IADC Drilling Manual Part 8 doc

Slow circulating kill rates are usually required when circulating kicks for several reasons: in orderthat time for drilling fluid mixing to increase mud density may be increased, to mini

Choke Operation System.

The choke position is usually controlled with a hydraulic spool valve which will deliver oil to either the open orclosed side of the choke actuator The valve is generally a spring centered type which when released will auto-matically return to the center position which closes both hydraulic lines leading to the actuator This action effec-tively locks the choke in its last position (if there are no hydraulic oil leaks) The choke position at any time isindicated by a choke position indicator located in the face of the console

The choke operation system will frequently contain a choke speed control valve This is usually a small needlevalve located upstream of the choke control valve By partially closing this valve the speed of opening or closingthe choke can be reduced thus providing for precise positioning of the choke

Standpipe and Casing Pressure Gauges.

The pressure condition in both The standpipe and casing is monitored by large diameter pressure gauges mounted

in the face of console These gauges are usually calibrated in 25 psi, or smaller, increments The gauges areconnected by flexible high pressure hose to their respective monitoring points The hoses are usually oil filled toprevent entry of drilling mud This is accomplished through the use of isolators at the standpipe and manifoldpressure connection points These isolators contain either a flexible diaphragm or floating piston which allowspressure to be transmitted into the hose In higher pressure systems (greater than 10,000 psi) the piston typeisolator will provide a 4:1 pressure reduction ratio in order to allow the use of lower working pressure hoses Thegauge faces are calibrated to actual system pressure, but have a working pressure four times less than the maxi-mum gauge reading

An alternative method for measuring and displaying these pressures is through the use of low pressure pneumaticpressure transducers These transducers are located at the standpipe and manifold pressure monitoring points andare supplied with low pressure air from the console The design is such that the signal returned through the sepa-rate signal line is proportional to the mud pressure being monitored This signal pressure will generally not exceed

30 psi The console gauges will display actual system working pressure, but will in fact be low pressure pneumaticgauges

Pump Stroke Counter.

The console also contains a pump stroke counter This counter takes its input signal from the limit switches located

at the mud pumps The counter will accumulate total strokes and the count totalizer may be reset to zero whenneeded In addition to the stroke totalizer the unit will also contain a stroke rate indicator which reads in strokes perminute The stroke counter unit will generally allow for switching from one pump to another if that is necessary.The stroke counter unit may be powered externally, but is most usually battery powered with lithium batteries.These batteries will generally provide a life of up to five years The unit may be constructed to meet explosionproof requirements, but many are built to be intrinsically safe which leads to a lighter weight unit

communi-The console should be securely attached to the floor This attachment should be permanent if the control system isowned by the rig owner If the control console and drilling choke is rental equipment, the attachment means isnecessarily temporary, but the attachment must be sufficient to prevent the console from moving as a result of rigvibration Should the console move around, the hydraulic and/or other lines connected to the console may be

The air supply line, the hydraulic power lines from the choke actuator, the standpipe and easing pressure lines, thechoke position transmitter lines, and the pump stroke counter lines need to be routed so that they do not becomekinked or otherwise damaged during the normal course of drilling operations Any excess line should be carefullyrolled up and stored near the console, but in a location where it will not interfere with operations or become

damaged

Care needs to be taken to ensure that all lines to the console are connected to the proper port on the console Forexample the casing pressure line should be connected at the choke manifold pressure transmitter and also to theconsole pea which leads to the casing pressure gauge on the face of the console The design of the console may

be such that the various hydraulic and pressure lines have different size connectors so that they can be connected

to only one port on the console, but this may not be the case so care must be exercised

The limit switches for the pump stroke counter must be installed on the frames of the mud pumps in such a waythat they are tripped by the pump plunger during each stroke of the pump If the control system is rented, the limitswitches are usually supplied with a "C" clamp to facilitate attachment to the mud pump frame

After all the lines are properly routed and attached, the oil reservoir should be checked to ensure that it is filled tothe proper level The hydraulic pump should then be started by opening the air supply line As soon as hydraulicpressure in the system builds up to the point where the pump shuts down, the choke control valve (or valves)should be cycled in order to move the choke actuator from open to closed and back several times to facilitateremoval of any air from the hydraulic system It may be necessary to add oil to the choke actuator during thisoperation

D Diverter Control Systems

Diverters

Diverter Systems are used where shallow gas is anticipated during the initial drilling of the well prior to reachingthe stable formation where the casing is cemented Once this "shoe" is established, the B.O.P stack can be

installed and the well closed in should a "kick" be encountered during further drilling

Prior to cementing and establishment of the "shoe", gas encountered during The initial drilling must be diverted.Normally two diverter lines are employed at right angles to the prevailing wind Diverting is accomplished byopening one or both of the diverter lines, then closing the annulus space, (flowline access) with the "packer"

element This directs gas away from the rotary and mud pits, through the diverter vent lines and harmlessly awayfrom the rig The shallow pocket of gas will normally loose its pressure and bridge closed in a matter of minutes.The critical issues when shallow gas is encountered and as soon as the "kick" is detected is to respond quickly andcorrectly Quickly because in the shallow well there is little hydrostatic head pressure and little distance for the gas

to travel before a blowout

Correctly because closing in the well could cause a blowout to occur around the conductor allowing gas to migrate

up the outside of the conductor and to the drill floor To prevent closing in the well, at least one vent line must beopen prior to closing the diverter packer (flowline access to the annulus)

The most common diverter systems used on land, or fixed offshore rigs consist of an annular type blowout

preventer with a top mounted bell nipple which has an outlet for the flowline to the shale shaker/mud pits and one

or two diverter lines to vent the diverted gas overboard When the diverter packer closes on the drill pipe it closesthe annulus space shutting off the flow of drilling mud through the flowline Even in simple systems like this, it isprudent to have the diverter control system designed in a manner to prevent closing the diverter packer until atleast one diverter vent is open It is even more imperative in the more complex platform diverter systems andsubsea diverter systems that critical functions occur automatically and that safeguards are employed to prevent

erroneous operation which could result in injury, damage to the rig and damage to the environment.

Generally accepted diverter control system recommended practices are listed in API RP 16E.5

General Information

The master hydraulic diverter control manifold or panel should be treated in the same manner as the B.O.P.hydraulic control unit as stated in API RP16E.2.6.7 It should be located in a safe (protected) area away from thedrill floor but accessible to rig personnel in case the drill floor has to be evacuated in an emergency This meansthat the diverter functions should be capable of remote control from the driller's position

The automatic sequencing circuitry and safety interlock circuitry should always be established in the masterhydraulic diverter control manifold If these circuits were to be established in the remote control panel, they could

be inaccessible or rendered inoperative by damage if the drill floor was evacuated because of gas, fire or fallingdebris

NORMAL AUTO SEQUENCE Not required in the control system

NORMAL SAFETY INTERLOCK Not required in the control system

NOTE: The FSP diverter is designed so that when the piston moves up to close the diverter packer closing theflow line out of the top mounted bell nipple, it clears the bottom outlet to the vent line which is blocked when thepiston is down (diverter packer open) The vent line cannot be closed There is a selector deflector to select port

or starboard

Vetco KFDJ

NORMAL AUTO SEQUENCE Placing the diverter packer control valve in the close position automaticallyshifts The pre-selected overboard control valve to the open position, and ensures The inflowing valves shifts to theposition indicated if they are rot already in that position:

Insert Packer Lock

Diverter Lock Dogs Lock

Flowline Seals Pressurized

Overshot Packer Pressurized

Flowline / shaker Valve Close

Trip Tank Valve Close (if applicable)

Fill-Up Valve Close (if applicable)

NORMAL SAFETY INTERLOCKS Hydraulic pressure to close the diverter packer is prevented until thefollowing pilot signals are sensed:

1 At least one overboard valve has been actuated to open

2 The insert packer has been actuated to lock

3 Pressure is applied to both the flowline and overshot packer seals

TIME DELAY CIRCUITS The following circuits should be designed so they can be overridden after a 10 to 60second delay:

1 Overboard valve can be shifted to port open / starboard close or starboard open / port close

2 Flowline valve can be opened or closed at the operators discretion

3 Trip tank valve can be opened or closed at the operators discretion

4 Riser fill valve can be opened or closed at the operators discretion

NOTE: If overriding these functions is desired by the operator with the overboard valves closed, the diverter-testvalve can be placed in the test position interrupting the auto sequence This is normally required for low pressuretesting of the diverter lines

Additional Features Common To Platform Diverters:

1 Safety circuit to prevent venting the flowline seals or overshot packer when the diverter packer is closed

2 Optional divert/strip function

3 Divert/test mode function allows closing all diverter functions for low pressure testing

4 Low deadband failsafe pneumatic motor driven remote controlled regulators Normally only the diverter packerpressure regulator is remotely operated All regulators can be remotely operated Remotely operated regulatorsshould be sensitive to down stream pressure changes within plus/minus 150 psi

5 KFDJ and KFDS diverter control systems should include a "Diverter Ready" indicator to indicate when thesafety interlock circuits have been preset to their proper position

6 Hydraulic safety logic should be used to reduce the dependence on pneumatic circuitry

7 Pneumatic circuits should be minimized for safety Air supply for a minimum of two times the volume to quence the diverter controls should be check, valved in and stored in the panel for emergency operation

se-8 Low air supply pressure and low hydraulic supply pressure warning lights should be included in diverter controlsystems with electric remote control Function position status indication should also be included

Vetco KFDS

The normal auto sequence, safety interlocks, delay circuits and additional features described in the KFDJ diverterbrief descriptions are generally applicable to the KFDS diverter controls for subsea systems KFDS systemsusually have more hydraulic functions than the KFDJ and will include a slip joint packer which may be energized

by air or hydraulic pressure

KFDS diverter control systems are normally self-contained units They include dedicated pumps, reservoirs andaccumulators.

Diverter Remote Controls

The master hydraulic diverter control manifold or control panel should be located off the drill floor in an arearelatively safe from gas, fire and falling debris and should be accessible to the drilling crew for operation in anemergency This means that the diverter control functions should be capable of remote control from the driller'slocation On offshore drilling rigs, the control panel at the driller's location should as a minimum include the follow-ing features:

1 Control and status position indication of all diverter control functions

2 Control of the diverter packer regulator to increase/decrease function

3 Low hydraulic supply and low air supply to the master panel alarms If the diverter control system is a contained" unit, low reservoir level of the diverter control fluid reservoir should be included

"self-4 Electric pump running light (Self-contained units with electric pump.)

5 "On battery power" indicator (units so equipped with emergency battery back-up)

6 Nitrogen back-up initiated (if so equipped)

7 Indication of all system pressures

8 Function controls oriented and represented in a graphic display of the diverter system

The driller's remote control panel should be designed in accordance with the recommendations of API RP16E.2.6(see API RP16E.5.6) Driller's panels should be suitable for installation in explosive gas environments

Diverter control panels can frequently be incorporated with the B.O.P control system panels to conserve space.Diverter functions should be electrically independent of the B.O.P control functions

Diverter Back-up Systems

The response time recommendation to sequence the diverter system and close the diverter packer within 30seconds for diverter packers up to 20 inch nominal bore size and 45 seconds for diverter packers over 20 inchnominal bore size (Ref API RP16E.5.1) can be met with a nitrogen back-up system or dedicated hydraulicaccumulators (Ref API RP16E.5.3.2) The back-up system can have manual intervention as long as it is select-able on demand (remote control from the driller's panel) or otherwise, automatic Automatic hydraulic back-upsystems sense the loss of a hydraulic pilot signal and automatically open the back-up accumulator supply into thehydraulic control manifold of the diverter control system

Automatic nitrogen back-up systems likewise sense the loss of hydraulic pilot pressure and automatically injectstored nitrogen pressure into the manifold circuit for sequencing the diverter functions and closing the diverterpacker

Either system can be "unit" mounted or "separate skid" mounted Hydraulic back-up systems, whether unit

mounted or separate skid mounted, must be designed with consideration of the reservoir size for the additional fluidvolume of the back-up accumulators

Pump up time for initially charging the back-up system accumulators need not be considered when sizing pumpsystems in accordance with API RP16E.5.31 The back-up accumulators will remain charged after the initialcharging unless operated in an emergency according to their design intent.

E Control Systems Typical Capacity And Performance Data / tions

Calcula-Blowout prevention equipment such as annular preventers and ram preventers are normally opened or closed byfluid pressure The fluid to accomplish this is stored in the accumulator The pressure used must meet the capacityand operator pressure requirements of the particular blowout preventer in order for it to perform as designed.The performance characteristics of blowout preventers are discussed in paragraph K1.8 The capacity require-ments, operator chamber design working pressure, and opening and closing ratios of most major manufacturers'blowout prevention equipment are shown in the Quick Reference Tables K1.8.1 through K1.8.5

Table K1-8-2 Hydril Annular BOPs - Operating Characteristics

Table K1-8-3 Cameron Annular BOPs - Operating Characteristics

Table K1-8-4 Shaffer Annular BOPs - Operating Characteristics

Table K1-8-5 Hydril Ram BOPs - Operating Characteristics

Table K1-8-6 MH Koomey Ram BOPs - Operating Characteristics

Table K1-8-7 Cameron Ram BOPs - Operating Characteristics

Table K1-8-8 Shaffer Ram BOPs - Operating Characteristics

Closing Time Of Preventers

Fast response capability is a key factor in blowout prevention and overall rig safety

API recommendations specify that ram BOPs for surface equipment should be capable of closing within 30

seconds of actuation regardless of size Closing time for annular preventers smaller than 18-3/4 inch nominal boreshould not exceed 30 seconds from actuation and annular preventers 18-3/4 inches and over should not exceed 45seconds When the BOPs are located on the ocean floor (subsea systems), an additional 15 seconds is generallyacceptable to allow for pilot signals from the surface which actuate the control valves mounted in control podswhich are located on the lower marine riser package

In order to have the fluid capacity at the pressure required to operate the BOPs within the specified time limit,accumulator bottles are used to store this energy Accumulator bottles are pressure vessels pre-charged withnitrogen gas to store the operating fluid under pressure

The basic principle of operation of the accumulator is that when the volume of gas is reduced by pumping liquidinto the bottle, its pressure increases Boyle's Law defines this relationship between the volume of gas and itspressure as given below;

"The absolute pressure of a confined body of gas varies inversely to its volume provided its temperature remainsconstant".

This means that if a volume of gas is compressed to 1/3 of its original size, the pressure will be 3 times greaterthan before compression at,er it has been allowed to cool to its original temperature (compression generates heat).Boyle's Law can be expressed by the following equation:

P1 x V1 = P2 x V2

Where:

P1 = initial pressure (nitrogen pre-charge)

V1 = initial gas volume

electro-pneumatic P2 = pressure at a later time

V2 = gas volume at a later time

There are two important considerations to Boyle's Law that have not been taken into account One is absolutepressure and the other is temperature effects

Absolute Pressure

A pressure gauge is calibrated to read zero psi when it is unconnected regardless of atmospheric pressure, tion, or barometric pressure This is written as psig, pounds per square inch - gauge At sea level, the weight of airproduces an atmospheric pressure of 14.7 psi if pressure is to be stated in absolute terms for solving problemsusing Boyle's Law, atmosphere pressure must be added to The gauge reading to obtain the absolute pressure leveland this should be written psia, pounds per square inch - absolute

eleva-Temperature

Nitrogen gas is used to pre-charge accumulators primarily because it is an inert gas This means it does not easilytake part in chemical reactions Therefore, nitrogen has the advantage of not being combustible under pressure inconjunction with petroleum based hydraulic fluid While there are other inert gases that could be used, nitrogen gas

is relatively cheap and readily available in many parts of the world

If compression and expansion of the nitrogen gas is allowed to occur slowly providing sufficient time for heat to bedissipated, this condition is referred to as isothermal and no allowance for the relationship between gas and tem-perature is entertained The safety factors included in standard calculations normally are sufficient to compensatefor absolute pressure and temperature effects These effects are therefore not considered in order to simplify thecalculations for the rig personnel

Application Of Boyle's Law For Calculating Stored Usable Fluid In Surface Accumulator Bottles

Since accumulator bottles are normally pre-charged to 1000 psi, that becomes the initial pressure (P1) Let us saythat the accumulator bottle has 10 gallons of capacity (V1), the minimum pressure required to operate the BOPfunction is 1200 psi, and the maximum pressure that will be placed in the bottle is 3000 psi

It is important to note that the "stored usable fluid" contained in the accumulator bottle is that amount pushed out ofthe bottle by the expanding nitrogen gas bubble as pressure falls from 3000 psi to 1200 psi Any fluid remaining inthe bottle at that time is not considered "usable"

We can calculate (under isothermal conditions) that amount not considered usable by solving the Boyle's Lawequation for V2 as given below:

V2 = P1 x V1/P2 = 1000 x 10 / 1200 = 8.3 gallons nitrogen

Where:

V2 = gallons of nitrogen at minimum system pressure

P1 = initial pressure (nitrogen pre-charge), psia

V1 = initial gas volume in gallons

P2 = minimum system pressure, psia

So as the pressure in the bottle rises from 1000 psi (pre-charge pressure) to 1200 psi (minimum system pressure),the nitrogen gas is compressed from 10 gallons to 8.3 gallons or 1.7 gallons of liquid was forced into the bottlecausing the pressure rise This 1.7 gallons is not considered stored usable fluid

The total volume of liquid in the bottle at the maximum system pressure can also be calculated using Boyle's Law

as given below:

V3 = P1 x V1 /P3 = 1000 x 10 / 3000 = 3.3 gallons nitrogen

Where:

V3 = gallons of nitrogen at maximum system pressure

P1 = initial pressure (nitrogen pre-charge)

V1 = initial gas volume in gallons

P3 = maximum system pressure in psi

Now we know that as the pressure in the bottle rises from 1000 psi (pre-charge pressure) to 3000 psi (maximumsystem pressure), the nitrogen gas is compressed from 10 gallons to 3.3 gallons or 6.7 gallons of liquid is now in thebottle Remembering that the 1.7 gallons is not usable, we can determine the stored usable fluid in the bottle by thefollowing equation:

Stored Usable Fluid = (6.7 - 1.7) gal = 5.0 gallons

Said another way, as the pressure in the 10 gallon accumulator falls from 3000 psi to 1200 psi, 5.0 gallons of liquidare forced out of the bottle and into the system

NOTE: Accumulator bottles come in various sizes Some manufacturers state the size in regard to their gas

volume while others state the physical inside volumetric capacity as the size It is sometimes necessary to subtractthe bladder or float displacement from the physical inside volumetric capacity in order to arrive at the true gasvolume or stored usable fluid volume For example, an 11 gallon accumulator bottle becomes 10 gallon capacitywhen subtracting approximately 1 gallon for bladder displacement

Sizing Accumulator System Capacity For Surface Blowout Preventers

Referring to the tables in K1.8, above, let us say that we have a surface BOP stack that requires the followingclosing volumes of fluid:

Annular gallons to close = 17.98 gallons

3 Rams @ 5.8 gal ea to close = 17.40 gallons

Total galonage required: 35.38 gallons

Plus 50% Safety Factor 17.69 gallons

Stored Usable Fluid Required = 53.07 gallons

Having previously calculated the stored usable fluid in a 10 gallon accumulator bottle, we can calculate the number

of bottles required according to the following equation;

Accumulator = (Stored Usable Fluid Required) / (Stored Usable Fluid per Bottle)

= (53.07 gallons )/(5.0 gallons/bottle) = 10.6 or 11 bottles

Government regulations of various countries and some oil companies have specific requirements regarding mulator capacity The preceding references and calculations are only intended to explain the considerations andfundamentals of calculating accumulator capacity using Boyle's Law which is a widely accepted method

accu-Maximum charging pressure, pre-charge pressure, and minimum working pressure of the accumulator system mayvary on certain "high pressure", (10,000 psi and above) BOP systems These pressures may be changed as a result

of requirements to close ram type BOPs against full well bore pressure Control system manufacturers mayrecommend alternative accumulator capacity calculations in order to optimize performance of the system whileminimizing cost IADC recommends contacting a reputable control system manufacturer when proper accumula-tor capacities are in question

Application Of Boyle's Law For Calculating Stored Usable Fluid In Subsea Accumulator Bottles

BOP control systems used to control blowout preventers which are connected to the wellhead at the ocean floorsometimes have accumulator bottles mounted on the BOP stack as well as surface accumulator bottles Thesesubsea bottles serve to give a quicker response by holding some of the stored usable fluid very close to the

preventers Also, if supply from the surface is interrupted, the stored usable fluid in the subsea bottles can be used

to close in the well while corrective action is taken

Accumulator bottles mounted below the water's surface are subject to additional pressure proportional to theservice depth When the subsea control valve is piloted sending pressure to close the BOP, the open side valvevents to the sea As the BOP closes, the fluid is being expelled from against the hydrostatic pressure of the

seawater This pressure can be expressed as hydrostatic pressure or as a pressure gradient One way to look athydrostatic pressure is by considering the operating fluid supply line to the accumulator bottles which would be theweight of the column of control system fluid from the surface; the other is to consider the weight of the seawater

at the depth of the function which the accumulator must overcome in order to discharge fluid Control system fluid

is basically water which has a weight density of 62.4 pounds per cubic foot or a pressure of 0.433 psi per foot.Seawater has a weight density of 64 pounds per cubic foot or a pressure of 0.445 psi per foot It is easy to see thatwhichever way you consider hydrostatic pressure there is not enough difference to be concerned about

Let us use Boyle's Law to calculate the stored usable fluid in a 10 gallon accumulator bottle that is to be operated

in 3000 feet of water In this case the correct pre-charge pressure is calculated as given below:

Pre-charge pressure = Seawater Hydrostatic Pressure for Subsea Bottles + Pre-charge Pressure

= (0.445 x 3000) + 1000 = 1335 + 1000 = 2335 psi

It is important to note that the minimum system pressure is still 200 psi above the pre-charge pressure and mum system pressure is still 2000 psi above pre-charge pressure Therefore;

maxi-Minimum System Pressure = 2335 + 200 = 2535 psi

Maximum System Pressure = 2335 + 2000 = 4335 psi

The stored usable fluid in our subsea bottle is calculated in exactly the same fashion as for a surface bottle Wecan calculate that amount not considered usable by solving the Boyle's Law equation as follows:

V2 = P1 x V1 /P2 = 2335 x 10 / 2535 = 9.2 gallons nitrogen

V2 = gallons of nitrogen at minimum system pressure

P1 = initial pressure (nitrogen pre-charge)

V1 = initial gas volume in gallons

P2 = minimum system pressure in psi

So as pressure in the accumulator bottle rises from 2335 psi (pre-charge pressure) to 2535 psi (minimum systempressure), the nitrogen gas is compressed from 10 gallons to 9.2 gallons or 0.8 gallons of liquid was forced into thebottle This 0.8 gallons is not considered stored usable fluid The total volume of liquid in the bottle at the maximumsystem pressure can also be calculated using Boyle's Law as given below:

V3 = P1 x V1 /P3 = 2335 x 10 / 4335 = 5.4 gallons nitrogen

Where:

V3 = gallons of nitrogen at maximum system pressure

P1 = initial pressure (nitrogen pre-charge)

V1 = initial gas volume in gallons

P3 = maximum system pressure in psi

Now we know that as the pressure in the bottle rises from 2335 psi (pre-charge pressure) to 4335 psi (maximumsystem pressure), the nitrogen gas is compressed from 10 gallons to 5.4 gallons or 4.6 gallons of liquid is now in thebottle Remembering that the 0.8 gallons does not count, we can determine the stored usable fluid in the bottle bythe following equation:

Stored Usable Fluid = (4.6 - 0.8) gal = 3.8 gallons

Said another way, as the pressure in the 10 gallon accumulator bottle falls from 4335 psi to 2535 psi, 3.8 gallons ofliquid are forced out of the bottle and into the lines One problem encountered in deepwater drilling is diminishingstored usable fluid inside subsea accumulator bottles as depth of water increases

NOTE: The maximum system pressure used in this example would exceed the design working pressure of dard 3000 psi WP accumulator bottles 5000 psi WP accumulator bottles must be used in this application

stan-Sizing Accumulator System Capacity For Subsea Blowout Preventers

Subsea systems because of their isolation by location and greater risk of environmental damage usually are sizedfor more accumulator volume than surface systems API RP16E.3.4.1 recommends capacity to close and open all

of the ram type BOPs and one annular BOP plus fifty percent reserve Consideration for minimum pressure is alsostated for closing a ram (excluding shear ram) against full rated wellbore pressure or the minimum pressure

required to open and hold open any kill or choke valve at maximum rated wellbore pressure

Calculations for surface mounted accumulators are the same as previously described When part of the tor volume is to be placed subsea, the subsea volume requirements can be subtracted from the total volume

accumula-requirement which leaves the surface volume accumula-requirement In other words, the subsea stored usable fluid volumeplus the surface stored usable fluid volume must meet or exceed the total fluid volume required at the minimumsystem pressure specified in order to operate the BOP function

For explanation purposes let us say the same BOPs are used for the subsea calculations as were previously used:Annular gallons to close = 17.98 gallons

Annular gallons to open = 14.16 gallons

Rams (3) @ 5.8 gal each to close = 17.40 gallons

Rams (3) @ 5.4 gal each to open = 16.20 gallons

Total gallonage required: 65.74 gallons

Plus 50% safety factor = 32.87 gallons

Stored usable fluid required = 98.61 gallons

We will say in this instance that the capacity to close the annular and one ram will be mounted subsea

This capacity can be subtracted from the surface capacity as given below:

98.61 gal - (17.98 gal + 5.80 gal) = 74.83 gal

Therefore we now know that we need to have enough accumulator bottles at surface to give 74.83 gallons ofstored usable fluid and enough accumulator bottles at the BOP stack to give (17.98 gal + 5.80 gal) 23.78 gallons ofstored usable fluid Since we have previously calculated the stored usable fluid in both surface and subsea 10gallon accumulator bottles, we can calculate the number of bottles required as follows:

Surface Accumulator Bottles Required = (Stored Usable Fluid Required)/( Stored Usable Fluid per Bottle)

= (74.83 gal)/(5.0 gal per bottle)= 15 bottles at surface

Subsea Accumulator Bottles Required = (Stored Usable Fluid Required) /(Stored Usable Fluid per Bottle)

= (23.78 gal)/(3.8 gal per bottle) = 6.3 or 7 bottles mounted subsea bottles on SS Stack

Calculating Reservoir Capacity

Closed hydraulic system reservoirs used to operate surface mounted BOP stacks should be sized to hold a mum of two times the usable fluid of the accumulator system The purpose of the additional reservoir capacity is toallow bleeding the accumulator system hydraulic pressure back to the reservoir without over-filling This meansthat during normal operation, if the reservoir is exactly sized for this capacity, it should be operated half full

mini-Open hydraulic system reservoirs used to operate subsea mounted BOP stacks should be at least equal to the totalaccumulator storage capacity There should be sufficient space in the reservoir above the upper hydraulic fluid fillvalve shut off level to permit draining the largest bank of accumulator bottles back into the tank without overflow

Sizing Pump Systems

Pump systems should be capable of delivering sufficient volume of control fluid with the accumulators isolatedfrom service to meet the greater of the following recommendations:

1 Close one annular BOP (excluding diverter) on open hole and open one choke line valve while attaining cient pressure to effect seal off as recommended by the annular BOP manufacturer at zero wellbore pressure(this is nominally 1200 psi) Verification should be by closing on the minimum size drill pipe to be used The pumpsystem should accomplish this within two minutes

suffi-2 Pump the entire accumulator system up from accumulator pre-charge pressure to full charging pressure (themaximum system pressure)within fifteen minutes

There should be a minimum of two independent pump systems operating from separate power sources Each ofthe pump systems should have sufficient sizes and quantity of pumps to meet the preceding recommendation

K3 Well Control Procedures

Basic Principles

Definition

A kick is an influx of formation fluids into the well bore A blowout is an uncontrolled kick The objective of wellcontrol procedures discussed in this section is to safely handle kicks and reestablish primary well control

Primary Well Control

During normal drilling operations, formation fluid flow into the wellbore is prevented by greater hydrostatic sure from drilling fluids in the wellbore When drilling or wellbore fluids have a hydrostatic pressure which isgreater than the pressure found in the formation fluids there is said to be an overbalance

Bottom-hole Pressure (Bhp) Vs Formation Pressure (Fp)

Bottom-Hole Pressure may be defined as the total pressure at the bottom of the well For Well Control Purposes,this may be considered as a downward force Formation Pressure, the pressure of the fluids in the formation, may

be considered an upward force, for Well Control purposes BHP and FP then act in opposite directions

When primary well control is working as intended BHP is greater than FP When a kick is occurring, FP isgreater than BHP

A BHP when well open and pumps off

BHP = Hydrostatic Pressure of Wellbore Fluids

B BHP when well open and pumps on

BHP = Hydrostatic Pressure of Wellbore Fluids plus Annulus Friction

Slow Circulating (Kill) Rate / Pressure

For well kick killing operations, a circulating pressure can be measured at a convenient slow circulating (kill) pumprate frequently one-half or less of the normal circulating rate It is recommended that the stroke rate and

pressure be recorded on the IADC daily drilling report for each pump and redone whenever any of the circulatingsystem pressure parameters is significantly changed, i.e., when drilling fluid density is changed by 0.2 ppg or more,when bit nozzle sizes are changed, when over 500 ft of new hole is drilled, after pump repairs or liner sizes arechanged, etc Slow circulating (kill) rates are usually required when circulating kicks for several reasons: in orderthat time for drilling fluid mixing (to increase mud density) may be increased, to minimize the amount of cuttingsthat may be circulated up and through the choke, in order that additional pressure to prevent formation flow can beadded without exceeding the pump liner rating, and to better enable the choke operator to make correct adjust-ments

Sub Sea Stack Considerations

One widely accepted method to determine Choke Line Friction (CLF) is to pump at each pre-determined slowcirculating (kill) pump rate in the normal drilling circulation path, i.e., down the drill string, up the annulus throughthe BOP and up the riser to the flow line After pumping in the usual flow path, the flow path should be changed tosimulate that of well fluids during a well kill To simulate the flow path of fluids during a kill, the BOP should beclosed and the valves on the BOP stack to the choke line opened, all choke manifold valves to and through theremote choke to the mud/gas separator opened and the choke itself fully opened, as well After completing thecorrect line-up, the pumps should then be run at the same slow circulating (kill) rates as through the normal drillingcirculation path

The differences between the pressures at the same pump rates on the same pump through the different flow paths

is considered the Choke Line Friction (CLF) at that pump rate and must be taken into account when killing wells

on floating rigs because it increases the pressure throughout the well

THE SLOW CIRCULATING PRESSURE THROUGH THE RISER IS CONSIDERED THE "KILL RATEPRESSURE" (KRP)

For subsea stacks in deep water, slow circulating (kill) rates (less than one-half normal circulating rate) may berequired to avoid excessive friction back pressure from pumping drilling fluids up the choke lines from the BOP tothe choke manifold (CLF), in addition to those reasons stated earlier in this section

Large changes in ANNULUS HYDROSTATIC PRESSURE occur when a choke line goes from being filled withmud to being filled with gas and later when the choke line goes back to being filled with mud These ANNULUSHYDROSTATIC PRESSURE changes cause changes in the bottom hole pressure of the well which are moreeasily compensated for with choke back pressure changes when the circulation rate is slow

II Pre-kill Procedures

Close-in (Shut-in) Procedures

1 Soft Close-in:

A Pre-kick line up:

BOP open

Remote choke open

Hydraulic valve(s) on BOP stack closed

All choke manifold valves to Remote Choke open All choke manifold valves past Remote Choke to Mud/GasSeparator (poorboy degasser) open

Remote choke closed

Hydraulic valve(s) on BOP stack closed

All choke manifold valves to Remote Choke open

All choke manifold valves past Remote Choke to Mud/Gas Separator (poorboy degasser) open

Remote choke closed

Hydraulic valve(s) on BOP stack closed

All choke manifold valves to Remote Choke open All choke manifold valves past Remote Choke to Mud/GasSeparator (poorboy degasser) open

If after closing in the well the surface pressures do not stop increasing, there is a strong possibility that there is agas influx in the hole and that it is rising (migrating) in the hole much the same as an air bubble in water

There is also a possibility that the formation has low permeability, and for that reason the total that the wellborehydrostatic pressure lacks to balance the Formation Pressure is slowly expressed on the Drill Pipe and CasingPressure Gauges

There is one good way to determine what the amount of underbalance is in a well where the closed-in pressurescontinue to rise rather than rising and then stabilizing after closing in the well This method requires that the driller,

or whoever monitors the closed-in pressures, write down the closed-in pressure values at some pre-agreed upontime interval, beginning as soon as possible after the initial close-in

The recommended time interval for writing down the Closed-in Drill Pipe and Closed-in Casing (annulus) sures is once every minute As the pressures are recorded, they need to be entered on to a sheet of graph paper.Increasing time would be expressed on the axis going from left to right Increasing pressure would be expressed

pres-on the axis going upwards See example graph pres-on following page When the rate of increasing pressure changes(slows) the pressure at that point may be considered the amount of underbalance

Figure K3-3 Closed-In Drill Pipe Pressure

Closed-in Drill Pipe Pressure

When the well is closed in, the bottom hole pressure will rise until equal to formation pressure As the drill pipe(and annulus) are in communication, the Closed-in Drill Pipe and the Closed-in Casing (annulus) pressures will alsorise and stabilize (in the absence of migrating gas) the Closed-in Drill Pipe pressure at this time indicates theamount of underbalance of the hydrostatic pressure in the drill string relative to the formation pressure It is

assumed that the drill string is filled with a column of clean drilling fluid of equal density from the rig floor to the bit,i.e., a known hydrostatic pressure value In well killing operations, the drilling fluid density is increased by theequivalent value of the Closed-in Drill Pipe pressure

Until circulation begins, if there is gas in the well, surface pressures will continue to rise due to gas migration.Increased drill pipe pressures due to gas migration read after any stabilized reading will indicate excessive drillingfluid density increase

Gas Migration Considerations

Migrating (rising) gas in a closed in well causes pressures to rise throughout the well the increasing pressure in thewell caused by migrating gas can lead to loss of integrity in the circulating system, i.e., lost circulation

Such excessive pressure should be avoided whether gas rises through a static drilling fluid column or if it is lated out by allowing the gas to expand as it rises while maintaining constant Bottom-Hole pressure Whenproperly using a well kill method which keeps Bottom-Hole pressure constant, any gas in the well will be allowed

circu-to expand by the amount necessary circu-to keep Botcircu-tom-Hole pressure constant This also requires that the pits beallowed to gain volume

If it is believed that there is migrating gas in the well when waiting to begin circulation and if the bit is at or nearbottom, to avoid excess wellbore pressures the choke should be used to bleed drilling fluid from the casing theamount of pressure to try to keep constant is the Closed-in Drill Pipe pressure value which reflects the amount ofunderbalance in the drill string, plus 100 or 200 psi See page 6 for choke adjustment considerations

Closed In Drill Pipe Pressure Determination With A Float In The String

To determine the closed-in drill pipe pressure when a back-pressure valve (float) is in the drill string, Closed-in DrillPipe pressure should be increased slowly in 50 or 100 psi increments using the smallest pump available

After each stage of increasing the Drill Pipe pressure, the Casing (annulus) pressure should be monitored for achange If the Casing pressure does not change (increase), the float has not opened, and the Closed-in Drill Pipepressure is less than the underbalance of the hydrostatic pressure in the drill string

When Casing pressure is seen to rise, pumping should be stopped immediately The current Closed-in Drill Pipepressure, minus any increase seen on the Casing (annulus) Pressure gauge, is the amount of underbalance of thehydrostatic pressure in the drill string relative to the formation pressure This is the value to be used when calculat-ing the Kill Weight Mud

III Formation Pressure Integrity Information

Leak-off Test And Masp

A leakoff test is made to determine the pressure at which a formation will begin to leak off Leakoff tests areusually run after drilling a short distance below the most recent casing shoe A leakoff test is performed by

pumping drilling fluid into the wellbore at a slow rate or in increments of volume, with blowout preventers closed.The resulting pressures are to be carefully plotted versus the volume pumped

The pressure at which the plotted curve begins to flatten, i.e when the pressure increases a smaller amount for avolume pumped, is the surface leakoff pressure Pumping should be stopped immediately The surface leakoffpressure plus the hydrostatic pressure of the drilling fluid at the shoe is the formation leakoff pressure

The formulas to calculate the formation fracture pressure and other Maximum Allowable Surface Pressures are to

be found on the kill sheets provided at the end of this section The gauge to monitor for Maximum AllowableSurface Pressures is the Casing (annulus) pressure gauge

Formation Competency Test And Masp

A formation competency test is made to evaluate if a wellbore will support drilling fluid of a higher pre-determineddensity than that which is currently in use The formation competency test is performed by pumping drilling fluidinto the wellbore at a slow rate or in increments of volume, with blowout preventers closed Pumping into thewellbore should be continued until reaching the pre-determined surface test pressure as calculated below:

Test Pressure (psi) = 0.052 x Casing TVD (ft) x density difference (ppg)*

*density difference (ppg) = desired drilling fluid density-drilling fluid density currently in use

While conducting this test, the surface pressure should be plotted against the volume pumped into the wellbore If

at any time the plotted curve should begin to flatten or the pressure decrease, pumping should be stopped ately (see page 3, Leak-Off Test, LOT, and MASP)

immedi-Kill Objective

After a kick has been stopped by well closure, it should be circulated to the surface at constant bottom-holepressure to avoid both further influx of formation fluids and excessive borehole pressures Also, drilling fluiddensity should be increased to reestablish primary well control

A drilling fluid of required density may be pumped while circulating out the kick (Wait and Weight Method), or thekick may be pumped out and then drilling fluid of required density circulated (Drillers Method) In the event ofinsufficient barite supply, drilling fluid density can be increased temporarily to an intermediate value using either ofthese methods

Establishing Circulation Surface Stacks

To establish the slow circulating (kill) rate while keeping a constant bottom-hole pressure, the pump rate should beincreased from zero spin to the kill rate spm's while holding a constant casing pressure equal to the closed-incasing pressure The recommended procedure is as follows:

1 Note the current Closed-in Drill Pipe and Closed-in Casing pressures

2 Concurrently open the choke and slowly bring the pump up to the slow circulating (kill) rate

3 While bringing the pump up to speed, adjust choke to hold the casing pressure constant at the closed-in value

By holding the casing pressure constant at the closed-in value for the short time required to bring the pump up tospeed, the bottom-hole pressure remains essentially constant

4 After the pump is running at the desired constant speed and the casing pressure is stabilized at the Closed-invalue, wait at least 2 seconds per thousand feet measured depth of the well and then read the drill pipe pressure

It is necessary to wait approximately two seconds per thousand feet of measured depth of the well to allow chokeadjustments to be reflected on the drill pipe pressure gauge

The Drill Pipe pressure read at this point is usually termed INITIAL CIRCULATING PRESSURE (ICP), ifthis pump start-up is taking place at the beginning of the kill The difference between the closed-in and pumpingdrill pipe pressures is the pressure required to cause the drilling fluid to circulate at the slow circulating (kill) rate,and is often termed the KILL RATE PRESSURE (KRP)

5 Compare any calculated or expected INITIAL CIRCULATING PRESSURE (ICP) to that which is now seen

on the Drill Pipe Pressure gauge If there is a difference and if the instructions above for establishing Initial

Circulating Pressure (ICP) have been followed, the pressure on the Drill Pipe Pressure gauge is correct if thecalculated Drill Pipe pressure is appreciably different from what is seen on the Drill Pipe Pressure gauge afterestablishing INITIAL CIRCULATING PRESSURE (ICP) it is recommended that the cause be identified

6 After bringing the pump strokes up to the slow circulating (kill) rate, it is absolutely necessary to keep the

PUMP STROKES constant in order to keep BOTTOM-HOLE PRESSURE constant

Establishing Circulation - Subsea Stacks - Method "A"

To establish the slow circulating (kill) rate while keeping a constant bottom-hole pressure, the pump rate should beincreased from zero spm to the kill rate spm's while holding a constant casing pressure equal to the closed-incasing pressure, MINUS THE CHOKE LINE FRICTION (CLF) VALUE FOR THE PUMP AND PUMPSPEED WHICH ARE TO BE UTILIZED The recommended procedure is as follows:

1 Note the current Closed-in Drill Pipe and Closed-in Casing pressures

2 Concurrently open the annulus choke and slowly bring the pump up to the slow circulating (kill) rate

3 While bringing the pump up to speed, adjust choke to reduce the Casing (Annulus) pressure from the closed-invalue to the closed-in value minus the Choke Line Friction (CLF) By holding the casing pressure constant at theclosed-in value minus the Choke Line Friction (CLF) value for the short time required to bring the pump up tospeed, the bottom-hole pressure remains essentially constant

4 After the pump is running at the desired constant speed and the easing pressure is stabilized at the Closed-invalue minus the Choke Line Friction (CLF) value, wait at least 2 second per thousand feet measured depth of thewell and then read the Drill Pipe pressure It is necessary to wait approximately two seconds per thousand feet ofmeasured depth of the well to allow choke adjustments to be reflected on the drill pipe pressure gauge

The drill pipe pressure read at this point is usually termed INITIAL CIRCULATING PRESSURE (ICP), if thispump start-up is taking place at the beginning of the kill The difference between the closed-in and pumping drillpipe pressures is the pressure required to cause the drilling fluid to circulate at the slow circulating (kill) rate, and isoften termed the KILL RATE PRESSURE (KRP).

5 Compare any calculated or expected INITIAL CIRCULATING PRESSURE (ICP) to that which is now seen

on the Drill Pipe Pressure gauge If there is a difference and if the instructions above for establishing Initial

Circulating pressure have been followed the pressure on the Drill Pipe Pressure gauge is correct If the calculatedDrill Pipe pressure is appreciably different from what is seen on the Drill Pipe Pressure gauge after establishingINITIAL CIRCULATING PRESSURE (ICP) it is recommended that the cause be identified

6 After bringing the pump strokes up to the slow circulating (kill) rate, it is absolutely necessary to keep thePUMP STROKES constant in order to keep BOTTOM HOLE-PRESSURE constant

Establishing Circulation - Subsea Stacks - Method "B"

The kill line pressure gauge can be used to monitor choke line friction and surface back pressure when circulation

is begun after a kick

1 The kill line should be opened to the surface manifold and the kill line pressure held constant by adjustment ofthe CHOKE LINE choke while bringing the pump up to the slow circulating (kill) rate

By holding the Kill Line pressure constant during the pump start-up, the Bottom-hole pressure remains tially constant

essen-2 After the pump is running at the desired constant speed and the Kill Line pressure is stabilized at the Closed-invalue, wait at least 2 seconds per thousand feet measured depth of the well and then read the Drill Pipe pressure

It is necessary to wait approximately two seconds per thousand feet of measured depth of the well to allow chokeadjustments to be reflected on the drill pipe pressure gauge

The drill pipe pressure read at this point is usually termed INITIAL CIRCULATING PRESSURE (ICP), if thispump start-up is taking place it the beginning of the kill the difference between the closed-in and pumping drill pipepressures is the pressure required to cause the drilling fluid to circulate at the slow circulating (kill) rate, and isoften termed the KILL RATE PRESSURE (KRP)

3 Compare any calculated or expected INITIAL CIRCULATING PRESSURE (ICP) to that which is now seen

on the Drill Pipe Pressure gauge If there is a difference and if the instructions above for establishing Initial

Circulating Pressure have been followed, the pressure on the Drill Pipe Pressure gauge is correct

!f the calculated Drill Pipe pressure is appreciably different from what is seen on the Drill Pipe Pressure gaugeafter establishing INITIAL CIRCULATING PRESSURE (ICP) it is recommended that the cause be identified

4 After bringing the pump strokes up to the slow circulating (kill) rate, it is absolutely necessary to keep thePUMP STROKES constant in order to keep BOTTOM-HOLE PRESSURE constant

Choke Adjustment Considerations

During the course of either of the kill methods presented here, it may be necessary to make adjustments to theDrill Pipe Pressure gauge by manipulating the choke The correct method is essential

1 When it is noted that a change is desired on the Drill Pipe Pressure gauge, note the amount of pressure bywhich it is to be changed

For example, if the current Drill Pipe pressure is 8:50 psi and the desired Drill Pipe pressure is 1000 psi, theamount of change desired is an additional 150 psi

2 Note the current Casing (annulus) gauge pressure and by manipulating the choke, change the Casing (annulus)gauge pressure by the amount of pressure change desired on the Drill Pipe pressure gauge.

For example continuing from the example in #1, above, if the current Casing (annulus) pressure is 1050 psi,the choke operator should close the choke to increase the Casing (annulus) pressure by 150 psi to 1200 psi

3 Wait at least two seconds for every 1000 feet of measured depth of the well for the pressure change to comefrom the choke to the Drill Pipe pressure gauge

IV Kill Techniques

Drillers Method

Please use the following information, the table below, and the Driller's Method kill sheet utilizing this kill method

Table K3-P8 Steps of the Driller's Method

1 The first step of the Driller's Method is most appropriate for use (by itself) when circulating out kicks that havebeen swabbed in while tripping out of the well The fact that the mud density is not increased in the first step ofthe Driller's Method makes it the best choice in that situation.

In a swabbed-in kick situation, it is not always necessary to increase the mud density before continuing to pullthe string out of the hole The assumption is that the well was stable with the mud in the hole before coming offbottom, therefore it should only be necessary to circulate out the swabbed-in kick and then the string should beable to be pulled out of the hole

2 it is assumed that in the second step of the Driller's method there is a column of clean drilling fluid of the samedensity in both the drill string and the annulus at the beginning of the circulation

As the Kill Weight Mud (KWM) is circulated from the surface to the bit, the Casing (annulus) pressure is heldconstant at, er bringing the pump up to the slow circulating (Kill) rate Since the hydrostatic pressure is stayingconstant in the annulus, and the surface CASING (annulus) pressure is kept constant through choke manipulation,the Bottom Hole pressure is held (essentially) constant

The pressure seen on the Drill Pipe pressure gauge when the Kill Weight Mud (KWM) reaches the bit is theFinal Circulating Pressure (FCP) for the Driller's Method

3 The third step of the Driller's Method begins when the Drill String has been filled with the Kill Weight Mud(KWM) The Kill Weight Mud (KWM) is circulated from the bit to surface in the annulus

Since the hydrostatic pressure in the Drill String stays constant and the surface Drill Pipe pressure is keptconstant at the Final Circulating Pressure (FCP) through choke manipulation, the Bottom hole pressure is held(essentially) constant

Also see: Driller's Method, Step-by-Step

Alternate Driller's Method

Wait And Weight Method

Please use this guide and kill sheet when utilizing this kill method

1 When the Wait and Weight Method is used, the well is closed in on the kick, drilling fluid density is increased asrequired, and the kick is circulated out using the weighted fluid

2 Circulation is established at the kill rate as described on pages 5 and 6

3 A schedule of drill pipe pressure changes should be prepared and followed if the calculated Initial CirculationPressure (ICP) conforms to the actual ICP at, er doing a correct pump start-up, as outlined on pages 5 and 6

If there is a difference between the actual (GAUGE) ICP and the calculated ICP, the GAUGE ICP SHOULD

BE CONSIDERED CORRECT If there is a difference between the gauge ICP and the calculated ICP, the DrillPipe pressure schedule should be adjusted up or down by the difference between the ACTUAL (GAUGE) ICPand the calculated ICP For example, if the pump start-up is conducted as outlined on pages 5 and 6 and the actualICP is 1500 and the calculated ICP is 1300, all of the values in the Pressure drop schedule, including the FinalCirculating Pressure (FCP) should be increased by the difference (1500 psi - 1300 psi = 200 psi) These correctedvalues should be followed by manipulating the choke, if necessary

4 After Kill Weight Mud has been circulated to the bit, Final Circulating Pressure (FCP) should be held constant

on the Drill Pipe pressure gauge until the Kill Weight Mud (KWM) is at the surface, confirmed by weighing thereturns

Comparison Of Kill Methods Advantages And Disadvantages

Kill Method

Table K3-P9 Driller's Method vs W&W Method

Driller's Method

ADVANTAGES

Circulation can be started almost immediately Simpler Fewer calculations

KWM can be mixed to uniform density while first circulation is completed

Does not require special consideration/modification in directional wells or wells with tapered strings.DISADVANTAGES

Minimum of two circulations More time Higher annulus pressures

More wear on choke and gas handling machinery

Wait and Weight

ADVANTAGES

Minimum of one circulation, less time Lower annulus pressures

Less wear on choke and gas handling machinery

DISADVANTAGES

Circulation must wait to start until kill weight mud (KWM) has been mixed (waiting period)

More calculations More complex

Requires special considerations or modifications in directional wells and wells with tapered strings

Diverter Usage

Where shallow casing strings are set, fracture gradients are often very low and wells may not be able to be safelyclosed in on a kick without danger of lost circulation and possible broaching to the surface Gas from shallow sandscan be abnormally pressured, increasing the possibility of lost circulation and the possibility of vertical fracturing ofshallow formations allowing formation fluids to vent to surface outside of the drilled hole

The time needed to get formation fluids to surface from shallow formations may be less than one minute Thisshort amount of time leaves the driller little time to react It is absolutely necessary that the driller know the signs

of and the appropriate actions to take in the event of a shallow gas kick

Drilling shallow sands too rapidly can cause excessive gas-cutting of the drilling fluid with cuttings gas to the extentthat expansion while being pumped to the surface lowers the hydrostatic pressure enough to cause formation flowbecause of the lack of Bottom-Hole pressure

Conversely, large amounts of drilled cuttings in the drilling fluid from drilling at high rates of penetration may causethe drilling fluid density to increase to a point that circulation may be lost When lost circulation occurs the level offluid may fall in the well, causing the hydrostatic head to drop to a point that may allow the well to flow

A diverter may be used in those areas with possible shallow gas sands to direct well flow away from the rig duringkicks the diverter should be arranged so that a diverter linc automatically opens or is open when the diverter isclosed in order to divert the kick fluids and prevent back pressure on the hole

Diversion is usually away from the rig, resulting in loss of drilling fluid from the circulating system Under theseconditions, formation fluid flow continues during the well control operation until the hole bridges or hydrostaticpressure can be built enough to regain primary control or until the formation is depleted

Pumping at a fast rate tends to improve the drilling fluid/gas ratio and also creates a small increase in bottom-holepressure due to annular friction pressure Increasing the drilling fluid density at a fast rate increases hydrostaticpressure and may eventually stop flow Thus, whoa a shallow gas flow occurs, the following actions should betaken immediately:

1 Pump as fast as possible

2 Increase drilling fluid density as rapidly as possible while pumping

3 If drilling fluid supply should be exhausted, continue by pumping water

4 Divert the well fluids in a safe path away from the rig floor

On large drilling rigs in areas with possible shallow gas, a reserve supply of drilling fluid weighted above the

current mud weight may be carried in reserve for use in shallow gas kick remediation Immediate pumping of apre-weighted kill mud into the well, if shallow gas kick occurs, should be considered as part of a shallow-gas kickcontingency plan

If the drilling fluid supply is exhausted, a plug may be attempted This procedure may serve to (1) increase thehydrostatic pressure, (2) to form a super viscous pill, or (3) to form a fast hardening concrete pill depending onthe plug type

Gas Migration Considerations While Out of The Hole Volumetric Method

Gas migration considerations when the bit is at or near bottom were discussed on page 4 In the event that the well

is shut in with the bit completely out of the well, the Drill Pipe pressure gauge value will be meaningless, i.e., zero.Since the Drill Pipe pressure value cannot be used in the event that the well is closed in while out of the hole, adifferent logic must be used to control Bottom-Hole pressure than that found in the paragraph on gas migration thelogic discussed in this section is based on monitoring the Casing (annulus) pressure gauge, and making chokeadjustments based on well parameters

Please refer to the following paragraphs in this section and the Volumetric Kill Guide at the end of this sectionwhen making preparations to use this kill technique

1 Determine the amount of underbalance A mechanism for identifying the amount of underbalance in a closed-inwell with migrating gas was discussed in the paragraph on stabilized pressures In the circumstances discussed inthis section, the Casing (annulus) pressure gauge value must be used, rather than the Drill Pipe pressure gauge

2 Calculate the height of a column of mud which is required to be bled from the well in order to lower hydrostaticpressure 100 psi

100 psi /(0.052 x mud weight, ppg) = the height of a column of mud to needed to change the hydrostatic sure by 100 psi

For example, in a well with 11.2 ppg mud, 100 psi /(0.052 x 11.2 ppg) = 171.7 feet

3 Calculate the volume of mud which is required to be bled from the well in order to lower hydrostatic pressure

100 psi

height of column of mud to change mud hydrostatic pressure 100 psi x Casing Capacity (bbl/ft) = volume

For example, using the information immediately above in a well with a casing ID of 9.12 inches:

171.7 feet x {(9.12 x 9.12)/1029.4} = volume of mud to change HP by 100 psi,

It is now assumed that the bottom-hole pressure is 200 psi greater than the formation pressure

5 Slowly bleed mud through the choke, maintaining easing (Annulus) pressure constant, until the volume of mud tolower hydrostatic pressure by 100 psi has been bled from the well

For example, continuing with the examples from this section, 13.87 barrels of mud should be bled during thefirst bleed operation At the end of the first bleed operation, the pressure on the casing (Annulus) pressure gaugeshould be the value which reflects the underbalance in the hole plus 200 psi

At this point in the kill it is assumed that the bottom-hole pressure is 100 psi greater than formation pressure

6 After completing the first bleed operation, the choke should be closed and the pressure allowed to increase 100psi more

For example, continuing with the examples from this section, after bleeding 13.87 barrels from the well thechoke is to be closed and the pressure on the Casing (annulus) gauge allowed to increase from 900 psi to 1000 psi.

It is now assumed that the bottom-hole pressure is 200 psi greater than the formation pressure

7 Slowly bleed mud through the choke, maintaining casing (Annulus) pressure constant, until the volume of mud tolower hydrostatic pressure by 100 psi has been bled from the well

8 After completing the above bleed operation, the choke should be closed and the pressure allowed to rise 100 psimore

9 Repeat #7 and #8 above until gas is at surface, then close the choke immediately

10 When the gas kick reaches the surface it is necessary to pump mud into the well to replace the gas and tomaintain Bottom-Hole pressure equal to or greater than Formation pressure It will be necessary to pump the mudinto the well through the Kill Line and then allow the mud time to fall through the gas

As the mud is pumped into the well through the Kill Line, the gas will be compressed, causing the Casing(annulus) pressure to increase It is critical that the person(s) conducting this kill note the Casing (annulus) pres-sure increase due to compressing the gas

11 Slowly pump the volume of mud necessary to increase hydrostatic pressure by 100 psi into the well, then waitfor the gas to separate from the mud

For example, continuing with the examples from this section, note the closed in Casing (annulus) pressure, thenslowly pump 13.87 barrels of 11.2 ppg mud into the well, then stop the pump and wait for the mud to fall throughthe gas Expected time for the gas to fall through (separate from) the mud is 10 to 20 minutes, Possibly Longer!

12 Slowly bleed GAS (ONLY!) from the choke, lowering the Casing (annulus) pressure to the value found on theCasing (annulus) pressure gauge immediately before pumping the volume of mud necessary to increase hydrostaticpressure by 100 psi, then bleed 100 psi more to compensate for the 100 psi increase in hydrostatic pressure due topumping the mud into the annulus

13 Repeat #11 and #12 until gas has been replaced by mud in the annulus Well should be flow checked, thenBOP opened(if dead), and pipe run to bottom

Well Kills In Directional Wells

When considering which of the several Well Kill techniques to utilize which have been presented in this section thefollowing should be considered

A If the reader is drilling a directional well, it should be noted that inaccuracies in the pressure drop schedules ofWait and Weight Method Kill Sheets (Surface or Sub-sea) can lead to over-pressuring the annulus increasing thelikelihood of stuck pipe or lost circulation

B If the reader is drilling a well with a tapered drill string it should be noted that inaccuracies in the pressure dropschedules of Wait and Weight Method Kill Sheets (Surface or Sub-sea) can lead to underpressuring the annulus increasing the likelihood of large secondary influxes

In order to avoid the problems associated with "A." immediately above, there are several choices available to thosecharged with deciding which kill technique is to be utilized

The inaccuracies caused by using a "regular" (Surface or Sub-sea) Wait and Weight Method Kill Sheet are unlikely

to be equal to or greater than 100 psi if:

1 The angle from vertical is equal to or less than 30 degrees; or

2 The Closed In Drill Pipe Pressure is less than 1000 psi

a If the well being drilled is a Build-and-Hold (two-part) type directional well the reader may use the DeviatedWell Pressure Drop Schedule found at the end of this section, especially if the Wait and Weight Method Kill is thepreferred method by the decision makers on site.

b If the well being drilled is a Build-Hold-and-Drop (three-part) type directional well, or if the reader does notwant to use the Deviated Well Pressure Drop Schedule in a Build-and-Hold (two-part) type directional well, and if

"1." and/or "2." above are not true, the Driller's method is recommended

c For the reason that the inaccuracies caused by using a "regular" Wait and Weight Kill Sheet (Surface or sea) are likely to be less than 100 psi if "1." and/or "2." above are not true, it may be advisable to utilize the "regu-lar" Wait and Weight Kill Sheet in that circumstance - if the Wait and Weight Method Kill is that which is preferred

Sub-by the persons making such decisions on the rig

In order to avoid the problems associated with "B." immediately above, the best of several choices available tothose charged with deciding which kill technique is to be utilized is presented immediately below

d If the smaller diameter drill string is longer than 1000 feet, it is recommended to use the Driller's Method

K-4 Glossary of Well Control Terms

Accumulator: A pressure vessel charged with nitrogen gas and used to store hydraulic fluid under pressure foroperation of blowout preventers

Accumulator Bank: An assemblage of multiple accumulators sharing a common manifold

Accumulator Unit: A hydraulic power unit with accumulators, pumps control fluid reservoir and hydraulic controlmanifold for operation of blowout preventers

Annular (BOP): A device with a generally toroidal shaped steel reinforced elastomer packing element that ishydraulically operated to close and seal around any size drill pipe or to provide full closure of the wellbore

Annulus: The space between the easing inside wall and the outside of the drill string providing a return path for thedrilling fluid to the surface and mud pits

API: American Petroleum Institute

ASME: American Society of Mechanical Engineers

BHA: Bottom Hole Assembly

Blind Ram (BOP): See BOP A BOP with ram blocks designed to mate against each other when closed to seal offthe wellbore when the well bore is open

BOP Ram Type: A device designed or form a seal on the hole with no pipe or in the annular space with pipe in thehole The equipment can use pipe rams, blind rams, or blind/shear/cutter rams to effect the required seal, according

to equipment availability, arrangement of the equipment, and/or existing well conditions Pipe rams have endscontoured to seal around pipe to close and seal the annular space Blind rams have ends not intended to sealagainst any tubulars, rather they seal against each other to effectively close and seal the wellbore

Blind/shear/cutter rams are blind rams equipped with a built-in cutting edge that will shear tubulars that may be inthe hole, thus allowing the blind rams to close against each

BOP Preventer Stack: The assembly of well control equipment including preventers, spools, valves, and nipplesconnected to the top of the casing-head

BOP Preventer Test Tool: A tool to allow pressure testing of the blowout preventer stack and accessory ment b sealing the wellbore immediately below the stack

equip-Choke Line: A high pressure line connected below a BOP to transmit fluid flow to the choke manifold during wellcontrol operations

Choke Manifold: An assembly of valves, chokes gauges, and lines used to control the rate of flow from the wellwhen the blowout preventers are closed

Choke Valve: A valve that permits flow in one direction only

Closing Unit: See Accumulator Unit

Conductor Casing: The first string of pipe cemented in the well on which the casing head is attached for mountingBOP's The first pipe intended to contain pressure

Dead Band: Term used to describe the change in regulated pressure required before a hydraulic pressure regulatorautomatically adjust to the change Also called search band

Drilling Spool: A connection component with ends either flanged or hubbed It must have an internal diameter atleast equal to the bore of the blowout preventer and can have smaller side outlets for connecting auxiliary lines

Fail Safe: This is said of equipment or a system so constructed that, in the event of failure or malfunction of anypart of the system, devices are automatically activated to stabilize or secure the safety of the operation Subseafailsafe valve in designed to "Fail Safe" close (spring loaded) should hydraulic operating pressure be lost.

Floater: Floating Drilling Rig Drill ship or semi-submersible vessel where the BOP stack is installed at the seafloor

Hydraulic Control Manifold: The assemblage of regulators and hydraulic control valves used to operate the BOPand well pressure control valves Normally part of the accumulator unit

IADC: International Association of Drilling Contractors

Influx: See Kick

Kick: Intrusion of gas into the well due to an unbalanced condition where hydrostatic pressure in the well is

insufficient to prevent the entrance of the higher pressure

Kill Line: A high pressure line between the rig pumps or cement pump to a connections below a BOP This lineallows fluid to be pumped into the well or annulus with the BOP closed during well control operations

Leak Off Test: A pressure test to determine the integrity of the casing, cement or shoe Establishes the maximumpressure allowed before migration of the drilling fluids into the formation

Marine Drilling Riser: A tubular conduit serving as an

extension of the well bore from the equipment on the

wellhead at the seafloor to a floating drilling rig

MMS: Minerals Management Service

Nipple Down: Disassembly of well control equipment and

Precharge: The initial nitrogen charge in the accumulator The nitrogen gas charge is compressed by the pumpshydraulically charging the accumulators and is used to expel the fluid when the pumps are off

PSI: Pounds per square inch Pressure

Ram: The closing and sealing component on a blowout preventer Rams are of three types: blind, pipe, and shear.Pipe rams, when closed, have a configuration such that they seal around the pipe; shear rams cut through drill pipeand then form a seal Blind rams seal on each other with no pipe in the hole

Ram BOP: A blowout preventer that uses rams to seal off pressure in the well bore; also called a ram preventer.Riser Joint: A riser joint consists of a section of pipe, with couplings on each end It may have provision for

supporting integral and non-integral auxiliary lines (flowlines, choke and kill lines, control bundles, etc.) and ancy devices

buoy-Rotating Head: A rotating pressure-sealing device used in drilling operations utilizing air, gas, foam, or any otherdrilling fluid whose hydrostatic pressure is less than the formation pressure

Shear Ram (BOP): See BOP A BOP with ram blocks designed to cut the drill pipe and seal the wellbore in anemergency Normally for subsea BOP stacks

Shoe: Established at the bottom end of the conductor easing by cementing See leak off test and conductor casing.Stripping: The process of running the drill string into or out of the well under "Kick" conditions (see Kick) Nor-mally through a closed annular BOP but may be run ram-to-ram by carefully closing, bleeding off pressure andopening rams to pass tool joints and collars

Swabbing: The lowering of the hydrostatic pressure in the hole due to upward movement of pipe and/or tools.Trip: Running the drill string into or out of the well.

Usable Fluid: The hydraulic fluid volume recoverable from the accumulator system between the maximum ing pressure and the minimum operating pressure of the accumulator The minimum operating pressure is estab-lished by the pressure at which the precharge pressure closes the accumulator poppet valve stopping further flowfrom the accumulator The poppet valve prevents loss of the nitrogen precharge into the hydraulic control lines.WP: Working Pressure (also design working pressure or maximum working pressure) The normal operatingpressure to which a component is designed to operate continuously with a safe margin below the point at which thematerial will yield or burst

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Chapter L

Derricks and Masts