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Casing Setting Depths and Sizes The principal purpose of casing is to ensure the integrity of the well during drilling and production. The selection of casing setting depths is critical for casing off troublesome formations, containing pressure, or protecting fresh water formations. Casing design evolves from completion requirements, as the completion equipment dictates the size of the production casing or liner. Casing sizes at necessary depths uphole escalate as needed for clearance. Tubular strengths are selected as the well conditions dictate, and materials are selected to resist corrosion. Wellhead and blowout-prevention systems must be compatible with the tubulars in pressure rating and material. Prior to designing casing strings, the engineer must study pressure requirements and prepare a mud-density schedule. A plot of fracture gradient versus depth should be prepared, although in some instances knowledge of the fracture gradients at the casing depths under study is sufficient. Leakoff data on new wells is particularly valuable. Hole problems must be thoroughly identified and the need to design for acid gases or other corrosion problems evaluated. Conductor Casing Setting depth is usually shallow (80 to 150 ft) and selected so that drilling fluid may be circulated to the mud pits while drilling the surface hole. The casing seat must be in an impermeable formation with sufficient fracturing resistance to allow fluid to circulate to the surface. With subsea wellheads, no attempt is made to circulate through the conductor string to the surface. It is set deep enough to assist in stabilizing a guide base to which guide lines are attached. Large sizes (usually 16 to 30 in.) are required as necessary to accommodate subsequently required strings. Surface Casing Setting depth should be in an impermeable section below fresh-water formations. In some instances, near-surface gravel or shallow gas may need to be cased off. The depth should be great enough to provide a fracture gradient sufficient to allow drilling to the next casing setting point and to provide reasonable assurance that broaching to the surface does not occur in event of closure on a kick. In hard-rock areas the string may be relatively shallow (300 to 800 ft), but in soft-rock areas deeper strings are necessary. Surface casing

Well Design Considerations

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Well Design Considerations

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Casing Setting Depths and Sizes

Casing Setting Depths and Sizes The principal purpose of casing is to ensure the integrity of the well during drilling and production. The selection of casing setting depths is critical for casing off troublesome formations, containing pressure, or protecting fresh water formations. Casing design evolves from completion requirements, as the completion equipment dictates the size of the production casing or liner. Casing sizes at necessary depths uphole escalate as needed for clearance. Tubular strengths are selected as the well conditions dictate, and materials are selected to resist corrosion. Wellhead and blowout-prevention systems must be compatible with the tubulars in pressure rating and material.

Prior to designing casing strings, the engineer must study pressure requirements and prepare a mud-density schedule. A plot of fracture gradient versus depth should be prepared, although in some instances knowledge of the fracture gradients at the casing depths under study is sufficient. Leakoff data on new wells is particularly valuable. Hole problems must be thoroughly identified and the need to design for acid gases or other corrosion problems evaluated. Conductor Casing

Setting depth is usually shallow (80 to 150 ft) and selected so that drilling fluid may be circulated to the mud pits while drilling the surface hole. The casing seat must be in an impermeable formation with sufficient fracturing resistance to allow fluid to circulate to the surface. With subsea wellheads, no attempt is made to circulate through the conductor string to the surface. It is set deep enough to assist in stabilizing a guide base to which guide lines are attached.

Large sizes (usually 16 to 30 in.) are required as necessary to accommodate subsequently required strings.

Surface Casing

Setting depth should be in an impermeable section below fresh-water formations. In some instances, near-surface gravel or shallow gas may need to be cased off. The depth should be great enough to provide a fracture gradient sufficient to allow drilling to the next casing setting point and to provide reasonable assurance that broaching to the surface does not occur in event of closure on a kick.

In hard-rock areas the string may be relatively shallow (300 to 800 ft), but in soft-rock areas deeper strings are necessary. Surface casing setting depths are often specified by government regulatory bodies to protect fresh-water sands.

Intermediate or Protective String

A protective string may be necessary to case off lost circulation, salt beds, or sloughing shales. In cases of pressure reversals with depth, protective casing may be set to allow reduction of mud density. The most predominant use is to protect normally pressured formations from the effects of increased mud density needed in deeper drilling.

When a transition zone is penetrated and mud density increased, the normal pressure interval below surface pipe is subjected to two detrimental effects:

The fracture gradient may be exceeded by the mud gradient, particularly if it becomes necessary to close in on a kick. The result is loss of circulation and possibly an underground blowout;

The differential between mud column pressure and formation pressure is increased, which increases the risk of stuck pipe.A practical "rule of thumb" is to set the intermediate casing when the mud density is approximately 12.5 to 13.0 ppg, which limits both of the detrimental effects described. However, even these mud weights may be excessive in certain areas. Attempts to drill to higher mud-weight requirements are sometimes successful, but many holes have been lost by attempts to extend the protective string setting depth beyond that indicated by the above rule. Either kicks occurred causing loss of circulation and possibly an underground blowout, the pipe became differentially stuck, or sloughing of the high-pressure zone caused stuck pipe.

Significantly, in soft-rock areas the fracture gradient increases relatively slowly as depth of the surface casing string is changed, but the pressure gradient in the transition zone usually changes rapidly. Emphasis is often placed on setting surface casing to an acceptable fracture gradient. It should be noted that greater control of potential conditions at the surface casing seat exists in the protective casing setting depth decision.

It is often tempting to "drill a little deeper" without setting pipe in exploratory wells. When pressure gradients are not increasing this can be a reasonably acceptable decision, but with increasing gradient the risk is great and should be carefully evaluated.

To ensure the integrity of the surface casing seat, leakoff tests should be specified in the Drilling Procedures section of the well plan.

It is sometimes necessary to alter the setting depth of the intermediate casing during drilling if:

hole problems prohibit continued drilling;

pore pressure changes occur substantially shallower or deeper than originally calculated or estimated.For this reason the well plan should state the pore-pressure requirement at which casing should be set in a transition zone.

Liner

A liner is often economically attractive in deep wells as opposed to setting a full casing string. This decision must be carefully considered because the intermediate string must be designed with a burst requirement suitable for the depth of the liner. This increases the cost of the intermediate string. Also, the possibility of continuing wear of the intermediate string must be evaluated. If there is to be a production liner, then either the production liner or the drilling liner should be tied back to the surface as production casing. If the drilling liner is to be tied back it is usually best to do so before drilling hole for the production liner. By doing so, the intermediate casing can be designed for a lower burst requirement, resulting in considerable savings. Also, any wear in the intermediate string is covered up prior to drilling the production interval.

If increased mud density will be required while drilling hole for the drilling liner, then leakoff tests should be specified under Drilling Procedures for the intermediate casing shoe. The fracture gradient at the shoe may limit the depth of the drilling liner. In Figure 1 the fracture gradient at the intermediate casing shoe is indicated to be 17.3 ppg.

Figure 1

This would limit drilling to 14,000 ft, where the mud weight requirement is 17.3 ppg. Leaving in a 0.5-ppg kick margin would limit drilling to about 13,500 feet. At this depth the fracture gradient would be approximately 18.6 ppg for further drilling below the drilling liner.

The conditions described are in a commonly found range, but the depth decisions depend on the accuracy of the fracture gradient calculations, which can have significant error. In areas where experience cannot be drawn upon for accurate fracture gradients, leakoff tests should be specified, and setting depths altered if necessary.

Production String

Whether production casing or liner is set, the depth is determined by the geological objective. Depths may have to be altered accordingly if the well runs higher or lower than the geologic prognosis. The objective and method of identifying the correct depth should be stated.

Casing and Hole Sizes

Generally, standard bit sizes should be run, but thick casing walls may be necessary in deep wells for sufficient strength. The designer can sometimes solve this problem by specifying special drift casing. This allows the use of bits with diameters approaching the inside diameter of the casing, rather than being limited by drift (tolerance) diameter. Manufacturers make oversize casing in several sizes providing strength comparable to APT sizes, but with clearance for standard bit sizes.

Tubular and Wellhead Design

Following the development of mud weight requirements and selection of casing setting depths, the first consideration in casing design is determination of design loads. These vary for surface casing, intermediate casing, and drilling liners as compared to production casing and production liners.

Surface and intermediate String Design

Collapse: Collapse load (or collapse pressure) is the point at which the hydrostatic pressure of the fluid column in the annulus exceeds the casing pressure, causing the casing to collapse. Cooke et al. 1982, 1983 have shown that after a cementing job, the annular pressure gradually reduces to formation pressure in both the drilling fluid and the cement. Usually, however, the hydrostatic pressure at the time of cementing is used in calculating the casing pressure required to prevent collapse, thus providing some safety margin.

Considerable cost savings result from basing design loads on the assumption that surface and intermediate strings will not be completely emptiedfor example, that the string will not be more than 15% empty. This might vary with the area to some extent, but has been used by some companies for years.

The lower end of casing is in compression due to hydrostatic pressure on the end of the pipe. Where the pipe is in axial tension the effect of tension on collapse rating should be considered.

Two special conditions should be carefully considered on a different assumed-load basis:

When strings are cemented through salt, particularly deep, thick salt at elevated temperature, there is usually a collapse load that is unidirectional and design load may need to be 1 psi/foot of depth. In some severe cases it has been necessary to set overlapping strings through the salt with cement between;

When cementing structural or surface strings through drillpipe, the collapse loads may be high due to the difference in hydrostatic pressure of the cement column in the casing/openhole annulus and the mud column in the drillpipe/casing annulus. Large casing having low collapse strength could collapse during cementing.Burst: The maximum burst load occurs if the string is emptied and the well is closed in on dry gas. The maximum load is at the surface. The maximum pressure at the casing seat is the formation pressure in the gas zone less the hydrostatic pressure of the gas back to the casing seat, or the fracture pressure at the casing seat, whichever is the lowest. The surface pressure is the maximum pressure at the casing seat less the hydrostatic pressure of the gas to the surface.

If oil is known to be the only hydrocarbon present, the hydrostatic pressure is taken as that of the oil column, but in exploratory drilling a gas column is usually assumed. Burst loads at the surface also dictate the wellhead and blowout prevention equipment ratings.

The burst load at the casing seat, or at any depth uphole, is the pressure inside the casing minus the formation pressure at that depth.

The above describes realistic maximum burst load conditions. However, the strings so designed are expensive and sometimes require high-strength casing, which is more prone to failure than more common grades. In very deep, high-pressure wells, 15,000+ psi surface pressures may occur if the well is emptied and closed in. Provision of adequate strength for the design basis described becomes more difficult. Sometimes either very high strength, brittle pipe must be used, or the assumed design load decreased. If hydrogen sulfide is expected, a lower-strength pipe, resistant to sulfide embrittlement, may need to be used.

In cases where surface pressures could exceed 20,000 psi, blowout preventers of sufficient rating are not available. It would be impossible to contain the maximum possible pressure.

Many companies design on the basis that less than maximum possible loads will occur. The U.S. Mineral Management Service only requires that casing be designed to withstand "anticipated pressure." Various assumptions are often made by different companiese.g., that the hole can always be kept full of sea water, that only a kick of a certain size and intensity will occur, or that maximum pressure will not exceed a certain amount.

Tension: The maximum tension load on a joint of casing usually occurs while it is hanging in the elevators because the tension decreases as the joint is run into the hole. This is due to the increasing hydrostatic pressure on the end of the pipe as it is run into the hole. Therefore, the tension load can be reasonably calculated at the top of a section as the buoyed weight of the pipe below. When the section is downhole the tensile stress is reduced, increasing the safety factor in tension above the calculated value. However, this effect is usually accepted and ignored in design.

Some companies design using air weight and others using buoyed weight. Often those who use buoyed weight use a higher design safety factor so that the resulting casing design may be nearly equal in tensile strength.

Two special conditions may warrant consideration of increased design load:

When pipe is set through a dogleg there will be a bending load, or, in an equivalent sense, a reduction in tensile strength;

In order to reciprocate pipe during cementing, drag and increased weight of cement inside casing will increase tension.In well planning, the first item is best handled by instructions in the drilling procedure to wipe out doglegs as they occur. The maximum permissible dogleg for each string should be calculated and included in the well plan.

The second can be handled by specifying a safe hook load (allowable pull) that will not reduce the tension safety factor below a preselected, safe value. When this is done, pipe often can be reciprocated during cementing; otherwise it may have seemed stuck, and movement would have stopped.

Presentation: Both the loads used in design and the strength of pipe are difficult to visualize from tabulated pipe and associated safety factors. A graphical design or supplementary graphical presentation such as shown schematically in Figure 2 is of considerable help in understanding the design.

Figure 2

In this illustration, the collapse and burst design loads (loads multiplied by a safety factor) are shown along with the strength of pipe used. Tensional designs can be shown graphically also. Usually the strength of pipe required in collapse and burst is high enough that tension strength automatically gives a design safety factor in excess of that stated as minimum.

Design: After the depths and sizes of casing and the loads have been determined, the next step is to select the most economical weights and grades of pipe that will satisfy the requirements. The designer must also determine if there is a need to select pipe resistant to sulfide stress cracking, and, if so, be familiar with suitable materials.

Change-over depths are easily determined graphically as shown in Figure 2 . The most economical weight and grade of pipe satisfying the collapse requirement at bottom is found and plotted on the graph as a vertical line. A second, more economical weight and grade is selected and plotted. The intersection with the load line determines the bottom of the second segment and the top of the first. Other, more economical segments are determined as necessary.

Burst (internal yield) ratings are graphed, along with collapse ratings. Toward the top of the hole the collapse strength greatly exceeds the collapse load, but the burst strength of the pipe may be less than the design load. An intersection of the burst strength line with the burst load design line determines the top of the segment and the bottom of a stronger segment needed to satisfy the higher burst loads nearer the surface.

When change-over depths are determined by calculation rather than graphically, a graph showing the loads and change-over depths is not essential. However, it can still be helpful in visualizing the design, particularly for review purposes.

The collapse strength of casing decreases with tension and burst strength increases with tension. Biaxial ellipse curves ( Figure 3 ) can be used to determine such changes when designing strings, but more recently triaxial stress calculations (Stair et al., 1983) have been used.

Figure 3

Triaxial stress calculations account for axial load and bending stress as well as internal and external pressures.

The strength of casing joints may be less (low efficiency), as high, or higher (high efficiency) than pipe body yield. The usable load (strength of pipe or joint divided by minimum safety factor) is often determined for both pipe and joint, and the lesser used for the maximum load to be hung on that kind of pipe. Approximately 80% of pipe problems appear to be with joints, particularly in tensional failures. Joint strengths are based on pullout force or minimum ultimate strength of the minimum cross section, and so are likely to fail at the published rating. The rating of the pipe body is based on minimum yield strength and the actual yield strength is normally higher. Although stretching pipe is not desirable, the pipe body would not part until the still higher ultimate strength is reached. This is 1.1 to 1.75 times as high as the yield strength. Thus, there is effectively a built-in safety factor in pipe body ratings compared to joint ratings.

Some companies take advantage of this situation by using a lesser safety factor for pipe body than for joint strengthe.g., 1.3 versus 1.75.

Makeup torque for the joint should be specified in the well plan.

When the number of segments in the design is small or a segment is short, consideration might be given to eliminating a weaker segment by extending a stronger segment. In some wells only one weight and grade might be used. This avoids making crossover joints and lessens the possibility of errors in running the segments in order. In deep wells, however, the use of a single weight and grade can be prohibitively expensive.

Allowable Pull: In emergency conditions it is necessary to know the maximum pull that can safely be exerted on casing. The advantage of an allowable pull calculation when reciprocating casing during cementing has already been explained. For this calculation a smaller safety factor (e.g., 1.3 versus 1.75) may be used.

Design Presentation: A form with blanks prompting inclusion of all relevant casing design items is helpful to the designer as a reminder of necessary calculations and as a step-by-step guide while making the design. It is also a vehicle for presenting in the well plan a condensed summary of the safety factors, sizes, weights and grades, joints, and lengths to be ordered and run, including screwage. It also calls for such important accessory design information as mud weight, fracture gradient, allowable pull, minimum ID and designer's identification. Blanks can also be included for triaxial stress safety factors and makeup torques.

Landing: Casing strings should be landed at least with hanging weight at time of cementing or according to calculated pick-up or slack-off loads to avoid casing buckling with increases in temperature and mud weight during deeper drilling. This should be clearly specified in the drilling procedures section of the well plan.

Holding the surface string in tension until the cement sets is critical. Any slack-off can create misalignment in the surface string and all subsequent strings, making the top joints subject to excessive wear, even though a drilling bushing is used.

Production Strings and Liners

Collapse: At some time during the history of the well there is a probability that the production string or liner will be emptied and maximum possible collapse load applied. Although the pressure in the annulus may reduce to formation pressure, the hydrostatic pressure at the time of cementing is usually used as the design load. Design on this basis results in an added safety factor above the calculated value, as does the strengthening of pipe in collapse by a cemented annulus and the effect of hydrostatically induced compression in the lower part of the string. The latter increases collapse strength above API rating. This uncalculated safety margin tends to counter corrosion that could weaken pipe in later years.

Burst: Burst loads are usually taken as the pressure that would result from a tubing leak at the surface. If lesser design loads are used, a pressure relief system for tubing-casing annulus would be necessary.

If the packer fluid has the same density as the backup fluid (or formation pressure if that basis is used), then the burst load is the same as tubing pressure from surface to packer for a full string. If the packer fluid has a higher density than the backup fluid, then burst load on the production casing increases with depth.

If the well is to be fracture-treated down casing, the surface pressure during the fracturing job must be known to the designer and incorporated into the casing design load.

Tension: Tension design loads are usually handled as for intermediate strings. Makeup torque for the joints should be specified.

Landing: Casing strings should be landed at least with hanging weight at time of cementing or according to calculated pick-up or slack-off loads to avoid buckling of the casing with temperature increases during production. This should be clearly specified in the Drilling Procedures section of the well plan.

Tubing Design

Joint strength of tubing is almost always greater than pipe-body yield, so design is usually on a pipe-body-yield basis. Conventionally, design is on an air-weight basis, since this provides considerable overpull in the event tubing is stuck in packer or mud.

On this design basis, the setting depth of tubing is determined by grade of pipe, regardless of size. Where deeper settings are required, a tapered string can be designed. If this is done, the same safety margin (strength less usable load) should be used for both sections after determining the usable load (pipe-body strength/safety factor) for the lower section.

Where lower-strength, sulfide stress cracking-resistant pipe must be used, setting depths can be extended by a tapered string design, use of a downhole tubing hanger, or a production liner with a polished bore receptacle through which production flows to the tubing string.

Burst design should be based on maximum expected surface tubing pressure unless the well is to be fractured, in which case the burst design should be based on the maximum expected surface pressure during fracturing.

Tubing for high-pressure wells should be pressure-tested to the rated value divided by the burst design safety factor. Mill test pressures are considerably lower than this value. The well designer may wish to specify mill tests to this value.

Industry experience in general indicates that the use of a teflon seal ring in joints is of considerable assistance in providing leak resistance. These are often used in high-pressure gas wells. Many premium connections are available that offer gas-tight sealing with or without a teflon seal ring.

Collapse safety factors are generally at least 1.0 as the strings may be swabbed, plugged, or used for formation tests, in which case internal pressure may drop to low levels.

Materials selection in deep, high-temperature wells with carbon dioxide and/or hydrogen sulfide can be affected by the decision as to how corrosion will be handled. Treatment methods may be by batch inhibition, continuous inhibitor injection, or use of high-alloy materials.

Landing nipples for bottomhole pressure gauges or plugs should be specified.

The type of packer or polished bore receptacle should be stated with the tubing design. The necessary slack-off or tension should be specified. Tubing landing practices and makeup procedures need to be fully described in the Completion Procedures section of the well plan.

Makeup: Makeup torque should be shown on the casing design summary. If the torque-turn method is to be used, it should also be designated and mentioned in the drilling procedure.

Mill test pressures are specified in APT Specification 5ST and are low compared to burst rating. These are not intended to be the basis for design. The test durations are short, usually about five seconds. Unless pressure tests to internal yield rating are specified, there is no assurance that the tubes will withstand rated pressure. When a 1.1 safety factor is used, the test might be 90% of rating. Joints may be tested at the mill in coupling made-up, hand-tight, or plain-tube condition. Couplings may be supplied by someone other than the tube manufacturer. Magnetic particle, ultrasonic, or electromagnetic inspection at the mill is often done only by the purchaser s request. All this indicates the unreliability of mill tests, even if inspected by a company representative at the time of manufacture. (In some instances, where pipe manufacture must be carefully controlled to ensure low hardness for sulfide use, mill inspectors may be necessary.) Even if pipe withstands mill tests, it can be damaged during shipment. In consideration of all these factors, field inspection of pipe is strongly recommended.

Field inspection is expensive and often is omitted in noncritical wells, but to ensure integrity of the pipe it should be field inspected by electromagnetic or ultrasonic testing methods. Threads (pipe and couplings) should be inspected by magnetic particle inspection or by Accu-Thread inspection.

Normally, tubing should be tested internally with water pressure equal to anticipated running pressure. These tests are brief, however, and leaks can still occur during actual use. Care in selection and makeup is the best insurance. Test pressures and inspection methods should be stated in the Drilling and Completion Procedures of the well plan.

Buckling

Increases in mud density, average temperature, and internally applied pressure tend to cause casing to buckle (corkscrew) . Tubular doglegs created by buckling become more severe in intervals of hole washout, resulting in high incidence of wear during continued drilling.

With tubing, a number of severe problems can occur:

Seals may move out of the packer, allowing treating pressures to burst casing;

Seal movement during production may wear out seals;

Seal movement during treating may be sufficient to permanently corkscrew tubing;

Excessive buckling of tubing may prevent tools from going to bottom;

Tubing may part in tension during treating;

Excessive rod wear may occur in buckled tubing.These can be avoided by prior analysis.

In severe circumstances, pressure may be held until cement sets and casing is landed to prevent severe buckling. Added tension may be pulled before landing to limit the buckling tendency and possible pipe movement in wellhead seals.

Service companies that do treating have computer programs that make tubing buckling analyses, or these may be done by the designer. In deep wells, such analyses are essential.

As a preventive measure, some designers run three joints of higher-grade pipe just above the packer to avoid permanent corkscrewing during treating or production. The necessary seals for treating conditions must be specified with a safe excess. Set-down weight to prevent tubing movement during production must be specified, and any increased loads due to treating must be incorporated in the tubing design.

Wellheads Casing spools and valves must have pressure ratings equal to or greater than the casing pressure rating. Considerable savings in nipple-up time can be realized by using spools in which two or more strings can be hung. This practice also avoids the necessary but unsafe procedure of removing blowout preventers in order to nipple up on casing conventionally. However, it tends to complicate pipe reciprocation during cementing.

Tubing heads must have provisions for removable tubing head plugs. Stainless trim or stainless heads are necessary for high-temperature, corrosive conditions. Metal-to-metal seals are preferred for severe conditions. A schematic drawing of the wellhead with an inventory and price list should be included in the well plan.

The entire tension loads of subsequent strings will be transferred to the surface string. The landing head on the surface pipe must be capable of supporting this load, as must the casing joints. In general, the compressive strength of casing is approximately equal to tensile strength if casing is well supported laterally, but there are exceptions.

Drilling Fluid Program Mud program design involves two stages. First, a data-gathering exercise is undertaken to accumulate information from as many sources as possible. Second, this data is used as background information to prepare the mud program for the upcoming well. The proposed mud program may be similar to past mud programs in the area or may be entirely different. The mud-program designers should feel free to make any changes, provided they will result in a more efficient drilling operation.

Information Gathering

Sources of In formation: Usually, the most accessible sources of information are the IADC drilling reports, mud recaps, and bit records for offset wells. Wireline and mud logs, which are sometimes more difficult to obtain, contain very valuable information. Consultations with personnel who have worked in the area can be very important. If the well to be drilled is in an entirely new area the geophysical and/or seismic data may be the only information available; in such cases, a discussion with the geophysicists may be helpful.

Data: One of the most important pieces of information is the pore pressure. Using the pore pressure, the mud weights required to drill the well safely can be estimated. The required mud weight sometimes affects the mud-type selection.

The casing program, usually submitted by the operator's drilling engineer, is another very important piece of data. A properly designed casing program cases off abnormal pressure zones and troublesome formations. Once the casing program has been approved, the mud program is then designed for maximum performance relative to borehole stability for each interval. This could require a complete change of mud types for different hole intervals. If at all possible the mud program should be designed so that one mud type, with progressive changes, can be used throughout the well, thus drastically reducing mud cost.

A review of the available mud recaps gives insight into the mud programs used previously in the area. Some important information on the mud recap is the mud type, type makeup water, mud weight requirements, mud-related problems, type of solids control equipment used, total days to drill the well, and mud cost. Careful attention should be given to the mud-related problems such as drag, torque, differential sticking, bridging, fill after trips, and lost circulation.

The available bit records, hydraulic programs, deviation program, and IADC drilling report should be reviewed for additional information. Downhole temperatures also affect the mud-type selection.

Mud Program Design

Having compiled and studied all the available information, the mud engineer is ready to begin planning the mud program for the upcoming well. The required casing program will have been submitted by the operator's drilling engineer to the person designing the mud program.

Mud Weight: From the pore pressure, the estimated mud weights for each interval are calculated along with fracture gradient. Factors directly affecting the mud weight program are abnormal pressure, lost circulation, water flows, gas intrusion, and borehole stability. Each of these parameters must be considered for each hole interval.

Mud Type Selection: Mud-type selection is based on numerous factors which must be considered for each interval drilled. One important factor is cost-effectiveness. Borehole stability is also an important parameter but must not overshadow economics. Trade-offs are sometimes necessary due to other factors such as available makeup water, bottomhole temperature, material availability, environmental constraints, solids-control equipment availability, logistics, and safety. In determining the most cost-effective system, all of the above factors play a role and must be considered together to obtain the most economical mud system.

Rheology and Fluid Loss: The rheological properties and fluid loss (API low-pressure and high-temperature/high-pressure) should be specified for each interval. Mud viscosity should be maintained as low as practical to improve penetration rate and assist in solids-control efficiency. Prior to weighting a mud, the API fluid loss should be reduced if differential sticking is a possibility. High-temperature/high-pressure fluid loss should never be specified at a temperature higher than the true bottomhole temperature of the well.

Problems and Contingencies: A thorough discussion of anticipated problems along with contingency plans should be provided. If lost circulation is prevalent in the area, a supply of materials should be maintained on location for preparing a lost-circulation treatment. If the possibility of differential sticking exists, materials for preparing a stuck pipe treatment should be maintained on location at all times, since freeing stuck pipe is time dependent (i.e., the sooner the treatment is spotted, the more likely the pipe will be freed) .

Corrosion Control: The possibility of corrosion should be assessed for the mud type being used. If the mud system may be corrosive, a corrosion monitoring program should be instituted. If necessary, a cost-effective chemical treatment program should be implemented to keep corrosion within acceptable limits.

Mud Products: A thorough discussion of mud products (their purpose and limitations) should be provided. Handling and mixing procedures should be specified for additives, especially hazardous materials. Drilling fluid additives of low quality should not be used, since the net result will probably be a more expensive mud system. Usually materials classified "API Approved" meet certain quality specifications, whereas materials not so designated may need to be checked for quality. Not all mud additives have API specifications, so testing may be required to determine quality.

An estimate of the materials necessary to complete the job should be furnished. This estimate is extremely important where product availability is a problem or where mud materials may be delivered only once or twice during the drilling of the well.

Solids-Control Equipment

Effective solids-control equipment is essential to running a cost-effective mud system. Solids-control equipment should be specified for each interval and a detailed discussion provided on its proper use. This discussion should include methods for determining the efficiency of each piece of mechanical equipment in use. If rental equipment is necessary to enhance solids removal, the cost can be justified by comparing its performance to rig equipment performance. A maintenance program for the solids-control equipment, whether rental or rig equipment, should be specified and executed.

The primary shaker is the most important piece of solids-removal equipment. It is essential for this piece of equipment to be working at maximum efficiency at all times.

In designing a solids-removal program, the fluid-handling capacity of the secondary solids-control equipment, with the exception of the centrifuge, should always be greater than the flow rate of the drilling fluid through the wellbore. It should not be assumed that contractors arrange mud pits and solids-control equipment to provide maximum solids removal. In remote drilling locations, mechanical solids-control equipment should be selected for ease of maintenance.

It is becoming increasingly important, especially in environmentally sensitive areas, to use solids-control equipment that discharges a relatively dry solid.

Cementing Program The primary purposes of cement are to seal the annulus between casing and formation, and to support the casing strings. The slurry selections and placement techniques vary widely, depending on the types of formation, well temperatures, hole and casing sizes, hole enlargement, formation pressures, and depths and loads of the casing strings.

The well planner must determine all of the conditions and requirements, select slurries that are appropriate, and prescribe placement and evaluation techniques that ensure effective results.

All this should be presented in the cement program in a concise manner, and appropriate instructions should be included in the drilling procedures section.

There is a large body of cementing technology with which the well planner should be familiar. Cementing company handbooks are the most readily available source illustrating the many variations in slurry compositions available for special conditions. Manufacturers catalogues are the most ready source of equipment choices. Cementing technology cannot be covered in depth here, but the principal concerns of the well planner are discussed.

Requirements and Considerations

The casing, hole sizes, depths, and the mud weight and type determined previously are the basic data for cement design.

Surface strings that support subsequent strings should be cemented to the surface with an excess of cement to ensure uncontaminated cement at the surface. Top fill with strong cement is necessary if the primary cement falls back. This is sometimes advisable even after circulation to the surface in order to place strong, uncontaminated cement at the top of the string. Top filling is done through 1-in. pipe lowered alongside the casing.

For subsequent strings, the desired height of the cement column must be determined and calculated with annular volume to determine cement volume requirements. Caliper logs should be used and some excess (usually 10 to 20%) specified, based on area experience, to ensure cement fill to the desired height. In some cases, only bit gauge is known, and a larger excess (usually 50%) should be specified to compensate for washout. This, too, depends on area experience.

The following are other considerations that affect volume requirements:

The cement height should be sufficient to minimize casing buckling during subsequent drilling;

The upper portion of a cement job often shows poor bonding as a result of insufficient contact time (the time that a given depth is flushed by cement) . All intervals that must be securely cemented need a minimum (recommended) contact time of ten minutes;

Potential lost-circulation problems often require the use of a light, scouring, lead slurry nearly matching the mud density, followed by denser, strong (neat) cement through potential producing intervals, or for the lower part of surface and intermediate string annuli. This is also more economical than using all neat cement;

Two-stage cementing may be used with separate volume calculations for each stage;

Liners should be cemented with an excess to be left inside casing. This provides less contaminated cement at the liner top.

Slurries

The best, most accessible sources of slurry choices are the cementing company handbooks. Usually, the cementing company selected is called upon for recommendations.

The following are common considerations in slurry selection and some comments:

Low-density slurries are often made with gel and pozzolan, but a good fill cement for low-temperature, near-surface conditions is Class A plus 16% gel plus 3% salt. These have sufficient strength for all but completion intervals at densities down to 12.2 ppg. For lower densities with adequate strength, more expensive Spherlite or gilsonite slurries can be used. In cases of severe lost circulation, foam cements may be employed. Foam cement slurries can be mixed at densities as low as 3 to 4 ppg; however, they are not impermeable at densities less than 7 ppg. A normally accepted minimum compressive strength is 500 psi in 24 hours at well temperature;

Gel cements should not be used at temperatures above 250 F. Pozzolanic materials or silica flour should be used at temperatures above 230 F to prevent strength retrogression;

Low-filtration slurries should be used where annular clearances are small, such as with liners;

Fresh water or sea water can be used to prepare slurries. Sea water is convenient and cheaper to use offshore;

Saturated salt water cement should be used when cementing through salt;

Cements with salt usually bind well with shale formations;

Lost-circulation materials can be added to slurries if lost circulation is a problem;

Accelerated cements can be used in shallow applications to speed thickening;

Sulfate resistance may be needed for corrosion protection if the formation water contains sulfate;

Normally, Class G or H cements are used with appropriate additives, but retarded cements (Classes D, E, and F) are sometimes used in deep wells with high bottom temperature.

Slurry Design: The slurry must be designed to give adequate thickening time (placement time plus at least one hour) and set in a reasonable time. It also must be pumpable, but not so thin that free water separates when the cement sets, as this would leave water pockets or high-side channels in the hole.

Retarders are added to slurries to give required pumping time, but these can alter minimum and maximum water requirements or over-retard. Slurries retarded for high bottomhole temperatures may not set at surface conditions.

Various brands of cement of the same class have different pumping times and even the same brand varies from manufacturer's batch to batch. Different water sources alter pumping times, as do different batches of additives and retarders.

All this indicates that except in shallow or very standard conditions, the well planner should specify laboratory testing of slurries for pumping time and strength, using the mix water, batches of cement, and additives that will be used in the well. This should be done well before each string is cemented to give adequate time for any necessary adjustments.

API Spec 10 gives procedures for testing oilwell cements. It includes schedules for applying pressure and temperature to slurries being tested for pumping time, based on a maximum circulating temperature derived from formation bottomhole temperature (BHT) . These schedules are also shown in cement company handbooks. Strength development is determined under BHT conditions. The BHT is usually obtained from maximum-recording thermometers run with electric logs. The temperature from comparable wells, if possible, should be determined and provided to the cement laboratory. Otherwise, the bottomhole temperature may be provided by area temperature charts. The estimated temperature should be listed in the well plan. Should logging indicate a significant change from estimated temperature, it may be necessary to rerun the tests, even at the expense of delay.

Slurries should be designed to provide rheological properties that allow turbulence. The advantages of placing slurries in turbulent flow are discussed later in the manual.

Field Mixing

Unless slurries are mixed in the field at the same water/cement ratio as the laboratory tests, the pumping time will be altered and free water may occur. Cement density measurements are usually taken just downstream of the hopper during mixing. As a result, the cement often contains considerable air, even if defoamers are used. If air-cut cement is mixed to the specified density, the slurry at downhole conditions will have excessive density and possibly shorter pumping time.

Density should be checked continuously when cement is mixed on the fly, and mixed carefully to required density when batch-mixed. Pressurized cement balances that measure the density of air-cut cement should always be specified and used. Also, densiometers can be provided that give a continuous record of slurry density and better control of mixing. These, too, should be specified.

Cement blending is not a precise science. When offshore bins filled with blended cements are tested, there may be considerable variation in pumping time between blends. For this reason, it is advisable to specify testing of blended mixtures in the field prior to critical jobs. Batch mixing should be specified whenever practical, as it affords better control and consistency of slurry component concentrations.

Dry samples of blended cement should be taken in the first, middle, and last stages of the cement job. If difficulties are encountered during the job, these samples should be laboratory tested using the field water. Wet samples are often taken and observed for set, but the setting time during such tests is likely to be different from downhole set time. The Procedures section of the well plan should specify the equipment to be used, the mix water requirement, the spacer, and the sample-catching method.

Placement

The greatest difficulty in cementing is the adequate displacement of mud and mud cake by cement. Many slurry compositions are adequate if adequately placed. The following are well-known significant factors in mud removal:

Borehole Specs A gauge hole is desirable;

Contact Time Sufficient cement should be pumped across the critical formation to adequately flush the interval. (A minimum of 10 minutes is suggested.);

Centralization All holes wander enough so that pipe is against the side of the hole for most of its length. Cement cannot be placed behind pipe in such conditions;

Pipe Movement This helps break up gels and creates some lateral movement that helps cement flow behind pipe;

Wipers or Scratchers These help remove mud in washouts even though they may not touch the wall;

Low-Viscosity Spacers These dilute the mud, making it easier to remove, and establish a favorable mobility ratio with the cement, thus improving displacement;

Turbulent Flow Turbulence displaces mud much more effectively than plug or laminar flow. Excessive pressures and flow rates are not required when the slurry is thinned;

Density The density of the slurry should be 1 to 2 ppg heavier than the mud whenever practical. Density difference aids mud displacement;

Mill Varnish Removal of mill varnish increases cement bonding to pipe.

The Cementing section of the well plan should include provision for the above, excepting Item 1, which is affected by the mud and hydraulics programs.

Other Considerations

The following are additional considerations that should be included in the Cementing sect ion of the well plan.

Centralizers: These should always meet or exceed APT specifications. In vertical holes, casing can be centralized adequately with 90-ft spacing. In directional holes, spacing should be calculated based on angle, pipe weight, and centralizer strength. Centralizers should be placed over collars or stop rings so that they are "pulled" into the hole. Closer spacing is needed on the bottom joints.

Wipers or Scratchers: These should be spaced (often at 15 ft) and pipe movement specified to overlap wiper or scratcher travel from bottom through productive intervals. Rotating scratchers or wipers should be continuous across producing intervals.

Pipe Movement: Pipe movement should begin during circulation and continue until the plug bumps. Plugs should be dropped without stopping pipe movement. When cement reaches the shoe, pipe should be lowered to bottom to flush out mud, and then pipe movement continued above. Rotation produces more cleaning than reciprocation, but is more limited in depth of use.

Allowable Pull: A safe allowable pull should be specified in the Casing Design and Drilling Procedures sections of the well plan. Casing is more likely to be reciprocated if this guide is used, particularly in directional holes.

Plugs: Two plugs should be used, because one plug behind cement picks up excessive mud film and forces it into the cement. Plugs should always be placed in cement, not in spacers. The front plug should be inserted after the spacer. When the top plug is ready to be dropped, the lines should be broken at the cementing head and flushed, then the spacer pumped behind the plug.

Accurate displacement of the top plug is essential. Even small amounts of over-displacement harm cement jobs. Therefore, displacement should be measured from cement tanks to avoid over-displacement in case a plug fails or is inadvertently left in the cementing head. Over-displacement volume should be limited to a maximum of one or two barrels over calculated value, depending on casing size. Displacement should be measured using measuring tanks on the cementing unit rather than barrel counters or pump strokes.

Float Shoes and Collars: Two check valves are often run, as one might fail. With occasional filling of pipe being run, float equipment failure can cause a blowout as annular fluid level drops due to U-tubing into the partially filled casing. The float collar should always be at least one joint above the shoe in order to prevent cement contaminated by mud film from circulating into the annulus. Epoxy cementing of collars and bottom joints should be specified in the Drilling Procedures section of the well plan.

Waiting on Cement: Time for cement to set is usually short as far as adequate support of pipe is concerned. However, slurries retarded for use in deep, high-temperature wells and circulated up the hole may have extended setting times. In these circumstances the cement company should be consulted and simulated tests run if needed.

Liners: Cement should be circulated well above liner tops (300 to 500 ft) to provide adequate flush, and left to be drilled out, rather than reversed out. Cementing at an excessive rate is a common mistake, causing excessive annular pressure and loss of circulation. A suitable rate should be specified in the well plan.

Evaluation

In routine jobs, the cement height is often not determined. But where circulation is lost, and in deep wells, either a temperature log or bond log (CBL) should be run to determine cement height. Bond logs are controversial, but can be of value in determining the adequacy of a cement job. These are necessary in unusual conditions and in critical wells.

The Drilling Procedures and Logging Program should list the surveys. Block squeezing of producing intervals is normally not necessary when the interval is reasonably near bottom, unless the bond log so indicates. However, contamination of cement placed uphole may require squeezing, and the bond log is the only tool available for evaluation.

Gas flow in the cemented annulus can be detected by noise logs, which should be run if this problem is suspected.

Annular Gas Flow

Tinsley, et al.(1979) and Cooke (1982) have shown that cement hydrostatic pressure tends to drop to formation fluid pressure when initial set begins. This can result in flow through the cement to the surface with surface strings, flow at liner tops, or interzonal flow through cement. These flows seem to be relatively small, but troublesome. Various solutions have been suggested, including holding pressure and pumping into the annulus during set.

Much research has been done recently regarding annular gas flow. Cementing companies have recommended solutions as diverse as thixotropic cements, and cements blended with aluminum powder. The aluminum powder reacts with the cement to generate small quantities of hydrogen gas, which maintains pressure in the cement column until the cement sets completely. There is not any clearly effective, direct solution, and such situations require special study.

Bit Program Designing a bit program involves much more than simply selecting a bit type. The objective is to employ a bit program and associated drilling practices that will minimize drilling cost per foot. The various bit company catalogues and manuals illustrate the large variety of bit types available, but admit that selecting the best bit to match the formation involves some trial and error. The well planner needs to be thoroughly familiar with such manuals, and with the proper application of rock bits and other bit types, as well as alternate drilling techniques.

The principal choices of bit type are:

Roller Cone Bits

- Mill tooth (commonly called "rock" bits)

- Tungsten carbide insert (commonly called "button" bits)Variations

- Standard or extended jet nozzles

- Soft to hard formation designs

- Roller or journal bearings

- Gauge protection

- Small to large diameters

Fixed Cutter Bits

- Polycrystalline diamond compact (PDC)

- Thermally stable PDC (TSP)

- Natural diamondVariations

- Soft to hard formation designs

- Parabolic, cone, or step bit crown profiles

- Nozzle, radial flow, or feeder/collector hydraulic flow patterns

- Gauge protection

- Small to large diameters

- Angle, shape, size, and density of cutters

- Steel body or tungsten carbide matrix body

- Hybrid combinations of cutter types

- Size and number of Junk slotsAll of these have design variations for use with downhole motors,

There are variations in both mill-tooth and tungsten carbide insert bit design for soft to hard formation types. The softest formations, particularly where bit balling is a problem, are usually drilled best with mill-toothed bits. Generally, these provide faster drilling rate and shorter tooth life than tungsten carbide insert designs for comparable hardness.

Rock-bit life may be limited by tooth wear, bearing wear, or loss of gauge protection, all of which are affected not only by the type of formation drilled, but also by the drilling fluid used, hydraulics, and drilling mechanics. Even the most appropriate bit for a formation can give poor results if these factors are not handled properly. A bit designed for softer formations almost always drills a given formation faster than would a bit designed for harder formations, The same bit type in a smaller size has smaller bearings and teeth, and consequently less penetration rate with the same drilling mechanics, and also has a shorter bearing life.

Sealed journal bearing bits tend to have a limitation on the maximum combination of weight (W) and rotary speed (N) that can be run and still afford satisfactory bearing life. Bit manufacturers publish recommended ranges of weight and rotary speed for each bit type in their catalogues. Except for cases where tooth penetration is so great that the cones ride on the formation (and this can be helped by hydraulics), higher bit weights and rotary speeds result in faster drilling. Consequently, if there are no other limitations, maximum WN values ( weight multiplied by rotary speed ) usually provide the most economical bit runs.

Even so, relative emphasis should be placed on higher rotary speed in soft formations and higher bit weight in hard formations. High rotary speeds accelerate tooth and bearing wear in harder formations and create vibrations leading to drillstring and bit failure. High bit weights tend to cause bit balling in soft formations..

PDC Bits: Compared to roller cone bits, PDC bits employ low weight-on-bit and high rotary speed. These bits may be limited in shallow drilling by bit balling (controllable to some extent by high hydraulics) and in harder formations by the effects of heat generated on the diamond cutter. Thermally stable PDC bits provide much better performance in this area.

PDC bits cost more than rock bits, particularly in large sizes (10-5/8 in. or larger) . The higher cost can be offset, however, by higher penetration rates and longer bit life.

Bit Selection: There is a strong tendency among field personnel to simplify the problem of bit selection based on hours run or footage made, but this often provides wrong answers. Bits are run for effective drilling, not to be conserved.

On exploratory wells there may be no offset bit records on which to base selection, but there are often records of wells drilling the same formation some distance away. Usually there are one or more bit records that can be studied and used judiciously.

The first step in bit comparison is to calculate the cost per foot for bits run in offset wells. These values are then plotted against depth ( Figure 1 ) . Sometimes the depths need to be adjusted to make comparisons on the basis of formation tops or measured depth, but this gives a far clearer indication of cost effectiveness than can be obtained by simple examination of bit records.

Figure 1

Notably, one of two bit runs in offset wells may be cheaper than the other, but the comparison can be reversed if the runs are started at different depths or the rig rate is changed equally for both rigs.

The tool on which comparisons of effectiveness should be based is the cost-per-foot for a bit run formula, which we may express as follows:

[ C/D ] = [ Cbit + Crig ( t + T ) ] /DWhere: C/D = cost per foot t = trip time, hours

Cbit = bit cost T = rotating time, hours

Crig = equivalent hourly rig costD = footage drilled

The principal applications of the cost-per-foot calculation are to (1) determine the cost per foot at intervals during a bit run, and (2) to make economic comparisons of bit runs or drilling techniques. The application relates principally to mill-tooth bits, whose drilling rate slows (and cost per foot increases) as their teeth become dull, indicating that the bit should be pulled. The second application allows comparison of subsequent bit run costs, offset well bit run comparison; and if suitable input is made, can compare such variations as using a downhole motor, air or mist drilling, etc.

In plotting comparisons ( Figure 1 ), it is best to use the equivalent hourly rig rate for the well to be drilled rather than for the rig actually used. The trip time factor should also be that anticipated for the well to be drilled. Otherwise, the comparison may be distorted or even reversed.

Even after calculation and plotting, selecting the bit and rotary practices is a matter of judgment selection based on low cost-per-foot could actually result in an expensive bit run if the bit gauge wears out and the hole must be reamed. High costs might also result from pulling a "green" bit, poor hydraulics practices, using excessive mud weight, or maintaining too low a bit weight or rotary speed.

Presentation: The bit program should list the bits to be run, the expected intervals of use, approximate weight and rpm, and discuss any appropriate special considerations.

Hydraulics The hydraulics program should provide for:

minimum annular velocities and flow rates;

maximum annular velocities and flow rates;

jet bit and other bit hydraulics design;

minimum pump and pump output horsepower.The objectives are to ensure adequate hole cleaning., minimize hole enlargement in some instances., ensure maximum drilling rate as related to hydraulics., and specify minimum pump horsepower.

Annular Velocity and Flow Rate

Hole cleaning is affected by a number of interdependent factors. These are drilling rate, bit size, pipe size, mud effective viscosity and density, circulating rate, annular velocity, flow regime., hole enlargement., sloughing rate., pipe rotation., cuttings and sloughings shape, mud type, and balling tendency. No expressions combining all these factors are available, although some semiquantitative expressions or estimates have been published.

Reasonably., the annular velocity should be as high in large diameter holes as it is in more common-sized holes, but this is seldom seen because available rig pumps do not have this capability. The lower annular velocities in larger holes are acceptable because of at least three effects. When drilling with water in hard rock., bit cuttings tend to break easily into fines and are more readily removed. Also., drill rate tends to be slow, so removal rates can be low. With drilling with mud, the low shear rates in large holes result in high effective viscosities that compensate for lower annular velocities. In soft rock, where drilling rates in large diameter holes are fast, the cuttings tend to disperse and make fine particles that are easily removed. Even so, drilling rates can be too fast, resulting in burying the bit and/or balling. In some instances maximum drilling rates may need to be specified.

One commonly stated axiom is that cuttings volume should not exceed 5% of mud volume. Undoubtedly, a mass of cuttings can accumulate., often in washouts where annular velocity is greatly reduced., and this can fall back when pumping stops for a connection. However, calculating slip velocity as a basis for setting minimum annular velocity is a very uncertain procedure. In laminar flow (Williams and Bruce, 1951), flat particles are subject to random turning and sliding downhole., but are better removed when pipe is rotated. More-rounded particles ride the center of the flow profile and can rise faster than the average flow rate. All this makes calculation of the cuttings removal rate very uncertain, hence the rule that flow rates maintain less than 5% cuttings.

As a practical matter, minimum circulating rates are usually selected based on area experience for the hole and pipe sizes under consideration. If fill on trips occurs or circulation tends to be restricted after connections, adjustments can be made in viscosity to improve hole cleaning. Density is sometimes increased to stop sloughing. When drilling with water or low-viscosity muds, pills or sweeps of high viscosity are sometimes used. If these procedures are anticipated, appropriate comments should be made in the Hole Problems and Mud Program sections of the well plan.

In special cases provisions may be necessary to ensure adequate hole cleaning in enlarged sections above liner tops or in risers.

The following are suggested minimum velocity guidelines:

Bit size (in.)DP OD (in.)gpmfpm

4-3/42-7/8100170

63-1/2150150

8-1/24-1/2250120

9-7/84-1/2 - 5350 - 330110

12-1/44-1/2 - 5530 - 510100

154-1/2 - 5585 - 57070

17-1/24-1/2 - 5700 - 69060

These may vary considerably, depending on specific conditions., and local practice should be checked before setting the minimum velocity and flow rate. Except in the lower part of the hole., circulation is usually at rates considerably above minimum. If unusual conditions exist, these should be stated in the well plan.

Larger hole sizes often require two large pumps to provide minimum annular velocity.

Maximum flow rate is usually the maximum flow rate of the pump., unless hole erosion is a consideration.

At any level of pump pressure on which a jet-bit program is based, pumping at less than the maximum rate (or, when the bit is deep enough., reducing the rate below the optimum rate) reduces bit hydraulics and sacrifices drilling rate. Therefore, flow rates should not drop below those inherent in a properly designed jet-bit program unless there is an overriding reason.

One such reason is hole erosion. In this case., maximum rates should be established and stated in the well plan. In order to avoid turbulent flow around drill collars or drillpipe, annular velocities are sometimes limited to less than critical velocity., calculated from a Reynolds number of 2000.

Borehole erosion due to excessive annular velocity is largely self-correcting. Small enlargements rapidly reduce annular velocity and there is a concurrent increase in effective viscosity that also reduces Reynolds number. Except in instances where excessive flow rates are known to cause a problem, maximum flow rates should be specified as indicated by jet-bit program design.

Jet-Bit Hydraulics Program

The hydraulics program must be designed with due regard to hole cleaning, mud-density requirements, hole geometry, drillstring sizes., and pumps to be used.

Industry opinion is divided as to whether jet-bit programs should be designed to provide maximum bit hydraulic horsepower or impact force. Optimum flow rates can be reduced by 25 to 30% at a given standpipe pressure by designing programs for maximum hydraulic horsepower rather than jet impact force. This results in decreased pump input horsepower requirement and decreased fuel consumption.

With either criterion., the most significant factor is that hydraulic energy is transmitted to the bit with less loss at high pressure. Therefore, the pump liner to be used is the smallest (with the highest pressure rating) that will provide minimum annular velocity. To improve the life of pump parts, programs are generally designed and run at less-than-rated liner pressure.

However, a small reduction in surface pressure results in a much larger reduction in bit hydraulic horsepower or impact force.

Demonstrably, increasing bit hydraulic horsepower or impact force increases drilling rate at constant bit weight. Often, increased bit hydraulics allows a higher maximum effective bit weight, which can further increase drilling rate. These effects lessen in hard rock, but are still present. The objective for the well plan is to specify a jet-bit program that ensures maximum drilling rate.

If rig equipment, mud-density requirements, and pump efficiency are accurately known, then a workable jet-bit program can be planned. However, the mud density is only approximately known and subject to unexpected variations. Actual pump efficiency varies from estimated values, and the use of viscosity-building and filtration-control polymers often varies the friction loss of muds so as to change the apparent pump efficiency. The drillstring design is subject to variation, and the exact pump liner size is not known until the rig has been selected.

Thus, a detailed hydraulics program planned for a well has to be modified as the well is drilled, and can be only approximate and illustrative. Where computer, calculator, or offset well programs are available., an illustrative program is sometimes worth including in the well plan, but is not mandatory.

The rules for designing jet-bit programs for maximum bit hydraulic horsepower or impact force (Kendall and Goins, 1960) can be applied to field data to determine the next bit nozzles. This avoids the unanticipated variations inherent in a completely preplanned program. Hydraulics programs should be based on maximum practical surface pressure, and allow for any anticipated mud density increase during the bit run. A procedure (Coins and Flak, 1984), based on the graphical technique used by Hughes Tool Company in their Practical Hydraulics text, provides for increases in pump pressure and/or mud density.

Design procedures must recognize minimum annular velocity limitations and maximum flow rate of the pump liner used. When maximum annular velocity is selected to avoid excessive hole erosion, the maximum flow rate must be recognized. With these considerations in mind, the following items should be specified in the well plan for each hole size:

minimum annular velocity and flow rate;

use of smallest liner that will provide minimum annular velocity;

maximum flow rateeither maximum pump rate or maximum flow rate based on limiting hole erosion;

nozzle selection for next bit run based on field data using calculation or graphical techniques allowing an increase in pump pressure and/or mud density.Hydraulic program design for PDC bits appears to be best done as for toothed jet bits. However., minimum flow-rate restrictions may be based on bit cooling rather than hole cleaning. The minimum flow rate is often specified by the bit manufacturer.

Pump Horsepower

Pump requirements should be based on maintaining minimum annular velocity at a preselected, maximum surface pressure. Horsepower requirements are high in large holes and decrease as hole size decreases. Horsepower requirements also decrease with depth in a given hole size.

Figure 1 illustrates how pump horsepower requirements vary with hole size and drillpipe size at selected surface pressure.

Figure 1

This illustration is based on 120 ft/min minimum annular velocity. Note that pump horsepower to provide maximum impact force or bit horsepower decreases with depth. Horsepower requirement is obtained by calculating flow rate to provide minimum annular velocity in the hole and drillpipe annulus., and multiplying by surface pressure divided by the appropriate constant; i.e., PHP = Q(gpm) X P(psi)/1714.

This must be done in the larger hole sizes using minimum annular velocities selected. The highest horsepower requirement should be increased assuming 90% hydraulic efficiency. Also, it is necessary to specify minimum mechanical horsepower input assuming 85% mechanical efficiency. In many cases, rigs cannot provide enough horsepower to run pumps at rated values. Horsepower requirements should be specified in the Rig Requirements section of the well plan.

Hole Deviation Unintentional hole deviation often results in a variety of serious (and occasionally disastrous) problems. Deviation is measured and expressed in degrees. In "vertical" hole sections, it is usually measured with either a plumb bob or gyroscopic instrument. Instruments can be run on slickline or dropped inside the drillstring. Except at deviation angles above 45 F, absolute deviation rarely causes problems of any consequence. Rather, it is rate of change of angle, known as dogleg severity (expressed as degrees change per hundred feet of hole), that causes problems. In shallow wells deviation is usually measured assuming direction does not change, but as depth increases, directional measurements are generally included. This is helpful both for maintaining a fix on the position of the hole in case of a blowout, and to obtain a more accurate measurement of dogleg severity. Dogleg severity is the direct cause of a number of well problems. These include drillpipe and casing wear, drillpipe fatigue, rod and tubing wear, key seats, high drillstring drag and torque, failure to get logs and casing to bottom, excessive loads on casing, and other problems related to or resulting from those listed here. In general, shallower doglegs cause more severe problems due to greater tension in the drillstring. Casing wear can result in failures which, in turn, lead to either lost circulation or blowouts.

Little is known about precisely which rock characteristics cause holes to deviate. It is known, however, that deviation generally becomes harder to control as rocks become harder. This is due to the nature of the rocks and the necessity for applying higher bit weights for penetration. Several authors (e.g., Milheim l979) have described the effects of added bit weight on deviation.

Experience in many areas shows that deviation problems are much more severe in some intervals that others. Problems in a particular interval may extend basinwide., or may be more localized. Problems are often related to geologic structure., hole size., and bottomhole drilling assembly clearances.

In soft to medium-hard rocks, deviation is often the result of sidewise rather than frontal drilling by the bit. Changes in rock strength., erosion of the borehole wall., and perhaps other effects tend to cause rather abrupt changes in hole deviation. These changes may or may not be observed on deviation surveys., but they often result in an effective hole diameter considerably less than bit size. Degree of offset and consequent reduction in effective hole diameter is dependent upon the relation of drill collar or stabilizer size to bit size (Qilaon., 1976) .

The need to bottom a well at a fixed location varies considerably. Lease boundaries or geologic considerations sometimes necessitate restriction of hole deviation. At other times., wells could be allowed to drift almost without limit. Since restrictions of deviation almost universally increase well cost., the maximum practical limits should be allowed. When deviation is severe and the direction of drift is predictable., it is often economically desirable to displace the surface location to such a point that normal drift will place the bottomhole at the desired location.

The large majority of wells tend to drift updip. In harder rocks., the tendency exceeds 95%. It is always desirable to plan deviation limitations to allow the maximum tolerable displacement. If the dip direction is known., deviation limitations can be relaxed or tightened accordingly to allow maximum penetration rates.

From a well-operation point of view., hole displacement in itself is of little consequence. Restrictions are required because of dogleg severity and hole angle.

Dogleg severity is the primary concern among deviation problems. For the reasons mentioned above., limits must be enforced to prevent severe problems. Much work has been done to establish maximum allowable dogleg severity (Lubinski, 1960; Williamson., 1981) and as long as recommended limits are observed, few problems occur.

Hole angle becomes important at higher values primarily for three reasons. First, as the lateral component of drillstring load increases., the likelihood of wall sticking increases. Second., carrying capacity of drilling fluid is decreased., allowing accumulation of cuttings in the borehole. Third., as the lateral component of drillstring load increases., both rotating torques and longitudinal drag are increased due to friction. The solution to all of these problems involves special attention to drilling fluids., hydraulics design., and drillstring design.

Hole deviation and dogleg severity are controlled by bottomhole assembly configuration and drilling rate parameters, or by directional drilling methods. The ideal condition for deviation control would be to run an infinitely stiff bottomhole assembly with zero clearance to the well bore. Since that condition is unattainable., the practical solution is to run the maximum-fishable-diameter drill collars to get maximum stiffness., and to run the minimum number of stabilizers that will keep deviation within tolerable limits while drilling at an acceptable penetration rate.

Bottomhole assembly selection is largely empirical. The relative ability of various assemblies to build., hold., or drop angle has been fairly well established (Milheim., l979) . However., the selection of the assembly for use in a particular well must still be based on experience. Records from similar wells, whether offsets or merely in a similar basin., often provide the best guide for selection of bottomhole assemblies.

The well plan should include the following items concerning deviation control:

a description of any anticipated problems;

the bottomhole assemblies to be used;

the method and frequency of surveys;

the limits of hole angle as a function of depth, if applicable;

a stipulation that doglegs above 3 degrees/100 ft be wiped out with string reamers.

In many instances, modern directional drilling techniques have replaced traditional methods of deviation control. Depending on the potential for deviation-related problems and the importance of maintaining a specified well trajectory, such equipment as downhole motors may be used even in "straight hole" applications.

Logging The drilling engineer can use several controls to maximize openhole log accuracy. The main control often is the mud program. Severe hole washout can ruin log quality. If this is a regional problem, the drilling engineer can specify a more inhibitive mud system to reduce hole erosion. If turbulent flow is causing hole enlargement in the region, then the hydraulics program can address the problem. The logging tools most affected by hole enlargement (in order of effect) are dipmeter, microlog, BHC sonic, neutron porosity, density porosity, and resistivity/ induction logs.

Excessive filtration into a producing zone can make fluid content evaluation from resistivity logs very difficult. The log analyst should provide the drilling engineer with the depths of possible production zones and practical fluid-loss limits.

Coring

The drilling engineer should be provided a coring program for well planning and cost estimation. Coring operations are expensive and time-consuming. Failure to include coring costs in an estimate could result in cost over runs.

Coring costs can be reduced if the drilling engineer is given some warning while preparing the well plan. PDC core heads can be used to core at substantially higher rates than natural diamond core heads in the right application. PDC core heads also reduce core barrel jamming, which allows much longer (90- to l20-ft) core barrels to be used.

Many times the drilling engineer is not informed of the need for core preservation and quick evaluation by the coring program initiators. If a representative core is required., the engineer should be instructed in pressure coring and "native state" coring techniques.

The sidewall coring (SWC) program should also be transmitted to the drilling engineer. The practicality of SWC on an intermediate log run should be evaluated carefully. If drilling is to proceed., the SWC barrels left in the hole will need to be fished out at additional cost. Again, the well plan should reflect the need for proper core preservation and quick evaluation.

Testing

A properly run and interpreted drillstem test (DST) probably yields more valuable information for its cost than any other evaluation tool. A DST can be defined as a temporary well completion in open or cased hole, which is designed to sample formation fluid and establish the probability of commercial production. Open hole DSTs are typically run in hard-rock areas., such as the Permian Basin of West Texas and in the midcontinental region of the United States.

The drilling engineer must be given every possible detail of the proposed DST when planning the well and estimating costs. Area knowledge may indicate that running a DST is impractical, or may suggest a particular DST technique to gain the most information. A well-run DST yields information about reservoir fluid composition, static reservoir pressure, and productivity. Transient pressure evaluation of recorded pressures yields information about flow capacity (KH product) and skin effect. This information can then be used by the drilling, completion, and reservoir engineers to determine the prospect commerciality, fluid composition., required tubing size, perforation density, and reservoir characteristics. Additionally., this information aids in the planning of effective well treatments and the development of a comprehensive production testing program after pipe is set. The Drilling Procedures section of the well plan should fully describe the DST procedure planned for the well. The reservoir engineering group should provide an on-site engineer during the test to evaluate the test data.

The completion procedure should fully describe any required cased hole production tests. This information should be summarized and included in the logging, coring, and testing section.

The completion procedure should accurately describe what would actually occur in the field. In this way, the well is "tested on paper" prior to the actual job. Deficiencies in the procedure can then be recognized and corrected.

If some basic assumptions can be made prior to drilling the well, the drilling/completion engineer can make some preliminary calculations to better estimate the required length of the test and the required test equipment capacity, and determine the best test technique.

The reservoir engineer, who depends on good, representative test data to make various evaluations, should be on location during testing to act as a quality-control inspector of the test data. This should be mentioned in the well plan.