ESP'S PLACED IN HORIZONTAL LATERAL INCREASE PRODUCTION

Andrew Gallup, B. L. Wilson
Oil Dynamics Inc.
Tulsa

Robert Marshall
Oryx Energy Co.
Dallas

By design, the electric submersible pump (ESP) is an effective method of lifting fluids from horizontal wells. But this ESP application does have unique installation and operating parameters that need to be considered.

ESP's have been used for many years in directional wells. This application provides an experience base for understanding deflection limits on the unit. To avoid damaging the ESP, special equipment may be required in some horizontal installations.

Several ESP's have been designed specifically for medium-radius wells. In these applications, the deeper pump setting provides for a significant increase in production rate. In general, to realize the full benefit of a horizontal installation, the ESP should be considered when planning, drilling, and completing the well.

Furthermore, a key element in the success of any horizontal ESP application is effective communication between user and manufacturer.

HORIZONTAL WELLS

Horizontal wells are currently the focus of attention in all aspects of drilling, completion, and production. The recent increase in horizontal well completions is largely the result of advances in drilling technology, including measurement-while-drilling (MWD) and steerable drilling tools.

Horizontal wells are more effective than conventional vertical wells in draining thin productive intervals and vertically fractured reservoirs. As a result, a horizontal well has the potential of delivering significantly more fluid than a conventional well in the same formation. Producing horizontal wells is certain to present new challenges for the artificial-lift industry.

ESP'S, in particular, will play a key role in producing these wells due to their inherent ability to lift large volumes of fluid at low bottom hole pressures. To realize the full benefit from a horizontal ESP installation, special application guidelines must be considered.

A conventional well, although considered straight and vertical, is in fact never truly straight or vertical over the entire length of the well bore. In actual practice, when drilling a well the bit often deviates from true vertical due to factors such as penetration rate, varying formation properties, etc.

In a directional well, the well bore is intentionally deviated to reach a target zone inaccessible with a straight hole. The location in the well where the deviation begins is referred to as the kickoff point (KOP) and is followed by a curved portion of the hole called the dogleg or build angle.

In the dogleg, the hole curvature is measured in 100 ft (Fig. 1) which is commonly referred to as the dogleg severity or angle build rate. Dogleg severity in directional wells is usually less than 7/100 ft with the total inclination from vertical building to as high as 85.

Many different deflection patterns are possible. Some patterns consist of multiple doglegs and drop angles to reach the pay zone.

A horizontal well, like the directional well, has a kickoff point where the well bore begins to build angle; however, in a horizontal well the angle continues to build until the well bore makes a lateral (approximately 90 inclination) penetration into the formation.

All horizontal wells share this characteristic because the objective is to position the well bore approximately parallel to the bedding plane of the formation.

Horizontal wells are classified (Fig. 2) by the radius or angle build rate in the transition between the vertical and horizontal sections.

Short-radius wells have a radius of 30-1 00 ft and a build rate of 60-200/100 ft. Medium-radius wells are those with a radius of 300-600 ft and a build rate of 10-20/100 ft. The third classification, long-radius wells, have a radius of 800-3,000 ft and a build angle of 2-7/100 ft.

This radius represents a nominal value as the actual build rate usually varies over the length of the curve. Also, the curve may include a straight tangent section (Fig. 3) which connects two build angles. These variations in curve profile are done for practical drilling considerations.

Many variables can affect angle build rate while drilling; therefore, it is often necessary to steer the well bore towards the target zone as drilling proceeds through the curve. Following the curve, the horizontal section of the well is typically 500-3,000 ft long. Depending on formation properties and preferred drilling practices, the horizontal section may be inclined slightly upward (greater than 90 inclination) or downward (less than 90).

PRODUCING WITH ESP'S

As a result of the increased formation exposure and the higher fluid volumes that follow, many horizontal well completions will be candidates for an ESP system. For these applications, the first point that must be addressed is the location of the unit in the well.

If producing bottom hole pressure above the kickoff point provides adequate intake pressure to avoid excessive gas locking (cycling), the unit can be installed in the vertical section of the hole. In this situation, standard equipment can be used and normal installation and operating procedures applied.

On the other hand, if the intake pressure is too low to avoid continuous gas locking or if more drawdown is desired, then a deeper setting must be considered.

When considering a deeper setting there are basically two alternatives in a horizontal well: Locate the unit on an incline in the straight tangent section of the curve, or locate it in the horizontal section. In either case, special application guidelines must be followed to avoid damaging the equipment and to ensure satisfactory operation.

An ESP can operate properly at any angle up to and including horizontal, provided the unit is straight. The primary concern in these applications is the bending that occurs as the unit passes through the curve.

Similar to a drillstring, the ESP can be considered flexible in some situations. An ESP differs from a drillstring, however, in that the components of the assembly are bolted together with flanged joints.

The flanged joints require an undercut area or neck to provide access to the attaching bolts. From the geometry of these flanges (Fig. 4), it is easily concluded that the flanges will be weaker in bending than the rest of the unit.

As the unit deflects when passing through a dogleg, the bending stress occurring at the flanges must not exceed the yield strength of the material if permanent bending is to be avoided. Obviously, a bent flange would cause extremely high radial loads on the adjacent shaft bearings, resulting in premature failure.

Historically, ESP's have been installed in directional wells with good success. This experience, coupled with experimental evidence, indicates that a standard ESP can tolerate 3/100 ft of deflection while passing through the curve without permanent bending.'

In most applications, the actual deflection of the ESP will be less than the dogleg severity indicated on the well survey. The difference between actual ESP deflection and the casing dogleg is a result of the clearance that exists between the inside diameter of the casing (Fig. 5) and the outside diameter of the unit. This is illustrated in the next example.

EXAMPLE

Assume an ESP is designed for the horizontal section of the well. This section of the well is straight with an 88 inclination and is completed with 5 1/2-in. casing. Locating the unit there will require it to pass through a curve consisting of several build angles, the most severe being an 8/100 ft dogleg in 9 1/8-in., 36-lb/ft casing. The assembled unit is 60 ft long.

The large clearance between the ESP outside diameter and the casing inside diameter will offset much of the dogleg severity in this case. Since the motor OD is 4.5 in. and the pump OD is 4.0 in., an average 4.25-in. OD will be used for the entire unit.

Casing Clearance

Casing ID - Unit OD = 8.921 - 4.250 = 4.671 in.

Because the unit is 60 ft long, the casing deflection in a 60-ft interval will be calculated. The deflection of the casing (represented by an arc, Fig. 5) for a given interval of the dogleg can be approximated as follows:

d = 2.6 (L/100)2 x a (1)

where:

d = Deflection at the center of arc, in.

L = Length of section, ft

a = Dogleg severity, /100 ft

Casing Deflection = 2.6 (60/100)2 x 8 = 7.488 in.

The actual deflection of the ESP is the difference between ESP-to-casing clearance and the casing deflection:

ESP Deflection = Casing Deflection - Clearance = 7.488 - 4.671 - 2.817 in.

An equivalent deflection angle for a 2.817-in. deflection in the middle of a 60 ft long unit can be obtained by rearranging Equation 1 and substituting values for d and L respectively:

a = d/[2.6 (L/100)2] (2)

ESP deflection angle = 2.817/[2.6(60/100)2] = 3.0/100 ft

Based on the 3/100 ft rule-of-thumb for ESP'S, this unit should pass through the radius without permanent damage.

This method has several limitations. First, because it is assumed that the deflection is very small relative to the radius of curvature, the formula (Equation 1) begins to lose accuracy with doglegs greater than 20/100 ft.

Second, it assumes the motor and pump are relatively close to the same diameter and therefore may be inaccurate when components of different nominal diameters are used.

Computer programs have been developed to evaluate applications that are beyond the limits of this method. The ESP manufacturer should always be consulted for recommendations on the specific equipment involved.

Specialized ESP equipment In general, standard ESP's are candidates for many long-radius wells, while the high build angles in medium-radius wells will likely require special equipment. Clearly, short-radius wells are limited to vertical ESP settings only because it is impossible to avoid equipment damage when passing through the extreme angle.

Special ESP equipment has been developed for horizontal installation in medium-radius wells. Specifically, several units have been designed and manufactured to withstand deflections up to 12/100 ft while passing through the curve.

The development of this equipment requires an understanding of how the unit is restrained by the casing. In other words, exact locations of all the points where the unit touches the casing, as well as the force applied at these points, is needed (Fig. 6).

A computer model has been developed to obtain this information .2 With a knowledge of the forces and moments applied to the unit, modifications can be made to accommodate the higher bending stress.

Actual deflection tests have been performed on assembled units to validate the computer model. These tests duplicated the forces imposed on the ESP when deflected in a dogleg and were found to be in close agreement with the predictions of the model. This model is now being used as a design tool for analyzing equipment deflections above 3/100 ft.

HORIZONTAL OPERATION

When designing an ESP for operation in the horizontal section of the well, each component of the system must be considered.

PUMP

The pump is unaffected by changes in orientation, since gravity has virtually no impact on its operation. The thrust forces on each impeller are an order of magnitude higher than the weight of the impeller itself; therefore, change in thrust washer wear is negligible.

Radial forces in a centrifugal pump are typically low, and downhole pumps have almost continuous shaft support over their entire length. The increased radial bearing load from the weight of the rotating mass is insignificant since the unit has more than ample radial bearing area.

GAS SEPARATOR

Gas separators are to a certain extent reliant on the buoyancy of gas for directing free gas back to the wellhead. Horizontal installations may diminish the performance of a standard gas separator.

SEAL CHAMBER

Labyrinth and blocking fluid-type seal chambers rely on a fluid interface to prevent well fluid entry into the motor. These units will not function in the horizontal position because well bore fluid would enter the motor. Bag-type seal chambers are effective in all positions.

MOTOR

The motor thrust bearing is designed to support the full weight of the motor shaft and rotors when in the vertical position. As the motor is inclined, the load on this bearing decreases, ultimately reaching zero load at 90 inclination. If the unit is positioned at an inclination greater than 90, (i.e., uphill) special provisions may be required to sustain the upward shaft and rotor weight.

Well fluid provides cooling for an ESP motor; therefore, the lack of circulation on the side of the motor laying against the casing may be a problem. In hot wells, centralizers should be considered to allow complete circulation around the motor.

CASE HISTORIES

Oryx Energy Co.'s well L. W. Sweet No. 3, in West Texas, is a medium-radius well (Fig. 7) with an average angle build rate of 120/100 ft through the curve. It was completed with a 5 1/2-in. liner from the kickoff point to the end of the hole.

Upon completion, the well was swab tested, and based on this test an ESP nominally rated at 700 b/d was selected. The unit was set in the vertical section just above the kickoff point at 5,800 ft true vertical depth (TVD). A variable-speed drive (VSD) was utilized, as variation in inflow performance was anticipated.

During the first several weeks of operation, the unit operated at 65 hz and cycled an average of 13 times/day.

Although the ESP was equipped with a gas separator, periodic slugs of gas overloaded the separator and the unit would shut down on the underload condition.

The slugging phenomena was likely the result of unstable flow occurring in the horizontal section, since free gas can collect on the upper side of the liner and hole. This situation was further aggravated by the upward inclination (93) of the horizontal section which effectively trapped the gas until sufficient well bore pressure and fluid velocity were present to carry the gas toward the vertical section.

After one month of operating in this mode, averaging run times of 9 hr/day, the decision was made to redesign the ESP for operation in the horizontal section.

By setting the unit 700 ft deeper in the horizontal section, additional drawdown and pump intake pressure could be obtained while possibly reducing the gas slugging problem. Since the unit would be required to pass through a 12/100 ft curve without damage, specialized equipment was necessary.

In addition, a tandem (piggyback) seal chamber and gas separator were also specified for the system. As in the vertical ESP installation, a 700-b/d pump running on a VSD was selected. A downhole pressure sensor was used to monitor pump intake pressure.

The unit was set just beyond the end of the curve in a straight horizontal section and, as expected, a substantial increase in production followed. Again, the ESP operated at 65 hz and cycled several times per day; however, average run time was increased to 14 hr/day, resulting in a 50% increase in fluid production. As of Mar. 16, the ESP had performed consistently for 8 months.

Based on the experience in L. W. Sweet No. 3, another Oryx well, the J. G. Adams No. 1, was considered a likely candidate for a horizontal ESP installation when the well was completed. J. G. Adams No. 1 also has a 12/100 ft curve (Fig. 8) but the curve is completed with 7-in. casing. The larger casing provides more pump-to-casing clearance and reduces the deflection imparted to the unit. A well test was performed with an ESP in the vertical section, and from these data a horizontal unit was designed.

A 500-b/d pump, tandem seal chamber, gas separator, and 45-hp motor running on a VSD were selected for the horizontal installation. A downhole pressure sensor similar to the one on L. W. Sweet No. 3 was used to monitor pump intake pressure.

The unit was set at 7,040 ft TVD, approximately 500 ft deeper than the ESP used in the initial well test. By using an ESP designed for the horizontal section, gas locking decreased significantly, and fluid production increased by 20%.

These two examples illustrate the potential of horizontal ESP installations when effective well planning and ESP designs are implemented. Much of the success of these applications was a direct result of planning for the horizontal installation even prior to drilling.

RECOMMENDATIONS

To maximize the potential of a horizontal ESP installation, the following practices are recommended:

Drill the well as large as economically possible. Increasing the clearance between the ESP and casing reduces the deflection that occurs as the unit passes through the curve. Additional clearance also provides room for cable protection devices and motor centralizers if required.
Drill the horizontal section to maintain a continuous downhill inclination (less than 90) towards the end of the hole if possible. A slight downhill inclination will provide a path for the gas to rise towards the wellhead thereby minimizing gas locking.
Inclinations greater than 90 cause the gas to collect at the end of the hole and slugging can result.
Design the build curve with a straight tangent as an alternate location for setting the ESP if the actual build rate in the bottom portion of the curve precludes horizontal installation.
Install a reduced-diameter liner from just below the ESP to the end of the hole to increase superficial velocity. Higher superficial velocity will minimize the possibility of slugging.
Use only bag-type seal chambers, as labyrinth seal chambers will not function in the horizontal position. If the bag-type seal chamber uses a labyrinth chamber for a secondary sealing system, a tandem seal chamber should be used.
Centralizers and cable protection devices will be required for some applications. They should be used with caution, however, since they reduce the ESP-to-casing clearance and increase unit deflection when passing through the curve,
Consider the use of a variable-speed drive. Reservoir productivity is inherently difficult to predict in horizontal wells. A variable-speed drive offers the flexibility of varying the production rate to optimize well performance.

REFERENCES

ODI Training Manual, Oil Dynamics Inc., Tulsa, 1987.
Wilson, B. L., "Micro Computer Analysis of ESP Bending," ESP Microcomputer Applications in Artificial Lift Workshop, Long Beach, Calif., Oct. 16-17, 1989.
Torre, A. J., Schmidt, Z., Blais, R.N., Doty, D. R., and Brill, J. P., "Casing Heading in Flowing Oil Wells," SPE Production Engineering, November 1987, pp. 297304.