HORIZONTAL WELLS-2 PLANNING MATCHES DRILLING EQUIPMENT TO OBJECTIVES

Greg Nazzal
Eastman Christensen
Houston

Developing a plan for optimizing drilling equipment methods and procedures will lead to a more efficient and less costly horizontal drilling operation.

Proper selection of personnel, well profile, bottom hole assemblies, and postwell analysis are necessary for a successful well program.

Horizontal drilling, though more common than ever, is a complex undertaking. At the same time, technology is changing so rapidly that it is often difficult for oil company personnel to assure themselves that they are applying the best available techniques for the application.

In general, the key factors for success in horizontal drilling are:

Careful and comprehensive prewell planning
Multidisciplined planning team
Contingency plans made in advance
Qualified rig-site personnel
Proper equipment selection
Postwell analysis.

PREWELL PLANNING

The drilling department planning its first horizontal well often makes the mistake of considering a horizontal well just "a high-angle directional well." This misconception can lead to serious problems.

Many factors unique to horizontal wells bear special consideration during well planning. These factors have direct influence on equipment selection.

For one thing, the target for a horizontal well is usually a three dimensional target, perhaps 20 ft high (compared to a two dimensional rectangle 100 or 200 ft on a side), requiring precise motor performance to drill accurately to target.

Once drilling is under way, the operator may discover that target zones are not located at the actual depth of the planned horizontal section, so development of contingency plans is essential. In addition, drill pipe used in horizontal drilling may differ from that normally used in more routine development drilling.

For example, in horizontal wells, drillstrings are typically run inverted with no drill collars. Drill pipe is run in compression, and heavy-weight drill pipe is normally placed in the more vertical portion of the hole to provide weight to the bottom hole assembly (BHA). 1

After a horizontal profile is selected, the planning process must include use of computer programs to analyze torque, drag, and both sinusoidal and helical buckling for the proposed BHA over the planned well trajectory. 2 Computer programs are widely used to plan the well profile and to perform torque, drag, and drillstring stress predictions, as well as casing and well clearance analyses.

Horizontal wells demand closer attention to detail in every aspect of drilling engineering than is typical of more conventional wells. In addition, it is important to clean effectively the horizontal hole, and the drillstring should be kept moving at all times to minimize the chances of sticking.

Thorough prewell planning will address aspects such as proper tubular and drilling fluid selection as well as contingency planning. Such a multifaceted approach to planning ultimately leads to the successful conclusion of a horizontal well.

MULTIDISCIPLINED PLANNING

For the horizontal well project to be a success, initial input from the reservoir, geological, production, and drilling departments is crucial. While a large operator can form a task force made up of individuals with expertise in these areas, a smaller operator may need to go outside for an expert consultant in one or more areas. Ultimately, this multidisciplined group outlines objectives for the horizontal well based on input from each member.

Horizontal well planning begins with reservoir and production considerations so the drilled hole can accommodate the necessary production hardware and meet the reservoir management objectives. 3 4

The reservoir member addresses reservoir management objectives and is responsible for determining the optimum length and placement of the horizontal interval in the production zone.

The geology member determines the vertical depth of the zone of interest, as well as the amount of inaccuracy given with this depth, while accounting for factors such as regional dip and faulting.

The production member defines optimum completion equipment for a desired production rate and for any anticipated production problems that might be encountered in the formations For example, the production string may need to address specific production requirements. These requirements can include isolating one or more zones for production tests, or providing sliding sleeves which can be closed in zones where water or gas coning is anticipated. 6 The completion program will influence the final hole size drilled, among other things.

Finally, the drilling member determines equipment needs, helps evaluate contractors, and determines the well profile from surface and geological constraints. Casing setting depths and drilling fluids also are determined by the drilling engineer.

After the task force has outlined the goals, objectives, constraints, and desired results, a prognosis is assembled. There no doubt will be compromises required between the needs of the different groups.

It is advisable to hold a planning meeting with the service companies, drilling contractor, and drilling representative to review and finalize the prognosis.

CONTINGENCIES

The first rule when drilling horizontally is that: "Anything that can go wrong, probably will."

One of the most common examples is the production zone that comes in too high or too low. 7 A contingency plan should be made to determine in advance what responses to the program are "desirable," "acceptable," and "unacceptable." 8

Because the target depth almost always changes during the horizontal drilling operation, it is necessary to have a plan flexible enough to hit a "moving target." In this example, the contingencies could range from having a higher-build-rate motor on location, to plugging back the well.

QUALIFIED PERSONNEL

Use of qualified rig site personnel may be the most important aspect of the successful horizontal drilling project.

In particular, the horizontal contractor should provide qualified horizontal support personnel, including a directional driller with local experience and a driller who is knowledgeable in horizontal drilling techniques and equipment.

The experienced horizontal driller and the "local" directional driller together make the best on site horizontal team. In addition, crews should be briefed on the differences expected in drilling horizontally and the safe operation of the rig under these conditions.

Finally, teamwork is essential for a successful horizontal well.

Each member of the group must communicate, cooperate, and compromise with other members for this approach to be effective. If procedures are to differ from conventional directional drilling, communication channels for reporting during the horizontal drilling operation should be established early.

PROFILE AND EQUIPMENT SELECTION

In general, three methods are widely recognized for turning a well bore from vertical to horizontal. They are long, medium, and short radius, as illustrated in Fig. 1.

LONG-RADIUS WELLS

A long-radius horizontal well profile is defined by build rates which range from 2 to 6/100 ft, with horizontal intervals extending up to 5,000 ft from the end of curve. 9 There is no limitation to long radius hole size.

Applications for long-radius horizontal drilling include fault block or extended-reach drilling, with the build rate defined, at times, by the surface and bottom hole locations. 10

Conventional drilling equipment is used to drill the long-radius horizontal well. Typically, either steerable motors or slick motors with bent subs are used to kick-off and initiate angle (Fig. 2).

The steerable motor's geometry is fixed by three points of contact: the bit, bearing housing stabilizer, and stabilizer above the motor (Fig. 3). 11 These three points define a constant arc of curvature corresponding to the desired build rate of the motor assembly. This principle also applies to some medium and short-radius motor designs.

Several factors influence motor performance for both steerable and slick motors. They are: weight-on-bit, hydraulic horsepower at the bit, flow rate, bit type, bit length, formation tendencies, mud properties, and alignment of the bent subs on the motor. All deserve special consideration during planning.

Typically, either a double-tilted universal housing (DTU) or single-tilted (bent housing) motor is used in long-radius applications.

Sometimes, a bent sub and slick (unstabilized) motor can be used to initiate deflection to angles less than 50 but, because there is only one fixed point on such an assembly, build rates are more inconsistent as inclination increases.

Where geologically feasible, jetting techniques also are used to build angle, although the resulting curve is not always smooth and consistent. Finally, rotary angle-building assemblies can be used to build inclination in long-radius wells, although they are subject to severe bit walking.

Similarly, the horizontal section can be drilled with either motor or rotary assemblies.

Today, steerable motors are the norm because they provide better control over a well's course.

In general, use of a steerable motor such as the DTU reduces drillstring torque and often results in higher penetration rates and reduced cost per foot drilled when compared to rotary assemblies.

For survey operations, the long-radius method can use either a single shot or steering tool, but measurement-while-drilling (MWD) is the preferred survey method, given the objective of reducing trip time and increasing drilling efficiency.

One long-radius example compares rotary and motor assemblies on ARCO's Java Sea horizontal project. 12 Results show that the cost per foot was reduced to $116 from $203 by using steerable motor technology (Fig. 4).

The profile of a typical Java Sea well can be seen in Fig. 5, which shows a gradual buildup to 90 at rates ranging from 3.5-6.75/100 ft using a DTU motor.

Offshore Holland, Elf-Petroland used steerable-motor technology to drill three long-radius wells which incorporated 11 stair step" profiles (Fig. 6). 13 This type of profile is unique in that horizontal intervals were placed in the reservoir's two most porous and permeable sandstone members, and were separated by vertical depths ranging from 65 to 130 ft.

In one case, gas production increased 2-3 times that of a 50 directional well, while costs were 1.2 times greater. 14

MEDIUM-RADIUS WELL

A medium-radius profile is defined as having build rates ranging from 8 to 20/100 ft with horizontal intervals up to 4,000 ft. Hole sizes range up to 12-1/4 in.

Medium-radius wells are most often drilled to limit water and gas coning, to reach thin reservoirs, and to connect vertical fractures. Other medium-radius applications include enhanced oil recovery (EOR), reef drilling, solution mining, and low energy or permeable reservoirs. 15

The heart of a medium-radius drilling system is the medium-radius motor. Virtually all medium-radius motors supplied to the industry today deliver low speed and high-torque output to the bit. The two types of motors are fixed and adjustable (Figs. 7a and b). Each has advantages.

Depending on desired build rate, the fixed-angle build motor has two or three tilts aligned along the same plane. The build rate of these motors, if properly designed, is extremely predictable. However, these types of fixed-angle build motors cannot be rotated because of the high bit offset they produce.

The typical medium-radius profile using fixed-angle build motors may be planned as a build-hold-build configuration, or with a constant build to horizontal (Fig. 8). Profile selection depends on the vertical tolerance and the horizontal displacement of the target entry point (Fig. 9).

For example, a fixed-angle build motor with a designed build rate of 14/30 m will drill a 122.8-m radius. However, if the system actually achieved 15/30 mm, the radius is 114.6 m, resulting in a potential miss of the target by 8.2 m unless the vertical tolerance is sufficient to accommodate this inconsistency.

The single bent-housing motor, with the tilt above the bearing-housing stabilizer, can be either fixed or adjustable. The single adjustable angle (SA) build motor has the advantage of allowing adjustment of the tilt angle at the rig site.

When adjustable motors are used, planning a tangent section to accommodate formation or motor inconsistencies is not necessary, even when targets are small vertically. However, build rates may not be as high as with the fixed-angle build motor. Therefore, a constant or compound arc profile may be used, with one or more build rates planned to reach horizontal.

Some medium-radius motors are steerable, meaning that orientation as well as rotary drilling is possible without tripping. Some adjustable motors, like the SA, are also steerable, but only within a predetermined build rate, typically from 6 to 13/100 ft for respective motor sizes of 8-4-3/4 in. OD.

Again, bottom hole assembly trips for tangent sections are not required when steerable motors are used, although a trip may be warranted to adjust the motor's build rate capability, if adjustable, depending upon target tolerance and any difference between actual and planned build rates (Fig. 9).

The most versatile motor type is the double-adjustable (DA) steerable angle build motor (Fig. 7c). This motor combines an adjustable bent housing with an adjustable top bent sub, providing several configuration options for achieving a range of dogleg capabilities.

By adjusting the DA bent housing to the desired angle from 1 to 2, and aligning with the top bent sub, which can be set from 1 to 3, the stabilized motor can achieve doglegs from 10.5 to 24.5/100 ft.

With the stabilizers removed, the bent sub can be set at 1 or 2 and aligned with the bent housing to achieve a range of build rates from 8 to 20/100 ft.

The DA motor also provides the flexibility of adjusting the build rate at the rig site. Constraints such as maximum allowable setting and rate of penetration (ROP) range for permissible rotation should be outlined by the horizontal drilling contractor.

Using a steerable motor, a fractional orientation profile can be planned such that the theoretical build rate of the motor in the steerable mode exceeds the planned build rate from 1 to 2/100 ft. Then, the assembly is oriented the majority of the time and rotated at short intervals to effect the planned curve. This way, a one-trip curve can be drilled.

One example of this technique is Conoco's K8-1A well, redrilled from the Kotter platform in the North Sea. Fig. 10 shows planned dogleg severities of 6, 8, and 10/100 ft with respect to depth.

A tangent section was necessary between the first two turns to move the well bore placement easterly to line up with the skewed target entry point.

After the original well was sidetracked, the next 2,264 ft of hole, which included a total azimuth turn of 175, was drilled with a steerable angle-build motor. This motor drilled to the top of the sand at 75 of inclination in one run, and was tripped to pick up a logging MWD. Actual build rates ranged up to 11.5/100 ft, and only 30 ft were rotated over the planned oriented section.

The well was finished ahead of the drilling curve and drilled for approximately half the cost of a new well. This horizontal completion produced 12,000 bo/d as compared to 3,000 bo/d for the average directional well from the platform into the same zone. 16

Because medium-radius technology affords such flexibility with respect to build rate and well profile in a wide range of applications, it has become the most common method of horizontal drilling.

SHORT-RADIUS WELLS

Short-radius horizontal drilling is defined as build rates from 1.5 to 3/ft. Typically, inclination is built to 90 over 20-40 ft, with horizontal intervals up to 1,000 ft. Short-radius drilling is used primarily for vertical fractures, low energy reservoirs, EOR, reef formations, and solution mining. 17

Advantages of the short-radius profile are that critical directional drilling is accomplished quickly, avoiding problem formations, and small targets can be hit accurately because of high build rates.

Because short-radius build rates are extremely consistent, no tangent section is planned, resulting in a constant arc profile. However, use of short-radius systems is limited to hole sizes ranging from 4-1/2 to 6-1/2 in.

Currently, there are two types of short-radius drilling systems. These are the mechanical or rotary system, which employs a curved drill guide, 18 and the articulated motor assembly (Figs. 7d and e). 19

The short-radius mechanical system utilizes a curved drill guide for deflection and is typically kicked off with an orienting guide whipstock, held in place by an open hole packer which has been oriented with a gyro or a single shot, depending on hole inclination and casing interference. Aside from articulated single-shot instruments, the only way to survey a well drilled with the short-radius mechanical system is to trip out of the hole and trip in with a surveying BHA. This is one reason use of the short-radius motor assembly may be preferred.

The short-radius motor employs an articulated steering tool to initiate deflection; therefore, constant monitoring of the BHA is possible, and no additional trips are necessary to survey the hole.

The short-radius motor system also can be steered in the horizontal section, and the downhole motor achieves higher ROP with higher azimuth accuracy than the mechanical system.

Amoco drilled several Austin chalk wells utilizing both short and medium-radius technology. 20 In this application, a typical short-radius profile, drilled using the mechanical curved drill guide, consisted of two short-radius laterals in opposite directions (Fig. 11). Production increases resulting from this profile ranged from 2.5 to 7 times that of a vertical well.

Another short-radius job was performed by a Canadian operator using the new articulated motor system, which achieved a total lateral length of 928 ft. The 6-in. short-radius hole was drilled in a sandstone reservoir and was maintained within a 23-ft target zone. The well was cased with a 4-1/2 in. liner.

OTHER CONSIDERATIONS

In horizontal drilling, proper equipment selection depends on a number of factors beyond mere motor performance. For the project to succeed, planning must address such aspects as bit design, MWD selection, and stress limits of various components.

BENDING STRESS

Use of properly designed tubulars in the BHA results in lower torque and drag in the horizontal hole and lower bending moments for the components.

Fig. 12 shows a comparison of bending stress for various curvatures, set to an arbitrary limit of 20,000 psi and calculated for a range of collar sizes. Because the connections between the collars will fail before the collar body, a 100% safety margin is used.

Thus, a 10,000 psi limit is set for the safe operating limits of connections before failure.

Table 1 was generated as a guide to match the optimum curvature. This table addresses only the safe operating range for a drill collar in a curved hole.

ALUMINUM DRILL PIPE

Aluminum drill pipe, being lighter in weight than standard tubulars, may be used in some horizontal applications, although to date, this practice is not common.

By placing heavy-weight drill pipe in the vertical portion of the well, and using the lighter aluminum drill pipe in the lateral section, it may be easier to "push" the drillstring along the wellbore without creating excessive drag.

MWD SELECTION

MWD selection in horizontal drilling must take into account the type of formation evaluation required by the reservoir and geology departments, such as gamma ray, resistivity, density, porosity, or neutron logging. In addition, MWD provides directional information.

If the MWD requires a stabilizer for a particular logging application, it should be nonintegral with the MWD, undergauge, and with tapered blades. It may be necessary to remove the stabilizer from the MWD to reduce friction in the horizontal interval while drilling in the orientated mode.

A directional measurement-while-drilling (DMWD) instrument is available for use in applications that include both horizontal and directional wells, slim holes, kickoffs, and sidetracks. The DMWD is fully wire line retrievable, and has an OD of 2 in.

In critical hole applications, the tool can be retrieved, the hole conditioned, and the DMWD run back into position without tripping out.

In high-temperature environments, it can be go-deviled to depth, data transmitted, and the tool retrieved, all within hours.

BIT DESIGN

Bit design is especially important when utilizing a high-offset motor like those used in medium-radius drilling. In addition to being able to drill the formation, bits must have sufficient gauge protection to maintain proper hole size while drilling with significant bit offset.

POSTWELL ANALYSIS

Postwell analysis is also important to successful horizontal drilling operations, particularly when planning for subsequent wells.

Time spent documenting performance information for inclusion in a comprehensive data base can be repaid many times over by the savings realized on subsequent wells."

Upon completion of a well, project objectives should be reviewed and compared to actual results. If any problems have occurred, they should be investigated by the responsible party and solutions recommended at a postwell meeting with the operator and service companies. Then, areas of improvement can be determined to ensure that future wells take advantage of the learning curve.

In this way, proper well planning can be seen as a cycle: Wells are planned, drilled, surveyed and analyzed.

Then the information on formation characteristics, bit performance, directional control, and other factors is used to plan the next well.

Given the constantly changing technical environment in which we operate today, this approach to well planning helps ensure proper selection of drilling equipment for a more efficient and cost-effective horizontal drilling program.

REFERENCES

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