MULTIPLE HORIZONTAL DRAINHOLES CAN IMPROVE PRODUCTIONS

Kyle S. Graves
Baker Huges Inteq
Houston

Drilling several horizontal sections from a single vertical well bore has improved the drilling and production economics on many wells, especially in South Texas, where multilateral wells are becoming more common.

A multilateral well consists of two or more horizontal drainholes drilled from one primary vertical well bore, either as a new well or as a re entry.

There are a number of advantages to drilling multilateral drainholes. Multilateral drainholes reduce drilling costs because only one main vertical bore is drilled (reduces drilling time and wellhead and casing costs). Of primary, importance is the increased well production compared to similar single horizontal wells and vertical wells.

The use of a single vertical well bore minimizes location, access road, and cleanup costs. Fewer surface production facilities may be necessary, and offshore, increasing the drainage area for a fixed number of well slots gives greater platform flexibility and allows more extensive field development.

One disadvantage, however, is the potential complications during well control because two or more well bores are open. Also, the ability to sen ice a particular well bore is more complex. To prevent future well bore service problems, each drainhole must be designed for later re entry.

SOUTH TEXAS

Drilling multilateral well bores has become a relatively commonplace technique in South Texas. This technology, has improved the economics of many wells in the Austin chalk trend and has similar potential in many other areas.

In 1990, multilateral drilling began in earnest in South Texas as a means of dealing with odd shaped leases. The irregular lease shapes put many restrictions on surface location sites.

In 1990, a horizontal displacement of 2,500 3,000 ft from a single drainhole was considered extraordinary, and the record displacement for a multilateral well was 5,649 ft. Today, a displacement of 5,649 ft is considered hi,h average for a single drainhole, and several have total displacements around 10,000 ft. Improvements in the technology have resulted in more footage in the pal, zone.

The multilateral "learning curve" has been overcome in South Texas, where approximately half of the horizontal drilling activity consists of multilateral wells. In 1991, multilateral drainhole technology was used in only 1.7% of the wells that Baker Hughes helped drill in South Texas. By 1992, the number rose to 13.7% and is estimated at 50% for 1993. Other service companies show similar trends toward multilateral wells in South Texas.

PLANNING

An operator should first find out if local regulations allow for two or more open drainholes from one well. An evaluation and planning team, consisting of both operator and service company personnel, should then assess the potential for a multilateral well, especially in marginal oil fields or new areas.

Before determining what type of multilateral drainhole to drill, all operator should thoroughly, examine the drilling environment. For a successful multilateral well, the zone should be thick relative to the radius of curvature and competent enough to allow for two open hole sections simultaneously. Reliable pore pressure data are important because the first lateral max. be open for some time while the last lateral sections are drilled.

Generally, multilateral drainholes are a viable drilling option under any of the following conditions:

One or more vertical permeability barriers are present.
The planned displacement is large.
The lease has an irregular shape.
Topography prevents multiple surface locations.
The surface is environmentally, sensitive.
An existing well bore is planned for re entry.
The offshore platform has a limited number of slots.
The zones are laminated and have various reservoir characteristics.

The guiding principle in deciding whether to drill a multilateral well is, of course, the production estimate.

FORMATION DIP

Determining the formation dip is important during the planning stages of a horizontal well. Inaccurate formation dip data can cause a drainhole to miss a target entirely. For example, a 0.50 error in dip on a 5,000 ft drainhole equates to a 44 ft difference in true vertical depth. In many wells, the target is less than this difference in true vertical depth.

Drillers must also be aware of the apparent dip, which should be calculated if the drainhole is drilled in a direction other than the true dip direction (Fig. 1).

During the design phase, it is imperative to decide whether to drill the updip or downdip lateral first because the build rate for the second lateral is affected by the build rate used in the first. If possible, the updip leg should be drilled first. The resulting build up rate required for the downdip leg will then be lower (Fig. 2).

The multilateral drainhole must be designed with realistic objectives. surface load prediction models (torque, drag, and hydraulics) should be used to help prevent any unwelcome surprises during operations.

The build rate should be flexible to allow for geological variations, such that the well plan may be changed without adversely affecting operation speed or objective.

TYPES

Although multilateral drainholes are generally referred to as a single type of well, there are actually several types: the over/under multilateral, the 1800 opposed bore well, and the well multilateral. Additionally, these wells may, be drilled in combination with one another or with the casing set at an angle. Multilateral sections are not limited by curve radius; short, medium, and long radiuses are possible.

OVER/UNDER

The over/under multilateral drainhole is drilled more often than any of the other types, The primary application of this well type is around a vertical permeability barrier.

Typically, the upper lateral is drilled first to facilitate a low side sidetrack. The upper build rate may or may not equal the lower build rate, and a tangent section may or may not be required. The upper and lower hold angles do not have to be equal, nor do the two azimuths.

For example, the well shown in Fig. 3 was planned as an over/under well with three southeast downdip lateral sections (wings). Because of vertical permeability barriers, the true vertical depth separations were 57 ft between the upper and middle wings and 42 ft between the middle and lower wings.

The curve section of the upper wing was drilled with 4# in. angle build motors in a 6# in. hole. The average dogleg severity in this section was 15.60/100 ft. The lateral section of the upper wing was drilled with one 4# in. angle hold motor to a horizontal displacement of 2,478 ft. This section had an average inclination of 88.20.

After the upper wing was completed, the bottom hole assembly, was pulled. The same motor was used to drill an open hole sidetrack. The remaining middle curve section was drilled with another 4# in., angle build motor; the average dogleg severity, was 170/100 ft. A similar motor drilled the lateral section to a total displacement of 2,479 ft and with an average inclination of 87.50.

The lower wing was drilled utilizing the same technique as in the middle wing. The total displacement was also 2,479 ft, and the average inclination was 87.60.

From kick off point (KOP) to total depth of the third wing, the operation took about 23 days. The total depth of the well reached 12,769 ft measured depth (MD).

OPPOSED DRAINHOLES

Opposed drainholes are drilled approximately 1800 apart. The opposed well bores are a viable option if a single vertical well is in one zone and the pay, area is large.

Typically, the updip build rate is less than the downdip build rate. The updip angle is often 900, and the downdip angle is often <900. Total displacements of >10,000 ft are currently possible with this type of well.

A recent opposed bore multilateral well was designed with one northwest updip wing with 4,000 ft of horizontal displacement and one southeast downdip wing also with 4,000 ft of horizontal displacement.

The vertical hole was cased with 9# in. casing. The initial curve was kicked off with a 6# in., angle build motor in an 8 in. hole. The curve section of the updip wing was drilled to 81.90 inclination with a dogleg severity averaging 130/100 ft. The lateral section was drilled with 6# in., angle hold motors to a total displacement of 4,104 ft. The average inclination of this section was 93.70.

Once the updip wing was completed, a 6# in., angle build motor was run in the hole to drill the sidetrack. The remainder of the curve section was drilled with the same assembly. The dogleg severity averaged 130/100 ft. The lateral section of this wing was drilled to a total displacement of 5,332 ft using 6# in., angle hold motors. The average inclination for this section was 86.30.

This operation took 45 days: 19 days to drill the updip wing from KOP to total depth and 26 days to drill the downdip wing.

Fig. 4 shows a 1800 opposed bore well drilled as a re entry, using slimhole technology. The dual wing horizontal well was planned with a southeast downdip wing and a northwest updip wing.

The well was planned to be sidetracked through a window in the existing 5 in. casing. Both wings would be drilled to total depth with 4# in. bits and 3# in. motors. The proposed horizontal displacement was 1,884 ft for the downdip wing and 978 ft for the updip wing. The plan called for the downdip wing to be drilled first, with the updip wing contingent on the results.

The downdip wing's curve was drilled first with an average dogleg severity of 15.60/100 ft. The lateral section was drilled to an average inclination of 870. The horizontal displacement was 1,881 ft.

Upon completion of the downdip wing, the bottom hole assembly was pulled, and an open hole sidetrack was started. The same 3# in., angle hold motor that finished the downdip wing was used to start the updip curve. The remainder of the updip curve section was drilled to an inclination of 89.10. The dogleg severity in this section averaged 23.10/100 ft, which is somewhat more difficult to achieve than a smaller dogleg severity.

The updip lateral was drilled to a total displacement of 972 ft and an average inclination of 920.

The job took about 16 days from KOP to total depth to drill 2,853 ft in the zone.

The resulting build rates demonstrate that drilling the updip wing first is preferable. Had the updip wing been drilled first, its build rate would have been lower, making the well easier to drill.

Y WELL

In multilateral Y wells, the wings are drilled out of phase (the difference in directions does not equal 1800).

This type of well is typically drilled on oddly shaped leases. Either the updip or downdip wing may be drilled first, depending on the calculated build rates.

Fig. 5 shows a well originally planned as a quadruple wing horizontal well, with two downdip southeast wings and two updip northwest wings.

The casing had to be set at an angle perpendicular to the proposed azimuths to achieve the necessary build rates in the thin pay zone. Each wing had a proposed horizontal displacement of 2,500 ft.

During drilling, the operator decided to drill only one updip wing and one downdip wing and to re enter the well at a later date to drill the remaining two wings.

The initial curve was kicked off in the 9# in. hole section perpendicular to the planned azimuth (southeast).

The inclination at the 7#in. casing point was 140. The 6# in., angle hold steerable motor used to drill this section achieved a 9.60/100 ft average build rate.

The curve was continued with 4# in. angle build motors in a 6 in. hole, reaching 80.70 inclination. The average dogleg severity in this build and turn section was 20.30/100 ft.

The remainder of the curve and the entire lateral section of the downdip wing were also drilled with 4#in., angle build motors. The average inclination of the lateral section was 870.

Once the downdip wing was completed, the bottom hole assembly was pulled, and the well was sidetracked in open hole.

The updip wing was started with the same 4# in., angle hold motor used to complete the downdip wing. The remainder of the updip curve section was drilled with a 4# in., angle build motor, which achieved an average dogleg severity of 18.20/100 ft.

The lateral section of the updip wing was drilled with 4# in., angle hold motors to a displacement of 1,792 ft with an average inclination of 940. The total directional drilling time on the well was 27 days.

ACKNOWLEDGMENT

The author wishes to thank Baker Hughes Inteq for permission to publish this article.

BIBLIOGRAPHY

Califf, B. and Kerr, D., "UPRC Completes First Quad Lateral Well," Petroleum Engineer International, September 1993.
Cooney, et al., "Case History of an Opposed Bore, Dual Horizontal Well in the Austin Chalk Formation of South Texas," SPE paper 21985 presented at the 1991 Society of Petroleum Engineers/International Association of Drilling Contractors Drilling Conference, Mar. 11 14, 1991, Amsterdam.
Graham, S.A., et al., "Drilling a Dual Bore Horizontal Well in the Austin Chalk: A Case History," prepared for World Oil 1992 Horizontal Drilling Conference, Houston.
McMann, et al., "Development of the Brookeland Field Austin Chalk Drilling Dual Lateral Horizontal Wells," SPE paper 26355 presented at Society of Petroleum Engineers Annual Technical Conference & Exhibition, Oct. 3 6, 1993, Houston.