drilling presentasion bojonegara.pptx

DRILLING

Erwan Setiawan

Drilling and Well Constructions.Drilling Program data. Before we work on the Drilling Program we must have the complete

the following data :

- Reservoir Program, what kind of formations will be produced c/w Formation pressure, depth, etc.

- The data of neighbor wells ( as references ).

- What kind of formation will be passed thru.

- Data of Shallow gas, if any.

- Data of Materials will be used in Drilling program, as :

1. Casing size and grade, Cementing Equipment, Centralizers and all accessories of Cementing Equipment, Cement and chemical for Cementing Job.

2. Drilling bits and all accessories for Drilling String, as the following and all Parts must be available on the rig with back up.

3. Wellhead and all accessories ( included X-mas tree or abandon well if Dry hole ).

4. Fishing tools , included DP or tubing Explosives and Chemical Cutter and to exploded DC or TJ threads for any sizes of tubular has on the rig.

5. Drilling Mud and fluids, Loss Circulating Materials ( LCM ), etc.

THE ROLE OF DRILLING PRACTICES

The term “Drilling Practices”

encompasses pretty much

everything from moving onto location to

reaching Well TD.


In reaching Well TD, a significant variety of things

can happen. Once we have

reached TD again, a significant

variety of things can happen.


Not is only is it vital that we drill / test / complete the well economically,

but it is vital – indeed crucial – that we drill the

well safely.

DRILLING OPERATIONS.Standard Phase, Bit and Casing

size.

Phase Conductor : (Casing 30’’ hammered)

Phase 26”: Bit 26”,Casing 20” Phase 17 ½”:Bit 17 ½”,Casing 13 3/8” Phase 12 1/4”:Bit 12 1/4”,Casing 9

5/8” Phase 8 1/2” : Bit 8 1/2” ,Casing 7”

28/04/2023

Standard Well Configuration

Conductor 30”Surface Casing 20”Intermediate Casing 13 3/8”Production Casing 9 5/8”Liner7” or 5 ½”Production Tubing 3 ½” to 4 ½”

7” 5200mTMD

(4200mTVD)

9”5/8 3800-4200mTMD (3200-3600mTVD)

12”1/4

8”1/2

Type 1 Standard Well

Standard Completion

13”3/8 1350mTMD (1200mTVD)

4.½” 5500mTMD

(4500mTVD)

DRILLING OPERATIONS

Gas Well Configuration Monobore.

Conductor 30” Surface Casing 13 3/8” Intermediate Casing 9 5/8” Production Casing 7” Production Tubing 4 ½”

28/04/2023

New Gas WellConfiguration Tubing Less

Conductor 30” Surface Casing NA Intermediate Casing 13-3/8” x 9 5/8” or

7” Production Casing 4 ½”

Type 3 Slimhole Well

Monobore Completion

9”7/8

6”

13”3/8 1350mTMD (1200mTVD)

7” 3800-4200mTMD

(3200-3600mTVD)

4.½” or 3.½”

5500mTMD (4500mTVD)

12”1/4

8”1/2

Type 2 Standard Well

Monobore Completion

13”3/8 1350mTMD (1200mTVD)

9”5/8 3800-4200mTMD

(3200-3600mTVD)

4.½” 5500 mTMD

(4500 mTVD )

6”

9”7/8

Type 4 Slimhole Well

Tubingless Completion

13”3/8 1350mTMD (1200mTVD)

4.½” or 3.½”

5500mTMD (4500mTVD)

Completion

7” 3800-4200mTMD

(3200-3600mTVD)

STATISTICALLY SHALLOW GAS IS THE MOST LIKELY SINGLE CAUSE OF KICKS LEADING TO BLOWOUTS

DRILLING PRACTICES

SHALLOW GAS

Shallow gas is considered to be any gas accumulation encountered during drilling at a depth above the setting point of the first string of casing intended for, or capable of, pressure containment. Shallow gas generally occurs as normally pressured accumulations in shallow sedimentary formations with high porosities and high permeability.Drilling through such a gas bearing formation requires extreme caution. Because of the difficulty in early detection of an influx while drilling top hole sections and the shallow nature of the hole, the gas, upon entering the wellbore, expands and reaches the surface very rapidly and with little warning.It may be decided to either shut-in the well or divert, if shut-in pressures combined with the hydrostatic pressure of the drilling fluid could result in breaking down the formation.

DRILLING PRACTICES

SHALLOW GAS

PLANNING AND ASSESSMENT OF RISK

PRIOR TO STARTING OF DRILLING OPERATIONS, THE RIG MANAGER

MUST DISCUSS WITH THE OPERATOR THE ASSESSMENT OF THE RISK OF

SHALLOW GAS. THE WELL DESIGN AND SPECIFIC

OPERATING PROCEDURES WILL BE REVIEWED IN THE LIGHT OF THIS

ASSESSMENT.

DRILLING PRACTICES

SHALLOW GAS

LOCATIONS WHERE SHALLOW GAS MAY OCCUR

· Exploration wells in general.

· Wells drilled in shallow gas prone areas.

· Wells with probable / possible shallow gas identified by a preliminary shallow gas investigation.

· Wells drilled in developed fields where charged shallow sands could occur due to poorly cemented casing strings.

DRILLING PRACTICES

SHALLOW GAS

EVALUATION OF SHALLOW GAS RISK

IS THERE A MULTI-CHANNEL, HIGH RESOLUTION DIGITAL SEISMIC SURVEY?

YES NO

IN THE ABSENCE OF THIS SURVEY DATA THE OPERATOR MUST BE REQUESTED TO CONDUCT THE SURVEY PRIOR TO SPUDDING. THE OPERATIONS MANAGER SHOULD REFER TO THE REGION MANAGER IF THE SURVEY WILL NOT BE DONE.

WHAT SOURCE WAS USED?

AIR GUNS OR WATER GUNS

SPARKER SURVEY OLD TECHNOLOGY POOR RESULTS

HOW MANY CHANNELS WERE RECORDED AND AT WHAT RATE

48 CHANNELS; 0.5 TO 1 MILLISECOND

RATE

24 CHANNELS OR LESS

WHAT LENGTH OF STREAMER WAS USED?

600 METRES, OK 300 METRES, NOT GOOD

DO YOU MIND IF I HAVE A CONFIDENTIAL COPY OF THE SURVEY FOR INDEPENDENT COMMENTS WITH RESECT TO SHALLOW GAS?

DRILLING PRACTICES

SHALLOW GAS

SHALLOW GAS PLAN

• CREW POSITIONS AND THEIR SPECIFIC DUTIES WILL BE REVIEWED.

• DRILLS MUST BE HELD BY EACH CREW AT THE BEGINNING OF EACH TOUR DURING THIS DRILLING PHASE TO FAMILIARIZE ALL PERSONNEL WITH THE APPROPRIATE AND IMMEDIATE ACTIONS IN CASE OF SHALLOW GAS KICK.

• ONE OF THESE DRILLS, CONDUCTED PRIOR TO DRILLING, WILL INCLUDE MUSTERING CREW AND SIMULATION OF PROCEDURES NECESSARY TO DISCONNECT / MOVE OFF LOCATION (FLOATING RIGS ONLY).

• EVACUATION PLANS FOR ALL NON-ESSENTIAL PERSONNEL MUST BE PREPARED.

• EMERGENCY POWER SHUT-DOWN PROCEDURES MUST BE PREPARED.

• DISCONNECTING AND / OR MOVING OFF LOCATION PROCEDURES FOR FLOATING RIGS MUST BE PREPARED.

DRILLING PRACTICES

SHALLOW GAS

PREPARATIONS PRIOR TO DRILLING (CHECKLIST)

· TEST ALL GAS DETECTORS AND ALARMS.

· AT LEAST ONE WINDSOCK MUST BE INSTALLED IN A PROMINENT POSITION VISIBLE FROM THE MUSTER POINT.

· HOLD SAFETY MEETINGS WITH ESSENTIAL PERSONNEL AND EXPLAIN PLANS AND PROCEDURES.

· A FLOAT VALVE MUST BE RUN TO PREVENT SUDDEN FLOW UP THE DRILLSTRING. (POLICY)

· FOR FLOATING RIGS, TO OBSERVE FOR GAS, THE SUBSEA TV OR AN ROV SHOULD BE POSITIONED SO THAT RETURNS CAN BE MONITORED AT THE SEABED. IN ADDITION, A WATCH MAY BE POSTED IN THE MOONPOOL AREA.

· THE STANDBY VESSEL WILL BE POSITIONED UPWIND OF THE RIG.

· DRILLING OPERATIONS WILL BE SUSPENDED AND A RISK ASSESSMENT CONDUCTED IF THE RIGS GAS DETECTION SYSTEM FAILS.

· DRILLING OPERATIONS WILL BE SUSPENDED AND A RISK ASSESSMENT CONDUCTED IF THE RIGS MUD MONITORING SYSTEM BECOME UNAVAILABLE WHILE USING A CLOSED MUD SYSTEM.

· HOT WORK WILL NOT BE PERMITTED WHILE SHALLOW GAS PROCEDURES ARE IN FORCE.

· WATER DELUGE SYSTEMS WILL BE RUNNING ON ALL ENGINE EXHAUST SYSTEMS INCLUDING THE EMERGENCY GENERATOR.

· THE DIVERTER INSERT WILL BE INSTALLED AND LOCKED IN POSITION AT ALL TIMES WITH THE EXCEPTION WHERE BHA COMPONENTS WILL NOT PASS THROUGH.

DRILLING PRACTICES

SHALLOW GAS

DIVERTER PROCEDURES WHILE DRILLING

SURFACE BOP’S

At first sign of flow:• Do not stop pumping.• Open diverter line to divert / close diverter (both functions should be interlocked).• Increase pump speed to maximum rate.• Switch suction on the mud pumps to heavy mud in the reserve pit.• Zero the stroke counter.• Raise the alarm and make announcement on PA system. Inform the Toolpusher and OIM. Post personnel to watch for gas.• If the well appears to have stop flowing after pumping the heavy mud, stop the pumps and observe the well.• If the well continues to flow after the heavy mud has been pumped, carry on pumping from the active system and prepare to pump water. Also consider mixing heavier kill mud. When all the mud has been consumed, switch the pumps to water. Do not stop pumping for as long as the well continues to flow.

DRILLING PRACTICES

SHALLOW GAS

SUBSEA BOP’S

Note: The slip joint packer is the most vulnerable item of equipment in the marine riser system during diverting operations.

• Rigs with subsea BOP’s should shut the well in when possible.• Moving the rig off location immediately may be the best option.• If diverting is necessary, do not stop pumping.• Open diverter line and close the diverter.• Increase pump strokes to maximum pumping rate. • If a pin connector is in use, unlatch the connector.• Switch the suction line on the pumps to heavy mud in the reserve pit.• Raise the alarm and make announcement on PA system. Inform the Toolpusher and OIM. Post personnel to watch for gas.• Continue to pump until all mud has been consumed, switch pumps to water.• Make preparations to move the rig off location.

DIVERTER PROCEDURES WHILE DRILLING

DRILLING PRACTICES

SHALLOW GAS

DIVERTER PROCEDURES WHILE TRIPPING

SURFACE BOP’S

At first sign of flow:• Set pipe in the slips.• Open diverter line, close diverter (functions should be interlocked).• Make up topdrive / kelly.• Start pumping at maximum pump speed. • Switch suction line to heavy mud in the reserve pit. Zero the stroke counter.• Raise the alarm on the PA system and notify the Toolpusher and OIM.• If the well appears to have stopped flowing after pumping the heavy mud, stop the pumps and observe the well.• Prepare to run back to bottom.• If the well continues to flow after the heavy mud has been pumped, carry on pumping from the active system and prepare to pump water. Also consider mixing heavier kill mud. • When all the mud has been consumed, switch the pumps to water. • Do not stop pumping for as long as the well continues to flow.

DRILLING PRACTICES

SHALLOW GAS

DIVERTER PROCEDURES WHILE TRIPPING

SUBSEA BOP’S

At first sign of flow:• Set pipe in the slips.• Open diverter line, close diverter (functions should be interlocked).• Disconnect the pin connector (or open dump valves and increase the slip joint packer pressure).• Make up top drive / kelly.• Start pumping at maximum pump speed. • Switch suction line to heavy mud in the reserve pit. Zero the stroke counter.• Raise the alarm on the PA system, notify Toolpusher and OIM.• Post personnel to watch for gas at the waterline.• If the well appears to continue to flow after the heavy mud has been pumped, carry on pumping from the active system and prepare to pump water. Also consider mixing heavier kill mud. When all the mud has been consumed, switch the pumps to water. Do not stop pumping for as long as the well continues to flow.• Prepare to move the rig off location.

DRILLING PRACTICES

SHALLOW GAS

PRIOR TO DRILLING1. Function test Diverter and flash with water2. Mud pump, kill mud and water pump alignment understood3. Gas detection system tested4. Drills carried out :

·Well control·ESD, black shutdown·Emergency fill-up·Abandon rig

5. Kill mud ready6. Hot Work Permits cancelled7. Cold start of cementing unit and gravity feed

AT FIRST INDICATION OF THE WELL FLOWING

IF WELL NOT FLOWING1. Gradually reduce pump rate and try to see if well is stable without pumping2. If it is stop pumps, observe well and wait for instructions

1. Evacuate all non essential personnel2. Pump until mud exhausted then switch to seawater3. Start generators and deluge system at wellhead area4. Evacuate remaining personnel

IF LOSSES1. Increase pump rate to maximum2. Pump water down annulus via emergency fill-up line3. Pump LCM pill4. If required switch to water. Attempt to keep the hole full

SHALLOW GAS PROCEDURE

Diverter Valves

Water Fill-up Valve (losses)

IF WELL STILL FLOWING

DURING DRILLING1. Choke Line HCR closed2. Upper and lower Kill Line HCR closed3. Manifold lined up through primary choke and degasser4. Choke and valve preceding choke closed

IF ANY OF THE FOLLOWING SIGNS OCCUR

1. Drilling break2. Increase in return flow3. Increase in pit level4. Gas cut mud5. Abnormal increase in flowline temperature INVESTIGATE

1. Pick up and put TJ at appropriate height to rotary table2. Shut off pumps3. Monitor on trip tank and call TP and Company Rep

IF WELL STABLE1. Circulate BU2. Check pit levels3. Resume drilling

IF WELL FLOWING FAST SHUT IN1. Close annular preventer2. Open choke HCR and valve upstream choke3. Check space out and close upper ram4. Open annular preventer5. Record DP and casing pressure

WELL CONTROL WHILST DRILLING

11/03/2004 DKF/DRL/MTH & DKF/DRL/TTH

F/SHUT IN POSITION

COMMENCE APPROPRIATE WELL KILL METHOD :1. Preferred well control technique is Drillers Method * Use HP slim hole Kick Control to select Circulation Rate, SICP, not to break at shoe2. Check influx volume against kick tolerance guidelines in drilling program to ensure kick can be circulated out. If not bullheading is indicated3. Use upper choke and upper kill line as primary4. Never bleed off pressure if MAASP exceeded unless surface equipment/casing is approaching the limit or there is a real risk of cratering around the rig5. Monitor mud gas separator at all times. Be prepared to divert overboard if mud seal is displaced by gas

DRILLING POSITION

SBR

PR

VBR

SBR

PR

VBR

SBR

PR

VBR

NORMAL KILL CIRC

DURING TRIPPING1. Choke line HCR closed2. Upper and lower kill line HCR closed3. Manifold lined up through primary choke and degasser4. Choke and valve preceding choke closed5. Well lined up on trip tank6. Driller and Mud Loggers recording well fill

IF WELL DOES NOT TAKE CORRECT FILL OR SIGNS OF FLOW

WELL CONTROL WHILST TRIPPING

11/03/2004 DKF/DRL/MTH& DKF/DRL/TTH

1. Stop tripping2. Set slips with TJ above rotary3. Stab full opening safety valve 4. Flow check5. Call Rig Superintendent and Comapany Representative

Well Stable1. Run pipe back to bottom2. Close annular3. Make up TDS and circulate bottoms up at SCR through open choke 4. If required adjust choke to keep DP pressure constant

Well Flowing1. Close full opening safety valve2. Close annular3. Open upper choke line HCR and valve upstream of choke 4. Monitor pressure5. Decide on well control procedure (possibly stripping)If unable to stab full opening safety valve

1. Make up TDS2. Close annular3. Open upper choke line HCR valve 4. Monitor pressure5. Decide on well control procedure

SBR

PR

VBR

DURING LOGGING1. Two Way Communications between driller and loggers

functional2. Wireline Cutter available at drillers console3. Drill Pipe with Dart Sub and full opening safety valve ready to

stab4. Trip tank pumps running5. Ready to monitor trip tank

Note: 7- 46NTXS 0.464” cable 1000 m = 0.109 m37- 46NTXSS 0.464” cable 1000 m = 0.109 m37- 48ZXXS 0.479” cable 1000 m = 0.116 m3

This volume valid for Schlumberger cableIF THE WELL GIVES ANY INDICATIONS OF THE FOLLOWING

WELL CONTROL WHILST LOGGING

11/03/2004 DKF/DRL/MTH& DKF/DRL/TTH

1. Well fill up anomaly2. Increase in return flow3. Pit level increase Perform the following procedures1. Stop logging2. Shut off trip tank pump3. Monitor well on trip tank4. Call Rig Superintendent and Company Representative

If well is stable1. Pull logging tool out slowly2. Run DP to bottom3. Circulate bottoms up4. Circulate last 1000m through the degasser

If well is flowing1. Close annular (low pressure)2. Lower sheave to slack off line3. Prepare to cut line

If Annular leaking with wire in the well1. Try increasing control pressure2. If still leaking cut cable3. Reduce pressure on annular to release cable4. Close shear rams5. Bleed off pressure above shear rams6. Open annular, ensure all HCR valves are closed7. Run DP with dart sub and full opening savety valve to below annular8. Close annular on DP9. Line up line below shear rams through the choke and monitor pressure10.Decide on well control method

SBR

PR

VBR

Directional Well Types

Vertical Type Slant (J) Type

“S” Type Horizontal Type

DRILLING PRACTICES

DIRECTIONAL DRILLING

DEFLECTION TECHNIQUES

The main techniques for deflecting a well are:

• WHIPSTOCKS

• JETTING

• ROTARY DRILLING

• MOTORS

DRILLING PRACTICES


Whipstocks

Typical Bottom trip style Whip stock

DIRECTIONAL CONTROL WITH ROTARY SYSTEMS

• RATE OF PENETRATION

Historically, it has always been possible to control the inclination of directional wells during rotary drilling by correct assembly design and the use of appropriate drilling parameters. Azimuth control, however, has always been difficult.

Trajectory is affected by the following parameters:• GAUGE AND PLACEMENT OF STABILISERS• DIAMETER AND LENGTH OF DRILL COLLARS

• WEIGHT ON BIT• ROTARY SPEED• BIT TYPE

• FORMATION ANISOTROPY (PROPERTIES VARY HORIZONTALLY/VERTICALLY) AND DIP ANGLE OF THE BEDDING PLANES

• FORMATION HARDNESS• FLOW RATE

DRILLING PRACTICES


GAUGE AND PLACEMENT OF STABILISERSThe gauge and placement of stabilisers, combined with drilling parameters, has a marked effect on the ability of a rotary assembly to build, drop or hold inclination. There are three fundamental principles:• FULCRUM PRINCIPLE

• STABILISATION PRINCIPLE

• PENDULUM PRINCIPLE

FULCRUM PRINCIPLE

WEIGHT

RESULTANT FORCE AT BIT

SIDE FORCE AT BIT

SIDE FORCE AT STABILISER

(PIVOT POINT)

FULL GAUGE NEAR BIT

STABILISER

FULCRUM

PIVOT POINT

An assembly with a full gauge near bit stabiliser and 40 ft – 120 ft of drill collars before the next stabiliser will build angle when weight is applied.

DRILLING PRACTICES


STABILISATION PRINCIPLE

BIT

FULL GAUGE NB STABILISER

SHORT DRILL COLLAR

FULL GAUGE STRING STABILISER

DRILL COLLAR


DRILL COLLAR

A

B

CB

A

B

A

PACKED ASSEMBLY FORCES BIT TO DRILL A REASONABLY STRAIGHT HOLE

DRILLING PRACTICES


PENDULUM PRINCIPLE

BIT


DRILL COLLAR


DRILL COLLAR

WOB

WEIGHT

EXCESSIVE WOB MAY CAUSE BUILD

DRILLING PRACTICES


BIT TYPE

No effect on build, hold or drop angle.Will tend to “walk” to the right.

Short toothed bits in hard formations, much lesser tendency to walk to the right.

Low weight on bit and high rotary speeds produce little “walk” tendency.

They do have an effect on hole angle.

DRILLING PRACTICES


FORMATION ANISOTROPY

UNEQUAL CHIP VOLUMESBEDDING PLANE

DIP ANGLE = < 45o up dip> 45o down dip

5000

5000

2500

2500

0

1000

1000

500

5000

Up-dip

Down-dip

Fd Deviation force (N)

Fd Deviation force (lbs)1

530

45

60

70

Fd

DRILLING PRACTICES


BIT WALK TENDENCIES

Less than 45o up dipGreater than 45o

down dip

Direction required is right of down dip

direction.

Direction required is left of down dip

direction.

Bit tends to walk left

Bit tends to walk right

Direction required is left of up dip

direction.

Bit tends to walk right

Bit tends to walk left

Direction required is right of up dip

direction.

DRILLING PRACTICES


FORMATION HARDNESS

SOFT FORMATIONS

REDUCE NOZZLE VELOCITY

CONNECTIONS

DROPPING EFFECT

HARD FORMATIONS

BHA’s BEHAVIOUR

ASSEMBLY DROP

DRILLING PRACTICES


What is Rotary Steerable Drilling? Allows controlled directional drilling to be performed while drilling entirely in the rotary drilling mode (as opposed to conventional slide drilling and by Controlling from Surface ). 2D Rotary Steerable – “Adjustable Stabilisers”- allow some small control in inclination only while rotating. 3D Rotary Steerable – This is what most people are referring to

when discussing “Rotary Steerable” technology.

RSS - Rotary Steerable System.

RSS BHA

RSS Advantages: - Better Borehole Quality (Hole Cleaning,Wellbore Path - Faster Drilling (ROP, Motor Orientation) - More Accurate Well Placement. - Better 3-Dimensional Trajectory Control . - Less Well CostRSS Type ( Method of Steering ) : - Push The Bit (Side force applied to the bit to increase

side cutting action). - Point The Bit (The bit is tilted relative to the rest of the

tool to achieve the desired trajectory)

PushThe Bit Technology – Powerdrive Xtra

•

Actuator

Actuator

Stationary control valve

Stationary control valve

RIGHT TURN

BUILD

The pad gives lateral force to the borehole, thus deviates the hole in the direction requested.

Direction of Pad displacement

Control Shaft, mechanically

linked to Control Shaft

Bias direction = “Tool Face”

Disc Valve rotation

Rotary Steerable System – Schlumberger.

Principle of Operation

• Side force or Push-the-Bit tool• Pads extend dynamically from a

rotating housing• Compact and Logistically Simple

PowerDrive BHA – Controlling Factors

Control variables Bit characteristics Stabilizer gauge Flex characteristics Hydraulics* (600-800 psi Delta P below

tool)

PowerDrive - Bias Unit

Actuators apply lateral force to the bit while rotating at bit speed

3 pads driven by hydraulic actuators

RSS BHA (Schlumberger) PushThe Bit Technology – Powerdrive Xtra

Bias Unit

Control Unit

Control Unit Bias Unit

Steering Actuator PadTurbine

RSS BHA (Halliburton)

• Rotating Shaft is deflected in center between bearings with dual eccentric cams

• Results in bit tilt in opposite direction

Point The Bit Technology - Geopilot

RSS BHA (Halliburton)

Shaft

Cantilever Bearing prevents shaft from bending above it. Focal Bearing

Allows Bit To Tilt

Eccentric Rings Bend Shaft

Drill Bit Tilts inOpposite Direction of

BendCreating a Toolface

Operation Principal

AutoTrak® Steering Unit(G2.5 & G3.0 systems)

• Reliability– Redundant rib design– Mud Cooled Bearings– No Rotating Seals– No Reciprocating

Dynamic Seals • Steering Precision

– Closed loop steering control

– Closed loop rib pressure control

– High accuracy near bit inclination

• Versatility– Modular design– Local Maintenance

Non-Rotating Sleeve

Steering Ribs & associated hydraulic systems

Baker Hughes Inteq.

Integrated BHA Concept

RotationalDensitiy

Caliper CorrectedNeutron (Porosity)

Acoustic Properties eXplorer

AutoTrakX-treme Motor

Two-way Telemetry Unit

Directional Vibration

Gamma RayResistivity

AnnularPressure

CSDPTesTrak

Formation Pressure Tester

Near Bit InclinationSteering Unit

Integrated RS and LWD System.

THANK YOU

drilling presentasion bojonegara.pptx

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