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Working in the oil field and loving to share knowledge.

What factors must be considered when designing a casing/tubing string?

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Casing and tubing selection are one of the critical tasks that engineers must carefully decide which type of casing/tubing will be used in the wellbore in order to meet the objective of each well.  I would like to share my knowledge about the selection criteria for casing/tubing string design.

Oilfield Tubing

Oilfield Tubing

The factors must be contemplated when designing a casing and/or tubing string as listed below;

• Reservoir fluid type (oil, gas, or combine)
• Depth of casing and tubing string
• Formation Pressure gradient and fracture gradient
• Reservoir temperature
• How much reserves of reservoir
• How long of production life of wells
• Economic consideration
• Strategy of completion technique as conventional completion, monobore completion, monobore horizontal completion, etc.
• Production plan as production rate, how plateau rate be maintained, secondary recovery plan, etc.
• Bottom hole reservoir pressure and expected surface pressure during future production plan
• Level of sour gas as H2S and CO2
• Hydrocarbon zones are required to be covered by cement
• Tubing size needed to achieve production and stimulation plan
• Artificial lift equipment requirements
• Future workover plan
• Physical property of material
• Clearances needed for fishing
• Type of connection

If you have any more considerations, please feel free to share : )


What is slug mud? How much volume and weight of slug mud should be?

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Slug Mud: It is heavy mud which is used to push lighter mud weight down before pulling drill pipe out of hole. Slug is used when pipe became wet while pulling out of hole.

Normally, 1.5 to 2 PPG over current mud weight is a rule of thumb to decide how much weight of slug should be. For example, current mud weight is 10 PPG. Slug weight should be about 11.5 to 12 PPG.

Normally, slug is pumped to push mud down approximate 200 ft (+/2 stands) and slug volume can be calculated by applying a concept of U-tube (see a figure below)

Volume of slug can be calculated by this following equation:

This equation expresses that the higher slug volume, the deeper of dry in drill pipe is met. As per the above equation, length of dry pipe can be substituted by 200 ft.

In normal practice, slug volume pumped to clean drill pipe is around 15-25 bbl depending on drillpipe size. Moreover, it also depends on situations because sometime mud in annulus side may be heavier than measured MW due to cutting, drilling solid contaminated in mud, hence more slug volume is needed.

Ref books: 

Lapeyrouse, N.J., 2002. Formulas and calculations for drilling, production and workover, Boston: Gulf Professional publishing.

Bourgoyne, A.J.T., Chenevert , M.E. & Millheim, K.K., 1986. SPE Textbook Series, Volume 2: Applied Drilling Engineering, Society of Petroleum Engineers.

Mitchell, R.F., Miska, S. & Aadny, B.S., 2011. Fundamentals of drilling engineering, Richardson, TX: Society of Petroleum Engineers.

Drilling Mud Motor Concerns and Practices

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I got some questions from Mike R Hogolan regarding mud motor concerns. The questions are very interesting and I would like to share some answers to you all as well.

Why is it more difficult to steer a motor the deeper section of wellbore?

It is harder to steer the motor when well is deeper because the friction exerted from formation to drillstring in open hole section increases. Motor cannot be effectively used to drilled deeper along all well path because high friction force exerted on BHA, higher temperature as well deeper can cause rotor, made of synthetic rubber, failure.

Why is the most effective steering by using the pump pressure gauge rather than the weight indicator?

Driller will use the pump pressure gauge as opposed to the weight indicator because WOB is not accurate while steering. High friction force between drillstring and formation is created when steering. If there are consistent circulating mud properties, flow rate and formation characteristics should be within the normal motor operating range, an increase or decrease in weight on bit will result in a directly proportional increase or decrease in pump pressure.

What is meant by stalling a motor?
Stalling motor means that steerable motor stalls at bottom hole (can not rotate) because of higher WOB, harder formation, not enough torque to turn the bit, etc. When motor stalling, stand pipe pressure increases significantly and ROP significantly drops.

What are indicators a motor is wearing out?
Indicators demonstrate a motor worn out as follows:
• Lower ROP without any changes of parameter on surface
• Difficult to control well direction as per designed well trajectory
• Increase in pump pressure
• Easily motor stall

Reference books: Directional Drilling Books

What are the differences between steering (orienting or sliding) and rotating?

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Steering (orienting or sliding) is drilling with mud downhole steerable mud motor. Drilling with the steerable motor does not rotate drill pipe because it uses hydraulic power to drive down hole motor and bit. Steering is used in order to control well direction.

Rotating is drilling with Topdrive or rotary table and drillstring is rotated in order to gouge the hole. Rotary drilling will be used when straight hole direction is needed.

Comparing between steering and rotating, steering can create dog leg more than rotating because mud motor incorporating with bend housing is designed to directionally drill to the specified direction; however, when Rotating, BHA is stiffer and has tendency to hold the direction.

Rotating ROP is always faster than steering ROP by these following reasons:
• Friction force exerts on stable drill string when steering is always more than rotating.
• When steering, WOB is limited. Motor can be stalled or worn out if WOB excesses.
• Direction of well must be controlled carefully that means well can not be drilled faster.

Reference books: Directional Drilling Books

What is the difference between drill solids and barite?

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Learn the difference between drill solids and barite and how these 2 kinds of weighting material will affect drilling operation.

Drill Solid: It is solid particles from formation generated while drilling. Its specific gravity is about 2.6 which is normally defined as Low Gravity Solid (LGS). Drill solid can increase mud weight; however, it will degrade mud properties such as Yield Point, viscosity, gel strength, etc. If mud excessively gets drill solid, drilling fluid properties especially rheology (Yield Point, viscosity) will be higher and mud cake with a lot of drill solid will be poor quality. Higher rheology will lead to more required energy in order to make circulation. In addition, poor mud cake can also lead to pipe struck situation.

In order to control drill solid content in mud, solid control equipment as shale shakers, desanders, desilters and centrifuges must be operated properly and effectively.

Barite: It is the weighting agent with specific gravity about 4.2 normally called High Gravity Solid. Both Drill solid and Barite are able to be weighting agent; however, Barite does not degrade other mud properties such as PV, YP, gel strength, etc.

Reference books: Drilling Fluid Books