For coring operation, the ton-miles calculation is also expressed in terms of work in round trip ton-miles. In order to determine the coring ton-miles, you need to figure out ton-miles for one round trip at the depth where coring stopped minus ton-miles for one round trip at the depth where coring began and the multiplied that value by 2.

The formula for calculating ton-mile for coring operation is shown below;

Tc = 2 x (T4 – T3)

Where;

Tc = ton-miles for coring operation
T4 = ton-miles for one round trip at depth where coring operation stopped before coming out of hole
T3 = ton-miles for one round trip at depth where coring get started

Example – Please determine coring ton-mils from 8000 ft to 8050 ft.

Ton-miles @ 8050 ft (end of coring operation) = 200
Ton-miles for trip @ 8000 ft (start of coring operation) = 190

Tc = 2 x (T4 – T3)
Tc = 2 x (200 – 190)
Tc = 20 ton-miles

Referencer book:

Formulas and Calculations for Drilling, Production and Workover, Second Edition

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Drilling or Connection ton-miles is  ton-miles of work in drilling operations. These are the actual ton-miles of work in drilling down the length of a section of drill pipe, usually around +/- 31 ft, plus picking up, connecting, and starting to drill again. In order to figure out connection or drilling ton-miles, it takes 3 times of ton-miles for current round trip minus ton-miles for previous round trip. The formula for calculating drilling ton mile is listed below;

Td = 3 x (T2 – T1)
Where;
Td = Ton-miles for drilling
T2 = Ton-miles for one round trip of last depth before coming out of hole.
T1 = Ton-miles for one round trip of first depth that drilling is started.

Example;
Please determine drilling tome-miles from 8000 ft to 9000 ft.
Ton-miles for trip @ 9000 ft = 230
Ton-miles for trip @ 8000 ft = 195
Td = 3 x (T2 – T1)
Td = 3 x (230 – 195)
Td = 3 x 35
Td = 105 ton-miles
Download the Excel sheet for calculating drilling or connection ton-mile.

Referencer book:

Formulas and Calculations for Drilling, Production and Workover, Second Edition

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1. Round trip ton-miles
2. Drilling or “connection” ton-miles
3. Coring ton-miles
4. Ton-miles setting casing
5. Short-trip ton-miles

For this time, I will show how to calculate round trip ton-mile.

Round Trip Ton-Miles Calculation

The formula for round trip ton-miles is listed below;

RTTM = (Wp x D x (Lp + D) + (2 x D) x (2 x Wb + Wc)) ÷ (5280 x 2000)

where
RTTM = Round Trip Ton-Miles
Wp = buoyed weight of drill pipe in lb/ft
D = hole measured depth in ft
Lp = Average length per stand of drill pipe in ft
Wb = weight of travelling block in lb
Wc = buoyed weight of BHA (drill collar + heavy weight drill pipe + BHA) in mud minus the buoyed weight of the same length of drill pipe in lb
** If you have BHA (mud motor, MWD, etc) and HWDP, you must add those weight into calculation as well not just only drill collar weight. **
2000 = number of pounds in one ton
5280 = number of feet in one mile

Example: Round trip ton-miles

Mud weight = 10.0 ppg
Average length per stand = 94 ft
Drill pipe weight = 13.3 lb/ft
Hole measure depth = 5500 ft
Drill collar length = 120 ft
Drill collar weight = 85 lb/ft
HWDP length = 49 lb/ft
HWDP weight = 450 ft
BHA weight from directional driller = 8,300 lb
BHA length = 94 ft
Travelling block assembly = 95,000 lb

Solution:

a) Buoyancy factor:
BF = (65.5 – 10.0) ÷ 65.5
BF = 0.847

b) Buoyed weight of drill pipe in mud, lb/ft (Wp):
Wp = 13.3 lb/ft x 0.847
Wp = 11.27 lb/ft

c) buoyed weight of BHA (drill collar + heavy weight drill pipe + BHA) in mud minus the buoyed weight of the same length of drill pipe in lb (Wc):

Wc = {[(120x85) + (49x450) + (8300)] x 0.847} – [(120+450+94) x13.3x 0.847]
Wc = 26,866 lb

Round trip ton-miles = [(11.27 x 5500 x (94+ 5500)) + (2 x 5500) x (2 x 95000 + 26,866)] ÷ (5280 x 2000)
RTTM = 258.75 ton-mile

Please find the excel sheet for round trip ton-miles calculation via click this link.

Referencer book:

Formulas and Calculations for Drilling, Production and Workover, Second Edition

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When drilling line is spooled on and off a drawworks drum during operation as drilling a well, running casing, coring, etc.The drilling line get worn out; therefore, drilling contractors must cut old section and replace with new section of drilling line at specific period based on ton mile calculation.

The most worn area is the end of drilling line where is constantly spooled over the draw works drum. A section of drilling line, typically around 100 ft, is cut then the drilling line is re-attached to the draw works drum and the amount cut off is spooled back on the drum. This operation is called “slip and cut drilling line”.

Note: Ton-mile is the important figure that must be recorded correctly. However, the most important is to visually inspect drilling line all time to see if there is any worn out wire. If you see the worn out line, you need to cut the drilling line even though the drilling line does  not reach ton-mile limit yet.

All types of ton-mile service should be calculated and recorded in order to obtain a true picture of the total service received from the rotary drilling line. There are several types of ton miles as follows;

1. Round trip ton-miles
2. Drilling or “connection” ton-miles
3. Coring ton-miles
4. Ton-miles setting casing
5. Short-trip ton-miles

Ref:  A Primer of Oilwell Drilling: A Basic Text of Oil and Gas Drilling

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Ref: Slb.com

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 : )

Ref: Casing And Liners for Drilling And Completion

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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.

Reference: Formulas and Calculations for Drilling, Production and Workover, Second Edition

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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

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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: Drilling Engineer Books

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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.

Ref: Drilling Fluids Books

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Density: Mud density is the weight per unit volume of mud and normally it is reported in Pound Per Gallon (PPG). Mud density is used for providing hydrostatic pressure to control well for drilling operation.

Viscosity: It is defined as the internal resistance of fluid flow. There are 2 types of viscosity which are Funnel Viscosity and Plastic Viscosity.

1) Funnel Viscosity: It is time, in seconds for one quart of mud to flow through a Marsh funnel which has a capacity of 946 cm3 (See Figure 1). A quart of water exits the funnel in 26 seconds. This is not a true viscosity, but serves as a qualitative measure of how thick the mud sample is. The funnel viscosity is useful only for relative comparisons.

Figure 1 Marsh Funnel

2) Plastic Viscosity (PV): A parameter of the Bingham plastic rheological model (See Figure 3). PV is the slope of the shear stress-shear rate plot above the yield point (See Figure 4). Viscometer is equipment to measure Plastic Viscosity (See Figure 2). Plastic Viscosity is derived from the 600 rpm reading minus the 300 rpm reading and PV is in centipoises (cp). A low PV indicates that the mud is capable of drilling rapidly because of the low viscosity of mud exiting at the bit. High PV is caused by a viscous base fluid and by excess colloidal solids. To lower PV, a reduction in solids content can be achieved by dilution.

There are many rheology models shown in Figure 3. Normally Bingham Plastic Model is used to describe mud properties as Plastic Viscosity and Yield Point (See Figure 4).

Figure 2 Viscometer

Figure 3 Rheology Model

Figure 4 Bingham Plastic Model describes PY and VP

Yield Point: Physical meaning is the resistance to initial flow, or the stress required starting fluid movement. The Bingham plastic fluid plots as a straight line on a shear-rate (x-axis) versus shear stress (y-axis) plot, in which YP is the zero-shear-rate intercept (PV is the slope of the line). YP is calculated from 300-rpm and 600-rpm viscometer dial readings by subtracting PV from the 300-rpm dial reading and it is reported as lbf/100 ft2. YP is used to evaluate the ability of mud to lift cuttings out of the annulus. A higher YP implies that drilling fluid has ability to carry cuttings better than a fluid of similar density but lower YP.

Gel Strength: It is the ability of fluid to suspend fluid while mud is in static condition. Before testing gel strength, mud must be agitated for awhile in order to prevent precipitation and then let mud is in static condition for a certain limited time (10 seconds, 10 minutes or maybe 30 minutes) and then open the viscometer at 3 rpm and read the maximum reading value. In a morning report, there are 3 values of gel strength, which are Gel 10sec (lbf/100 ft2), Gel 10 mins (lbf/100 ft2) and Gel 30 mins (lbf/100 ft2).

Ph: This value tells the acid of drilling fluid. Ph paper is used to measure Ph.

Electrical Stability (ES): This value reflects to the stability of emulsion of SDF. If water disperses well in oil phase (good emulsion), the resistivity of drilling fluid will be higher. In contrast, if water disperses badly in oil phase (bad emulsion), the resistivity of drilling fluid will be lower. As the concept above, applied Ohm’s law (V=IR), electricity from the electrical stability meter is emitted in to mud and voltage is measured by the electrical probe. Normally if the measured voltage is higher than 500 volt, the electrical stability is good.

Figure 5 Electrical Stability Meter

CaCl2 Concentration: Cl+ can prevent formation swell hence this value must be maintained. It is measured by a titration test by using silver nitrate as titrant with potassium chromate as the endpoint indicator and when titration reaches the equilibrium point mud will change into red.

Retort Test: There are 2 values that are Saraline Water Ratio (SWR) and Solid Content (LGS, Barite) obtained from this testing. Mud is retorted in retort test skid at 950 F for 2 hrs. High temperature can vaporize liquid phase into gas phase and then gas phase will be transferred to a condenser and condense in liquid form. Liquid is stored in a tube that has a level indicator to see how much of water and oil (saraline) extracted. Moreover, solid left in the retort reflects the solid content in mud.

Figure 6 Retort Test Skid

HTHP Fluid Loss: This test is conducted for testing fluid loss behavior of mud. Mud is pressed through filter paper located in the HTHP filter press at 300 F with differential pressure at 500 psi for 30 mins. Thickness of filter cake stuck in filter paper should be less than 2 ml.

Figure 7 HTHP filter press

Ref: Drilling Fluids Books

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