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Determining depth to set casing
The first design task in preparing the well plan is selecting depths that the casing will be run and cemented.
- 1 Overview
- 2 Types of casing and tubing
- 3 Setting-depth design procedures
- 4 References
- 5 See also
- 6 Noteworthy papers in OnePetro
- 7 External links
- 8 Category
The drilling engineer must consider geological conditions such as:
- Formation pressures and fracture mud weights.
- Hole problems.
- Internal company policies.
- A variety of government regulations.
The program results should allow the well to be drilled safely without the necessity of building “a steel monument” of casing strings. Unfortunately, many well plans give significant considerations to the actual pipe design, yet give only cursory attention to the pipe setting depth.
The importance of selecting proper depths for setting casing cannot be overemphasized. Many wells have been engineering or economic failures because the casing program specified setting depths too shallow or deep. Applying a few basic drilling principles combined with a basic knowledge of the geological conditions in an area can help determine where casing strings should be set to ensure that drilling can proceed with minimum difficulty.
Types of casing and tubing
Drilling environments often require several casing strings to reach the total desired depth. Some of the strings are:
- Drive, or conductor.
- Intermediate (also known as protection pipe).
- Production (also known as an oil string).
- Tubing (flow string).
Fig. 1 shows the relationship of some of these strings. In addition, the illustration shows some problems and drilling hazards the strings are designed to control.
All wells will not use each casing type. The conditions encountered in each well must be analyzed to determine types and amount of pipe necessary to drill it. The general functions of all casing strings are listed next:
- Segregate and isolate various formations to minimize drilling problems or maximize production.
- Furnish a stable well with a known diameter through which future drilling and completion operations can be executed.
- Provide a secure means to which pressure-control equipment can be attached.
Drive pipe or conductor casing
The first string run or placed in the well is usually the drive pipe, or conductor casing. Depths range from 40 to 300 ft. In soft-rock areas such as southern Louisiana or most offshore environments, the pipe is hammered into the ground with a large diesel hammer. Hard-rock areas require that a large-diameter, shallow hole be drilled before running and cementing the pipe. Conductor casing can be as elaborate as heavy-wall steel pipe or as simple as a few old oil drums tacked together.
A primary purpose of this string is to provide a fluid conduit from the bit to the surface. Very shallow formations tend to wash out severely, and must be protected with pipe. In addition, most shallow formations exhibit some type of lost-circulation problem that must be minimized.
An additional function of the pipe is to minimize hole-caving problems. Gravel beds and unconsolidated rock may continue to fall into the well if not stabilized with casing. Typically, the operator is required to drill through these zones by pumping viscous muds at high rates.
Occasionally, drilling conditions will require that an additional string of casing be run between the drive pipe and surface casing. Typical depths range from 600 to 1,000 ft. Purposes for the pipe include solving additional lost-circulation or hole-caving problems and minimizing kick problems from shallow gas zones.
Surface Casing. Many purposes exist for running surface casing including:
- Cover freshwater sands.
- Maintain hole integrity by preventing caving.
- Minimize lost circulation into shallow, permeable zones.
- Cover weak incompetent zones to control kick-imposed pressures.
- Provide a means for attaching the blowout preventers.
- Support the weight of all casing strings (except liners) run below the surface pipe.
The primary applications of intermediate casing involve abnormally high formation pressures. Because higher mud weights are required to control these pressures, shallower weak formations must be protected to prevent lost circulation or stuck pipe. Occasionally, intermediate pipe is used to isolate salt zones or zones that cause hole problems, such as heaving and sloughing shales.
Drilling liners are used for the same purpose as intermediate casing. Instead of running the pipe to the surface, an abbreviated string is used from the bottom of the hole to a shallower depth inside the intermediate pipe. Usually, the overlap between the two strings is 300 to 500 ft. In this case, the intermediate pipe is exposed to the same drilling considerations as the liner (Fig. 1).
Drilling (and production) liners are used frequently as a cost-effective method to attain pressure or fracture-mud-weight control without the expense of running a string to the surface. When a liner is used, the upper exposed casing, usually intermediate pipe, must be evaluated with respect to burst and collapse pressures for drilling the open hole below the liner. Remember that a full string of casing can be run to the surface instead of a liner, if required (i.e., two intermediate strings).
The production casing is often called the oil string. The pipe may be set at a depth slightly above, midway through, or below the pay zone. The pipe has the following purposes:
- Isolate the producing zone from the other formations.
- Provide a work shaft of known diameter to the pay zone.
- Protect the production-tubing equipment.
The drilling liner is often used as part of the production casing rather than running an additional full string of pipe from the surface to the producing zone. The liner is tied back or connected to the surface by running the amount of pipe required to connect to the liner top. This procedure is particularly common when producing hydrocarbons are behind the liner and the deeper section is not commercial.
Setting-depth design procedures
Casing-seat depths are affected by geological conditions. In some cases, the prime criterion for selecting casing seats is to cover exposed, lost-circulation zones. In others, the seat may be based on differential-sticking problems, perhaps resulting from pressure depletion in a field. In deep wells, however, the primary consideration is usually based on controlling abnormal formation pressures and preventing their exposure to weaker shallow zones. This criterion of controlling formation pressures generally applies to most drilling areas.
Selecting casing seats for pressure control starts with knowing geological conditions, such as formation pressures and fracture mud weights. This information is generally available within some degree of accuracy. Prespud calculations and the actual drilling conditions determine the exact locations for each casing seat.
The principle used to determine setting-depth selection can be adequately described by the adage, “hindsight is 20/20.” The initial step is to determine the formation pressures and fracture mud weights that will be penetrated. After these have been established, the operator must design a casing program based on the assumption that he already knows the behavior of the well before it is drilled.
This principle is used extensively for infill drilling where the known conditions dictate the casing program. Using these guidelines, the operator can select the most effective casing program that meets the necessary pressure requirements and minimize the casing cost.
Setting-depth selection for intermediate and deeper strings
Setting-depth selection should be made for the deepest strings to be run in the well and successively designed from the bottom to surface. Although this procedure may appear at first to be reversed, it avoids several time-consuming iterative procedures. Surface-casing design procedures are based on other criteria.
The first criterion for selecting deep casing depths is for mud weight to control formation pressures without fracturing shallow formations. This procedure is implemented bottom to top. After these depths have been established, differential-pressure-sticking considerations are made to determine if the casing string will become stuck when running it into the well. These considerations are made from top to bottom, the reverse from the first selection criterion.
The initial design step is to establish the projected formation pressures and fracture mud weights. In Fig. 2, a 15.6-lbm/gal (equivalent) formation pressure exists at the hole bottom. To reach this depth, wellbore pressures greater than 15.6 lbm/gal are necessary and must be taken into account.
The pressures that must be considered include:
- A trip margin of mud weight to control swab pressures.
- An equivalent-mud-weight increase, because of surge pressures associated with running the casing.
- A safety factor.
These pressures usually range from 0.2 to 0.3 lbm/gal, respectively, and may vary because of mud viscosity and hole geometry. Therefore, the actual pressures at the bottom of the well include the mud weight required to control the 15.6-lbm/gal pore pressure and the 0.6- to 0.9-lbm/gal (equivalent) mud weight increases from the swab, surge, and safety factor considerations. As a result, formations exhibiting fracture mud weights 16.5 lbm/gal or less (15.6 lbm/gal + 0.9 lbm/gal) must be protected with casing. The depth at which this fracture mud weight is encountered becomes the tentative intermediate-pipe setting depth.
The next step is to determine if pipe sticking will occur when running the casing. Pipe sticking generally occurs where the maximum differential pressures are encountered. In most cases, this depth is the deepest normal-pressure zone (i.e., at the transition into abnormal pressures).
Field studies have been used to establish general values for the amount of differential pressure that can be tolerated before sticking occurs:
Normal-pressure zones 2,000 to 2,300 psi Abnormal-pressure zones 2,500 to 3,000 psi
These values are recommended as reasonable guides. Their accuracy in day-to-day operations depends on the general attention given to mud properties and drillstring configuration.
The tentative intermediate-pipe setting depth becomes the actual setting depth, if the differential pressure at the deepest normal zone is less than 2,000 to 2,300 psi. If the value is greater than this limit, the depth is redefined as the shallowest liner setting depth required to drill the well. In this case, an additional step is necessary to determine the intermediate-pipe depth.
An example problem illustrates this procedure. The section following the example shows the case in which differential pressure considerations require the additional step to select the intermediate pipe depth.
Use Fig. 2.a to determine the proper setting depth for intermediate pipe. Assume a 0.3-lbm/gal factor for swab and surge and a 0.2-lbm/gal safety factor. Use a maximum limit of 2,200-psi differential pressure for normal-pressure zones.
1. Evaluate the maximum pressures (equivalent mud weights) at the total depth of the well.
2. Determine formations that cannot withstand 16.4-lbm/gal pressures (i.e., those formations that must be protected with casing). Construct a vertical line from 16.4 lbm/gal to an intersection of the fracture-mud-weight line ( Fig. 2 Part B). The depth of intersection is the tentative intermediate casing setting depth, or 8,600 ft in this example.
Check the tentative depth to determine if differential pipe sticking will be a problem when running the casing to 8,600 ft. The mud required to reach 8,600 ft is
Differential-sticking potential is evaluated at the deepest normal-pressure (9.0 lbm/gal) zone, 8,000 ft.
3. Check the interval from 8,600 to 12,000 ft to determine if the differential pressure exceeds the 3,000- to 3,300-psi range. In this case, pressure ≈ 2,700 psi at 8,600 ft.
Example 1 illustrated the case in which the vertical line from 16.4 lbm/gal intersected the fracture-mud-weight curve in an abnormal-pressure region. A calculation was performed to determine if the casing would stick when run into the well. If the pressures had been greater than the limit of 2,200 psi, procedures in the following sections would be implemented. Cases arising when the vertical line intersects the fracture-mud-weight curve in the normal-pressure region are discussed later.
Altering the tentative intermediate-casing setting depth because of potential differential-sticking problems is required in many cases. The previously defined tentative intermediate-pipe setting depth is redefined as the shallowest liner depth. The procedure must now be worked from the top to the bottom of the high-pressure zone, rather than the reverse approach used to establish the tentative intermediate depth. The new intermediate depth is established using sticking criteria. The deepest liner-setting depth is determined from formation-pressure/fracture-mud-weight guidelines. After the deepest liner depth is established, the operator must determine the exact liner-setting depth between the previously calculated shallowest and deepest possible depths. The final liner depth can be established from criteria such as minimizing the amount of small hole that must be drilled below the liner and preventing excessive amounts of open hole between the intermediate-liner section or the liner pay-zone section.
Eqs. 1 and Eqs. 2 can be used to help determine the new intermediate depth if sticking is a concern.
ρ = mud weight, lbm/gal;
Dn = deepest normal zone, ft;
Δ p = differential pressure, psi.
A limit of 2,000 to 2,300 psi is normally used for Δ p . The mud weight, ρ, from Eq. 1 can be used to locate the depth where the Δ p value will exist.
ρ = mud weight, lbm/gal;
Δρ = trip margin, lbm/gal;
pform = formation pressure, lbm/gal.
The depth at which the formation pressure, pform , occurs is defined as the new intermediate-pipe depth.
The deepest liner setting depth is established from the intermediate setting depth ’ s fracture mud weight. Using procedures reversed from those presented in Example 1 , subtract the swab, surge, and safety factors from the fracture mud weight to determine the maximum allowable formation pressure in the deeper sections of the hole. The depth at which this pressure is encountered becomes the deepest liner depth. The establishment of a setting depth between the shallowest and deep depths generally depends on operator preference and the geological conditions.
Use Fig. 3 to select liner and intermediate setting depths. Assume a differential-pressure limit of 2,200 psi. Use the following design factors:
1. From Fig. 3 , the maximum equivalent mud weight that can be seen at the bottom of the well can be calculated.
2. Construct a vertical line to intersect the fracture-mud-weight curve ( Fig. 3 ). The depth of intersection, 13,000 ft, is the tentative intermediate casing setting depth. All shallower formations must be protected with casing because their respective fracture mud weights are less than the maximum projected requirements (18.0 lbm/gal) at the bottom of the well.
3. Evaluate the tentative depth for differential sticking by assuming that 14.3-lbm/gal mud will be required to drill the formation at 13,000 ft:
Because 2,480 psi > 2,200 psi, intermediate pipe cannot safely be run to 13,000 ft. The depth of 13,000 ft is redefined as the shallowest liner depth. 4. The intermediate-pipe depth is defined with Eqs. 1 and Eqs. 2.
From Fig. 3.b , a 13.4-lbm/gal formation pressure occurs at 10,900 ft.
5. The deepest possible setting depth for the liner is determined by evaluating the fracture mud weight at 10,900 ft. What is the maximum formation pressure below 10,900 ft that can be safely controlled with a fracture mud weight of 17.1 lbm/gal?
From Fig. 3.c , a 16.3-lbm/gal formation pressure occurs at 16,300 ft. The depth is defined as the deepest allowable depth for setting the liner.
6. The shallow and deep liner depths are based on formation-pressure/fracture-mud-weight considerations at the hole bottom (18,000 ft) and the intermediate-pipe depth (10,900 ft), respectively. Any depth between the 13,000- to 16,000-ft range is satisfactory. A depth selection can be based on:
Minimizing small-diameter sections below the liner Minimizing the openhole length and thereby reducing pipe costs Other considerations as specified by the operator.
As an example, assume that a depth of 15,000 ft is selected. It reduces the small-diameter hole to a 3,000-ft segment (15,000 to 18,000 ft) while allowing only 4,100 ft of open hole (10,900 to 15,000 ft) ( Fig. 3.d ).
Examples 1 and 2 illustrated the cases in which the initial formation pressure/fracture mud weight at the bottom required pipe depths in the abnormal-pressure regions. Different techniques must be used if the tentative pipe-setting depth is in a normal pressure region.
The initial step is to evaluate differential-sticking possibilities at the deepest normal pressure zone. If the mud weight required at the bottom of the well does not create differential pressures in excess of some limit (2,000 to 2,300 psi), a deep surface-casing string is satisfactory. Eqs. 1 and Eqs. 2 must be used when the differential pressures exceed the allowable limit.
Surface-casing depth selection
Shallow casing strings, such as surface casing, are often imposed to equivalent mud weights more severe than the considerations used to select the setting depths for intermediate casing and liner. These pressures usually result from kicks inadvertently taken when drilling deeper sections. As a result, surface setting depths are selected to contain kick pressures rather than the previously described procedures for intermediate casing. This philosophy differs for the intermediate hole, because the kick pressures are usually lower than the previously discussed swab/surge/safety-factor logic for deep strings.
Kick-imposed equivalent mud weights are the cause for most underground blowouts. When a kick occurs, the shut-in casing pressure added to the drilling-mud hydrostatic pressure exceeds the formation fracture pressure and results in an induced fracture. The objective of a seat-selection procedure that avoids underground blowouts would be to choose a depth that can competently withstand the pressures of reasonable kick conditions.
Determination of kick-imposed pressures can be difficult. However, a procedure that estimates the values has been proved in field applications to be quick and effective. Fig. 4 represents a well whose pumps and blowout preventers have simulated a kick. Eq. 3 describes the pressure relationships.
ρekick = equivalent mud weight at the depth of interest, lbm/gal;
D = deepest interval, ft;
Di = depth of interest, ft;
Δρ = incremental kick mud-weight increase, lbm/gal;
ρo = original mud weight, lbm/gal.
Eq. 3 can be used iteratively along with a suitable theoretical fracture-mud-weight calculation to determine a surface-pipe depth with sufficient strength to resist kick pressures. Initially, a shallow depth is chosen for which the fracture mud weight and equivalent mud weights are calculated. If the equivalent mud weight is greater than the fracture mud weight, a deeper interval must be selected and the calculations repeated. This procedure is iterated until the fracture mud weight exceeds the equivalent mud weights. When this occurs, a depth has been selected that will withstand the designed kick pressures. Example 3 illustrates the procedure.
Using Fig. 5, select a surface-casing depth and, if necessary, setting depths for deeper strings. Use the following design factors:
0.3 = swab, surge factor, lbm/gal.
0.2 = safety factor, lbm/gal.
0.5 = kick factor, lbm/gal.
2,200 = maximum allowable differential pressure, psi.
1. Evaluate the maximum pressures anticipated at the bottom of the well.
A vertical line from 12.8 lbm/gal intersects the fracture mud weight in a normal region, which indicates that intermediate casing will not be required unless differential sticking is a problem.
2. Assume that 12.3 lbm/gal will be used at the bottom of the well and determine if differential sticking may occur.
Because 1,544 psi is less than the arbitrary limit of 2,200 psi, intermediate casing will not be used for pipe-sticking considerations. Only surface casing is required.
3. Use Eq. 3 and the fracture-mud-weight curve to determine the depth at which the fracture mud weight exceeds the kick loading mud weight. Perform a trial calculation at 1,000 ft.
The fracture mud weight at 1,000 ft is 12.0 lbm/gal. Because the kick loading is greater than the rock strength, a deeper trial depth must be chosen. Results from several iterations are given next and plotted on Fig. 5.
4. A setting depth of 3,600 ft is selected.
The value of 0.5 lbm/gal used in Example 3 for the kick incremental mud-weight increase is widely accepted. It represents the average (maximum) mud-weight increase necessary to kill a kick. Using this variable in Eq. 3 allows the operator to (inadvertently) drill a formation in which the pressure is in excess of 0.5 lbm/gal greater than the original calculated value and still safely control the kick. In fact, if the original mud-weight variable is 0.3 to 0.4 lbm/gal greater than the anticipated formation pressure, the equation would account for formation-pressure calculation errors of 0.8 to 0.9 lbm/gal. If necessary, an operator may alter the 0.5-lbm/gal variable to whatever is deemed most suitable for the drilling environment.
A valid argument can be raised concerning Eq. 3 and its representation of field circumstances. In actual kick situations, the equivalent mud weights are controlled to a certain degree by casing pressure, which is not directly taken into account in the equation. An inspection of casing pressure shows the two components in the pressure are:
- The degree of underbalance between the original mud and the formation pressure
- The degree of underbalance between the influx fluid and the formation pressure
The first of these components is taken into account in the equation by the incremental mud-weight-increase term, while the latter is not considered. In most kick situations, the average value of the second component will range from 100 to 300 psi. If an operator believes the second component is significant enough to alter the equation, he can change the incremental mud-weight-increase term to a higher value.
The considerations are illustrated in Fig. 4 and Figs. 6 and 7 . Figs. 4 and 6 represent a 1.0-lbm/gal kick in simple and actual hole geometries, respectively. Fig. 6 shows the shut-in well with a 20-bbl kick at the bottom. Fig. 7 shows the equivalent mud weights for both cases. If an operator is concerned about the difference shown in Fig. 7, Eq. 3 should be modified, or a different equation should be used.
Drive pipe and/or conductor casing
Pipe setting depths above the surface casing are usually determined from various government regulations or localized drilling problems. For example, an area may have severe lost-circulation problems at 75 to 100 ft that can be solved by placing drive pipe below the zone. Other drilling conditions that may affect setting depths include water-bearing sands, unconsolidated formations, or shallow gas. An evaluation of local drilling records will normally identify these conditions. Most governments require that freshwater sands be cased.