Petroleum engineering (drilling) project 2

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Class9_BOP_WellControl.pdf

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Drilling Engineering

Class 9

Blowout Preventers

• Blowout Preventers (BOPs) are used to seal off the annular area and prevent flow out of the well.

• When used with associated equipment and well control practices, a drilling crew can control a kick before it becomes a blowout.

• Kick- any influx of higher pressured liquids or gasses into the wellbore.

• Blowout- when a kick is gone undetected and not properly controlled, the influx can make its way to surface and result in an uncontrollable release of liquid or gas.

BOPs

• The BOP and equipment (BOPE) has 3 main functions:

1. Seal off the annular flow area at the surface (shut-in)

2. Allow the crew to control the release of fluids and/or gas

3. Allow pumping into the well by a means other than through the drill string

• BOPE must be rated above maximum anticipated surface pressure

• Must be enough casing in the ground to anchor the wellhead and BOP

• BOP must be able to shut the well in with or without pipe in the hole. (ie. Drillpipe, collars, casing, wireline, nothing) 3

BOP Ratings

• BOP stacks come in a variety of sizes and pressure ratings

• Typically the burst rating of the casing is the weakest link

• BOPE should be pressure tested each time it is assembled, anytime a seal is broken and put back together, or every 21 days per API.

• Nipple Up (N/U)- when the BOP stack is assembled

• Nipple Down (N/D)- when the BOP stack is disassembled

• The BOP stack should be function tested daily to ensure its in proper working order

BOP Arrangement

• The BOP once it is Nippled Up is sometimes referred to as the “Stack”

• The stack is described as follows:

1. Working Pressure

2. Size (internal diameter)

3. Arrangement of components

BOPE Identification G Rotating Head

A Annular Preventer

R Single Ram type Preventer

Rd Double Ram type Preventer

Rt Triple Ram type Preventer

S Spool

BOP Pressure Ratings

API Class Working Pressure

[psi]

Working Pressure [pa (105)]

Service Condition

2M 2,000 138 Light Duty

3M 3,000 207 Low Pressure

5M 5,000 345 Medium Pressure

10M 10,000 689 High Pressure

15M 15,000 1,034 Extreme Pressure

BOP Stack Components • Spool

• Typically on or near the bottom of the BOP stack.

• Attaches directly to the wellhead

• Typically has two ports for use during well control (flow in and flow out)

• Choke line- allows flow out through the HCR valve and to the choke manifold

• Kill line- permits pumping of kill mud down the annulus if needed

BOP Stack Components

• Ram type BOPs • Seals the wellbore with two closing arms

• Cannot rotate or reciprocate the pipe when rams are closed

• Typically have more than one in the stack arrangement

• Comes in single, double, & triple ram assemblies

• The ram internals can be interchanged with various sizes or types • Blind Rams- Flat steel plates used to seal off the well with no pipe or

wireline in the hole

• Pipe Rams- Curved plates designed to seal around a specific sized pipe

• Shear Rams- Cuts off whatever is in the hole in a last resort extreme situation

• Variable Bore Rams- VBRs- Has multiple sizes of curved plates designed to seal around a range of pipe sizes (ie. 3.5”-5.5” has 5 plates) 8

BOP Stack Components

• Annular Preventer

• Sometimes referred to as the “bag” or “Hydril”

• Seals off the annular space of the well around any size or shaped item downhole

• Allows for pipe reciprocation (stripping) but no rotation

• Consists of a internal rubber (WBM) or nitrile (OBM) element that will squeeze around the pipe and provide a seal

BOP Stack Components

• Annular Preventer

BOP Stack Components • Rotating Head Assembly

• The upper most part of the stack

• Allows centered rotation of pipe through the stack

• The flowline intersects the rotating head assembly

• Contains a rotating rubber element to seal around the pipe while circulating the well

• This is not a high pressure seal, but only a means to prevent fluid and gas from reaching the rig floor by diverting it out the flowline

Well Control Equipment

• Choke Manifold

• Series of piping, pressure gauges, and valves to control the flow out of a well anytime the BOP stack is closed

• Typically has 1 entrance of fluid/gas from the well coming from the choke line and HCR and has 2 means of exit from the manifold.

• Continuing Choke Line-Through a choking valve to the Mud/Gas separator, then mud goes to the shakers and gas to be flared

• Panic Line-Through a choking valve and to a storage tank

Well Control Equipment • Mud Gas Separator

• Used to separate the gas from the mud and cuttings

• The gas will go to the flare to ignite and the mud and/or cuttings will go to the shakers to be processed

• Need sufficient mud leg height so hydrostatic head will force gas to the flare stack

Well Control Equipment • Accumulator

• Provides compressed hydraulic fluid to open and close the BOP.

• Several high pressure cylinders that store nitrogen (in bladders) and hydraulic fluid under pressure

• Need sufficient volume to close/open all preventers and accumulator pressure must be maintained all time.

• According to API RP53, your reservoir tank should have a total volume at least 2 times of usable volume to close all BOP equipment

Well Control Equipment

• Accumulators

• Components consist of

• Hydraulic fluid reservoir tank

• Pumping system (compressors)

• Must have 3 independent compressor sources

1. Rig air for pneumatic pump

2. Electric pump

3. Stored bottles of compressed nitrogen

• Manifold, pressure regulators, and lever valves

• Bottles

Well Control Equipment • Accumulator

• The electric pump is the primary compressor. It will provide compressed hydraulic fluid to function the BOP

• The pneumatic pumps are a backup to the electric pump

• Bottles are used to store pressurized hydraulic fluid for closing/opening all blow out preventers.

• Each bottle, with a rubber bladder inside, has a storage volume of 10 gal.

• The rubber bladder is pre-charged to 1,000 psi with nitrogen.

• Each bottle (outside the bladder) will be pressured up 200 psi over the pre-charge pressure using 1.7 gal of hydraulic fluid to compress the gas filled bladder. This is called “minimum operating pressure”.

• Hydraulic fluid will be pumped into the bottle until pressure in the bottle reaches 3,000 psi, called “Operating Pressure”.

• Volume of hydraulic fluid used to pressure up from 1200 psi to 3000 psi, called “Useable Fluid”, is equal to 5 gal

Well Control

• What is a kick?

• An unscheduled entry of formation fluid/gas into the wellbore

• The pressure inside the wellbore is lower than the formation pore pressure (in a permeable formation).

• Mud density is too low

• Fluid level is too low - trips or lost circ.

• Swabbing/Surge

• Drilled into a fault or hi pressure zone

Well Control

• Kick Detection • Pit Gain

• Increase in flow from drilling fluid

• Drilling Break

• Decrease in circulating pressure (Stand Pipe Pressure)

• Well flows after the pumps are off (flow check)

• Increase in Hookload

• Incorrect fill up volumes on trips

• Goals • Keep the kick size small (early detection)

• Shut-in well at BOP

• Circulate out the kick using choke to maintain constant bottom hole pressure BHP

• Replace well with kill weight mud 19

Well Control • Drillers Method

• Requires 2 complete circulations 1. Circulate the gas bubble to surface

2. Replace original mud with kill weight mud

• Wait and Weight Method (Engineer’s Method) • Requires 1 complete circulation

1. Circulate the gas bubble to surface using the kill weight mud

• Both Methods • BOP is closed at first sign of kick (keep kick as small as possible)

• HCR is opened to allow annular to flow to choke manifold

• From choke manifold the flow travels to the gas buster

• Choke is used to manually control DP and CSG pressure

• CSG pressure is affected immediately upon action of the choke

• DP pressure will be delayed upon action of the choke • ~1 second delay per 1,000ft traveled

Well Control • In this class we will focus on the Wait & Weight Method

• Also called the Engineer’s Method

1. Determine stable shut in drill pipe and casing pressures after shutting in on a kick.

2. Weight up pits to desired kill mud weight.

3. Bring pump on line to the desired kill rate speed very slowly in small increments. At this time, the circulating pressure on the drill pipe side becomes your initial circulating pressure. Maintain this constant drill pipe side circulating pressure while removing kick from the well.

4. When circulating kill fluid down the drill pipe, follow the step down chart found on killsheets for initial circulating pressure to final circulating pressure.

5. Circulate kick out of the hole, maintaining final circulating pressure.

6. Shut well back in a second time and determine if well is dead. If pressures increase, additional circulations or additional weight may be required.

Well Control

• Wait and Weight Method (Engineer’s Method)

• Depth= 10,000ft (Vertical Hole)

• Hole Dia.= 12.25”

• Drill Pipe: 4-1/2” OD; 12.74 lb/ft; ID= 4.00”

• Casing: 4,000ft of 13-3/8” OD; 68 lb/ft; L-80; 12.415” ID

• Current MW= 10ppg

From initial shut-in:

• Shut-in Casing Pressure (SICP)= 600psi

• Shut-in Drill Pipe Pressure (SIDPP)= 500psi

• Kick Size= 30bbl (interpreted from mud pit gain)

Well Control

• At no time during the process of removing the kick fluid from the wellbore will the pressure exceed the pressure limits of

• The formation

• The casing

• The wellhead equipment

• When the process is complete, the wellbore will be filled with a fluid of sufficient density (kill mud) to control the formation pressure.

• Under these conditions the well will not flow when the BOP’s are opened.

• Keep the BHP constant throughout the circulation process.

Well Control

• From the initial shut-in data, we can calculate:

1. Bottom Hole Pressure BHP

2. Casing Shoe Pressure (compare to casing burst rating)

3. Density of kill weight mud

4. Length of the kick at surface

1. BHP= SIDPP + Hydrostatic Pressure in DP

= 500psi + 0.052 * 10.0ppg * 10,000ft

BHP = 5,700 psi

Well Control

2. Pressure at the casing shoe

• Pshoe = SICP + HYD_ANN Surface to shoe

• Pshoe = SICP + 0.052 * 10ppg * 4,000ft

• Pshoe = 2,680 psi

3. Density of kill weight mud

• KMW= SIDPP/(0.052*TVD) +MW

• = 500/ (0.052*10,000) + 10 = 10.96 = 11ppg 25

Well Control

Annulus Drill String

SICP + HYD_ANN + PKICK = SIDPP + HYD_DP

600 + [0.052*10*(10,000-231)] + PKICK = 500 + (0.052*10*10,000)

600 + 5,080 + PKICK = 500 + 5,200

Well Control

lb/gal 67.1 231*052.0

20 

KB 

This kick is composed primarily of gas

PKICK = 20psi

Well Control

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surface

RTnZ

BBB

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• Goal is to keep BHP constant throughout the entire Kill process

• Casing and Drill Pipe Pressure will change • What will be the height of the kick once it

reaches the surface? • Let’s look at the annulus:

Ignoring changes due to compressibility factor (Z) and temperature, we get:

Since cross-sectional area = constant: assume minimal change from open hole and casing

Well Control

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constAA

hPhPei

hAPhAP

VPVP

Bot

BotBot

BotBotBot

BotBot

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Well Control

𝑃0ℎ0 = 𝑃𝐵𝑜𝑡ℎ𝐵𝑜𝑡 → Τℎ0 = 𝑃𝐵𝑜𝑡ℎ𝐵𝑜𝑡 𝑃0 • We have two unknowns, P0 and h0

4. Calculate Height of Kick

BHP = Surface Pressure + Hydrostatic Head

5,700 = P0 + Pkick + HYDANN

5,700 = P0 + 20psi + 0.052*10*(10,000-h0)

5,700 - 20 - 5,200 = P0 - 0.52 * 0

hP BotBot

Well Control

psi 102,1862240

684,684*4480480

0684684P480

231*5700*52.0 480



 

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𝑃0ℎ0 = 𝑃𝐵𝑜𝑡ℎ𝐵𝑜𝑡 → 1102𝑝𝑠𝑖 ∗ ℎ0 = 5700𝑝𝑠𝑖 ∗ 231𝑓𝑡

∴ ℎ0 = 1195𝑓𝑡, this is the height of the gas kick once at surface if controlled by the choke. What if the kick was not detected? (ie. 𝑃0= 14.7psi)

Well Control

• It is important to keep a Slow Pump Rate recorded while drilling.

• Driller will stop drilling several times a day and turn the pumps on slow (~30-40spm) and record pump pressure (SPP)

• This provides system pressure loss or Kill Rate Pressure (KRP)

• Use SPR= 40spm on pump #1 @ 1200psi

• Initial Circulating Pressure (ICP) 𝐼𝐶𝑃 = 𝑆𝐼𝐷𝑃𝑃 + 𝐾𝑅𝑃 = 500 + 1200 = 1700𝑝𝑠𝑖

• Final Circulating Pressure (FCP)

𝐹𝐶𝑃 = 𝐾𝑅𝑃 ∗ ൗ𝐾𝑀𝑊 𝑀𝑊 = 1200𝑝𝑠𝑖 ∗ ൗ 11

10 = 1320𝑝𝑠𝑖

• Strokessurface to bit (stksS-B):use 2000stks for this example 𝑠𝑡𝑘𝑠𝑆−𝐵 = 𝐷𝑆𝑐𝑎𝑝 ÷ 𝑃𝑢𝑚𝑝 𝑂𝑢𝑡𝑝𝑢𝑡

• Last step is to complete the Pressure Chart

• You are now ready to begin to pump and kill the well

Well Control

• Pressure Chart

• “Kill Sheets” are documents provided by service companies to help guide the calculations of killing a well

• Need: # strokes from surface to bit, ICP, FCP

• As the pumps are brought online, the choke will be adjusted to maintain DP pressure according to the chart

• Actual DP Pressure will be recorded in the field while the pumping is taking place to compare calculated to actuals

Pressure Chart

Step # strokes

Calculated DP Pressure

Actual DP Pressure

1 0 ICP=

Bit FCP=

Surface to Bit Strokes =