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The E*C TRAK Torque and Drag Module

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The E*C TRAK Torque and Drag Module
This program, developed at the Drilling Research Center in Celle,
Germany, is used to calculate torque and drag when a friction factor
(coefficient of sliding friction) is known or estimated. It will calculate the
friction factor when either torque or hookload is known.
Software accuracy has been verified against actual field data, with inputs
and outputs handled in user selected units.
General Uses
The program may be used to:
• Optimize well path design for minimum torque and drag
• Analyze problems either current or post-well
• Determine drillstring design limitations
• Determine rig size requirements
Inputs Required
• Drillstring component data (OD, ID, tool joint, and material
composition)
• Survey data (actual or planned)
• Friction factor(s) or actual hookload or torque values (for friction
factor calculation)
Outputs
Information concerning loads, torques and stresses are calculated for
discrete points in the drillstring from rotary table to the bit. These values
are output in both tabular (summary or detailed) and graphical formats:
• Drag load (pick-up or slack-off)
• Pick up load
• Slackoff load
• Rotating off bottom load
• Drilling load
• Rotating off bottom torque
• Rotary torque (drilling and off-bottom)
• Maximum allowable hook load (at minimum yield)
• Drillstring weight (in air)
• Bit to neutral point distance drillstring twist
• Drillstring twist
• Axial stress
• Torsional stress
• Bending stress
• Total equivalent stress

Cement Additives

Accelerators

An accelerator is a chemical additive used to speed up the normal rate of reaction between cement and water which shortens the thickening time of the cement, increase the early strength of cement, and saves time on the drilling rig. Cement slurries used opposite shallow, low-temperature formations require accelerators to shorten the time for "waiting-oncement". Most operators wait on cement to reach a minimum compressive strength of 500 psi before resuming drilling operations. When using accelerators, this strength can be developed in 4 hours. It is a good practice to use accelerators with basic cements because at temperatures below 100oF, neat cement may require 1 or 2 days to develop a 500 psicompressive strength.

Common accelerators are sodium metasilicate, sodium chloride, sea water, anhydrous calcium chloride, potassium chloride and gypsum.

Retarders

Neat cement slurries set quickly at a BHT greater than 110oF. A retarder is an additive used to increase the thickening time of cements. Besides extending the pumping time of cements, most retarders affect the viscosity to some degree. The governing factors for the use of retarders are temperature and depth. Common retarders are lignosulfonates, modified cellulose, organic acids, organic materials and borax.

Extenders

Extended cement slurries are used to reduce the hydrostatic pressure on weak formations and to decrease the cost of slurries. Extenders work by allowing the addition of more water to the slurry to lighten the mixture and to keep the solids from separating. These additives change the thickening times, compressive strengths and water loss. Common extenders are fly ash, bentonite, and diatomaceous earth.

Pozzolans

Pozzolans are natural or artificial siliceous materials added to portland cement to reduce slurry density and viscosity. The material may be either a volcanic ash or a clay high in silica. The silica in the pozzolans combines with the free lime in dry cement, which means a soluble constituent is removed from the cement and the new cement is made more resistive. Common pozzolans are diatomaceous earth and fly ash.

Cementing Nomenclature

Casing Centralizers

Centralizers assist in the removal of filter cake and displacement of drilling fluid by providing a more uniform flow path for the cement slurry. Close scrutiny of the mudlog and wireline logs will help in the placement of centralizers. Zones of increased permeability, doglegs and areas of key seating, should have centralizers placed around the casing

Wall Scratchers

These are most useful when running casing through a high fluid-loss drilling fluid. There are two types of wall scratchers, rotating scratchers used when the casing can be rotated (normally in vertical wells), and reciprocating scratchers used when the pipe is reciprocated (moved up and down). When these scratchers are placed in 15 to 20 foot intervals, overlapping cleaning occurs.

Wiper Plugs

Both top and bottom plugs are used during cementing operations. They are used to separate the various fluids from one another. The red bottom plug has a shallow top, is made of rubber, and has a hollow core. It is used ahead of the cement slurry to prevent cement/drilling fluid contamination and to clean the casing wall of filter cake. After the bottom plug comes into contact with the float valve, sufficient pressure (150 to 350 psi) causes the top diaphragm to rupture, allowing the cement slurry to

flow through it. The black top plug has a deep cup on its top and has a solid, molded rubber core. It is dropped after the cement slurry has been pumped, to prevent contamination with the displacement fluid. The top plug also signals the end of displacement by forming a seal on top of the bottom plug, causing a pressure increase.

Chemical Washes

Chemical washes are fluids containing surfactants and mud thinners, designed to thin and disperse the drilling fluid so that it can be removed from the casing and borehole. Washes are available for water-based and oil-based drilling fluids. They are designed to be used in turbulent flow conditions.

Spacers

Spacers are fluids of controlled viscosity, density and gel strength used to form a buffer between the cement and drilling fluid. They also help in the removal of drilling fluid during cementing.

Removal of the Drilling Fluid

Removal of the Drilling Fluid
For cementing operations to be successful, all annular spaces must be filled with cement, and the cement properly bonded to the previous casing and formation. In order for this to occur, all the drilling fluid must be displaced by the cement slurry. This is not always an easy matter, because there are several factors which affect the removal of the drilling fluid:

• washouts in the open hole, making it difficult to remove drilling fluid and filter cake
• crooked holes, making casing centralization difficult and drilling fluid not being removed from the low side
• poorly treated drilling fluids having high fluid losses Good drilling practices will not assure a good cement job, but they may help prevent a failure. The ideal drilling fluid for cementing operations should have:

• a low gel strength, with low PV and low YP
• a low density
• a low fluid loss
• a chemical make-up similar to the cement

Since these conditions are very seldom met, fluid washes and spacers are usually pumped ahead of the cement to remove as much drilling fluid as possible.

Cement Slurries

Water is added to dry cement to cause hydration and to make a pumpable

slurry. To be used correctly, several properties must be known: the yield per unit (cubic feet per sack), the amount of water required (gallons per sack), and its density (pounds per gallon).

Another important parameter is the cements “absolute volume”. This is the actual volume occupied by the material (the bulk volume includes the open spaces between the cement particles). For example, one sack (94 lbs) of cement has a bulk volume of 1 ft3, but if all the open spaces between the particles were removed, the absolute volume would be 0.478 ft3.

With dry materials (cement and additives), the absolute volume is used along with the water requirements to determine the slurry. For example, the absolute volume of one sack of cement (0.478 ft3) plus the water volume (5.18 gal/sk or 0.693 ft3) yields a slurry volume of 1.171 ft3 (0.478 +

0.693).

The absolute volume of the cement's components are normally found in tables, but may be calculated using:

For components that dissolve in water (sodium chloride, etc.), since they do not occupy as much space as the specific gravities would indicate, the absolute volume is determined from experimental data and placed. Slurry density is also determined. Since one sack of cement weighs 94 lbs, and 0.693 ft3 of water weighs 43.2 lbs, when mixed they yield 137.2 lbs of slurry. The slurry's density is then calculated by dividing slurry weight by slurry volume, 137.2 lbs / 1.171 ft3 equals 117.1 lbs/ft3 (15.7 ppg). Yield is converted to cubic feet per sack by using the constant 7.4805 (62.4

lbs/ft3 / 8.34 lbs/gal).

Fly ash, a synthetic pozzolan, is another major constituent of cements. A fly ash/cement mixture is designated as the ratio of fly ash to cement (expressed as 50:50 or 60:40, etc.) with the total always equaling 100. The first number is the percentage of fly ash (74 lbs/sack), the second number is cement (94 lbs/sack). A sack of fly ash and a sack of cement have the same absolute volume.

If other additives are included (gel, accelerators, retarders, etc.), the mixture is expressed as a percentage of weight of both cement and fly ash. The slurry is then expressed: 50:50:2% gel

Cementing Introduction

Cementing
Introduction

Oil well cementing is the process of mixing and displacing a slurry down the casing and up the annulus, behind the casing, where is allowed to “set”, thus bonding the casing to the formation. Some additional functions of cementing include:

• Protecting producing formations
• Providing support for the casing
• Protecting the casing from corrosion
• Sealing off troublesome zones
• Protecting the borehole in the event of problems

The main ingredient in most cements is “Portland” cement, a mixture of limestone and clay. This name comes from the solid mixture resembling the rocks quarried on the Isle of Portland, off the coast of England.

All cement is manufactured in essentially the same way. Calcareous and argillaceous materials (containing iron and aluminum oxides) are finely ground and mixed in correct proportions, either in a dry condition (dry processing) or with water (water processing). The mixture is then fed into the upper end of a sloping kiln at a uniform rate. The kiln is heated to temperatures from 2600o to 3000oF. As the mixture falls to the lower end, the mixture melts and chemical reactions occur between the raw materials.

When the mixture cools, it is called “clinker”. The clinker is then ground with a controlled amount of gypsum (1.5 to 3.0% by weight), to form portland cement.

The principle compounds resulting from the burning process are Tricalcium Silicate (C3S), Dicalcium Silicate (C2S), Tricalcium Aluminate(C3A), and Tetracalcium Aluminoferrite(C4AF). contains more information on the properties of these compounds. These materials are in an anhydrous form. When water is added, they convert to their hydrous form, which is then called a “cement slurry”.
The American Petroleum Institute (API) has established a classification system for the various types of cements, which must meet specified chemical and physical requirements. classifications and their applications to depths of 16,000 ft. (4880 m), under various temperature and pressure conditions.

Casing Couplings

Couplings are short pieces of casing used to connect the individual joints. They are normally made of the same grade of steel as the casing. Through their strength can be different than the casing. The API has specifications for four types of couplings.

• Short round threads and couplings (CSG)

• Long round threads and couplings (LCSG)

• Buttress threads and couplings (BCSG)

• Extremeline threads (XCSG)

The CSG and LCSG have the same basic thread design. The threads have a rounded shape, with eight threads per inch. These threads are generally referred to as API 8-round. The only difference between the two is that the LCSG has a longer thread run-out, which offers more strength for the connection. LCSG are very common couplings.

Buttress (BCSG) threads are more square, with five threads per inch. They are also longer couplings, with corresponding longer thread run-out. The XCSG (Extremeline) couplings are different from the other three connectors in that they are integral connectors, meaning the coupling has both box and pin ends.

Coupling threads are cut on a taper, causing stress to build up as the threads are made up. A loose connection can result in a leaking joint. An over-tight connection will result in galling, which again, will cause leaking. Proper make-up is monitored using torque make-up tables and the number of required turns.

A special thread compound (pipe dope) is used on casing couplings, each type of coupling having its own special compound. Many companies have their own couplings, in addition to the API standards, which offer additional features not available on the API couplings.

Casing properties

Casing properties are defined as:

• Yield Strength: The tensile stress required to produce a total elongation of 0.5% per unit length

• Collapse Strength: The maximum external pressure or force required to collapse the casing joint

• Burst Strength: The maximum internal pressure required to cause a casing joint to yield

Casing dimensions are specified by its outside diameter (OD) and nominal wall thickness. Normal wellsite conventions specify casing by its OD and weight per foot. As stated earlier, one should specify which weight one is referring to, though most often it is the nominal weight.

Casing Standards

Casing Standards

The American Petroleum Institute (API) has developed certain standards and specifications for oil-field related casing and tubing. One of the more common standards is weight per unit length. There are three “weights” used:

• Nominal Weight: Based on the theoretical calculated weight per foot for a 20 ft length of threaded and coupled casing joint.
• Plain End Weight: The weight of the joint of casing without the threads and couplings.
• Threaded and Coupled Weight: The weight of a casing joint with threads on both ends and a coupling at one end.

The Plain End Weight, and the Threaded and Coupled Weight are calculated using API formulas. These can be found in API Bulletin 5C3. API standards include three length ranges, which are:

• R-1: Joint length must be within the range of 16 to 25 feet, and 95% must have lengths greater than 18 feet
• R-2: Joint length must be within the range of 25 to 34 feet, and 95% must have lengths greater than 28 feet
• R-3: Joint length must be over 34 feet, and 95% must have lengths greater than 36 feet.

The API grade of casing denotes the steel properties of the casing. The grade has a letter, which designates the grade, and a number, which designates the minimum yield strength in thousands of psi.

Casing - liner

Liner

A liner is a string of casing that does not reach the surface. They are usually “hung” (attached to the intermediate casing using an arrangement of packers and slips) from the base of the intermediate casing and reach to the bottom of the hole. The major advantage of a liner is the cost of the string is reduced, as are running and cementing times. During the course of the well, if the liner has to be extended to the surface (making it another string of casing), the string attaching the liner to the surface is known as a “tie-back” string.

Casing - Production Casing

Production Casing

Production casing is usually the last full string of pipe set in a well. These strings are run to isolate producing formations and provide for selective production in multi-zone production areas. The size of production casing will depend on the expected production rate, the higher the barrel per day production rate, the larger the inside diameter of the pipe. Common sizes are between 3 and 7 inch (outside diameter).

Casing - Intermediate Casing

Intermediate Casing

Intermediate casing is set after surface casing, normally to seal off a problem formation. The size of intermediate casing, will depend on the size of the surface casing and the grade required to withstand the subsurface conditions. Normal sizes are between 9 5/8 and 13 3/8 inch (outside diameter).

Casing - Surface Casing

Surface Casing

The amount of surface casing used will depend on the depth of the unconsolidated formations. Surface casing is usually set in the first competent formation. Normal size for surface casing is between 20 inch and 13-3/8 inch (outside diameter). Since temperature, pressure and corrosive fluids tend to increase with depth, different grades of casing will be required to handle the different well conditions.

Purposes of surface casing are to:

• protect fresh water formations

• seal off unconsolidated formations and lost circulation zones

• provide a place to install the B.O.P.'s

• protect “build” sections on deviated wells

• provide for a sufficient “leak-off” test to be conducted

Casing - Conductor Casing

Conductor Casing

Conductor pipe or drive pipe if it is hammer-driven to depth, is the first string of casing to be used. The setting depth can vary from 10 ft to around 300 ft. The normal size range for conductor pipe is from 16 to 36 inches (outside diameter). The conductor pipe must be large enough to allow the other casing strings to be run through it. Purposes of conductor pipe are to:

• raise the level of circulating fluid so that fluid returns are possible

• prevent washouts in the near surface, normally unconsolidated formations

Casing

Casing has several important functions during the drilling and completing of a well. It is used to prevent the borehole from caving in during the drilling of the well, to provide a means of controlling fluids encountered while drilling, to prevent contamination of fluids to be produced, and to protect or isolate certain formations during the course of a well. Casing is also one of the most expensive parts of a well, around 20% of the cost of a completed well.

Casing is usually divided into five basic types.

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