IPM IDPT
Well Engineering Module Basic Well Control
IDPT Basic WC
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Basic Well Control • Module Contents • Objectives and Introduction • Well Control Fundamentals CD (Self Study) • WC Incident root causes and IPM Standards • Primary, Secondary and Tertiary Well Control • Well Control Mathematics and the “U” Tube • Kick Causes and Prevention • Well Control Equipment (HP, LP, BOP, Accumulator, MGS) • Shut In and Well Kill procedures • Well Control reporting (Kick reporting, Kill Sheets, etc..) IDPT Basic WC
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Basic Well Control • Module Objectives • At the end of this lecture and completion of the WCF CD YOU will be able to: • Define the terms “kick” and “Blowout” • Perform basic Well Control calculations • Understand the causes of Well Control incidents • State primary, secondary and tertiary Well Control procedures • Understand Well Control Equipment • Describe the Shut In and Kill methods • Explain the reporting procedures for Well Control incidents IDPT Basic WC
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“A catastrophic well control incident could put IPM out of business” - Antonio J. Campo IPM President
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Basic Well Control • Introduction • In simple terms, a kick can only occur when the formation pressure exceeds the mud hydrostatic pressure • The resultant positive differential pressure is transferred into the wellbore and there is an influx of formation fluids • If the well is shut in after determining that a kick has occurred then the well can be killed under controlled conditions • Blow-outs occur when the kick (influx) can not be controlled and there is an emission of wellbore and/or formation fluids at surface • The rig crew must be fully trained and alert at all times in order to take immediate action to bring the well under control. IDPT Basic WC
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Basic Well Control • An uncontrolled Kick !
Workover Rig Land Well Russia Cause: >Proper equipment not deployed >Poor practices >Lack of training
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Basic Well Control Can turn into this: Or this:
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Well Control Incidents - Root Causes • Lack of knowledge and skills of rig personnel • Improper work practices • Lack of understanding of Well Control from certification training • Lack of application of policies and standards • Poor contractor & supplier management • Inadequate Risk Management & Management of Change
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IPM Standards Standards 3 HSE 4 Quality 28 Engineering
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IPM Standards Reference IPM-PO-QAS-001 IPM-PO-QAS-002 IPM-ST-QAS-001 IPM-ST-QAS-002 IPM-ST-QAS-003 IPM-ST-QAS-004 IPM-PR-QAS-001 IPM-FO-QAS-001 IPM-CORP-S004 IPM-ST-HSE-001 IPM-ST-HSE-002 IPM-ST-HSE-003 IPM-PR-HSE-004 IPM-PR-HSE-005 IPM-ST-WCI-001 IPM-ST-WCI-002 IPM-ST-WCI-003 IPM-ST-WCI-004 IPM-ST-WCI-005 IPM-ST-WCI-006 IPM-ST-WCI-007 IPM-ST-WCI-008 IPM-ST-WCI-009 IPM-ST-WCI-010
Title Corporate QHSE Policy Engineering Policy Document Formatting Standard Project Bridging Document Glossary of QHSE Definitions Management of Change Document Numbering and Control Procedure Management of Change Form Indemnity and Risk Gas Detection Service and Equipment Life Saving and Evacuation Equipment Simultaneous Operations Hygiene in Camps and Accommodations Preparation of a Simultaneous Operations Manual Well Engineering Management System (WEMS) Information to be Kept on Location Kick Detection Equipment Well Control Equipment Testing Requirements BOP Stack and Diverter Minimum Requirements Well Control Certification Consensus of Well Control Procedures Well Control Drills Casing Liner and Tubing Pressure Testing Minimum Chemical Stocks
InTouch # 3286066 3286067 3274817 3286070 3286072 3286073 3274819 3286075 3286076 3286077 3286078 3286079 3286082 3286083 3286084 3286085 3286086 3286087 3286088 3286089 3286090 3286091 3286092 3286093
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IPM Standards (2) Reference IPM-ST-WCI-011 IPM-ST-WCI-012 IPM-ST-WCI-013 IPM-ST-WCI-014 IPM-ST-WCI-015 IPM-ST-WCI-016 IPM-ST-WCI-017 IPM-ST-WCI-018 IPM-ST-WCI-019 IPM-ST-WCI-020 IPM-ST-WCI-021 IPM-ST-WCI-022 IPM-ST-WCI-023 IPM-ST-WCI-024 IPM-ST-WCI-025 IPM-ST-WCI-026 IPM-ST-WCI-027 IPM-ST-WCI-028 IPM-PR-WCI-002 IPM-PR-WCI-003 IPM-PR-WCI-004 IPM-PR-WCI-005 IPM-PR-WCI-006 IPM-PR-WCI-007 IPM-PR-WCI-008 IPM-REF-WCI-001
Title InTouch # Kick Tolerance 3286095 Barriers 3286096 Authority during Well Operations 3286098 Agreement on Specific Well Control Procedures 3286099 Well Shut-in Method 3286101 Well Control Method 3286103 Kick Detection 3286104 Kick Prevention 3286106 Constant Bottomhole Pressure 3286107 Reporting of Kicks 3286108 Shallow Gas Risk Assessment and Contingencies 3286109 Well Control while Running Casing 3286110 Leak Off Test or Shoe Test 3286111 Procedures for Radioactive Sources 3286112 Casing and Tubing Design 3286113 Temporary and Permanent Abandonment 3286114 Wellbore Surveying and Collision Avoidance 3286115 Well Control Briefing Standard 3286116 Contingency Stripping Procedure 3286117 Testing of Cement Mixing and Pumping Equipment 3286118 Operational Requirements for Cement Slurries 3286119 Cement Placement 3286120 Setting and Verification of Cement Plugs 3286122 Survey Program Preparation Technical and Operational Integrity 3303422 Derivation of Kick Tolerance Calculation 3286124
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Basic Well Control • The primary formula for Well Control • U-Tube principles • The calculation of pressures in the Static and Dynamic U-Tube conditions
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Well Control • Primary Well Control : • The use of the Mud Weight to provide sufficient pressure to prevent an influx of formation fluid into the wellbore
• Secondary Well Control: • Control Kick with Mud Weight and BOP Equipment
• Tertiary Well Control: • An Underground Blowout – to avoid a surface blowout
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Ht: 1 ft.
Well Control Math
Volume: 1 gallon = 230.75 in3
Area: 19.23 in2
If MW = 1 ppg P = 1 lb. = 0.052 psi 19.23 in2 Gradient = Change = 0.052 psi/ft If MW = 10 ppg P =
10 lb. = 0.52 psi 19.23 in2 Gradient = Change = 0.52 psi/ft G = 0.052 x MW (psi/ft) (ppg)
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Well Control Math 0
1
0.52 MW: 10 ppg
2
1.04
3
1.56
Pressure -psi
Depth - ft
0
G = 0.052 x MW (psi/ft) (ppg) HP = G x (psi) (psi/ft)
D (ft)
Only TVD is Considered Not MD
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How vs Why Given: • Gas Kick taken while drilling at 6000 ft • Well Shut-In • MW = 10 ppg • Kill MW = ???
SIDPP = 600 psi
SICPP = 900 psi
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How vs Why How to calculate KMW:
Why KMW is 12 ppg:
KMW = (0.052 x MW x D) + SIDPP D x 0.052 KMW = (0.052 x 10 x 6000) + 600 6000 x 0.052 KMW = 11.923 = 12 ppg
G10 = 0.052 x 10 = 0.52 psi/ft HP10 = G x D = 0.52 psi/ft x 6000ft HP10 = 3120 psi Pzone = HP10 + SIDPP = 3120 + 600 Pzone = 3720 psi Gkill = Pzone = 3720 = 0.62 psi/ft 6000 D KMW = Gkill = 0.62 =11.923 ppg=12 ppg 0.052 0.052 IDPT Basic WC
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How vs Why SIDPP = 600 psi
What is the significance of the 600 psi SIDPP? Why was the Drill Pipe gauge pressure used in the calculation rather than the SICP gauge pressure? Why do we round up to 12 ppg for the KMW?
SICPP = 900 psi
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The ‘U’-Tube An arrangement of pipes in which the two legs are attached at the bottom
A
B
The Pressure at Point A = Pressure at Point B
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The Well as a ‘U’-Tube The ‘U’-Tube Can Be Either: • Static • Dynamic
Pressure Contributors: • Pump Pressure • DP Friction Loss
What are the Pressure Contributors?
• Bit Pressure Loss • Annular Pressure Loss (ECD) • Back Pressure from Choke
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Static ‘U’-Tube Given: • Shut-In after Gas Kick • Depth: 10,000 ft • MW: 10 ppg • BHP: ?? • Avg Grad Ann: ?? • EMW: ?? • How Big was the Kick??
SIDPP = 500 psi
SICP = 700 psi
– 8-1/2” Vertical Well – 5 Stands 6-3/4”DC
P1 = P2 IDPT Basic WC
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Static ‘U’-Tube SIDPP = 500 psi
BHP = SIDPP + HPDS BHP = 500 + (0.052 x 10 x 10,000) BHP = 5700 psi SICP = 700 psi
BHP = SICP + HPA HPA = BHP – SICP HPA = 5700 – 700 = 5000 psi GA = HPA = 5000 psi = 0.5 psi/ft D 10,000 ft EMWA = GA = 0.5 = 9.6 ppg 0.052 0.052
Note that BHP: P1 = P2 P1 = P2 IDPT Basic WC
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Static ‘U’-Tube Height of Influx = SICP - SIDPP GMud - GInflux = 700 psi - 500 psi (10 ppg x 0.052) - GInflux Gas Influx: < 0.2 psi/ft Water Influx: > 0.4 psi/ft Worst Case: Assume Gas Influx = 0.1 psi/ft
=
700 - 500 = 200 psi 0.52 psi/ft – 0.1 psi/ft 0.42 psi/ft Height of Influx = 476.2 ft (TVD) Kick Size = Height of Influx (MD) x Annular Volume (5 Stands of 6-3/4” DC in 8-1/2” Hole) = 476.2 ft x 0.0259 bbl/ft Kick Size = 12.4 bbls
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Dynamic ‘U’-Tube Given: • What does the CDPP measure? • How are DP losses calculated? • How are Annular pressure losses calculated?
CDPP psi
CCP psi
P1 ≥ P2 IDPT Basic WC
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DS Pressure Loss • Step 1: Obtain the following dimensional parameters • • • • • •
Drill pipe ID ddp – inches Drill pipe Length Ldp – feet Drill collar ID ddc – inches Drill collar Length Ldc – feet Plastic Viscosity PV – centipoise Yield Point YP - lb/100ft2
• Step 2: Calculate the average fluid velocity (ft/sec): • Drill collars: Vdc = GPM/(2.448 x ddc2) • Drill pipe: Vdp = GPM/(2.448 x ddp2)
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DS Pressure Loss • Step 3: Calculate the frictional pressure loss: • Drill collars: PLdc = [(PV x Vdc x Ldc)/(1500 xddc2)] + [(YP x Ldc)/(225 x ddc)] • Drill pipe: PLdp = [(PV x Vdp x Ldp)/(1500 xddp2)] + [(YP x Ldp)/(225 x ddp)]
• DSPL = PLdc + PLdp
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Dynamic ‘U’-Tube Given: • Depth: 10,000 ft • MW: 10 ppg • Circ DPP (CDPP): 2000 psi • Circ CP (CCP): 500 psi
CDPP = 2000 psi
CCP = 500 psi
• (backpressure)
• DS Pres Loss (dPDS): 1300 psi • Anl Pres Loss (dPA): 200 psi • BHP: ??? P1 ≥ P2 IDPT Basic WC
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Dynamic ‘U’-Tube CDPP = 2000 psi
BHP = CCP + HPA + dPA = 500 + (0.052 x 10 x 10,000) + 200 BHP = 5900 psi
CCP = 500 psi
OR BHP = CDPP + HPDS - dPDS = 2000 + (0.052 x 10 x 10,000) - 1300 BHP = 5900
P1 ≥ P2 IDPT Basic WC
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Problem #1
THE ‘U’ –TUBE 1/2 hour
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Problem #1 156
SICP = 0 psi (overbalanced U-Tube) BHP = SICP + HPAnn = 0 + (0.052 x 10 ppg x 10,000 ft) BHP = 5200 psi
0 10
9.7
+350
SITP = BHP - HPTub = 5200 – (0.052 x 9.7 ppg x 10,000 ft) SITP = 156 psi Zone Overbalance = BHP – Zone Pressure = 5200 – 4850 psi Zone Overbalance = 350 psi
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Problem #1 CTP = 156 psi (Held Constant)
156
CCP = dPAnn+ dPTub = 300 + 70 CCP = 370 psi
370
BHP = CCP + HPAnn - dPAnn = 370 + 5200 – 70 BHP = 5500 psi Zone Overbalance = BHP – Zone Pressure = 5500 – 4850 psi Zone Overbalance = 650 psi ( 300 psi above Shut-In)
+650
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Problem #1 CTP = 0 psi (U-Tube Balanced) (Choke Fully Open)
0 L
370
CCP = dPAnn + dPTub = 300 + 70 CCP = 370 psi (Pressure Loss in U-Tube) Volume of 9.7 ppgAnn = L x CapacityAnn = L x 0.0986 = = 0.1186L = L = 10,000 – L =
+623
Volume of 10 ppg Tub (10,000 – L) x CapacityTub (10,000 – L) x 0.02 200 – L x 0.02 200 1686 ft 8314 ft
BHP = CTP + HP9.7 + HP10 - dPT = 0 + (0.052 x 9.7 ppg x 1686 ft) + (0.052 x 10 ppg x 8314 ft) + 300 = 0 + 850 + 4323 + 300 BHP = 5473 psi Zone Overbalance = BHP – Zone Pressure = 5473 – 4850 psi Zone Overbalance = 623 psi
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Problem #1 CTP = 0 psi (HPTub Greater than HPAnn) (Choke Fully Open)
0 L
402
BHP = CTP + HPT + dPT = 0 + 5200 + 300 BHP = 5500 psi Zone Overbalance = BHP – Zone Pressure = 5500 – 4850 psi Zone Overbalance = 650 psi Volume of 9.7 ppgAnn L x CapacityAnn L x 0.0986 L 10,000 – L
+650
= Volume of 10 ppg Tub = 10,000 x CapacityTub = 10,000 x 0.02 = 2028 ft = 7972 ft
BHP = CCP + HP9.7 + HP10 - dPAnn CCP = BHP - HP9.7 - HP10 + dPAnn = 5500 - (0.052 x 9.7 ppg x 2028 ft) + (0.052 x 10 ppg x 7972 ft) + 70 = 5500 - 1023 - 4145 + 70 CCP = 402 psi
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Problem #1 0 CTP = 0 psi (HPTub Greater than HPAnn) (Choke Fully Open)
526 BHP = 5500 psi (Same as (#4)) Zone Overbalance = 650 psi (Same as (#4))
+650
CCP = BHP – HPAnn + dPAnn = 5500 - (0.052 x 9.7 ppg x 10,000 ft) + 70 = 5500 - 5044 + 70 CCP = 526 psi
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Problem #1 0
CTP = 0 psi (U-Tube Balanced) (Choke Fully Open)
370
CCP = 370 psi (Pressure Loss in U-Tube) BHP = CTP + HPTub + dPTub = 0 + 5044 + 300 BHP = 5344 psi Zone Overbalance = BHP – Zone Pressure = 5344 – 4850 psi Zone Overbalance = 494 psi
+494
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Problem #1 600
526
CTP/CCP - psi
500
402
400
370
370
300
200
156 100
0 0
1
2
3
4
5
6
Tubing Volumes IDPT Basic WC
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Problem #1 1000
900
Overbalance - psi
800
650
700
600
650 623
500
494
400
300
200
100
0 0
1
2
3
4
5
6
Tubing Volumes IDPT Basic WC
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Kicks – Cause
There is ONE condition that allows a kick to occur: The pressure in the wellbore becomes less than the pressure in the formation
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Kicks – Causes and Prevention Most Common
Cause
Best Prevented By: Measurement of fill-up volume when tripping Trip Tank!!
1. Failure to keep hole full of proper weight fluid 2. Drilling into zones of known
Good engineering & well procedures and an alert, questioning attitude by WSS READ THE PROGRAM
pressure with mud weight too low 3. Drilling into unexpected,
Careful engineering, proper well design STUDY OFFSET WELLS
abnormal formation Least Common
pressure
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Kicks – Causes and Prevention Most Common
Cause
Best Prevented By:
4. Lost Circulation (Fluid Level, not rate of loss is critical in well control) 5. Unloading mud by pulling balled assembly 6. Mud weight high enough to drill, but not to trip Least Common
Careful engineering, proper well design Case off Loss Circ ASAP! Measurement of fill-up volume when pulling drill string – TRIP TANK! Measurement of fill-up volume when pulling drill string – TRIP TANK!
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Uncontrolled Kicks = Blowouts
Do
e L t n’
H t i t
n e p ap
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Well Control Equipment • Trip Tank • LP and HP Well Control Equipment • BOP Configuration and testing • Accumulator, Manifold and Mud Gas Separator
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Well Control Equipment - Overview LOW Pressure
HIGH Pressure Pump
Mud Storage
Mud Mixing
Trip Tank
PVT
D
P
Suction Degasser
Gas Buster
Choke
To Pump
BOP Stack Well Head
Accum
CSG IDPT Basic WC
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Well Control Equipment What is the most important piece of well control equipment on the rig?
The Trip Tank
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Surface BOP Stack Configuration ANNULAR TOP RAMS BLIND RAMS
Choke Line HCR
Kill Line Replace with Double Gate (Pipe Rams – Blind Rams) in Selected Cases
BOTTOM RAMS
BOTTOM RAMS
VR Plug Installed in Casing Head IDPT Basic WC
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Sub-Sea BOP Stack Arrangement UPPER ANNULAR
LMRP CON LOWER ANNULAR
Inner Outer Choke Choke
BOTTOM RAMS
SHEAR RAMS
Outer Inner Choke Choke
BLIND RAMS BOTTOM RAMS
UPPER RAMS BOTTOM RAMS
MIDDLE RAMS
Outer Inner Choke Choke
Inner Outer Choke Choke
BOTTOM RAMS
LOWER RAMS
Stack Connector IDPT Basic WC
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Pressure Test Frequency The pressure tests of all blowout preventers, wellhead components and their connections, BOP operating unit, choke manifold, kill and choke lines, standpipe manifold, kelly and kelly cocks, safety valves and inside BOPS shall be made:
During the first trip after the14-day interval with a maximum interval of 21 days or before as specified by local regulations Prior to installation where possible After installation of wellhead and BOP assembly and prior to drilling When any component change is made Prior to drilling into a suspected high pressure zone At any time requested by the Operator’s Drilling Representative After Repairs Prior to the initial opening of the drill stem test tools When bonnets have been opened solely for the purpose of changing rams prior to running casing, a body test to ensure the integrity of the bonnet seals will suffice
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Accumulator Bottle
Bladder Assembly Shell Fluid Port Assembly IDPT Basic WC
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Accumulator Sizing
Non-Flammable Gas
1000 psi
VOLUME AT ACCUMULATOR OPERATING PRESS
MIN OPER PRESS 200 psi ABOVE PRECHARGE PRESS
3000 psi
Accumulator Fluid
PRECHARGE
1200 psi
USABLE VOLUME
- MOST ALL MODERN ACCULULATORS ARE 3000 psi WORKING PRESSURE
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Accumulator Sizing SLB STANDARD SPECIFICATION:
The accumulator volume of the BOP systems should be sized to keep a remaining stored accumulator pressure of 1380 kPa (200 psi) or more above the minimum recommended precharge pressure after conducting the following operations (with pumps inoperative): • • • •
Close all (rams and annular) functions and Open all HCRs valves Open all (rams and annular) functions and Close all HCRs valves Close Annular Open choke line remote operated valve
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Accumulator Sizing SLB STANDARD EXAMPLE:
BOP Equipment: 1 Annular + 3 Rams + HCR Valve Closing Volume (CV): 20 + (3 x 10) + 1 = 56 Gal Opening Volume (OV): 20 + (3 x 10) + 1 = 56 Gal Closing Volume (CV): 20 = 20 Gal Open Choke Line Valve (OV): 1 = 1 Gal Usable Volume (UV): = 133 Gal Nominal (Bottle) Volume (NV): 2 x UV
= 266 Gal
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Accumulator Sizing 3000 psi
Accumulator Fluid
Non-Flammable Gas
1000 psi
1
1200 psi USABLE VOLUME
2
3
Calculation of Usable (Bottle) Volume Pre-Charge
Operating
Useable
Pressure
1000
3000
1200
Gas Vol
10
3.33
8.33
PxV
10,000
10,000
10,000
Liquid Vol
0
6.67
1.67
UV = 6.67 – 1.67 UV = 5
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Hydraulic Pumps SPECIFICATION:
The unit will include one (1) electric pump and two (2) back-up air pumps for accumulator charging. With the accumulator system removed from service, the pumps should be capable of: • Closing annular preventer (excluding diverter) on minimum size drill pipe being used • Opening hydraulic operated choke line valve • Obtain a minimum of 1380 kPa (200 psi) pressure above accumulator precharge pressure on closing unit within two (2) minutes or less
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Choke and Standpipe Manifold At least three flow paths must be provided that are capable of flowing well returns through conduits that are 76.14 mm (3”) nominal diameter or larger. At least one flow path: • Shall be equipped with a remotely controlled, pressure operated adjustable choke. Simplified choke manifolds without remote control choke may be acceptable on light rigs with 2-3k psi stacks. • Shall be equipped with a manually operated adjustable choke. • Must permit returns to flow directly to the pit, discharge manifold or other downstream piping without passing through a choke. Two gate valves with full rated working pressure must be provided in this unchoked path.
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Float Valves SPECIFICATION:
Float valves must be used while drilling and opening hole prior to setting surface casing or any time the posted well control plan is to divert and can also be used in deeper sections of the hole. They: • Prevent sudden influx entry into the drill string • Prevent back flow of annular cuttings from plugging bit nozzles
Either plain or ported floats are acceptable
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Mud-Gas Separator Vent Line
GAS
D
Mud
1. Diameter and length controls the amount of pressure in separator Baffle Plates
Impingement Plate d
Siphon Breaker
No Valves!!
No Valves!!
Drain Line w/Valve
From Choke
MUD
2. Height and diameter and internal design control separation efficiency
3. Height of ‘U’-Tube (D) and distance from bottom of separator to top of ‘U’-Tube controls fluid level and stops gas from going out of the bottom IDPT Basic WC
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Exercise - MGS Design
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Exercise - MGS Design EXAMPLE: Well Depth: 10, 000’ Hole/CSG Size (12-1/4” x 13-3/8”): 0.125 bbl/ft Drill Pipe (5”, 19.5#): 0.025 bbl/ft MW: 12 ppg KMW: 14 ppg Kick Vol: 50 bbl Kill Speed: 3 BPM Well Killed by Driller’s Method Csg Press when gas reaches surface: 1987 psi Csg Press when gas out: 1057 psi Avg Gas Rate during 1st minute of venting: 3,202 MCF/D Avg Gas Rate during last minute of venting: 1,722 MCF/D Avg Gas Rate while venting: 2,462 MCF/D IDPT Basic WC
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Exercise - MGS Design 30
Pressure Loss in 100 ft
20
Downstream Pressure = Atmospheric
6” ID
10
15
4” ID
8” ID
10” ID
5
Upstream Pressure – psi
25
Gas Temp = 75º F
12” ID
0
0
5
5
10
10
15
15
20
20
Gas Flowrate – MMSCF/D IDPT Basic WC
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Well Control Equipment
DIVERTERS Are NOT Well Control Equipment
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Diverters
• Diverter Requirements • Diverter Procedures
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Diverters Designed to direct UNCONTROLLED flow away from personnel • Major weaknesses of the Diverter: 1) Plugging: 1/4 -1/2” A large number particles of this size: Can bridge off these flow paths:
8”
12”
2) Erosion: • Gas/Sand mixtures flowing through diverter lines have been measured to erode though steel at the rate of 8”/hour • Water mixtures have been measured at 16”/hour NO RELIABLE MEANS EXIST TO ELIMINATE THESE PROBLEMS IDPT Basic WC
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Diverter Configuration Flow Line Diverter Diverter Line
Riser Surface Casing Shoe
Entry IDPT Basic WC
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SLB Diverter Requirements Land, Swamp Barge & Jack-Up
Relief Lines • At least two relief lines installed to permit venting at opposite ends or sides of the rig • On Land a single line is permissible
• The relief line shall be at least 8” (203 mm) • No other lines into or out of diverter lines or housing
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SLB Diverter Requirements Land, Swamp Barge & Jack-Up
Relief System • The diverter relief system shall be inserted with a minimum number of bends and all lines well secured. Each diverter relief line will be equipped with a pressure-operated full opening, unrestricted valve. The operating sequence of the diverter will be as follows: • Open selected valve • Close diverter
These functions shall be interlocked. A means of switching flow from one vent to the other without closing in the system must be provided.
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SLB Diverter Requirements Land, Swamp Barge & Jack-Up
Relief System • Special care should be taken to protect pipe bends form erosion. This may include: • • • •
Use of long radius pipe bends Providing extra metal thickness at bends Sleeve-type connections shall not be used in the diverter system A power-operated valve must be installed to automatically shut off mud returns to the pits when the diverter is closed, if the mud return line and diverter relief outlet from the well is a common outlet or the mud return line connects below the diverter head
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SLB Diverter Requirements Land, Swamp Barge & Jack-Up
Relief System • Special care should be taken to protect pipe bends form erosion. This may include: • • • •
Use of long radius pipe bends Providing extra metal thickness at bends Sleeve-type connections shall not be used in the diverter system A power-operated valve must be installed to automatically shut off mud returns to the pits when the diverter is closed, if the mud return line and diverter relief outlet from the well is a common outlet or the mud return line connects below the diverter head
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Shut-In Procedure while Drilling Paths on Choke Manifold Closed (Hard Shut-In), Float in Drill string 1. Stop rotation 2. Raise string to shut-in position (time permitting) 3. Stop the pumps and flow check; if well flows, proceed without delay to next step 4. Close annular/ open remote controlled choke line valve (HCR) 5. Notify man in charge 6. Check space out and close pipe rams and locks 7. Bleed off pressure between pipe rams and annular (if possible) 8. Record annulus and drill pipe pressure and pit gain IDPT Basic WC
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Shut-In Procedure while Tripping Paths on Choke Manifold Closed (Hard Shut-In), Float in Drill string 1. Set slips below tool joint (No tool next to shear ram) 2. Install full opening safety valve and close same 3. Close annular/open remote controlled choke line valve (HCR) 4. Notify man in charge 5. Make up kelly or top drive (insert a pup joint or single between safety valve and top drive) and open safety valve 6. Read annulus and drill pipe pressure and pit gain
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Hard Shut-In vs. Soft Shut-In Hard Shut-In Advantages: • Influx stopped in shortest possible time • Quick and simple procedure Disadvantages: • Perceived pressure pulse or ‘Water Hammer’ effect that is thought to damage formation
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Hard Shut-In vs. Soft Shut-In Soft Shut-In Advantages: • Perceived pressure pulse is reduced Disadvantages: • A larger influx is obtained due to the delay in fully shutting the well in • More complex due to requirement of ensuring valve alignment before closing BOP
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Hard Shut-In vs. Soft Shut-In Conclusions Soft Shut-In • Little improvement to pressure pulse • Significant effect from additional influx
Hard Shut-In • ‘Water Hammer’ smaller than shut-in pressure rise • Formation exposed to lower net pressure • Results favor Hard Shut-In • Minimum confusion, Less influx volume, Lower annular pressure
• Safety of personnel and equipment without risk to well
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Well Kill Procedures CONSTANT BHP WELL CONTROL METHOD
Circulate Gas Out Holding Constant BHP
P1 = P2 IDPT Basic WC
IPM
Well Kill Procedures • 4 Methods • Drillers Method • Circulate kick out • Then pump kill weight mud
• Wait and Weight Method • Mix KW mud (Well shut in) and pump into wellbore.
• Volumetric, Lubricate and Bleed • When circulation is a problem
• Bullheading
IDPT Basic WC
IPM
37
Driller’s Method ADVANTAGES • • • •
Simplicity – Less calculations are required than Wait and Weight Can start circulation immediately – Effect of gas migration reduced Removes influx and stabilizes wellbore pressure at earliest possible time Viable option if limited barite is available
DISADVANTAGES • Method will require at least two circulations • Under certain conditions the highest shoe pressure • Two circulations may cause damage to Well Control Equipment
IDPT Basic WC
IPM
Wait and Weight Method ADVANTAGES •
In some circumstances, it generates the lowest pressure on the formation near casing seat.
•
In a long open hole section, it is the least likely method to induce lost circulation.
•
Requires one less circulation, therefore less damage to Well Control Equipment
•
Defacto standard for majority of our clients
DISADVANTAGES •
Requires longest waiting period prior to circulation. In a case where a significant amount of hole is drilled prior to encountering the kick, the cuttings may settle out and plug annulus
•
Gas migration is a problem while the density of the system is increased IDPT Basic WC
IPM
38
Well Control Incident Reporting • All WC Incidents will be reported in QUEST within 24 hours of the incident.
• The QUEST entry shall be accompanied by a Well Control Incident Report
IDPT Basic WC
IPM
Well Control Incident Reporting
IDPT Basic WC
IPM
39
Well Control Incident Reporting
IDPT Basic WC
IPM
Well Control Incident Reporting
IDPT Basic WC
IPM
40
Basic Well Control • Now you should be able to: • Define the terms “kick” and “Blowout” • Understand the causes of kicks and blowouts • Describe primary, secondary and tertiary WC procedures • Perform basic WC calculations • Describe the necessary equipment for Well Control • Be able to report a WC incident in Quest • Fill out a killsheet.
IDPT Basic WC
IPM
41