they should be watched carefully and inspections, tests amaintenance executed conscientiously. Not seldom was a blow-out the result of damaged or failing B

equipment.

This topic will deal with annularand ram-typepreventers anddiverters.

5.3.1 ANNULAR PREVENTERS

GENERAL

The annular preventer (also called bag type, spherical or universal preventer) is the most versatile piece

equipment on the BOP stack since it can close around casing, drill pipe, drill collars, wireline and even closeopen hole. The rubber packing elements of the annular preventers, which allow this flexibility, are also subj


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to wear and abuse. Treated properly, the packing unit of the annular preventer has a long, reliable life span, it can be destroyed in a very short time or very few closing cycles by improper use.

The following factors influence the life span of annular preventers:

The closing pressure as regulated through the control system should be as low as practically possible

order to maximise the life of the packing unit. Testing the annular preventer under high test pressures significantly shortens the life of the packing un

Closing the annular preventer without pipe in the hole will shorten the life of the packing unit, especiawhen high closing pressures are required to achieve this.

Motion reversal is hard on the packing unit, so pipe should be moved as far as possible in one directbefore reversing the direction (i.e. long strokes).

Spare packing units should be stored in a dark, cool room.

Closing time of annular preventers

The main disadvantage of the annular preventer is the time required to close it. The annular preventer ta

three to ten times the volume of fluid to close, compared to a set of rams, and therefore requires a longer clostime. Even though current regulations specify a 38 mm (11/2") minimum diameter hydraulic control line, m

surface stacks may still have hydraulic lines to the annular preventer that are smaller, or have a restrictionthem which prevents rapid closing. Raising the closing pressure does not help as much as using larger lines a

fittings. In addition it increases the wear on the packing unit. The small lines and/or restrictions make packing unit movement inflexible when trying to strip, and cause excessive packing unit wear during stripp

operations, especially when tool joints are passing through it.

The regulator valve , used to regulate the annular preventer closing pressure, should allow fluid passage bathrough it if the line pressure increases. That way the packing unit can open against the closing pressure wh

stripping a tool joint. It is very important to see to it that this regulator is in good shape, that there are no chevalves ahead of it (often present in the four-way valve), or that it has been replaced by a plain regulator.

The arrangement where a small accumulator bottle (surge bottle) is placed in the closing line of the annupreventer, to allow for hydraulic fluid movement when stripping, is very desirable from the viewpoint

reducing packing unit wear. This arrangement is recommended for all surface and subsurface stacks.

There are some differences in the operation of the various annular preventers. Therefore the most commoused types will be discussed.

HYDRIL GK ANNULAR PREVENTER

The Hydril GK annular preventer (Figure 3.5.16) is the most common annular preventer in use, particularlysurface stack installations, and is unique in its response to well pressures. Like most other annular prevente

the preventer is closed with about 5,520 kPa (800 psi) pressure. The Hydril GK annular preventer witworking pressure of less than 69,000 kPa (10,000 psi) is however also energised by the well pressure so t

when the well pressure increases, the closing pressure must be reduced to avoid damaging the packing uThis wellhead pressure assist is derived from its piston configuration and applies also to the GL and MSP ty

of annular preventers (except the 749.3 mm/295", 3,450 kPa/500 psi unit) The manufacturer's instructionsHydril annular preventers should be consulted for more detailed information. Charts, determining operat

pressures, are also provided in the manufacturer's literature.


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The packing element Figure 3.5.16: Hydril GK annular preventer

The packing element or unit has steelsegments, vulcanised into the rubber

body, to reinforce it and limit theamount of extrusion of the rubber

when it is activated Figure 3.5.16ashows how the packing unit extrudes

due to the vertical movement of thepiston, whose taper squeezes the

packing rubber inward.

The type of elastomer (natural rubber,synthetic rubber or neoprene) used in

the packing element should be themost suitable for the particular well conditions. Refer to Table 3.5.1.

Table 3.5.1 :Packing unit selection Figure 3.5.16a: Packing element of Hydril GK annular preventer

Replacing a worn packing unit is fairly simple:

Bleed off operating pressure. Unlock and remove preventer cover.

Lift out worn packing unit. Check seals on head and piston.

Drop in new packing unit, and replace and lock cover.

Should the packing unit have to be replaced while pipe is in the hole, the packing unit has

to be cut with a knife between two steel segments, preferably at 90 to the lifting eye boltholes.

It is also advisable to use the kelly and a special cover break-out sub with plate for this job

(see Figure 3.5.17). The tools required are lifting bolts with the correct thread for thepacking element and lifting bolts with the correct thread and sufficiently long to lift the

piston out.

Figure 3.5.17 : Cbreak p


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NL SHAFFER SPHERICAL ANNULAR PREVENTER

Figure 3.5.18NL Shaffer spherical annular preventer

The NL Shaffer spherical annular preventer uses a

closing piston that forces the rubber packingelement up against a concave cover, which in turn

forces the packing element to close. NL Shaffersuggests a closing pressure of 10,350 kPa (1,500

psi) in its literature, but also notes that the pressureshould be reduced according to the operating

characteristic tables if the pipe is to be moved.

Figure 3.5.19 illustrates the action of the packing

element. Steel segments moulded into the elementpartially close over the top of the rubber to prevent

excessive extrusion when sealing high pressures.These segments always move out of the well bore

when the element is opened, even when the element is old and worn far beyond normal replacement condition

Figure 3.5.19 : Action of the packing element of NL Shaffer spherical annular preventers

Figure 3.5.19a:Detail of the packing

element

Only the top portion of the rubber, in the spherical sealing element, contathe drill string or kelly. Most of the rubber is held in reserve, to be used

sealing once abrasion makes it necessary. This large reservoir of rubber mait possible to strip into or out of a hole without replacing the element during

trip.

Long stripping life is especially valuable in offshore use, because an annupreventer closed around the drill pipe of a floating vessel, is constan

exposed to stripping movement due to vessel motion.

Stripping is claimed to be smooth with a spherical BOP because the elemopens and closes easily, due to the steel segments moulded into the rubb

They make metal-to-metal sliding contact with the sphere of the housiproviding a low coefficient of friction.


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CAMERON TYPE D ANNULAR PREVENTER

The Cameron type D annular preventer, shown in Figure 3.5.20, has a different type of packing element apiston design. During closing the hydraulic pressure is admitted below the inverted T-shaped operating pist

moving it and its pusher plate upwards. The upward movement of the pusher plate forces a large solid rubbtoroid (or doughnut) to move the packing

element into the closed position around pipeor over the open hole.

Figure 3.5.20: Cameron type D annular preventer

During opening the process is reversed.

Hydraulic pressure above the flange sectionof the operating piston forces it downwards

allowing the preventer to open.

When the packing element is closing, itssteel reinforcing members rotate inward to

maintain a continuous steel support ringaround the drill pipe. This prevents packing

element extrusion far more effectively thanthe conventional widely spaced radial

fingers .

STRIPPING THROUGH CLOSED PREVENTER

Stripping using the annular preventer is considered the simplest and preferred technique. In order to ensur

long operating life of the annular packing element it is important to reduce the closing pressure to accommodthe annular pressures encountered. Thus low annular pressures allow the closing pressures to be as low as 3,4

kPa (500 psi), whereas higher pressures (10,350 kPa/1,500 psi) and above could severely reduce the conditof the element, in particular when tool joints pass through .

To further ensure that the annular is not subjected to excessive pressures as the tool joint is stripped through

element, a surge dampener must be placed in the closing line (see figure 3.5.22). Any check valve installedthe closing line - to ensure that the BOP stays closed if

hydraulic supply is lost - should be removed, such that theannular regulator can be used effectively.

To facilitate the accurate recording of bled-off volumes in thetrip tank, it is advised to install a stripping tank adjacent to the

trip tank (see Figure 3.5.23). The strip tank should becalibrated to account for the closed-end displacement of the

pipe in use.

Figure 3.5.22 : Surge dampener connected to the closing line of an annular preventer


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5.3.2 RAM TYPE PREVENTERS

GENERAL

The ram type blow-out preventer (of which a typical examples areseen in Figures 3.5.25, 3.5.29a and 3.5.34) is the result of some

seventy years of development. It is an extremely rugged and reliablepiece of equipment. The normal preventer consists of a ram head

with extrudable packer material for sealing and a pipe centringwedge. The ram head sits on a piston rod, which connects it to the

hydraulic chambers and seals.

Rams can be furnished to fit any size of pipe. Stainless steel rams,

offset rams for multiple completions, as well as shear rams forcutting off pipe in case of emergency, are available. Figure 3.5.23 : Rig layout for combined stripping

static volumetric method

Generally the closing pressure is less than 10,350 kPa/1,500 psi. There are however high pressure r

preventers, notably from Hydril, which require pressures in excess of 13,100 kPa/1,900 psi. The manufacturdata should be consulted for more details.

Pipe rams.

BOP pipe rams must form a seal around the pipe and against each other, to seal off well pressure. Ram packelements are self feeding and contain a reserve of material in order to assure seal life under wear conditio

They should however be inspected regularly for wear.

Pipe rams are made to close around a certain size pipe. They should not be closed on open hole with full clospressure (10,350 kPa or 1,500 psi), as the packer will be damaged by extrusion. If pipe rams are to be funct

tested on an open hole, it would be better to close them with reduced operating pressure (2,950 kPa or 500 pto avoid damage to the ram packing and also possible damage to the ram face.

When stripping or moving pipe through the rams, there is less wear to the packer element if the closing pressuis reduced to the minimum value sufficient to effect a seal. This practice is accepted only if sufficient back

rams are available. Stripping through rams is not in the scope of this course.

Shearing blind rams

Shearing blind rams (SBRs) are rams with blades integral to the body. Under normal operating conditions thare used as blind rams. If emergency conditions make it necessary to shear the drill pipe, the closing shear ra

will cut the pipe and seal the well bore, regardless of whether the lower section of the cut pipe is suspendedthe lower pipe rams or dropped. If the fish is not dropped, the lower shear ram will bend the cut pipe ove

shoulder and away from the front face of the lower shear ram which then seals against the packer in the upshear ram.

The recommended shearing procedure is:

Raise the bit off the bottom and position drill pipe in the preventer so that the tool joint is definitely nlocated in the shear ram cavity.


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On surface BOPs this is usually by means of bolts that are manually operated via extension rods to whhandwheels can be attached. The handwheels must be well accessible and easy to operate. Should there b

total power failure or a long period without activity the manual lock bolts can be used to close the rams. In sua case a check should be made that the opening pressure has been bled off !

On subsea BOPs a hydraulic system has to be used to lock the rams. Such hydraulic locks are also becom

more common on surface BOPs in place of the slower manually operated locking bolts.

Opening and closing ratios

Ram type preventers have specially designed opening and closing ratios (as shown in Table 3.5.2). These

the ratios between the well pressures and the operating pressures needed to open or close the rams. Closratios are generally of the order of seven to one. That means that a BOP having a closing ratio of seven to o

would require a closing pressure of 3,450 kPa/500 psi to close the rams when the well bore pressure is 24,1kPa/3,500 psi. Opening ratios are much lower because the well bore pressure acts behind the ram to opp

opening. Opening ratios of two to one are common.

Examples of Cameron,NL Shafferand Hydrilram type BOPs are shown in the following pages.

Note that opening rams under pressure is not recommended and might damage equipment. It is also not good safety

practice.

THE HYDRIL RAM TYPE BOP

A Hydril ram type BOP is shown in Figure 3.5.34. This is again a "single" BOP with a manual lock

mechanism designed for land operations. Like the Shaffer system the rams are contained in hinged ousections of the housing so that when the latter is hinged open the rams can be removed from them (by apply

the "closing" procedure) and lifted straight up. One particular feature of the Hydril BOP is that two separ

hinges are used at each joint in order to separate the two functions of the hinge, which are to carry the load ato make a connection for the hydraulic fluid.

Hydril rams are basically similar to those of Cameron and Shaffer. Both the front packer and the upper seal bonded to anti-extrusion plates and are easily replaceable in the ram itself. See Figure 3.5.37.

The mechanical locking mechanism used by Hydril is virtually identical to the one used by Shaffer.

Hydril's hydraulic locking mechanism is called Multiple Position Locking (MPL) and also locks the raautomatically each time that they are closed. This is shown in Figures 3.5.35 & 3.5.36. It consists of a nut wit

very coarse pitch thread - three turns per foot, six start - working in combination with a clutch that

asymmetric teeth on the engaging faces such that when they are in contact rotation is possible in one directbut not in the other (i.e. a sort of rotating ratchet). The nut is free to turn but is constrained from moving althe shaft by thrust bearings in the housing. One clutch plate is fixed to the nut and the other rides on spline

the housing so that it can move to disengage from the other plate (plus nut) but cannot rotate. It is normally kin contact with the other plate by means of springs.


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Figure 3.5.35 : Hydril's MPL automatic ram locking mechanism

Figure 3.5.36 : Detail ofHydril's MPL automatic ram locking mechanism

The clutch is arranged so that when closing pressure is applied the ram moves inwards and the coarse thread c

rotate the nut. If pressure is released the piston and ram tries to move outwards but the clutch prevents the from rotating and the whole mechanism is locked. The design of the piston and cylinder is such that wh

opening pressure is applied the cylinder move along its axis, just enough to press against the outside clutch pland compress the springs far enough to disengage the two plates and allow the nut to rotate.

SHAFFER RAM TYPE BOP

Figure 3.5.29ashows an Shaffer tripleram type blow-out preventer. It shows

that blow-out preventers are notnecessarily manufactured as single

units. This specific design is verycompact, and therefore attractive for

situations where there is little headroom below the substructure. It does,

however, have the disadvantage that ifone preventer body is damaged the

whole stack must be sent for repair.

Figure 3.5.29b :Hydraulic connections

The special design features of the Shaffer BOP are that each ram and its operator are completely self-contain

in the end section, with hydraulic connections built into the hinge. This eliminates drainage problems and need to break or remake connections when changing or servicing rams. Rams are easily changed by unboltand swinging open the doors. The bottom doors swing out from under the upper cylinders so a hoisting line

be attached directly to the rams for easy handling.

In Shaffer rams sealing is effected on the top side and the faces of the rams by one single rubber, which is hin place by a block bolted to the holder. A selection is shown in Figure 3.5.30.


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The shear rams cut pipe and seal the well bore in one operation. These rams also function as CSO (compshut-off) rams for normal operations. When shearing, the lower blade passes below the sharp lower edge of

upper ram block and shears the pipe as shown in Figure 3.5.31. The lower section of cut pipe is accommodain the space between the lower blade and the upper holder. The upper section of cut pipe is accommodated

the recess in the top of the lower ram block.

Figure 3.5.31 : The operation of NL Shaffer shear rams

The closing motion of the rams continues until the ram

block ends meet. Continued closing of the holdersqueezes the semicircular seals upward into sealing

contact with the seat in the BOP body. These seals havemoulded in steel half-rings which limit the squeeze

imparted to them by the holders. The horizontal seal isenergised at the same time as the semicircular seal. The

closing motion of the upper holder pushes the horizontalseal forward and downward on top of the lower blade

resulting in a tight sealing contact. The horizontal sealhas a moulded-in support plate which holds it in place

when the rams are open.

For the size of pipes which can be cut in the several types

of preventers reference must be made to themanufacturer's manual..

Casing shear rams

Conventional shear rams are designed to crush the pipe and then shear the flattened mass. That presentproblem when large diameter pipe has to be cut. If an attempt was made to cut 133/8" casing, for example,in

183/4" bore preventer using conventional shear rams, the pipe would not be cut but be crushed and jammedthe bore of the preventer. In addition there may be severe damage to the shear ram blade and the preven

cavity. This is due to the lack of available space between the casing OD and the preventer bore ID. The typerams of Shaffer have cutting blades that overcome this problem and prevent excessive flattening of the cas

during shear by spreading the cutting stress uniformly over the casing circumference. For instance 133/8" caswould not swell more than up to 15", giving the additional benefit that the lower portion of the sheared cas

can be retrieved more easily by conventional fishing tools. Note that in order to accomplish the above thpreventers should be fitted with large sized cylinders plus boosters).

CAMERON TYPE U RAM TYPE BOP

Cameron type U BOPs are available as single or as double units. A cut-away drawing of a single type U B

(i.e. with only one pair of rams), is shown inFigure 3.5.25.

Diagrams showing the type in three operating positions are presented in Figure 3.5.26.


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Figure 3.5.26 : Type U BOP operation

Open position(Figure 3.5.26a). Hydraulic

pressure is supplied via port J to the ramside of the ram pistons E. The closing

fluid returns via port K. Closed position (Figure 3.5.26b).

Hydraulic pressure is supplied via port Kto the locking bolt side of the ram pistons

E. The opening fluid returns then via portJ.

Replacement of rams (Figure 3.5.26c).The ram closing pressure on port K also

serves to open the bonnets to give accessto the rams. When the bonnet bolts are

unscrewed and closing pressure is applied,hydraulic fluid pushes the rams inward

and at the same time moves the bonnetsaway from the preventer body. Eventhough the rams move inward the bonnet

stroke is sufficient to bring the rams out ofthe preventer bore.

Applying opening pressure on port J will now

close the bonnets. The hydraulic fluid then drawsthe bonnets back against the preventer body. After

the rams have been pulled back the bonnet bolts serve to hold the bonnets closed.

In Cameron rams the material of the packing element is bonded to steel plates, which confine it to the sealarea. A selection of rams for the type U BOP is shown in Figure 3.5.27.

The variable bore ram packer contains steel reinforcing inserts similar to those in the type "D" annular Bpacker. The inserts rotate inward when the rams are closed so that the steel provides solid support for the rub

which seals against the pipe. The inserts serve the same purpose as the retainer plates in the standard type "

pipe ram packer.

In standard fatigue tests variable bore ram packers have shown excellent performance, comparable to that

standard pipe ram packers.

The mechanical locking mechanism used by Cameron is a simple bolt engaging the thread in a "locking scrhousing" that is flanged onto the bonnet. Like most mechanical systems it can be used to close the rams in

absence of hydraulic power, but cannot re-open them as there is no solid connection with the operating pistoit can "push" but not "pull". The sub-sea system is called a "wedge lock", using hydraulic power to forc

wedge across the end of an extension rod attached to the operating piston as shown in Figure 3.5.28.


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Figure 3.5.28 :Hydraulic ram lock mechanism

Locking mechanism

The mechanical locking mechanism used by Shaffer is a bolt

which screws not into a housing but into the ram shaft itself. Oncethe rams are closed the locking shaft is backed out of the ram shaft

until a collar shoulders against the cylinder head. This can be seenin Figure 3.5.32. It too can be used to close the rams in the absence

of hydraulic power, but cannot re-open them. An advantage of thissystem is that threads on the manual locking shaft are enclosed in

the hydraulic fluid and are not exposed to corrosion from mud andsalt water or to freezing.

Figure 3.5.32: Manual locking system for NL Shaffer ram

Shaffer call their sub-sea system "Poslock". This is shown in Figure 3.5.33. Poslock operators automatica

lock the rams each time they are closed. This eliminates the additional complication and cost of a secohydraulic function for locking the rams. It also simplifies the emergency operation, because the rams are b

closed and locked just by activating the close function.

Figure 3.5.33 : Hydraulic locking system for NL Shaffer rams ("Poslock" syst

When closing hydraulic pressure is applied, the complete piston assembly moves inward and pushes the rainto the well bore. As the piston reaches the fully closed position, the locking segments slide toward the pis

O.D. over the locking shoulder because the locking cone is forced inward by the closing hydraulic pressure.

The locking cone holds the locking segments in position and is prevented by a spring from vibrating outwardthe hydraulic closing pressure is removed.


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Actually, the locking cone is a second piston inside the main piston. It is forced inward by closing hydraupressure and outward by opening hydraulic pressure. Figure 3.5.38 : Diverter system for surface stack

5.3.3 DIVERTERS

If a kick is taken when the conductor is set in incompetent

formation, the well will not be shut-in, but diverted instead.A surface diverter system (see Figure 3.5.38), consisting of

an annular preventer and vent lines, allows the flow to bedirected to a safe area, preferably down wind, away from

the rig and personnel.

Vent lines should be as large (3048 mm/12" minimum)

and as straight as practical, so as to minimise backpressure, erosion and the risk of plugging by formation

debris. The lines should be adequately braced to absorbsevere shock loading; sections likely to suffer erosion, such

as bends, should be reinforced. There should be no restriction to the bore and any valves in the lines shouldfull opening ball valves.

To prevent the well being inadvertently shut in, any valves in the vent line should be designed to automatica

open when the diverter element is closed. The minimum working pressure of a large bore diverter line systshould be 3,450 kPa (500 psi); the hydraulic operating line should have a 381 mm (1 1/2") diameter, this allo

hydraullc control systems to close diverters smaller than 508 mm (20") within 30 seconds and diverters larthan 508 mm (20") to close within 45 seconds, both of which are API RP requirements.

Hydraulic BOP operating units

A large volume of hydraulic operating fluid, stored under high pressure in the accumulator, delivers

hydraulic energy required to close and open the BOPs and the remotely operated valves.

5.4.1 REQUIREMENTS

The hydraulic BOP operating unit, also called the hydraulic BOP control system should :

be provided with a control manifold, rated for 20,700 kPa (3,000 psi) WP, which clearly shows "op

and "closed" positions for preventer(s) and remote operated choke line valve. It is essential that all and hydraulic BOP operating units be equipped with 0 - 20,700 kPa (0 - 3,000 psi) regulator val

similar to the Koomey type TR-5, which will not fail open causing complete loss of operating pressur be provided with electrically and air-driven high pressure pumps which automatically charge

accumulator bottles to the pre-set pressure. The electric pump should be fitted with an electric pressswitch, which automatically stops the electric pump when the accumulator pressure reaches 20,700 k

(3,000 psi) and starts the pump again when the pressure drops to 18,970 kPa (2,750 psi) or below . Tair-driven pump should be fitted with an air pressure switch, which automatically stops the air-driv

pump when the manifold pressure reaches 20,700 kPa (3,000 psi) and starts the pump again when pressure drops to 18,620 kPa (2,700 psi) or below.


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be provided with two graphic remote control panels, both clearly showing "open" and "closed" positifor each preventer and the choke line valves. Each of these panels should include a master shutoff va

and controls for regulator valves and for a bypass valve. One panel must be located near the drillposition, the other panel near the exit of the location or near the toolpusher's office.

preferably use high-pressure control hoseswith a working pressure of 20,700 kPa (3,000 psi), althousteel pipe and joints are acceptable.

allow all master and remote operating panel handles to be free to move into either position at all timi.e. the shear ram operating handles should not be locked (but should be protected from inadvert

operation). have all spare operating lines and connections, which are not used in the system, properly blocked off

5.4.2 HYDRAULIC BOP CONTROL UNIT

A general view of a Koomey hydraulic BOP control unit is given in Figure 3.5.41. A simplified diagram

shown in Figure 3.5.40where the arrangement of the four-way valvescan be seen.

5.4.3 ACCUMULATOR CAPACITY

The hydraulic energy required to operate the BOPs is stored in a number of accumulator bottles which cont

either a bladder type diaphragm or a piston (see Figure 3.5.39) to separate the nitrogen from the hydraulic flu

Figure 3.5.39 : Accumulators

The precharge pressure of the nitrogen should be approximately 1,380 kPa/200 psi below the minimoperating pressure. Usually this will result in a value of 6,900 kPa/1,000 psi in a 20,700 kPa/3,000 psi clos

unit system. The precharge of the nitrogen should be checked monthly; if operationally possible this shoulddone with a depressurised hydraulic system using only nitrogen to recharge (see Topic 3.2.5 - Pulsat

dampeners in Part 3.3).

Bottles are available with a capacity of 3785 l (10 gallons), 757 l (20 gallons) or 11355 l (30 gallons) each.


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It is good practice for a driller, before he goes on shift, to check the accumulator, the pressure settings, and the hydraulic fluidlevel.

Official Shell Group policy is that, without recharging, the accumulator capacity shall be adequate for closing and opening all

preventers and closing again the annular preventer and one ram type preventer, and holding them closed against the rated

working pressures of the preventers (or the highest anticipated surface pressure, whichever value prevails). If the operating unit's

policy is in accordance with the Shell Group's policy, then the required accumulator capacity can be calculated from the total

usable fluid volume used to carry out the above-mentioned opening/closing functions, thereby not dropping the operating

pressure below the recommended minimum value. The total usable fluid volume is based on Boyle's law.

5.4.4 BOP STACK OPERATION

FOUR-WAY VALVES

Four-way valves are used for closing and opening the blow-out preventers and they are actuated either

remote control, which activates a hydraulic cylinder, or by hand. If remotely operated, a pilot signal may factivate a three-way pilot valve. The pilot signal can be either electric (solenoid valves), acoustic, hydraulic

pneumatic.

All four-way valves should be either in the fully open or fully closed positions, as required; they should not normally be left in

the neutral or block position.

The four-way valve has to turn a full 90 to close or open a BOP.

Figure 3.5.42 : Operation of 4-way valves

PRESSURE REGULATING VALVES

Pressure regulators keep a pre-set reduced pressure on a hydraulic system (see Nos. 24 and 30 in Figure 3.5.4

Regulators work on the principle of a pressure differential between the force exerted by a spring (which w

keep the regulator open) and the oil pressure to the regulator (which will close the regulator and let off excpressure, if necessary).


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Equilibrium is reached therefore when the set spring pressure is equal to the force exerted by the oil pressurthe regulator is then closed.

If the pressure to the regulator is higher than the spring force, for example when a tool joint has to pass

annular preventer, the regulator spool will rise, overcoming the spring force, and allow oil to escape. As soonthe pressure behind the regulator has dropped below the set value, e.g. because a tool joint has passed

annular preventer during stripping, the spring force will move the spool downwards and supply oil until required pressure has been achieved.

Regulator pressure can be adjusted either by hand or by a pneumatic cylinder.

The hydraulic closing unit may be fitted with an annular unit/remote selector valve. This valve selects the moof annular regulation from the unit or from the air remote control panel.

The regulator illustrated in Figure 3.5.43 maintains regulated pressure even if its pilot signal is lost, because

position of the regulator is fixed by the spindle.

Figure 3.5.45 : Self closing couplings Figure 3.5.43 : Fail-safe regulator


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REMOTE CONTROL PANELS

Control panels are provided with the graphic outline design of the blow-out preventer stack, to reduce mistamade by operating the wrong lever during emergency situations.

Figure 3.5.44 : Remote control panel

Control panels are connected to thehydraulic BOP operating unit in such a way

that, should they be destroyed, all preventerscan be controlled from the master hydraulic

control manifold by operating the four-wayvalves manually.

Two hands are required to operate the panel.

The master control valve must be actuatedand held in place with one hand while the

correct function is chosen and operated withthe other hand. This procedure prevents

accidental operation due to bumping into thepanel control valves.

HYDRAULIC LINES

The connections between the hydraulic unitand the preventers should consist of HP fire

resistant hoses or steel pipe and joints.

To prevent oil losses and to keep the hoses or pipes full of oil during rig move, self-closing couplings are use

SELF CLOSING COUPLING

Each coupling half is provided with a spring loaded check valve. As long as the connection is disengaged

valves remain closed and the oil is trapped. (Figure 3.5.45a).

Once the connection has been engaged the pins on the check valves open the check valves to allow free flowthe liquid (Figure 3.5.45b).

Self closing couplings also can be made as quick-lock couplings (Figure 3.5.45).

Additional well control equipment

5.5.1 INTRODUCTION

As long as the kelly or top drive is connected to the drill string the drill pipe can be shut off by one or mo

kelly cocks, also called drill pipe safety valves.


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The valve body of the Hydril kelly guard is made of one single piece which means that it is not necessarybreak any tightened connections when a seat or ball has to be renewed. It is only half the weight of a stand

kelly cock and is therefore much easier to handle. The simplicity and reduced weight of this type of valve hled to it being used more and more as a stab-in valve. It can be ordered with either left-hand or right-h

thread, and could in principle also replace the Omsco upper kelly cock.

5.5.3 INSIDE BOPS

Three types of inside BOPs can be used:

Gray valve

Drop-in check valve

Float sub (bit sub)

All these valves are check valves closing with flow from below but free topump through from above. They are shown in the accompanying figures

The Gray valve is stored on the rig floor and is kept in the open position by avalve rod and a valve release screw.

If the well starts flowing while tripping the drill pipe must be closed in first.When there is a light flow the Gray valve can be installed directly on the drill

pipe. However, with strong back flow the force of the flowing mud can be sostrong that it is not possible to install the Gray valve due to its obstructed

bore. In such a situation a kelly cock, which has full bore passage, has to beinstalled first. After the kelly cock is made up and closed, the annular

preventer is closed. If it is decided to strip the string into the hole the Grayvalve will be installed. The valve release screw is undone and the spring will

close the valve. The locking sub is then removed and the kelly cock opened.

Presently there are alternative valves on the market which have anunrestricted bore with the (flapper) valve retained by a sleeve.

For information about drop-in check valves and float subs refer to Part 2.1

(subs).

Figure 3.5.48: Gray valve/inside B

Figure 3.5.49: Float sub Figure 3.5.50: Dart sub


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5.5.4 CIRCULATING HEADS

Figure 3.5.51 : Circulating head with hydraulic pack-off

Circulating heads are found in different

configurations. In operations such assetting packers, where the pipe must be

rotated to activate the settingmechanism, the circulating head may

need considerable bearing capacity. Thebearings in such heads have sufficient

capacity to even withstand prolongedrotation.

A circulating head may also have to beused when carrying out wireline bore

hole surveying (see Figure 3.5.51)through the drill string. One common

characteristic though is that they must bedesigned to withstand the rated pressure

of all other surface equipment andpossess the same standards of safety.

Figure 3.5.52 : Mud-gas separator

5.5.5 MUD/GAS SEPARATOR

In critical situations, when circulating out a gas kick, amixture of gas and drilling fluid may be ejected from the

well at high rates - as a foam, as gas and as slugs of more-

or-less gas free liquid in rapid (and chaotic) succession. Inthe absence of efficient separation of the gas and liquidphases a substantial quantity of drilling fluid may be lost at

surface, forcing a suspension of well killing activities whilefresh supplies of fluid are made up. This is a hazard to be

avoided if at all possible.The required separation is provided by the "mud/gas

separator" (occasionally known as the atmospheric gasseparator), which is designed to provide rapid venting of

gas and recovery of the bulk of the drilling fluid.It isstandard equipment on drilling units and has the advantages

of being robust and simple in operation.The main design features are:

Adequate height and diameter. Internal baffling to aid gas break-out.

Fluid seal by U-tube into the trip tank or dip tube. Gas vent outlet of adequate diameter and length.

Liquid outlet to be large diameter


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The mud/gas separator is designed to cope with a range of conditions, since drilling fluid properties may vwidely, as will the characteristics and behaviour of the kick fluids. The type of drilling fluid and the particu

conditions existing within the well bore will also considerably affect the environment within which separator has to operate.

SIZE OF VESSEL

The size of the separator is critical in determining the volume of fluid and gas which can be safely handl

Reasonable minimum size criteria are a diameter of 48" and a vessel height of at least 16 feet to provsufficient capacity to handle the majority of gas kick situations. Note that the separator inlet should have at le

the same ID as the largest choke manifold line after the chokes. This is typically 4" ID, though larger sizes often used.

The efficiency of the separator may be improved by arranging for a tangential inlet. This will help creatcentrifugal action which encourages faster gas break-out. To protect the tank wall at the inlet area a target pl

should be provided to minimise erosion where the gas-liquid mixture initially contacts the separator wall. It wbe necessary to arrange for an inspection hatch access nearby to allow a means of checking plate wear

carrying out replacement when needed.

The inlet should be located approximately at the tank mid-point. This permits the top half to act as a gchamber while the lower portion allows gas to separate out in the retained fluid. As the mixture of drilling flu

and gas enters, the operating pressure will be atmospheric plus vent line friction back pressure. The vertidistance from the inlet to the static fluid level is intended to allow time for gas break-out on the baffles. It a

provides an allowance for fluid levels to rise during the separator operation to overcome liquid outlet lfriction losses.

BAFFLES

The interior of the separator may be provided with a series of baffles. These are thin sheets, often cut as hdiameter circles and arranged in a spiral pattern of cascades to encourage liquid gas separation. The pla

should be well braced to the vessel body.

FLUID SEAL

If gas pressure in the separator overcomes the hydrostatic pressure of the fluid in the U-tube trap at the separabottom, gas will blow through into the shaker room. The U-tube or liquid outlet system should be arranged

provide a minimum U-tube height of at least 10 feet. This, with fluid of say 052 psi/ft, will support a bpressure of 5 psi. The liquid outlet line is recommended to be at least 8" ID, although 12" is advised to impr

the handling of high viscosity contaminated drilling fluid flows. Some combinations of drilling fluid types awell fluids can produce very high viscosity and significant gellation.

VENT LINE

The derrick gas vent line should be of large diameter, with as few bends as possible, to minimise bapressures. 8" ID lines are strongly recommended. It has been common practice in the past to use thick wal

line pipe for these derrick vents. This seems unnecessary, given the pressures involved, and reduces the interdimensions, limiting the capacity of the degasser vent line.


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5.5.6 VACUUM DEGASSER Figure 3.5..53 : Swaco degasser

Virtually all the gas which is entrained in thedrilling fluid can be removed by circulating it

through a degasser which is held at a partialvacuum. In this equipment (see Figure 3.5.53) gas-

cut drilling fluid is picked up from the shakers tankand pulled through the degasser vessel by a jet

pump. The small vacuum pump mounted on top ofthe vessel removes the freed gas and freely vents

these gases to the atmosphere.

The most commonly used degasser, that of Swaco,

has a large contact area with the drilling fluidflowing over a corrugated baffle plate. The vent line

from the degasser should preferably not beconnected the vent line of the mud/gas separator,

but if connected, a check valve must be inserted between these two vent lines.

Testing well control and related equipment

5.6.1 INTRODUCTION

Well head and well control equipment must be tested to ensure proper operation and pressure integrity agaithe highest anticipated pressures.

A functional test on

all preventers which close around pipe,

all pressure and manually operated kill- and choke line valves, and all kelly cocks,

should be carried out each time they have been installed and each time a new bit has been run to the casishoe. The blind/shear rams should be operated at least once a week.

If any of the above tests indicate faulty equipment, then that equipment must be repaired and re-tested bef

resuming operations.

A pressure test should be made on all blow-out preventers, wellhead components and their connections, BOP closing unit, the choke manifold, kill- and choke lines, the kelly or top drive valves and other drill str

shut-off valves in line with governmental regulations and/or

After installation of wellhead and BOP assembly and prior to drilling

Every week or every fortnight, depending on type of operation, operator's or governmenprocedures/regulations


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Prior to drilling into expected high pressure zones Prior to a production test

At any time requested by the Company drilling representative:

This Topic covers the procedures for testing casing, wellheads and well control equipmentand the evaluationthe tests.

5.6.2 CASING TESTS

INITIAL PRESSURE TESTS

The purpose of any casing pressure test is to verify that the casing string integrity is sufficient to contain maximum anticipated burst loads i.e. the design load case. Integrity for collapse loads is generally only test

indirectly, when inflow testing liner laps. Exerting a suitable differential test pressure at any point in the casstring is complicated by the fact that the fluids inside and outside the casing during the test are unlikely to

those expected to be present for the design load case. This means that the application of a given pressuresurface for a single test may result in insufficient or excessive differential pressures deeper in the well.

Ideally, casing pressure tests should thus be designed so that the differential pressure exerted at any poin

equal to or exceeds the maximum expected load but remains less than 91% of the rated internal yield pressuFor new casing the latter value can be ascertained from data handbooks. Where wear has occurred the follow

equation may be used :

Where:

P = the internal yield pressure, without safety factors

Y = the specified minimum yield strength for the given casing grade

t = the actual wall thickness

D = the actual OD

all in consistent units

Even when more than one weight and/or grade of casing is not present, it will often require the use oretrievable packer to test a casing string adequately.

The preferred time to test the casing is immediately following cementation prior to the cement setting, a

called "green cement test". This avoids the possibility of creating a micro-annulus, but such a test may notsufficient as it is further limited to ensure that:

the differential pressure at the casing shoe does not exceed the pressure rating of the float equipmeThis is commonly 21 MPa but equipment can be supplied with ratings of 34.5 MPa and above.


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the resultant tensile load does not exceed 77% of the rated pipe body yield strength at the critical poof the string. (This is consistent with the recommended design factor of 1.3 - see Topic 6.3.6.4

Section 2 Part 6- Casing Design )

During a pressure test the tensile load has three components :-

o

the load due to the pressureo the load due to the buoyant weight, and

o the bending load in doglegs.

For the calculation of the tensile load associated with a dogleg refer to Topic 6.3.2.2 of Section 2 Part

Casing Design). In a nominally vertical well the dogleg angle is taken as 2/100 ft (0.65/10m), unlegreater valaue has been measured.

Notes :

EP 89-1500 also recommends that a green cement pressure test is restricted to 75% of the casing inter

yield pressure. When testing with a retrievable packer, it should preferably be set above

the top of cement. In any case EP 89-1500 states that it shall not be placed within 80 m of the shoewithin 80m of a hydrocarbon bearing zone.

Casing pressure tests should be carried out for 10 minutes (EP89-1500). Problems may be experienced when trying to set packers in high grade casings due to the problem

getting the slips to bite.

SUBSEQUENT PRESSURE TESTS

The surface and intermediate casings may be pressure tested after a maximum period of about 30 days drill

through it and thereafter when it is judged necessary. These casings are also tested after a liner has binstalled.

The bottom 80 m (250 ft) of the casing is not pressure tested during these subsequent tests. This is to av

damage to the primary cementation by causing a microannulus to form. The same consideration appliehydrocarbons are present behind the casing, and pressure testing is not carried out within 80 m (250 ft) of

relevant section.

5.6.3 TESTS OF X-BUSHING AND SLIP AND SEAL ASSEMBLY OR BRX HANGER

Before a casing head spool is installed on the well head the side outlet valves are installed. These valves are f

pressure tested to their rated pressure using a test flange.

Once the spool is installed on the well head the X-bushing seal is energised by injecting plastic (see SectionPart 2 - Well heads). As soon as the seal is energised it is pressure tested before the complete BOP stack

bolted onto it.

If a BRX hanger has been used the pressure test can be carried out immediately after the spool is installed.


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5.6.4 SURFACE WELLHEAD AND BOP TESTS

After flanging up the BOPs a function test is done to ensure all hydraulic operatinglines are hooked up correctly. The complete well head, stack and manifold connections

can then be pressure tested using the cup type tester and the closed annular preventer.

The test pressure is the lower value of casing burst pressure andrated pressure of well head and BOP.

The preventers are tested to their working pressure using a plugtype tester which seats in the landing area of the casing head spool.

A bowl type tester or a combination tool for testing and runningthe wear bushing can also be used (see figures 3.5.54 to 3.5.56).

Figure 3.5.54: Plug type testerFigure 3.5.55 : Cup t

tester

Figure 3.5.56: Combination running and testing tool

When applying test pressure the side outlets of the

casing head spool, which are or could be exposedbelow the test plug, should be open to avoid

pressurising the casing below.

To test preventers closing around pipe, either a

test joint or short test sub with a hole drilled intothe side, or the kill line can be used. The first

method has the advantage that the test pressurecan be bled off at a choke, installed for this

purpose in the standpipe manifold.

To test the blind rams, the kill line must be used,because well pressure (or test pressure) assists in closing most preventers. They should also be tested at a l

operating pressure (3450 kPa or 500 psi).

The cup type tester is run with open ended pipe to prevent pressurisation of the casing. The pipe must be stroenough to withstand the tensile load caused by the hydraulic pressure on the cup area.

F = p x A,

where:

F = pipe load .. p = pressure A = cup area

The test string is in such a case suspended from the block to monitor the tensile load. When the blind rams

tested, the plug type tester must be converted into a blind plug (see Figure 3.5.56).


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36/36


Figure 3.5.57: Pressure drop versus time

A constant pressure during the full 10

minutes of test is the ideal result, but acertain drop in pressure is also often

acceptable, depending on the way inwhich this drop occurs (see Figure 3.5.57).

Installation requirements for wellhead & BO

equipment

The following practices and procedures enable safe well control operations to be carried out:

Adequate well head equipment should be installed to withstand anticipated pressures and allow

future remedial operations. Ram type preventers should be installed the correct way up.

All connections, valves, fittings, piping, etc., subject to well pressure, must be flanged, clampedwelded and have a minimum working pressure equal to the rated working pressure of the preventers.

Valves must be of the flush through bore type when in the open position. Screwed valves and fittings only acceptable on installations up to 13,800 kPa (2,000 psi) WP.

When installed, all ring gaskets should be new, checked for cleanliness and coated with light oil. Dand/or previously used ring gaskets should never be installed.

All bolts and fittings should be in place and tight, and all connections pressure tested, before drillingresumed.

The ID of the bell nipple to be installed should be large enough for hanger and seal assemblies to pthrough. Slip and seal assemblies should preferably be landed through the BOPs before lifting the B

stack. When boll-weevil hangers (BRX) are used to land the casing string before cementing, well head s

outlets should have a bore large enough to avoid excessive annular pressure whilst cementing. All manually operated valves should be equipped with handwheels, and be ready for immediate use.

Ram type preventers on surface BOP stacks should be installed with extensions and handwheconnected, and be ready for use.

The Company drilling representative should inspect and approve every BOP installation after flang

up and testing. Well head side outlets should not be used for killing purposes, except in case of serious emergencies. All pipe lines should be securely anchored.

Choke lines should be as straight as possible: no more than one choke line should be connected to choke manifold.

Kill lines should not be used for routine fill-up operations.

Well Control Equip

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