SUMMER TRAINING REPORT OIL AND NATURAL GAS CORPORATION LIMITED, ANKLESHWAR

WELL CONTROL PRACTICES AND

PROCEDURES TO DEAL WITH ANY

UNCONTROLLED SITUATION &

CASE STUDY Under the guidance of Mr. R. P. Singh CE (D) – I/C CMT

ONGC, Ankleshwar.

Submitted by: University of Petroleum and Energy Studies, Dehradun

Shricharan Arumugam B.Tech (Applied Petroleum Engineering)

Sugat Srivastava B.Tech (Applied Petroleum Engineering)

Shiv Prakash Legha B.Tech (Applied Petroleum Engineering)

Vivek Pathak B.Tech (Applied Petroleum Engineering)

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If you know the laws of buoyancy it doesn’t mean that you know how to

swim. It’s only through jumping in the water that you get to feel the depth.

This is applicable to every aspect of life.

Therefore Industrial training is of utmost importance.

The objective of the undergoing training was to familiarise with the day to

day functioning of the industry, hands on training and most importantly to

learn to put theory into practice.

I have been greatly privileged to have undergone training at, OIL & NATURAL GAS CORPORATION LTD., ANKLESHWAR ASSET, GUJARAT

The report contains the extracts of the operations in well control & drilling

services during my training period.

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CONTENTS

................................... 6

........................................................................................ 7

................................................................................................................ 8

..................................................................................................... 9

POWER SYSTEM ..................................................................................................... 10

HOISTING SYSTEM ................................................................................................. 10

CIRCULATING SYSTEM ......................................................................................... 11

ROTARY SYSTEM .................................................................................................... 12

WELL CONTROL SYSTEM ..................................................................................... 13

WELL MONITORING SYSTEMS ............................................................................ 14

.......................................................................... 15

KICK ............................................................................................................................. 15

BLOWOUT .................................................................................................................. 15

PRIMARY WELL CONTROL ................................................................................... 15

SECONDARY WELL CONTROL ............................................................................ 15

TERTIARY WELL CONTROL .................................................................................. 15

PRESSURE ................................................................................................................ 15

3.6.1 Hydrostatic Pressure.................................................................................................. 15

3.6.2 Pressure Gradient ...................................................................................................... 15

3.6.3 Bottom Hole Pressure (BHP) .................................................................................... 16

3.6.4 Formation Pressure.................................................................................................... 17

3.6.5 Kick Tolerance ............................................................................................................ 17

CAUSES OF REDUCTION IN HYDROSTATIC HEAD ....................................... 17

3.7.1 Failure to fill the hole .................................................................................................. 17

3.7.2 Water dilution at surface (on rotary or at shale shaker) ....................................... 17

3.7.3 Removal of parts of barite from the mud, by mud handling system, such as

centrifuge etc. ............................................................................................................. 17

3.7.4 Cement Setting ........................................................................................................... 17

3.7.5 Settling of Weighing Material .................................................................................... 18

MAXIMUM ALLOWABLE ANNULAR SURFACE PRESSURE (MAASP) ........ 18

SWAB AND SURGE EFFECTS .............................................................................. 18

TRIP MARGIN ............................................................................................................ 19

EQUIVALENT MUD DENSITY IN THE ANNULUS .............................................. 19

EQUIVALENT CIRCULATION DENSITY (ECD) .................................................. 19

LEAK-OFF TEST ....................................................................................................... 19

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............................................................ 21

PRIMARY CONTROL ............................................................................................... 21

4.1.1 ................................................................................................... 21

4.1.2 ........................................................................................... 25

SECONDARY CONTROL ........................................................................................ 30

4.2.1 .................................................................................................... 30

4.2.2 ....................................................................................................................... 31

4.2.3 ................................................................................................. 32

.................................................................. 40

LOST CIRCULATION ............................................................................................... 40

5.1.1 ................................................................................... 40

5.1.2 ................................................. 40

................................................................................................................. 40

5.2.1 ................................................................................................................... 41

5.2.2 .......................................................................................................... 41

5.2.3 .............................................................................................................. 41

5.2.4 ..................................................................................................... 41

............................................................................... 42

5.3.1 ................................................................................ 42

5.3.2 .................................................................................................... 42

5.3.3 ........................................................................................ 43

.................. 43

5.4.1 .................................................................................................................... 43

5.4.2 .......................................................................................................................... 44

.................................................................................................... 45

5.5.1 .................................................................................................................. 45

5.5.2 ............................................................................................................. 45

.............................................................................................. 45

5.6.1 ................................................................................................................. 46

5.6.2 ............................................................................................................. 48

....................................................................................... 48

5.7.1 ........................................................................................................................... 48

5.7.2 ...................................................................................................... 48

5.7.3 ................................................................................................ 49

5.7.4 ................................................................................................. 49

5.7.5 ............................................................................................ 49

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................................................................................... 50

............................................... 50

..................................... 51

...................................................................................... 51

6.3.1 .................................................................................................... 51

6.3.2 .................................................................................................. 54

6.3.3 .......................................................................................................... 57

6.3.4 .......................................................................................................... 60

6.3.5 .................................................................................................... 61

6.3.6 ................................................................................ 62

.................................................................................................. 65

........................................................................................................ 67

............................................................................................. 68

............................................................................................... 69

STANDARD OPERATING PROCEDURE TO BE FOLLOWED: ....................... 69

PERIODIC INSPECTION AND MAINTENANCE .................................................. 70

DRILLS AND TRAINING .......................................................................................... 71

7.3.1 .................................................................................................... 71

7.3.2 ...................................................................................... 71

7.3.3 .................................................................... 72

7.3.4 ................................................................................. 72

............................................................................................................. 73

CASE STUDY – 1 ...................................................................................................... 73

CASE STUDY – 2 ...................................................................................................... 75

............................................................................................................. 77

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Figure 1 Ankleshwar Oil Field

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Figure 2 CMT Organogram

HCMT Corporate Mumbai

RCMT, Mumbai RCMT, SBS RCMT, RJY RCMT, Baroda

CMT, Ahemdabad CMT, Mehsana CMT, Ankleshwar

R P Singh, CE(D)- I/C CMT

J M Bemat, DySE (D)

Saket, EE (D)

D G Valand, EE(D)

Sanjay Kumar, AEE(D)

Sandip Vasava, FO(D)

S K Sahare, AEE(P)

S D Patel, AEE(M)

Head Drilling Services

Ankleshwar

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Figure 3 Drilling Rig

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POWER SYSTEM

Figure 4 Power System

HOISTING SYSTEM

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Figure 5 Hoisting System

CIRCULATING SYSTEM

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Figure 6 Circulating System

ROTARY SYSTEM

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Figure 7 Rotary System

WELL CONTROL SYSTEM

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Figure 8 Well Control Stack

WELL MONITORING SYSTEMS

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KICK

BLOWOUT

PRIMARY WELL CONTROL

SECONDARY WELL CONTROL

TERTIARY WELL CONTROL

PRESSURE

3.6.1 Hydrostatic Pressure

(psi) (TVD-feet) (ppg)(0.052 is a conversion constant)

3.6.2 Pressure Gradient

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(psi)

(psi /ft) (feet) (psi)

x x (psi)

3.6.3 Bottom Hole Pressure (BHP)

BHP in different well situations:

i)

NOTE: Usually annular pressure losses are not taken into account for calculation of BHP during killing.

(Note: Terms Surge & Swab pressure are explained at 3.9 in detail)

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3.6.4 Formation Pressure

3.6.5 Kick Tolerance

CAUSES OF REDUCTION IN HYDROSTATIC HEAD

3.7.1 Failure to fill the hole

NOTE: Reduction in bottom hole pressure due to pulling out without filling hole will be much higher

for drill collars, if pulled out dry or, wet without filling the hole.

3.7.2 Water dilution at surface (on rotary or at shale shaker)

3.7.3 Removal of parts of barite from the mud, by mud handling system, such as

centrifuge etc.

3.7.4 Cement Setting

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3.7.5 Settling of Weighing Material

MAXIMUM ALLOWABLE ANNULAR SURFACE PRESSURE

(MAASP)

NOTE: MAASP value must be known & posted on the rig at all times during drilling. As the mud weight is changed or another LOT is conducted, MAASP must be recalculated accordingly.

SWAB AND SURGE EFFECTS

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TRIP MARGIN

(ppg) = [8.33 / 98( - )]

Where, = lbs/100 sq.ft = inches = inches

EQUIVALENT MUD DENSITY IN THE ANNULUS

EQUIVALENT CIRCULATION DENSITY (ECD)

(ppg) (ppg) (psi)(ft)

LEAK-OFF TEST

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Figure 9 Idealised Leak-off test curves

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PRIMARY CONTROL

4.1.1

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4.1.2

Suitable safety valves with appropriate connections of crossover subs to fit all drillpipe and B.H.A.

connections must be on the rig floor, in the 'open' position ready for use with proper fittings and

handling devices. The closing/opening wrench must be readily available for immediate use.

A trip sheet will be filled out on each trip

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When tripping, flow checks will be taken as follows

Just off bottom

At the lowest casing shoe

Prior to pulling drill collars through the BOP stack.

If the hole is taking the proper amount of fluid and if there is no drag or overpull which could generate swabbing, then the pipe wiper will be installed after pulling the first 5 stands or after the bit is pulled into cased hole.

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Drilling breaks will be flow checked.

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d)

e)

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Clear written instruction must be issued to the drillers by the man-incharge, regarding the specific

action to take in case of a kick while drilling the tophole section. This could involve either shutting in

or diverting the well. A copy of the procedure must be prominently posted near the BOP/diverter

control panels.

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SECONDARY CONTROL

4.2.1

.

Examples of full opening safety valves are T.I.W., Hydril, S.M.F. but not Gray.

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IF UNABLE TO SHUT-IN THE DRILLSTRING, CLOSE SHEAR RAMS OR DROP STRING.

4.2.2

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i)

4.2.3

NOTE: All methods at keeping bottom hole pressure constant and equal to formation pressure

Note : While bringing the pump to kill speed keeping casing pressure constant, there might be slight reduction

in bottom hole pressure due to expansion of gas but this is compensated by the annular pressure losses.

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NOTE: In case recorded SIDPP & SICP are equal but more than original SIDPP value, it indicates trapped

pressure in wellbore. Whereas if SICP is more than original SIDPP, it indicates that some influx is still in the

wellbore.

v.

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Figure- Pressure profile – 1st cycle of Driller’s Method

Figure- Pressure profile – 2nd cycle of Driller’s Method

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.

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Figure- Pressure profile – Wait & Weight Method.

4.2.3.4 COMPARISON OF METHODS

1.

2.

3.

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4.2.3.5.1 Stripping through annular preventer

a)

b)

c)

d)

e)

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f)

g)

4.2.3.5.2 Stripping Through Ram Preventers

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If it is not possible to strip the string into the well, the volumetric method or

bullheading may have to be employed.

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LOST CIRCULATION

5.1.1

5.1.2

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5.2.1

5.2.2 Power to force the pipe in the hole is generated by a system of pulleys and cables or chains attached to the rig traveling block. As the traveling block is pulled upward, the traveling snubbers grip the pipe and force the pipe into the hole.

5.2.3

The standard hydraulic snubbing unit is self-contained. A traveling snubber with slips is connected to a piston that supplies the force to move pipe in the hole. In addition to a set of traveling snubbers, the unit is equipped with a set of stationary snubbers that are closed after the piston has moved the pipe the length of its full stroke. The stationary snubbers grip the pipe and the piston is retracted. The traveling snubber is then engaged, the stationary snubbers are opened and the process is repeated.

5.2.4

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If normal well killing techniques with conventional circulation are not possible or will result in critical well control conditions, bullheading may be considered as a useful method to improve the situation. Mud/influx are displaced/squeezed back down hole into the weakest exposed open hole formation.

5.3.1

5.3.2

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5.3.3

5.4.1

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e)

5.4.2

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5.5.1

5.5.2

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5.6.1

REQUIRED VOLUME OF WEIGHT OF

DENSITY DIESEL OIL BARITE

kg/l (ppg) m3 (bbl) kg (lb)

2.15 (18) 0.102 (0.642) 240 (530) 2.40 (20) 0.089 (0.560) 292 (643) 2.51 (21) 0.084 (0.528) 315 (695) 2.63 (22) 0.078 (0.490) 340 (750)

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REQUIRED VOLUME OF WEIGHT OF

DENSITY DIESEL OIL BARITE

kg/l (ppg) m3 (bbl) kg (lb)

2.15 (18) 0.097 (0.610) 259 (572) 2.40 (20) 0.086 (0.541) 308 (679) 2.51 (21) 0.080 (0.503) 331 (730) 2.63 (22) 0.075 (0.471) 354 (781)

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5.6.2

5.7.1

5.7.2

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5.7.3

5.7.4

5.7.5

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Figure 10 Well Control Stack

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6.3.1

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Figure 11 Annular Preventer

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Figure 12 Annular Preventer - Exploded View

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6.3.2

Figure 13 Ram BOP - Exploded Vieew

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Figure 14 Pipe Rams

Figure 15 Blind Rams

Figure 16 Variable bore rams (VBR)

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Figure 17 Shear blind rams (SBR)

Figure 18 Fuctioning of Shear Blind Rams

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6.3.3

Figure 19 Cameron Wedge Lock

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Figure 20 Shaffer Poslock

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Figure 21 Shaffer Ultralock

Figure 22 Koomey Auto lock

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Figure 23 Hydril Multiple Position Lock (MPL)

6.3.4

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Figure 24 Diverter System

6.3.5

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Figure 25 Mud-Gas Seperator

6.3.6

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Figure 26 Upper Kelly Cock/FOSV

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Figure 27 IBOP

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Figure 28 Drop-In Check Valve

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Figure 29 Choke Manifold

Figure 30 Manually adjusted choke

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Figure 31 Remote Control Adjustable Choke

Figure 32 Gate Valves and Check Valves

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Figure 33 Accuulator Unit

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STANDARD OPERATING PROCEDURE TO BE FOLLOWED:

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PERIODIC INSPECTION AND MAINTENANCE

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DRILLS AND TRAINING

7.3.1

7.3.2

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7.3.3

7.3.4

Well control training Asst. Shift In-charge/Asst. Driller and above supervisory personnel should have accredited control certificate (of the appropriate level). At least one trained person should be present on derrick floor to observe well for activity even during shutdown period.

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CASE STUDY – 1

1

•Made pumping line connections from cementing unit to annulus and tested the same at 2500 psi.

•Started pumping water through annulus line to make the gas wet to prevent fire.

•Attempted to kill the well dynamically by pumping 50 m3 mud of sp. gr. 1.6gm/cc at high rate but no success.

•The blowing stream was continuously cooled by pumping water through annulus as well as through fire monitor of fire services to keep the gas wet.

2

•A plan was made to change the Pipe ram with blind rams in the lower cavity.

•Changed the pipe rams with blind rams in the lower cavity under full water umbrella and with utmost safety.

•Closed the rams and observed flow reduced considerably.

•Pumped 10 m3 water from annulus followed by 40 m3 mud of Sp. Gr. 1.6 at very high rate, flow got reduced drastically but well could not be controlled as sealing area of ram cavity of the BOP got cut due to the severe flow.

3

•Plan was made to change the damaged BOP with a 7 1/16" HCR Valve to cap the well. A CMT meeting was held in the Morning to put the capping operation with micro planning on paper and assigning the duties to CMT members.

•Four teams were made to carry out the different jobs simultaneously in assigned sequence of operations. Role of each person was defined to avoid any confusion at the time of actual operation. In between the total operation two safety meetings were planned to carry out the capping operation with utmost safety and competently.

•Well continued to blow gas and water and was cooled by water jets and by pumping water through annulus

•During blow out control operations while working for changing the damaged BOP to cap the blowing well, suddenly well caught fire at about 12.30 hours.

•Four CMT personnel and five crane and rig crew sustained burn injuries, they were immediately given first aid and were sent to hospital. Subsequently seven people were shifted to a burns specialty hospital by ICU on wheels to Mumbai.

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4

•Preparation to control blowing well with fire started immediately and blow out control equipment were mobilized from RCMT Vadodara and Rajahmundry.

•Two International Blowout control experts from M/S Boots & Coots were mobilized to advise CMT ONGC to carry out further safe blow out control operations.

•Simultaneously preparation of relief well started as standby option other than top intervention for capping,

•As the well caught fire it damaged the structure and mast of the rig, in this condition to control the well it was essential to remove all the debris lying around the well to access the blowing well.

•Started digging fire pits for water storage.

5

•Received blow out control equipment from RCMT Baroda which include 03 fire pumps, Athey wagon, Bulldozer, sand cutter etc.

•Two Nos fire pits for water storage were dug having total capacity of 3500 m3.

•Placed the three pumps and all the fire monitors were installed with heat shield after fabrication of manifold.

•OSD (T&FS) inspected the well by going close to the well under water umbrella.

6

• Debris removal operation started under heavy water umbrella.

•Removed the crane, mast, rig carrier, mud pumps, tanks and ell the bunk houses and fallen stands of pipes.

•Removed Huge pile of damaged pipe stands & tubing stands, Koomey unit, Generator & its electrical control panel.

•Placed two more fire pumps and made it operational-

7

•Assembled the Athey wagon and fabricated the rack arrangement and assemble the same.

•Athey wagon was taken from staging area to blowout site and kept at e strategic position.

•While removing the sub structure, with the help of Athey wagon the pumping line from annulus to cementing unit got snapped and flow started from annulus also horizontally.

•Cut the frames of substructure with the help of oxy-lance magna rod cutting and removed the same.

•The entire operation was carried out under heavy water umbrella and within a distance of about 2 to 3 meters from the well.

8

•Well bridged and fire stopped at hours on 30 April. Observed feeble fire. Put off the fire.

•Inspected the Well head closely and removed remaining debris around it.

•Removed old annulus valve and installed new valves on both side of tubing spool.

•Prepare annulus pumping line to cementing unit. Tested the line at 3000psi.

•Suddenly observed fierce flow of gas from kill side valve of tubing spool.

•Closed the valve and started pumping. Pumped 7 m3 of 1.12 mud and kill the well.

•Placed the accumulator unit at a safe distance end charged up to 3000psi.

•Cut the studs of damaged BOP and removed the same.

•Capped the well successfully by installing pre- tested 7 1/16’’ double ram BOP fitted with two blind rams, closed the Lower Blind rams and secondary control was restored.

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CASE STUDY – 2

1

•Well was subdued with 1.05 sp gr. High viscosity bentonite gel and the X-MAS tree was removed for installation of 7 1/16” BOP.

•Observed well flow, rig crew tried to tighten the X-MAS tree but the intensity of flow increased.

•Well was flowing dry gas vigourously, the fire tenders were mobilized to spray water on the gas flow to avoid fire.

•The area was cordoned off.

•Gas blowout at well RO #9 was reported at 20.30 hrs

2

•Team CMT reached the site at 1430 hrs.

•line was laid from well to cementing unit.

•Plan was to pump water followed by mud to control the well.

•When mud was pumped it came out immediately from X-MAS tree flange

•Observed no mud flow from crown valve

3

•The blowout was controlled in the shortest possible time of 6 days.

•The well was capped by in- house expertise before arrival of M/s Boots & Coots.

•Utmost safety precautions taken have resulted in no fire and no injury

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1. ONGC-Well Control Training Manual. 2. Schlumberger-Well Control Manual. 3. Sedco Forex-Well Control Manual. 4. Rigtrain – Well Control for the Drilling Team. 5. Aberdeen Drilling Schools and well control training center – well control

for the rig site drilling team. 6. Heriot Wyatt University- Drilling engineering.