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Petroleum Engineering Handbook

Larry W. Lake, Editor-in-Chief

Volume II - Drilling Engineering

Robert F. Mitchell, Editor

Chapter 11 - Introduction to Well Planning

By Neal Adams, Neal Adams Services

Pgs. 455-518

ISBN 978-1-55563-114-7
Get permission for reuse

Well planning is perhaps the most demanding aspect of drilling engineering. It requires the integration of engineering principles, corporate or personal philosophies, and experience factors. Although well planning methods and practices may vary within the drilling industry, the end result should be a safely drilled, minimum-cost hole that satisfies the reservoir engineer ’

s requirements for oil/gas production.

The skilled well planners normally have three common traits. They are experienced drilling personnel who understand how all aspects of the drilling operation must be integrated smoothly. They utilize available engineering tools, such as computers and third-party recommendations, to guide the development of the well plan. And they usually have an investigative characteristic that drives them to research and review every aspect of the plan in an effort to isolate and remove potential problem areas.

Well Planning


The objective of well planning is to formulate from many variables a program for drilling a well that has the following characteristics: safe, minimum cost, and usable. Unfortunately, it is not always possible to accomplish these objectives on each well because of constraints based on geology, drilling equipment, temperature, casing limitations, hole sizing, or budget.

Safety. Safety should be the highest priority in well planning. Personnel considerations must be placed above all other aspects of the plan. In some cases, the plan must be altered during the course of drilling the well when unforeseen drilling problems endanger the crew. Failure to stress crew safety has resulted in loss of life and burned or permanently crippled individuals.

The second priority involves the safety of the well. The well plan must be designed to minimize the risk of blowouts and other factors that could create problems. This design requirement must be adhered to rigorously in all aspects of the plan. Example 11.1 illustrates a case in which this consideration was neglected in the earliest phase of well planning, which is data collection.

Example 11.1 A turnkey drilling contractor began drilling a 9,000-ft well in September 1979. The well was in a high-activity area where 52 wells had been drilled previously in a township (approximately 36 sq miles). The contractor was reputable and had a successful history.

The drilling superintendent called a bit company and obtained records on two wells in the section where the prospect well was to be drilled. Although the records were approximately 15 years old, it appeared that the formation pressures would be normal to a depth of 9,800 ft. Because the prospect well was to be drilled to 9,000 ft, pressure problems were not anticipated. The contractor elected to set 10¾-in. casing to 1,800 ft and use a 9.5-lbm/gal mud to 9,000 ft in a 9⅞-in. hole. At that point, responsibility would be turned over to the oil company.

Drilling was uneventful until a depth of 8,750 ft was reached. At that point, a severe kick was taken. An underground blowout occurred that soon erupted into a surface blowout. The rig was destroyed and natural resources were lost until the well was killed three weeks later.

A study was conducted that yielded the following results:

  • All wells in the area appeared to be normal pressured until 9,800 ft.
  • However, 4 of the 52 wells in the specific township and range had blown out in the past five years. It appeared that the blowouts came from the same zone as the well in question.
  • A total of 16 of the remaining 48 wells had taken kicks or severe gas cutting from the same zone.
  • All problems appeared to occur after a 1973 blowout taken from a 12,200-ft abnormal-pressure zone.


  • The drilling contractor did not research the surrounding wells thoroughly in an effort to detect problems that could endanger his well or crews.
  • The final settlement by the insurance company was more than U.S. $16 million. The incident probably would not have occurred if the contractor had spent U.S. $800 to $1,000 to obtain proper drilling data.

Minimum Cost. A valid objective of the well-planning process is to minimize the cost of the well without jeopardizing the safety aspects. In most cases, costs can be reduced to a certain level as additional effort is given to the planning (Fig. 11.1). It is not noble to build "steel monuments" in the name of safety if the additional expense is not required. On the other hand, funds should be spent as necessary to develop a safe system.

Usable Holes. Drilling a hole to the target depth is unsatisfactory if the final well configuration is not usable. In this case, the term "usable" implies the following:
  • The hole diameter is sufficiently large so an adequate completion can be made.
  • The hole or producing formation is not irreparably damaged.

This requirement of the well planning process can be difficult to achieve in abnormal-pressure, deep zones that can cause hole-geometry or mud problems.

Well-Type Classification

The drilling engineer is required to plan a variety of well types, including: wildcats, exploratory holes, step-outs, infills, and re-entries. Generally, wildcats require more planning than the other types. Infill wells and re-entries require minimum planning in most cases.

Wildcats are drilled where little or no known geological information is available. The site may have been selected because of wells drilled some distance from the proposed location but on a terrain that appeared similar to the proposed site. The term "wildcatter" was originated to describe the bold frontiersman willing to gamble on a hunch.

Rank wildcats are seldom drilled in today ’

s industry. Well costs are so high that gambling on wellsite selection is not done in most cases. In addition, numerous drilling prospects with reasonable productive potential are available from several sources. However, the romantic legend of the wildcatter will probably never die. Characteristics of various well types are shown in Table 11.1.

Formation Pressure

The formation, or pore, pressure encountered by the well significantly affects the well plan. The pressures may be normal, abnormal (high), or subnormal (low).

Normal-pressure wells generally do not create planning problems. The mud weights are in the range of 8.5 to 9.5 lbm/gal. Kicks- and blowout-prevention problems should be minimized but not eliminated altogether. Casing requirements can be stringent even in normal-pressure wells deeper than 20,000 ft because of tension/collapse design constraints.

Subnormal-pressure wells may require setting additional casing strings to cover weak or low-pressure zones. The lower-than-normal pressures may result from geological or tectonic factors or from pressure depletion in producing intervals. The design considerations can be demanding if other sections of the well are abnormal pressured.

Abnormal pressures affect the well plan in many areas, including: casing and tubing design, mud-weight and type-selection, casing-setting-depth selection, and cement planning. In addition, the following problems must be considered as a result of high formation pressures: kicks and blowouts, differential-pressure pipe sticking, lost circulation resulting from high mud weights, and heaving shale. Well costs increase significantly with geopressures.

Because of the difficulties associated with well planning for high-pressure exploratory wells, many design criteria, publications, and studies have been devoted to this area. The amount of effort expended is justified. Unfortunately, the drilling engineer still must define the planning parameters that can be relaxed or modified when drilling normal-pressure holes or well types such as step-outs or infills.

Planning Costs

The costs required to plan a well properly are insignificant in comparison to the actual drilling costs. In many cases, less than U.S. $1,000 is spent in planning a U.S. $1 million well. This represents 1/10 of 1%; of the well costs.

Unfortunately, many historical instances can be used to demonstrate that well planning costs were sacrificed or avoided in an effort to be cost conscious. The end result often is a final well cost that exceeds the amount required to drill the well if proper planning had been exercised. Perhaps the most common attempted shortcut is to minimize data-collection work. Although good data can normally be obtained for small sums, many well plans are generated without the knowledge of possible drilling problems. This lack of expenditure in the early stages of the planning process generally results in higher-than-anticipated drilling costs.

Overview of the Planning Process

Well planning is an orderly process. It requires that some aspects of the plan be developed before designing other items. For example, the mud density plan must be developed before the casing program because mud weights have an impact on pipe requirements (Fig. 11.2).

Bit programming can be done at any time in the plan after the historical data have been analyzed. The bit program is usually based on drilling parameters from offset wells. However, bit selection can be affected by the mud plan

[ i.e., the performance of polycrystalline-diamond (PCD) bits in oil muds] . Casing-drift-diameter requirements may control bit sizing.

Casing and tubing should be considered as an integral design. This fact is particularly valid for production casing. A design criterion for tubing is the drift diameter of the production casing, whereas the packer-to-tubing forces created by the tubing’

s tendencies for movement can adversely affect the production casing. Unfortunately, these calculations are complex and often neglected.

The completion plan must be visualized reasonably early in the process. Its primary effect is on the size of casing and tubing to be used if oversized tubing or packers are required. In addition, the plan can require the use of high-strength tubing or unusually long seal assemblies in certain situations.

Fig. 11.2 defines an orderly process for well planning. This process must be altered for various cases. The flow path in this illustration will be followed, for the most part, throughout this text.

Data Collection

The most important aspect of preparing the well plan, and subsequent drilling engineering, is determining the expected characteristics and problems to be encountered in the well. A well cannot be planned properly if these environments are unknown. Therefore, the drilling engineer must initially pursue various types of data to gain insight used to develop the projected drilling conditions.

Offset-Well Selection

The drilling engineer is usually not responsible for selecting well sites. However, he must work with the geologist for the following reasons:

  • Develop an understanding of the expected drilling geology.
  • Define fault-block structures to help select offset wells similar in nature to the prospect well.
  • Identify geological anomalies as they may be encountered in drilling the prospect well.

A close working relationship between drilling and geology groups can be the difference between a producer and an abandoned well.

An example of geological information that the drilling group may receive is shown in Fig. 11.3. The geologists have found significant production from E.B. White #2. Contouring the pay zones produces the map in Fig. 11.3. The prospect well should encounter the producing structure at the approximate depth as the E.B. White #2.

Maps showing the surface location of offset wells are available from commercial cartographers (Fig. 11.4). These maps normally provide the well location relative to other wells, operator, well name, depth, and type of produced fluids. In addition, some maps contour regional formation tops.

The map in Fig. 11.4 is defined according to a United States land grant system using townships, ranges, and sections. Important terms used with this system are defined next.
  • Section: Basic unit of the system—a square tract of land 1 × 1 mile containing 640 acres.
  • Township: 36 sections arranged in a 6 × 6 array measuring 6 × 6 miles. Sections are numbered beginning with the northeast-most section, proceeding west to 6, then south along the west edge of the township and then back to the east.
  • Range: Assigned to a township by measuring east or west of a principle meridian.
  • Range Lines: North-to-south lines that mark township boundaries.
  • Township Lines: East to west lines that mark township boundaries.
  • Principal Meridian: Reference or beginning point for measuring east or west ranges.
  • Base Line: Reference or beginning point for measuring north or south townships.

In rare cases, a specific township and range may have several hundred sections. This scheme is used throughout the United States except in a few states including Texas, where the location is described in terms of trees, streams, rocks, and neighboring landowners (Fig. 11.5).

The latitude/longitude mapping system is widely used worldwide, except in the United States. This approach is more orderly and easily allows the wells to be located in relation to other known wells or landmarks. The "lat/long" system is now being introduced in the United States in conjunction with the township/range scheme.

Selecting offset wells to be used in data collection is important. Using Fig. 11.4 as an example, assume that a 13,000-ft prospect is to be drilled in the northeast corner of Section 30, T18S, R15E. The best candidates for offset analyses are shown in Table 11.2. Although these wells were selected for control analysis, available data from any well in the area should be analyzed.

Data Sources

Data sources should be available for virtually every well drilled in the United States. Drilling costs prohibit the rank wildcatting that occurred years ago. Although wildcats are currently being drilled, seismic data, as a minimum, should be available for pore-pressure estimation.

Common data types used by the drilling engineer are listed next:

  • Bit, mud, mud-logging, and operator’

s drilling records.

  • Drilling reports from operators or the Intl. Assn. of Drilling Contractors (IADC).
  • Scout tickets.
  • Log headers.
  • Production history.
  • Seismic studies.
  • Well surveys.
  • Geological contours.
  • Databases of service company files.

Each record contains data that may not be available with other sources. For example, log headers and seismic work are useful, particularly if these data are the only available sources.

Many data sources exist in the industry. Some operators consider the records confidential, when in fact the important information, such as well-testing and production data, becomes public domain a short time after the well is completed. The drilling engineer must assume the role of "detective" to define and locate the required data.

Data sources include bit manufacturers and mud companies who regularly record pertinent information on well recaps. Bit and mud companies usually make these data available to the operator. Log libraries provide log headers and scout tickets. Internal company files often contain drilling reports, IADC reports, and mud logs. Many operators share old offset information if they have no further leasing interest.

Bit Records

An excellent source of offset drilling information is the bit record. It contains data relative to the actual on-bottom drilling operation. A typical record for a relatively shallow well is shown in Fig. 11.6.

The heading of the bit record provides information such as the operator, contractor, rig number, well location, drillstring characteristics, and pump data. In addition, the bit heading provides dates for spudding, drilling out from under the surface casing, intermediate-casing depth, and reaching the hole bottom.

The main body of the bit record provides the number and type of bits, jet sizes, footage and drill rates per bit, bit weight and rotary operating conditions, hole deviation, pump data, mud properties, dull-bit grading, and comments. The vertical deviation is useful in detecting potential dogleg problems.

Comments throughout the various bit runs are informative. Typical notes such as "stuck pipe" and washout in drillstring can explain drilling times greater than expected. Drilling engineers often consider the comments section on bit (and mud) records to be as important as the information in the main body of the record.

Bit-grading data can be valuable if the operator assumes the observed data are correct and representative of the actual bit condition. The bit grades assist in preparation of a bit program identifying the most (and least) successful bits in the area. Bit running problems such as broken teeth, gauge wear, and premature failures can be observed, and preventive measures can be formulated for the new well.

Drilling Analysis. Bit records can provide additional useful data if the raw information is analyzed. Plots can be prepared that detect lithology changes and trends. Cost-per-foot analyses can be made. Crude, but often useful, pore-pressure plots can be prepared.

Raw drill-rate data from a well and an area can detect trends and anomalies. Fig. 11.7 shows drill-rate data from a well in south Louisiana. A drill rate that decreases with depth is expected as shown.

Changes in the trend might suggest an anomaly, as in Fig. 11.8. This illustration is the composite drill rates for all wells in a south Louisiana township and range. The trend change at approximately 10,000 ft was later defined as the entrance into a massive shale section.

Cost-per-foot studies are useful in defining optimum, minimum-cost drilling conditions. A cost comparison of each bit run on all available wells in the area will identify bits and operating conditions for minimum drilling costs. The drilling engineer provides his expected rig costs, bit costs, and assumed average trip times. The cost-per-foot calculations are completed with Eq. 11.1.


$/ft = cost per foot, U.S dollars;
CB = bit cost, U.S. dollars;
CR = rig cost, U.S dollars;
TR = rotating time, hours;
TT = trip time, hours;


Y = footage per bit run.
A cost-per-foot analysis for Fig. 11.6 is shown in Fig. 11.9.

Trip times should be averaged for various depth intervals. Several operators have conducted field studies to develop trip-time relationships (Table 11.3). The most significant factors affecting trip time include depth and hole geometry (i.e., number and size of collars, and downhole tools). Table 11.3 can be used in the cost-per-foot equation (Eq. 11.1).

Example 11.2 Calculate the cost per foot and the cumulative section costs for the following data. Assume a rig cost of U.S. $12,000/day.


Determine which drilling conditions, Well A or B, should be followed in the prospect well. Use a 9.875-in. bit.


1. The hourly rig cost is U.S. $500. Trip times from 7,150 and 8,000 ft are 6.0 and 6.5 hours, respectively.

2. The cost per foot for Bit 1 on Well A (6,000 to 7,150 ft) is


For Bit 2,


3. The cumulative cost for Well A is


4. The cost per foot for Well B is


The section cost is $27,230.

5. Because the cost per foot is lower in Well B, drilling conditions for Well B should be implemented.

Mud Records

Drilling-mud records describe the physical and chemical characteristics of mud system. The reports are usually prepared daily. In addition to the mud data, hole and drilling conditions can be inferred. Most personnel believe this record is important and useful.

Mud engineers usually prepare a daily mud-check report form. Copies are distributed to the operator and drilling contractor. The form contains current drilling data such as well depth, bit size and number, pit volume, pump data, solids-control equipment, and drillstring data. The report also contains mud-properties data such as mud weight; pH; funnel viscosity; plastic viscosity; yield point; gel strength; chloride, calcium, and solids content; cation-exchange capacity; and fluid loss.

An analysis of these characteristics taken in the context of the drilling conditions can provide clues to possible hole problems or changes in the drilling environment. For example, an unusual increase in the yield point, water loss, and chloride content suggests that salt (or salt water) has contaminated a freshwater mud. If kick-control problems had not been encountered, it is probable that salt zones were drilled.

A composite mud recap form is usually prepared. It contains a daily properties summary. It may also include comments pertaining to hole problems.

Drilling Analysis. Daily reports prepared by the mud engineer are useful in generating depths-vs.-days plots (Fig. 11.10). These plots are as important to well-cost estimating as pore pressures are to the overall well plan. Other types of records (i.e., bit records and log headers) do not provide sufficient daily detail to construct the plot as accurately as mud records.

An analysis of the plots in the offset area surrounding the prospect well can provide:
  • Expected drilling times for various intervals.
  • Identification of improved operating conditions by examining the lowest drilling times in the offset wells.
  • Location of potential problem zones by comparing common difficulties in the wells.

After the offset wells have been analyzed, a projected-depth vs. days plot is prepared for the prospect well.

IADC Reports

The drilling contractor maintains a daily log of the drilling operations recorded on the standard IADC-API report. It contains hourly reports for drilling operations, drillstring characteristics, mud properties, bit performance, and time breakdowns for all operations. These reports are usually unavailable to other contractors or operators and, as a result, cannot be obtained for offset-well analysis without the operator ’ s cooperation.

Scout Tickets

Scout tickets have been available as a commercial service for many years. The tickets were originally prepared by oil company representatives who "scouted" operations of other oil companies. Current scout tickets contain a brief summary of the well (Fig. 11.11). The data usually include:

  • Well name, location, and operator.
  • Spud and completion dates.
  • Casing geometries and cement volumes.
  • Production-test data.
  • Completion information.
  • Tops of various geological zones.

The data source for scout tickets are the state or federal report forms filed by oil companies during the course of drilling the well.

Mud-Logging Records

A mud log is a foot-by-foot record of drilling, mud, and formation parameters. Mud-logging units are often used on high-pressure or troublesome wells. Many engineers consider the mud log to be the best source of penetration-rate data. Mud logging records are seldom available to groups other than the well operators.

A section of a mud log is shown in Fig. 11.12. Drilling parameters normally included are penetration rate, bit weight and rotary speed, bit number and type, and rotary torque.

Mud-logging scales are often arranged so the drill-rate curve can be compared to the spontaneous potential (SP) or gamma ray curve on offset logs. The mud log may contain drilling-related parameters such as mud temperatures; chlorides; gas content in the mud and cuttings, usually measured in

’ units’

lithology; and pore-pressure analysis. The pore pressure can be computed from models such as the d-exponent or other proprietary equations or can be measured by drillstem tests.

Log Headers

Drilling records similar to the previously described information are not available on all offset wells. In these cases, log headers can yield useful drilling data. Easily attainable data from the log headers include logging depths, mud weight and viscosity at each logging depth, bit sizes, inferred casing sizes, and actual setting depths. If enough logging runs were made, a useful depth-vs.-days plot can be constructed.

Production History

Production records in the offset area can provide clues to problems that may be encountered in the prospect well. Oil/gas production can reduce the formation pressure and cause differential pipe sticking. Production records provide pressure data from the flowing zones. Unfortunately, pressures in the over- and underlying formations will not change appreciably. This obscures detection with drilling parameters.

Example 11.3 A prospect well has the Concordia B sand as its intermediate target zone. Production records indicate the original bottomhole pressure (BHP), before production from the B sand, was 5,389 psia at 9,890 ft true vertical depth (TVD). Currently, the producing BHP is 3,812 psia, and the product is gas. A 10.7-lbm/gal mud was required to drill the intermediate shale sections contiguous to the Concordia sand. A 12.1-lbm/gal mud is required to drill to 12,050 ft. If a maximum pressure of 2,000 psi is used as the upper differential limit, can the well be drilled with the Concordia sand exposed or must the casing be set below the sand before reaching 12,050 ft? (Convert all mud hydrostatic pressures to absolute pressure by adding 15 psia for atmospheric conditions.)

Solution. 1. The mud required to balance the Concordia sand is 10.7 lbm/gal, which exerts a hydrostatic pressure of


2. The differential pressure with 10.7 lbm/gal is


Therefore, pipe sticking should not be a problem with the 10.7-lbm/gal mud.

3. A 12.1-lbm/gal mud is required to reach 12,050 ft. This mud weight will create a hydrostatic pressure at 9,890 ft of


The differential pressure will be


4. A casing string, or liner, must be set below 9,890 ft because the 12.1 lbm/gal required at the bottom creates a differential pressure at the Concordia B sand in excess of the 2,000-psi upper limit.

Seismic Studies

Wildcat wells are seldom drilled without preliminary seismic work being done in the area. Analysis of seismic reflections can eliminate the "wildcat" status of the well by predicting pore pressures. Several authors have shown that good agreement on the pore pressures can be attained with seismic and sonic-log data.

Casing Setting-Depth Selection

The first design task in preparing the well plan is selecting depths that the casing will be run and cemented. The drilling engineer must consider geological conditions such as formation pressures and fracture mud weights, hole problems, internal company policies, and, in many cases, 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; structural; surface; intermediate (also known as protection pipe); liners; production (also known as an oil string); and tubing (flow string). Fig. 11.13 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.

Structural Casing. 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.

Intermediate Casing. 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.

Liners. 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. 11.13).

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).

Production Casing. 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.

Tieback String. 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 even 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. 11.14, 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, and 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.

Example 11.4

Use Fig. 11.14a 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. 11.14 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 11.4 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. 11.2 and 11.3 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. 11.2 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 11.4 , 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.

Example 11.5 Use Fig. 11.15 to select liner and intermediate setting depths. Assume a differential-pressure limit of 2,200 psi. Use the following design factors:



1. From Fig. 11.15 , 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. 11.15 ). 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. 11.2 and 11.3 .




From Fig. 11.15b , 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. 11.15c , 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 (1) minimizing small-diameter sections below the liner, (2) minimizing the openhole length and thereby reducing pipe costs, or (3) 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. 11.15d ).

Examples 11.4 and 11.5 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. 11.2 and 11.3 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. 11.16 represents a well whose pumps and blowout preventers have simulated a kick. Eq. 11.4 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. 11.4 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 11.6 illustrates the procedure.

Example 11.6 Using Fig. 11.17, 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. 11.4 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. 11.17 .


4. A setting depth of 3,600 ft is selected.

The value of 0.5 lbm/gal used in Example 11.6 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. 11.4 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. 11.4 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 (1) the degree of underbalance between the original mud and the formation pressure and (2) 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. 11.16 and Figs. 11.18 and 11.19 . Figs. 11.16 and 11.18 represent a 1.0-lbm/gal kick in simple and actual hole geometries, respectively. Fig. 11.18 shows the shut-in well with a 20-bbl kick at the bottom. Fig. 11.19 shows the equivalent mud weights for both cases. If an operator is concerned about the difference shown in Fig. 11.19, Eq. 11.4 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.

Hole-Geometry Selection

Bit- and casing-size selection can mean the difference between a well that must be abandoned before completion and a well that is an economic and engineering success. Improper size selection can result in holes so small that the well must be abandoned because of drilling or completion problems. The drilling engineer (and well planner) is responsible for designing the hole geometry to avoid these problems.

However, a successful well is not necessarily an economic success. For example, a well design that allows for satisfactory, trouble-free drilling and completion may be an economic failure because the drilling costs are greater than the expected return on investment. Hole-geometry selection is a part of the engineering plan that can make the difference between economic and engineering failure or success.

General Design Procedures

The drilling industry ’ s experience has developed several commonly used hole-geometry programs. These programs are based on bit- and casing-size availability as well as the expected drilling conditions.

Deep, high-pressure wells often require deviations from common geometries. Reasons include:

  • Prolific production rates requiring large tubing strings.
  • Drilling problems requiring the use of an intermediate string and one or more liners.
  • Tension design problems because thick-walled pipe must be used to control burst or collapse.
  • Rig limitations in running heavy strings of pipe.

Because deep, high-pressure wells are being drilled with increasing frequency, careful attention must be given to hole sizing.

Bottom-to-Top Approach. The highest priority in well planning should be developing a design that provides for economic production from the pay zone. Even in exploratory drilling for geological investigations, a large hole may be necessary for thorough formation evaluation. The pay zone should be analyzed with respect to its flow potential and the drilling problems that will be encountered in reaching it.

Flow-String Sizing. The flow, or tubing, string must be given consideration relative to its ability to conduct oil/gas to surface at economical rates. Small-diameter tubing restricts, or chokes, flow rates because of high friction pressures.

Completion problems can be more complicated with small tubing and casing. The reduced radial clearances make tool placement and operations more difficult, and workover activities are more complicated.

Typical well designs are shown in Fig. 11.20. The geometries in parts (a) and (c) use large-diameter tubing. The small tubing string (b) will probably restrict the fluid flow from the producing zone. In addition, the design in (b) will probably require special clearance couplings, whereas parts (a) and (c) could use standard-diameter couplings.

Planning for Problems. Geological uncertainties may make it difficult to predict the expected drilling environment. For example, crossing a fault into a high-pressure region may necessitate a drilling liner, whereas an intermediate string may be satisfactory if the fault is not encountered. Hole geometries are often selected to allow the option for an additional casing string if required ( Fig. 11.21).

Size-Selection Problems

Many interrelated size-selection problems must be considered before the final hole geometry is established. These problems primarily relate to casing size and openhole considerations, and they are interrelated with casing design. A working knowledge of casing-design problems influences pipe-size selection.

Casing Design. The large flow string in Fig. 11.20 resulted in a 13⅜-in. intermediate string and a 20-in. surface casing. However, these strings may be difficult to design if high formation pressures are encountered. Table 11.4 shows the pipe required for various conditions on the intermediate string, assuming that a single weight and grade will be used.

Tension designs become critical in cases similar to Table 11.4 . The in-air hook load of the string is 887,700 lbf for the worst case shown in the table. If a design factor of 1.5 is used to assess rig requirements, the design weight will be 1,331,550 lbf for derrick and substructure selection. It should be apparent that pipe yield, connector strength, and rig ratings affect casing and sizing selection.

Casing-to-Hole Annulus. Cementing problems may occur if the casing-to-hole annulus is small. Small clearances around the pipe and couplings may cause premature dehydration of the cement and result in a cement bridge. Cement companies report that this bridging occurs more frequently in deeper, hot wells. These companies suggest a minimum annular clearance of 0.375 to 0.50 in. on each side of the pipe, with 0.750 in. preferable.

Drillstring/Hole Annulus. The area between the drillstring and the hole creates problems if too large or small. Inadequate hole cleaning may occur if the hole is large. High friction pressures and turbulent erosion may occur in small holes. Large holes normally occur in the shallow depths, and small holes are found in the bottom sections.

Hole cleaning describes the ability of the drilling fluid to remove cuttings from the annulus. The important factors are mud viscosity, cuttings settling velocity, and annular mud flow rate. The annular mud velocity, Eq. 11.5 , is usually considered the most important aspect.



v = annular velocity, ft/min;

Qm = mud flow rate, gal/min;

dH = hole diameter, in.;


dDS = drillstring diameter, in.

Mud engineers often use other forms of an annular velocity equation.



v = annular velocity, ft/min;

Qp = pump output, bbl/min;


V = annular volume, bbl/1,000 ft.

The annular volume, in bbl/1,000 ft, can be estimated from the rule-of-thumb guide in Eq. 11.7 .



dH and dDS = hole and drillstring diameter, in.

As an example, an 8½ × 4½-in. annulus has approximately 52 bbl/1,000 ft of annulus. Many drilling rigs do not have adequate pump horsepower to clean the surface regions of the hole and, as such, rely on high-viscosity-gel plugs to clean the annulus. Example 11.7 illustrates the hole-cleaning problem.

Example 11.7 Use the hole geometries in Fig. 11.20 to determine the required flow rate to achieve an annular velocity of 75 ft/min. In addition, determine the surface horsepower required if the pump pressure is limited to 2,500 psi. Use 5-in. drillpipe for A and C and 4½-in. pipe for B.


1. From Fig. 11.20 , the annular geometries in the largest hole sections are


2. Use Eq. 11.5 to determine the required pump rate for A.


3. Determine the surface horsepower (HP) requirements if the pressure is limited to 2,500 psi. For A,


Based on results from Example 11.7, hole geometry C will be difficult to clean because many rigs are unable to deliver 2,905 hp under continuous service. Poor hole cleaning is a common cause of annular solids buildup, plugging, and lost circulation.

Most rigs are HP limited when drilling surface hole. Even though a pump may be rated to 3,000 psi, the maximum flow rate usually will be reached before achieving 3,000-psi surface pressure. Typical pressures for surface hole may be 600 to 1,500 psi even when using two pumps. If the pumps are unable to adequately clean the annulus, well-planning provisions must be made for periodic high-viscosity slurries to sweep the annulus.

Small-diameter holes create problems from turbulent erosion and hydraulics. The resultant problems can be cementing difficulties and poor hole cleaning in the enlarged area.

Hydraulics are complicated in the downhole, small-diameter sections. High friction pressures reduce the available hydraulic cleaning action at the bit and increase the chip-holddown effect on the cuttings. Swab and surge pressures can be large and range from 0.3 to 1.0-lbm/gal equivalent mud weight in small holes when heavy muds are used.

Underreaming. This technique enlarges the hole size in excess of the amount attainable with a drill bit. The underreamer tool has expandable arms with bit cones that can be activated with pump pressure. The important negative aspect of underreaming is that the tool arms are frequently damaged or lost in the hole. It is difficult to retrieve a lost underreamer arm.

This technique does have applications in some areas. One important application involves running a liner in an open hole that might be considered too small without underreaming. For example, a 7⅝-in. flush-joint liner run in an 8½-in. hole may be considered unacceptable (by some companies) without underreaming. A 7.0-in. liner may be an alternative, which would result in pipe-size restrictions in deeper sections.

Casing- and Bit-Size Selection

A casing- and bit-size program must consider the problems described in the previous section in addition to the actual casing- and bit-size characteristics. These include casing inner and outer diameter, drift and coupling diameter, and bit size. A working knowledge of these variables is important for selection of a viable geometry program.

Pipe Selection. Casing availability is a priority consideration in hole geometry selection. High-strength casing, often required for deep wells, may have a small (drift) diameter that will influence subsequent casing- and bit-size selection. Unfortunately, supply-and-demand cycles in the pipe industry may control the pipe design rather than engineering considerations.

The casing outer diameter (OD) is available in numerous sizes. The drift diameter, which is smaller than the inner diameter (ID), controls the bit selection for the open hole below the casing. As heavier-weight pipe is required to meet design specifications, the available drift diameter is reduced. A rule-of-thumb that has proved satisfactory in most field cases is to allow 1 in. of wall thickness to achieve a suitable design without resorting to the use of ultrahigh-strength pipe. As an example, 9⅞-in. casing can usually be designed properly if 8⅝-in. drift diameters are allowed.

Hole-geometry-selection approach may dictate the casing drift diameter as the controlling criterion. The options are as follows:

  • Try to design the pipe under the specific drift and OD conditions.
  • Use high-strength materials.
  • Use special drift pipe available from some manufacturers.
  • As a last resort, pipe manufacturers can prepare a special pipe design based on minimum drift requirements by enlarging the wall thickness and OD.

The fourth option is occasionally required in hydrogen sulfide environments where low-strength metals must be used.

Coupling Selection. Pipe couplings are generally designed to satisfy requirements such as burst, collapse, tension, and sealing effectiveness. However, coupling diameters may be a design guideline in some wells. Table 11.5 shows the OD of various types of couplings and pipe sizes. American Petroleum Inst. (API) couplings are normally 1 in. larger than the pipe in sizes greater than 7⅝ in.

Advantages are provided by using premium couplings. These couplings usually have clearances less than comparable API connections and occasionally allow the use of smaller pipe in a well. In many cases, more-expensive premium couplings can reduce the total well cost by allowing smaller pipe and hole geometries. In Fig. 11.20b , the hole geometry would not be difficult to achieve if premium couplings were used, whereas clearances might be unacceptable if API couplings were used.

Bit-Size Selection. Sizing the bit program is dependent on the required casing sizes. Bits are available in almost any desired size range. However, nonstandard bits or unusual sizes may not possess all of the desirable features, such as center-jet or gauge-protection characteristics. In addition, bit selection and availability become more difficult in odd or small bit sizes (less than 6.5 in.).

Table 11.6 illustrates size availability for Hughes insert-tooth bits. Bit sizes less than 6½ in. restrict bit-type selection. In addition, bit selection is restricted for sizes greater than 12¼ in.

Standard Bit/Casing Combinations

Fig. 11.22 can be used to select casing and bit sizes required to fulfill many drilling programs. To use the chart, determine the casing or liner size for the last size of pipe to be run. The flow of the chart indicates hole sizes that may be required to set that size of pipe (i.e., 5-in. liner inside 6⅛- or 6¼-in. hole).

Solid lines indicate commonly used bits for that size pipe that can be considered to have adequate clearance to run and cement the casing or liner (i.e., 5½-in. casing in a 7⅞-in. hole). The broken lines indicate less-commonly-used hole sizes. The selection of one of these broken paths requires that special attention be given to the connection, mud weight, cementing, and doglegs. Bicentered bits provide more flexibility in bit and hole size.

Preparation of Authority for Expenditures(AFE)

Preparing cost estimates for a well and getting management approval in the form of an AFE is the final step in well planning. The AFE is often accompanied by a projected payout schedule or revenue forecast. Although an essential part of well planning, the cost estimate is often the most difficult to obtain with any degree of reliability.

A properly prepared well cost estimate may require as much engineering work as the well design. The costs should address dry holes and completed wells. In addition, accounting considerations such as tangible and intangible items must be taken into account. Unfortunately, many cost "guestimates" are the "back of the napkin" type, with only a small amount of engineering work used in the process.

The cost estimate is the last item to be considered in the well plan because it is heavily dependent on the technical aspects of the projected well. After the technical aspects are established, the expected time required to drill the well must be determined. The actual well cost is obtained by integrating expected drilling and completion times with the well design.

Projected Drilling Time

The time required to drill the well has a significant impact on many items in the cost estimate. These items include drilling rig, mud, offshore transportation, rental tools, and support services. The effect of these items on the overall well cost is dependent on the actual unit cost (i.e., U.S. $15,000/day for a land rig vs. U.S. $250,000/day for a drillship, and the amount of drilling time).

Consider the well in Fig. 11.23. Assume the well will be drilled in east Texas. Table 11.7 summarizes the projected times for the well in three cases and illustrates the cost differences. The worst case has a 21%; greater cost than the best drilling times. This example illustrates the importance of preparing accurate projections for drilling time, or "depth vs. days," as it is often termed. A typical depth-vs.-days plot is shown in Fig. 11.24.

Drilling-Time Information. Numerous sources are available to estimate drilling times for a well. These include bit and mud records, log header information, and operator

’ s well histories. Other items such as scout tickets and production histories provide information that will affect the time projections.

Bit records are valuable sources to estimate drilling time. Although few bit manufacturers incorporate a column for dates in the depth-record forms, most drilling engineers who routinely complete the forms make notes in the remarks column as to the time or date the bits were run. In addition, most records contain the dates for well spudding, completion, and pipe setting. Additional inferences can be made from the individual bit-life hours and the cumulative drilling time for each well.

Mud records usually provide the most authoritative information about the drilling-time data. These records are maintained daily and usually contain remarks about the time required for each drilling activity. In addition, time allocated to hole problems can be evaluated to determine if the same amount of time should be included in the upcoming well. For example, hole sloughing may be an expected occurrence in an area, while kicks and twist-offs are unusual activities.

Log header data contain some drilling-time information and dates for each successive logging run. In addition, scout tickets attached to some logs include spud and completion dates.

The operator well histories provide a comprehensive evaluation of drilling times and offset wells. Although not generally available to noncompany personnel, the histories should contain all previously described sources of information as well as geological and production data. These operator records, when available, should be the basis for the drilling-time projections on the prospect.

Scout tickets and production histories can be valuable to supplement depth-vs.-days projections. Significant production from a zone may significantly reduce formation pressures, which can induce pipe sticking or lost-circulation problems. Infill drilling or drilling adjacent to two producing wells or fields must include this factor in the time estimate for the new well.

Time Categories

Drilling times are usually categorized for dry holes and completed wells. These categories are important as the management decision guide to evaluate potential risk vs. production economics. The dry hole assumes that all casing strings had been run except for production casing and tubing. Dry holes must include time allotments for setting several cased and openhole plugs and the possible retrieval of some casing. Completed wells normally include all well-completion operations up to the point of building production facilities. Well testing is usually included in the time for completion.

Time Considerations

Several factors affect the amount of time spent in drilling a well.

  • Drill rate.
  • Trip time.
  • Hole problems.
  • Casing running.
  • Directional drilling.
  • Completion type.
  • Move-in and move-out with the rig.
  • Weather.

Each factor may vary with geology, geographical location, operator philosophy and efficiency.

Drill Rate. The cumulative drilling time spent on a well depends primarily on rock type and bit selection. Hard-rock drilling usually needs significantly more drilling time than soft-rock drilling. In addition, the wide variety of bits available to the industry makes bit selection an important factor in drilling hard and soft formations. Other items that usually affect the drill rate are proper selection of weight and rotary speeds for optimum drilling, mud type, and differential pressure.

Trip Time. Pulling and running the drillstring is an important item in estimating total rotating time. In many cases, it is equal to or exceeds the on-bottom drilling time. Trip time is dependent on well depth, amount of mud trip margin, hole problems, rig capacity, and crew efficiency. A rule-of-thumb for trip-time estimations is 1 hr/1,000 ft of a well.

Long bit runs from 50 to 200 hours often require a short trip of several thousand feet out of and back into the hole. The purpose of the short trip is to remove or reduce any buildup of filter cake that significantly increases the swabbing tendencies of the drillstring. Short trips are dependent on company philosophy, mud type, and bit life.

Hole Problems. Various hole problems are routinely addressed in the drilling-time projections, while others are considered improbable. For example, severe kicks and blowouts are usually unlikely if the operator devotes sufficient attention to drilling activities. The geological conditions and drilling histories and the area of the prospect well will often define other pertinent hole problems.

The type of problems often regarded as standard are hole sloughing, lost circulation, and slow drilling rates. Many operators have encountered formations that slough or heave into the wellbore regardless of the amount of attention given to the mud systems or well plan. Lost circulation will occur in some formations even if the mud density is approximately equal to that of freshwater. Slow drilling rates will usually occur in environments with high differential pressures, such as the case of formation-pressure regressions while maintaining consistent mud weights. However, these hole problems can be eliminated or mitigated in most areas by exercising good engineering judgment in preparing the well plan.

Casing Running. The time required to run casing into the well is dependent on casing size and depth, hole conditions, crew efficiency, and use special equipment such as pickup machines or electric stabbing boards. A heavy casing string may require that the drillstring be laid down rather than setback in the derrick. In addition, nippling-up the blowout preventers and testing the casing and formation must be considered.

Directional Drilling. Directional control of a well requires increases in the drilling time. These increases apply to (1) attempting to drill a well directionally, or (2) maintain vertical control of a well that has deviation tendencies. The increases in drilling time usually result from obtaining surveys and from the inability to apply desired weights or rotary speeds. Many operators increase the expected drilling time in a directional well by a factor two.

Well Completions. Completion systems vary in complexity and, as a result, have a significant variation in time to implement the system. A standard single, perforated completion can be finished in 6 to 8 days. Dual-completed wells usually require an additional 2 to 3 days. Gravel packs, acidizing, fracturing, and other forms of well treatments must be evaluated on a case-by-case basis. Needless to say, the efficiency of all associated personnel and their experiences with a particular type of completion has a major impact on the required time.

Rig Move-in and Move-out. Rig moving affects several areas of the cost estimate and must be considered in the time projections. Move-in and rig-up occur before spudding the well. Rig-down and move-out occur after well completion. If a completion rig is used rather than the drilling rig for the completion work, an additional rig move must be considered from both a cost and time standpoint.

A rule of thumb for estimating rig moving times is based on the IADC rig hydraulics code of 1, 2, 3, or 4, where the higher numbers represent larger rigs. Codes 1 and 2 can usually move in and out in 4 days because they are frequently mobile and truck mounted. Codes 3 and 4 require approximately 8 days to move in, rig up, and move out. These time estimates affect the move-in cost, supervision time, and overhead allocations.

Weather. The effect of weather on the projected time is not considered in most well plans. As an example, hurricanes and tornadoes cannot be routinely expected. However, weather problems such as those that routinely occur in the North Sea must be considered in the plan.

Cost Categories

The well cost estimate should be divided into several categories for engineering and accounting purposes. Engineering considerations include dry-hole and completed costs, logical grouping such as completion equipment or tubular goods, and convenience groupings such as rental equipment. Accounting considerations include tangible, intangible, and contingency items. The sample AFE summary in Fig. 11.25 illustrates several cost categories.

Tangible and Intangible Costs

Accounting and tax principles treat tangible and intangible costs in different ways. As a result, they must be segregated in the cost estimate. Although intangible costs are difficult to define precisely, they include expenditures incurred by the operator for labor, fuel, repairs, hauling, and supplies used in (1) drilling, perforating, and cleaning wells, (2) preparing the surface site prior to drilling, and (3) construction derricks, tanks, pipelines, and other structures erected in connection with drilling, but not including the cost of the materials themselves. The fundamental test is defining the salvage value of the item. If the item does not have a salvage value, it is an intangible.

Intangible drilling and development costs do not include the following:

  • Tangible property ordinarily considered as having salvage value.
  • Wages, fuel, repairs, hauling, supplies, etc., in connection with equipment facilities or structures not incident to or necessary for the drilling of wells, such as structures for storing oil.
  • Casing, even though required by state law.
  • Installation of production facilities.
  • Oilwell pumps, separators, or pipelines.

Detailed Cost Analysis. It is usually desirable to provide more cost detail than the general summary in Fig. 11.25. A sample of a detailed summary is shown in Fig. 11.26. Engineers wishing to evaluate detailed cost analysis worksheets should refer to Adams.[1]

Factors considered in the detailed cost analysis will be presented in the next section. The cost divisions presented in Fig. 11.25 will be used. These factors are heavily dependent on company drilling philosophy and, as such, may not apply to all companies.

Location Preparation

Preparing the location to accept the rig is an important cost factor and perhaps the most difficult to quantify. It includes a legal cost, surveying the location site, physical location preparation, and post-drilling cleanup. These costs are affected by the rig type, rig size, and well location.

Location costs include only those variables actually involved with a rig move-in. These costs do not include lease fees or bidding cost. Individual companies must determine appropriate methods for handling these costs in the well cost estimate.

Permits, or "permitting" the well, are required in virtually every drilling area in the world. Some permit procedures are as simple as preparing a few fill-in-the-blank documents, while others may require extensive, time-consuming efforts such as environmental and economic impact statements. Some well permits must be granted from federal or national authorities, while others may be obtained quickly from local agencies. Permitting a well is primarily a legal matter that often requires significant consultation with legal groups.

"Spotting" the well involves surveying the wellsite and determining its exact location. Land sites can be spotted by professional surveyors with the use of local, known markers. Offshore sites are spotted from offset platforms in the area. Satellite surveys can be used when spotting a well in an area, particularly in offshore environments where marker sites such as existing platforms are not available.

Right-of-way from a public access road to the actual drilling site for land wells must be considered. If the off-road distance is small or through single owner land, the permit may be obtained quite easily in some cases. Difficulties may arise for distant locations, multiple landowners, or public access areas. As in the case of obtaining permits, right-of-ways are often a matter for the legal departments.

Preparing the location to accept the rig depends on the rig type and size, as well as the location. Land rigs may require the construction of a board road and location if the soil is too soft to support transport vehicles and the rig. Sometimes pilings are required under the substructure. The size of the turnaround and the number of board plys will increase with larger rigs. Mountainous locations may need a road built to the site. In addition, factors such as the size of the mud reserve pit and the chemicals storage area depend on drilling times, mud types, and mud weights.

Marsh areas usually require that a canal or channel be dredged to the site. The depth and width of the canal must be coordinated with the size of the rig. The rigsite at the end of the canal is a larger area that must be dredged. Shell pads for a rig foundation may be required in marshy areas if the water depth is sufficiently deep to prevent the direct use of a barge rig or if the seabed is very soft or erodes because of subsea currents.

Offshore sites often require the least amount of location preparation. If surveys of the seafloor show that no obstructions are present, the rig can be moved to the site with no additional efforts. Floating rigs are seldom troubled with soft subsurface formations that may hamper settling of the legs for jackup rigs.

Location cleanup after drilling has been completed is currently undergoing close scrutiny by regulatory bodies. Most sites must be restored to a predrilling condition that may involve site leveling, trucking, and in some cases replanting wildlife vegetation. Offshore sites usually are required to ensure that no remaining obstructions will hamper commercial fishing operations.

Drilling Rig and Tools

The cost for drilling and completion rigs plus the associated drilling tools can be a substantial fraction of the total drilling costs. Consider drilling and completing the well in Fig. 11.24 in 75 days and use the rig costs shown in Table 11.8 for purposes of this example.

The first three cases used the same well design criteria and equipment (i.e., casing, mud, and logging—with the exception of the rig cost). Case 4 uses the same well in an offshore environment, resulting in the need for a jackup rig. As a result, it is easily seen that careful attention must be given to defining cost for the drilling rig and tools.

Move-in and Move-out. Moving the rig into the location before drilling the well and out of the location after it is completed can be a substantial cost item. Jack-up rigs require a fleet of tugboats, while drillships may be able to move themselves onto the location. Many states have published tariffs that specify the allowable trucking charges for various types of moves. Large land rigs are normally transported by truck to the location. Generally, IADC Type 3 and 4 rigs are sufficiently large that they must be transported piecewise by truck. Types 1 and 2 are usually truck-mounted rigs, which reduces the moving time and associated trucking requirements.

Procedures for estimating rig cost can be developed with the rig cost and average moving times. A survey of numerous drilling contractors showed that Type 1 and 2 rigs usually require approximately 4 days for move-in, rig-up, rig-down, and move-out. Type-3 and -4 rigs required 8 days for land and offshore rates, although the elements of this time value are different (i.e., land rigs are transported by truck while jackups are towed by boat.

The cost for move-in and move-out is estimated as the standby rig rate over the moving time (4 or 8 days). The standby rate is slightly less than the day rate for drilling and may include support services such as crewboats that would be required for normal drilling operations. This method for estimating the rig moving costs is effective and reasonably accurate. It is not useful, however, in unusual circumstances such as overseas rig moves and drillsites requiring helicopter transportation.

Footage Bid. Many operators prefer to drill on a footage or turnkey basis. The drilling contractor provides a bid to drill the well to a certain depth, or until a certain event, such as encountering a particular formation, kickoff point, or geopressure. Footage contracts may call for drilling and casing a certain size hole through or to the expected pay zone. Contract clauses may allow reversion to day work (flat rate per day) if a marked increase in drilling hazards (loss of circulation, kick, etc.) occurs. For example, ABC Oil Co. may contract XYZ Drilling Co. to drill a well to 10,000 ft for a flat fee of U.S. $27.50/ft. The drilling company is responsible for all well operations until the contracted depth is reached.

The footage contract defines cost responsibilities for both parties. The operator may pay for all pipe, cement, logging, and mud cost. The contractor is responsible for all rig-associated costs such as move-in and move-out, drilling time, and bits. At the target depth or operation, all costs and operational responsibilities revert to the operator.

This contract arrangement can offer significant advantages to both parties. Operators are not required to staff a drilling department for drilling a single well or a few wells. The drilling contractor, with proper bid preparation and efficient drilling practices, can gain a greater profit than while on straight day-work rates. Possible problem areas for the drilling contractor include mechanical breakdowns creating unexpected costs, poor well planning, geological anomalies, or "force majeure" situations.

Day-Work Bid. Perhaps the most common drilling contract is the day-work rate. The contractor furnishes the rig at a contracted cost per day. The operator directs all drilling activities and is responsible for the well-being of the hole. The rig may be with or without crews or drillpipe. In addition, options such as high-pressure blowout preventers (BOPs) or sophisticated solids-control equipment required by the operator must be furnished at his own expense.

Rig selection and cost depend on the well. Although rigs are often rated by their capability to drill to a certain depth, the controlling criterion is usually the casing-running capability (i.e., derrick and substucture capacity). A rig rated for 18,000 ft of drilling may not be capable of running 15,000 ft of heavy 9⅝-in. casing. Therefore, the well plan must be developed and analyzed before rig selection.

Rig costs vary considerably and are dependent on items such as supply and demand, rig characteristics, and standard items found on the rig. Results of a study to compare U.S.-operated rig costs are shown in Fig. 11.27. The guidelines were the rig

s derrick and structure capacity and disregarded items such as optional equipment that might otherwise be rented for lesser rigs. An interesting point on the illustration is that the over-supply rig costs were reasonably equal regardless of the rig size (i.e., U.S. $6,000 vs. $9,500/day for small to very large rigs).

Standby rates for drilling rigs usually range from U.S. $200 to $500/day less than the amounts shown in Fig. 11.27. The rates include crews and drillpipe. The costs are used to estimate move-in and move-out charges.

Fuel. Drilling contracts are either inclusive or exclusive of fuel on the rig. This major contract policy change occurred in the late 1970s when fuel charges increased from $0.20 to $1.20/gal.

Fuel usage is dependent on equipment type and rig. Fuel consumption rates were evaluated in the study previously described for rig cost rates. The results are shown in Fig. 11.28. The average consumption rate is evaluated as a function of the rig size measured by its ability to run casing.

Water. A supply of water is an important consideration. The water is used to wash the rig, mix mud and cement, and cool the engines and equipment.

Water can be supplied in three ways. A shallow water well can be drilled. This method is common in most land operations, but it is not feasible offshore or with deepwater tables on land. Water can be transported to the rig by means of truck, pipelines, barges, or boats. In addition, offshore rigs can use seawater.

Many engineers use a value of U.S. $5,000 to $10,000 for water costs. This amount is approximately the cost to drill a shallow water well. It is also a fair estimate of the cost to lay a water line from a nearby water source. In any case, water costs are seldom considered as a major impact on the total cost estimate.

Bits. Establishing a bit cost depends on the number, size, and type of bits and their respective cost. The bit type, size, and number should have been previously defined in the well plan by the time the AFE is prepared. If the bit is a standard IADC-code bit, published prices are available. Prices are not readily available for specialty bits or for diamond and polycrystalline bits.

Diamond-bit costs depend on the bit size as well as the diamond size, spacing, and quality. In most cases, these bits are made upon demand and are not off-the-shelf items. A rule-of-thumb cost guide for diamond bits is $2,500/in. of bit diameter. For example, a 10-in. bit would cost approximately U.S. $25,000. Salvage values of up to 40%; of the bit cost are often granted on used bits. From a conservative view, many engineers prefer to disregard bit salvage value when estimating bit costs, in case the bit is completely destroyed.

Polycrystalline bits are a staple in the drilling industry. Their physical structure, drilling performance, and cost are significantly different from roller-cone or diamond bits. Sample costs for these bits are shown in Table 11.9.

Completion Rigs. A completion rig is a small workover rig that costs considerably less than a large drilling rig. Operators often use these rigs when the completion procedures are expected to require significant amounts of time. The drilling rig is used until the production casing is run and cemented.

Costs for completion rigs can be determined from Fig. 11.27. Tubing or small drillstring load requirements are used instead of casing capacity. Economic decisions to use a completion rig must also consider the cost of the rig moving onto the location, as well as the daily-rate differences between the drilling and completion rigs.

Drilling Fluids

Drilling fluids are an important part of the well plan and drilling program. The prices are based on build cost for a certain mud weight and a daily maintenance expense. These costs vary from different mud types and are dependent on the chemicals and weighting material required and on the base fluid phase, such as water or oil. Miscellaneous cost factors include specialty products such as hydrogen sulfide scavengers, lost-circulation materials, and hole-stability chemicals.

The build cost for a mud system (Fig. 11.29) is the price for the individual components and mixing requirements. Oil-based muds have a higher build cost than most water-based muds because of the expensive oil phase, the mixing and emulsion-stability chemicals, and the additional barite required to achieve comparable densities with water-based muds. Fig. 11.30 shows a comparison of build costs for an oil-based mud (invert type) and a lignosulfonate mud. The total build cost includes purchasing the initial mud system and the expenses involved with increasing mud weight in the well as it is drilled.

The maintenance costs for deep, high-pressure wells are usually larger than the build costs. The maintenance fee includes the chemicals required daily to maintain the desired mud properties. These chemicals include fluid-loss agents, thinners, and caustic soda.

Fig. 11.30 shows an estimate of empirically derived maintenance costs for invert emulsion, oil muds, and lignosulfonate water muds. The illustration demonstrates that heavy muds can have high daily fees. A system with 1,000 bbl of 16.0-lbm/gal lignosulfonate mud would cost approximately U.S. $2,700 for daily maintenance. In addition, note that the maintenance costs for invert-emulsion muds is significantly less than that for lignosulfonate muds, even though the reverse is true for build costs.

Several additional factors affect mud costs. Small mud companies can often provide less-expensive mud systems than larger companies, although a sacrifice is made occasionally in terms of technical support and mud-problem testing capabilities. In addition, many mud companies offer mud without technical support at a price reduction over mud with engineering support.

Packer Fluids. Packer fluids are placed between the tubing and production casing above the packer. The fluid is usually a treated brine but can be an oil mud or treated water-based mud-type fluid. In some cases, a packer fluid will not be used. Although a low-density brine is commonly used, occasionally a higher-density water or mud is used for pressure control.

Completion Fluids. Special fluids are occasionally used for well-completion purposes. They are usually designed to minimize formation damage. The fluids may be filtered brine, nitrogen, or oil. Costs for these fluids must be considered on a case-by-case basis.

Rental Equipment

Drilling equipment that is beyond the scope of the contractor-furnished items is almost always required to drill a well. These items must be rented at the expense of the contractor or operator, depending on the provisions of the contract. They can include well-control equipment, rotary tools and accessories, mud-related equipment, and casing tools. These items can represent a substantial sum in deep, high-pressure wells.

Well-Control Equipment. Drilling contractors usually furnish BOPs, chokes, choke manifolds, and, in some cases, atmospheric degasser units. However, the equipment may not be satisfactory for a particular well. In addition, some land rigs currently operate with well-control equipment that is not state of the art, such as positive chokes, manual chokes, and manifold systems that do not have centrally located drillpipe- and casing-pressure gauges.

BOP rental is expensive. High-pressure stacks range from U.S. $1,500 to $3,000/day, exclusive of chokes or manifolds. The operator must define the worst pressure case that can feasibly be attained and select preventers accordingly. Cost estimates for a complete stack must consider the spherical, multiple ram sets, spools, studs, ring gaskets, and outlet valves.

Remotely controlled, hydraulic adjustable chokes are considered state-of-the-art and are available from several sources. Contractors seldom furnish this type of choke primarily because operators have always assumed this cost responsibility. These chokes usually cost U.S. $50 to $125/day with a 30-day minimum charge. Choke manifolds must be designed to withstand the maximum pressure ratings in addition to coinciding with current company philosophy.

Rotary Tools and Accessories. Rotary tools are items related to the drillstring or equipment that turns the string. The operator may be required to furnish (1) support equipment for the contractor ’ s drillpipe, or (2) a completely different string if the contractor’ s drillpipe does not meet the requirements (i.e., tapered or work strings). Some of the items that may require consideration include drillpipe, drill collars, Kelly drive bushing, Kelly cock valves (upper and lower), inside BOP, full-opening safety valves (FOSV), safety clamps, elevators, slips, and pipe rubbers. The operator must evaluate the requirements for drillpipe sizes different from those offered by the contractor’

s rig. A recent study of U.S. rigs showed that pipe sizes on the rig could be correlated with the IADC hydraulics code (Table 11.10). In addition, Table 11.10 includes guides for drill-collar and casing combinations.

For example, 4.5-in. drillpipe with 6.5-in. collars would not be recommended for drilling inside of 7.625-in. casing because of the wear of the tool joints and collars on the casing. A smaller pipe- and collar-size combination would be recommended. If the 7.625-in. pipe were a drilling liner, a tapered string would be satisfactory, but an extra BOP might be required.

A work string consists of small-diameter drillpipe and collars. It is used generally during completions or workover operations. Because the pipe will be used inside production casing, the usual sizes are 2.375 to 3.5 in. Most operations require a rental string because few rigs drill with this size pipe.

Mud-Related Equipment. A properly maintained mud system offers many benefits to the operator. To achieve the desired level of system efficiency, several specialized pieces of equipment may be required. Some of the equipment must be rented, even though the drilling rig may be well equipped with other drilling tools.

A complete suite of equipment required for the mud job usually depends on the mud type and weight. The following suite may be used for mud weights in the 8.33- to 12.0-lbm/gal range.
  • Multiscreen shaker.
  • Desilter (with pumps).
  • Mud/gas separator.
  • Degasser (vacuum).
  • Pit/flow monitors.
  • Drill-rate recorder.
  • Gas detector.

Mud weights greater than 12.0 lbm/gal may require the use of additional equipment such as a centrifuge or mud cleaner. Oil muds need a cuttings cleaner to remove the oil from the cuttings prior to dumping.

Casing Tools. Recently, great strides have been made in running casing. Specialized equipment and crews normally handle the task rather than using the rig crew and equipment. Because most rigs are not furnished with casing-running equipment, it must be rented.

Casing tools must be selected according to size and loading requirements. A commonly used method for evaluating the load requirement is to add a design factor of 1.5 to the in-air weight of the casing string. For example, a casing string that weighed 500,000 lbf in air would require 375-ton casing tools.

The suite of equipment to run casing depends on the operator ’ s preference. It can include elevators, slips, bales, protector rubbers, power tongs, a power-tong hydraulic unit, stabbing boards, drift gauges, a thread-cleaning unit, and safety clamps. In addition, it is usually desirable to rent several pieces of backup equipment in case of breakdowns, in most cases an inexpensive type of insurance. These items include backup tongs, a backup power unit, and a backup elevator/slip combination unit. Laydown and pickup machines were introduced to the industry in the late 1970s. These units increase the efficiency and safety of picking pipe up to the rig floor or laying it down on the pipe rack. Also, they usually minimize possible damage to pipe threads.


Cost development for cementing charges requires an evaluation of the cement type and volume, spacer-fluid requirements, special additives, and pumping charges. These various charges usually apply for each primary cement job, stage slurries, squeeze slurries, plugs, and surface-casing top-outs. Cost will vary for land and offshore jobs.

Pumping Charges. Onshore and offshore pumping charges for one cementing company are shown in Fig. 11.31. The charges increase with depth and for the offshore case. Also, pumping charges for casing and drillpipe will vary.

In addition to the primary cementing pump, most operators use a standby pump unit in case of mechanical failure on the primary unit. The ill effects of cementing-up the casing or drillpipe as a result of equipment failure overshadow the standby pumping unit charges. Rates for land-based standby pump trucks are approximately U.S. $100 to $150/hour.

Cement Spacers. A cement spacer is used to separate the cement from the drilling mud in an effort to reduce cement contamination. The chemical cost for a barrel of spacer fluid is approximately U.S. $50 to $100 depending on the amount of retarder. Barite charges or other weight materials must be added. In addition, diesel charges in the spacer must be considered when the drilling fluid has a continuous oil phase.

Cement Additives. The major cost for large cement jobs such as surface casing is the chemical and additives charges. Typical costs are listed next.
  • Cement U.S. $7.00/sack
  • Barite U.S. $15.00/sack
  • Gel U.S. $15.00/sack
  • Mixing charges U.S. $0.95/ft 3

A reasonable rule-of-thumb for computing the cost of special additives such as water-loss agents and thinners is 75%; of the charges for cement, gel, and barite.

Quick-set, top-out cement is often used on surface casing. It provides short-term strength that allows surface-equipment rigging to proceed while waiting on the other cement to cure. The slurry usually consists of 50 to 100 sacks of cement at approximately U.S. $10/sack.

Support Services

Drilling operations require the services of many support groups. In some cases, these groups are used because they can do a particular job more efficiently than the rig crew. An example of this efficiency is casing crews who are experienced in running large-diameter tubulars. Other support groups may provide services that cannot be performed by the rig crew or operator (i.e., well logging, pipe inspection, or specialized completions). Regardless of the reasons for using support services, their costs affect the total well cost and, as such, must be considered.

Casing Crews. During the early years of the drilling industry, the rig crews ran all casing and tubing strings into the well. However, increasing well depths and tubular sizes made the process more difficult. In addition, items such as specialized couplings and pipe torque measurements gave rise to the requirements for the use of casing crews specialized in running the tubulars. Today ’

s industry uses not only casing crews but also groups specialized in picking up and laying down casing, tubing, and drillpipe.

Casing crew charges are dependent on crew size, pipe size, and well depth. Crew sizes usually range from 1 to 5 members. Fig. 11.32 shows the charges for a 5-member crew. In addition, a power-tong operator is required at rates ranging from U.S. $75 to $125/hour.

Mud Logging. Monitoring services such as mud logging, cuttings interpretation, and gas monitoring are often used on deep or high-pressure wells. A variety of services at different costs are available. A few services and general cost ranges are shown in Table 11.11.

Well Logging. Formation-evaluation services, or well logging, are done on every well. The service may include formation evaluation, casing and cement logging, and hole-inclination surveys.

Charges for well logging vary with suppliers. However, some consistency does exist across the industry. Each logging operation will have a flat setup charge for each time the unit is rigged up (i.e., once for openhole logging call-out and once for cased-hole logging at each depth). A depth charge, usually on a per-foot basis, is applied to the deepest depth for each tool run. An operation charge is applied for each foot that the tool is operated. Estimation of the logging cost requires that a well logging program be established (Table 11.12). In addition, offshore logging is significantly more expensive than land operations.

Perforating. Perforating charges may not apply if the well is gravel packed or abandoned. The charges include setup, depth charge for minimum shots (usually 20), and a charge per shot over the minimum (Table 11.13). The total shots depend on the length of the productive zone and the shot density (e.g., 4 shots/ft). Assuming a setup charge of U.S. $750 and 20 shots as the minimum, Table 11.13 illustrates some of the costs involved with perforating.

Formation Testing. Wireline formation testing is an economical method of obtaining reliable formation information. The repeating formation tester is a device that takes samples of pressure and fluids from a zone of interest. It should be included in the cost estimate for every exploratory well.

Charges for the service are on a depth and per-sample basis. Setup charges are usually not applicable because the service is often run in conjunction with other logs. An example cost for a 15,000-ft sample would be U.S. $2,550/sample with a U.S. $0.55/ft depth charge.

Completion Logging. Various types of production logs can be run on the well if it is completed. These logs are generally run before perforation so that pre- and post-production formation evaluations can be made. Because production logging is a complex subject, the appropriate log suite must be developed jointly by the drilling and production engineers.

Tubular Inspection. Pipe inspection is an important aspect of the casing and tubing program. These support services may include magnetic particle inspection, thread and end-area visual inspection, hydrostatic pressure testing, and pipe drifting. Typical charges for the services are U.S. $5 to $30/joint for each item and are service and pipe-size dependent.

Galley Services. Catering services for the galley of offshore or marsh rigs may not be included in the day-rate charges for the rig. The catering company will supply the cooks, support crews, and food for a per-man-day fee. Typical charges are U.S. $50/man-day for crews with less than 30 members and U.S. $47/man-day for crews with more than 30 members. For cost calculation purposes, average crew sizes for various rigs are given next.

Marsh barge: 30 men Jackup: 50 men

Floater: 70 men

Special Labor. Many items used on the rig and during drilling operations require specialized labor. These services are usually on a per-hour basis and at a minimum charge (4 to 8 hours). Typical considerations are:


In addition to the hourly charges for this labor, mileage and expenses must be considered.


Well costs are often underestimated because of subtle items such as transportation. For example, trucking charges for cementing a casing string may exceed U.S. $3,000, which includes round-trip charges for two pump units and a bulk truck. Careful evaluation of these charges will provide a better estimate of well costs.

Transportation can include charges for land-based trucks, barges, boats, and helicopters. Long-distance crew charges via commercial or chartered airplanes may be a significant cost. Accurate estimates of transportation costs require a detailed well plan, knowledge of the distance to the rig from local stock points, and rig characteristics such as standard equipment and crew size.

Trucking charges are computed from estimates of the number of trips, the round-trip mileage, and the per-mile cost. Current trucking costs are approximately U.S. $3.50/mile. A rule of thumb for round-trip mileage is to establish a base of 100 miles from the local stock point to the rig (round trip, 200 miles). Table 11.14 gives some guidelines for estimating the number of round trips to be considered on a well.

Marine charges are incurred for offshore operations and marshes. The costs include boats and any dock facilities. Current charges for boats operating in the Gulf of Mexico are summarized in Table 11.15.

Air charges occur for offshore operations and marshes. The costs include boats on a day-rate basis and begin at rig move-in. A small helicopter (3 to 4 passenger capacity) is required for day-to-day operations. A large helicopter is used for weekly crew damages (Table 11.16).

Supervision and Administration

Project management costs must be considered. These charges include well supervision and administration. Large costs can be incurred for deep wells or problem wells, such as those with H2S incident.

Supervision includes direct management of the well, including the on-site supervisor and any members of the office staff who are dedicated to the project. Mud or completion consultants may be considered as supervision. Specialized personnel such as mud loggers are not considered in the supervisory charges.

Administration charges can be handled in several manners. Some companies prefer to apply only direct supervision charges to a given well and charge support office staff members to general company overhead. Other companies divide all overhead charges among the wells to be drilled in a fiscal year.

Regardless of the accounting method, some of the charges that must be considered are

  • Staff engineering support.
  • Clerical support.
  • Office overhead.
  • Special insurance, including blowout insurance, and bonds.
  • Legal work.
  • Special document preparation.

A method for computing supervision and administration costs is to assume that a consultant will handle all operations. The on-site supervisor is the drilling consultant. An office consultant performs all administrative functions on an hourly basis (e.g., 200 hours for a dry hole and 300 hours for a completed well).


Casing and tubing costs are significant factors in the well cost. In some cases, they may account for 50 to 60%; of the total expenditures. The costs are dependent on well depth, size, grade requirements, and couplings.

Pipe costs are influenced heavily by several factors. Pipe size is a major consideration. Fig. 11.33 illustrates cost variations according to pipe size for N-80 grade long-thread and coupling (LTC) pipe that exceeds a burst rating of 5,000 psi in several sizes. Although engineering considerations should have the major impact on the pipe size selection, cost considerations should have some influence.

Costs increase with higher pipe grades. Table 11.17 shows costs for 40.0-lbm/ft., 9.625-in. pipe with LTC couplings. As in the case of the pipe sizes, however, pipe-grade selection is an engineering decision. Couplings are seldom selected as a result of costs. However, higher-price premium couplings may allow the use of smaller pipe sizes, which will reduce the overall well costs (Table 11.18).

Casing Equipment. Casing (or cementing) accessory equipment is used to accomplish an effective primary cement job. Although the equipment does not have a major impact on well costs, it should be considered. Table 11.19 shows a typical suite of equipment requirements for running and cementing casing. This equipment would cost approximately U.S. $3,500 for a 7⅝-in. casing string and U.S. $25,000 for a 7⅝-in. liner.

Drive-pipe costs must be calculated for wells that utilize the pipe. The charges vary for pipe sizes and wall thickness. A drive-shoe cost must be included. Typical drive-pipe size and costs are given in Table 11.20.

Wellhead Equipment

The wellhead equipment is attached to the casing string for pressure and stability support. Its cost is dependent on the number and size of the casing and tubing strings, pressure requirements, equipment components, and special features such as H2S stainless duty. Total equipment costs can range from U.S. $7,500 for a low-pressure set of equipment to U.S. $1,500,000 for high-pressure, stainless-steel wellhead equipment and a tree. Subsea completions are even more expensive.

The wellhead equipment consists of the casing head, intermediate and tubing spools, and the production tree. The casing head is attached to the surface casing and will ultimately support all casing loads. Intermediate or production casing is hung inside the casing head. The intermediate spool supports the production casing if an intermediate string is run. The tubing spool is run only if the well is completed. It is set on the casing head or intermediate spool. The tree contains the production valves and chokes used for producing the oil or gas.

Completion Equipment

The completion equipment consists of downhole tools related to the tubing string. These items include: packers, seal assemblies, flow couplings, blast joints, and landing nipples. They are dependent primarily on tubing size and fluid content.

Packers. The packer is designed to divert formation fluids into the production tubing. It is selected according to production-casing size, bore size requirements, tensile loading, and seal-assembly type. In addition, H2S-serviceable packers contain seals that are approximately 100 times more costly than the standard rubbers.

Blast Joints. Blast joints are thick-walled tubulars placed in the tubing string opposite the perforations to minimize the damage from erosion by the produced fluids. Their cost is dependent on tubing size and number of joints.

Seal Assembly. The seal assembly is an important part of the completion equipment. The cost is affected by the required number of seal units, the connection type, and the pipe size.


CB = bit cost, U.S. dollars
CR = rig cost, U.S. dollars
d = diameter, in.
dDS = drillstring diameter, in.
dH = hole diameter, in.
D = deepest interval, ft
Di = depth of interest, ft
Dn = deepest normal zone, ft
pform = formation pressure, lbm/gal
ph = hydrostatic pressure, psi
Qm = mud-flow rate, gal/min
Qp = pump output, bbl/min
TR = rotating time, hours
TT = trip time, hours
v = annular velocity, ft/min
V = annular volume, bbl/1,000 ft
Vα = annular velocity, ft/min
Y = footage per bit run, ft
ρ = mud weight, lbm/gal
ρekick = equivalent mud weight at the depth of interest, lbm/gal
ρo = original mud weight, lbm/gal
Δp = differential pressure, psi
Δρtrip = trip margin, lbm/gal
Δρkick = incremental kick mud weight increase, lbm/gal


  1. _

General References

Adams, N.J. 1977. How to Control Differential Pipe Sticking, Part 1—What is the Problem. Petroleum Engineer. 49 (September).

Adams, N.J. 1977. How to Control Differential Pipe Sticking, Part 2—Procedures to Free the Drill String. Petroleum Engineer. 49 (October).

Adams, N.J. 1977. How to Control Differential Pipe Sticking, Part 3—Field Study Presents New Results. Petroleum Engineer. 49 (November).

Adams, N.J. 1978. How to Control Differential Pipe Sticking, Part 4—Economic Methods to Avoid or Free Stuck Pipe. Petroleum Engineer 50 (January).

Hunter, D. and Adams, N. 1978. Laboratory and Field Data Indicate Water Based Drilling Fluids That Resist Differential-Pressure Pipe Sticking. Presented at the Offshore Technology Conference, Houston, Texas, 8–11 May. OTC-3239-MS.

Adams, N. and Frederick, M. 1982. How to estimate well costs. Oil Gas J. 80 (49): 131-136.

Adams, N. and Frederick, M. 1982. Rig, mud, rental tools account for about half the cost of a new well. Oil Gas J. 80 (50): 104-108.

Adams, N. and Frederick, M. 1982. Tangible drilling expenses complete authorization-for-expenditure preparation. Oil Gas J. 80 (52): 194-196.

Adams, N. 1985. Three-step bit selection can trim drilling costs. Oil Gas J. 83 (24): 118-122, 127-128.

Adams, N.J. 1978 Well Control Problems and Solutions. Tulsa, Oklahoma: PennWell Publishing Co.

Bourgoyne, A.T., Millheim, K.K., Chenevert , M.E. et al. 1991. Applied Drilling Engineering. Richardson, Texas: Textbook Series, SPE.

Greenip, J. 1978. Care and Handling of Oilfield Tubulars. Oil & Gas J. (October 9).

Fertl, W.H., Chilingar, G.V., and Rieke, H.H. 1976. Abnormal Formation Pressures. New York City: Elsevier Scientific Publishing Company.

Prentice, C.M. 1970. "Maximum Load" Casing Design. J Pet Technol 22 (7): 805-811. SPE-2560-PA.

SI Metric Conversion Factors

bbl × 1.589 873 E – 01 = m3
ft × 3.048* E – 01 = m
ft3 × 2.831 685 E – 02 = m3
gal × 3.785 412 E – 03 = m3
in. × 2.54* E+


= cm
lbm × 4.535 924 E – 01 = kg
mile × 1.609 344* E+


= km
sq mile × 2.589 988 E+


= km2
psi × 6.894 757 E+


= kPa
ton × 9.071 847 E – 01 = Mg
  • Conversion factor is exact.