Level 6 multilateral succeeds in heavy oil field trial

Jan. 18, 1999
During September 1998, the world's first TAML Level 6 multilateral was completed in the shallow-sand environment of the Belridge field, near Bakersfield, Calif. The completion system, with the trademark name FORMation Junction, provides an hydraulically sealed, multilateral casing junction that allows two lateral sections to be drilled from a single main bore. For the project, Baker Oil Tools worked with Shell Oil Co. and the field's operator, AERA Energy LLC.
Cliff Hogg, Alan MacKenzie, David Crews
Baker Oil Tools
Houston
During September 1998, the world's first TAML Level 6 multilateral was completed in the shallow-sand environment of the Belridge field, near Bakersfield, Calif.

The completion system, with the trademark name FORMation Junction, provides an hydraulically sealed, multilateral casing junction that allows two lateral sections to be drilled from a single main bore.

For the project, Baker Oil Tools worked with Shell Oil Co. and the field's operator, AERA Energy LLC.

The junction uses formed metal technology to create a full-size multilateral junction that, during installation, has an effective outside diameter less than the sum of the junction's two lateral casing legs.

The system is run in a preformed mode as part of a standard casing or liner string and is reformed downhole using swaging technology. Conventional drilling and completion techniques finish construction and completion of the well bore.

The junction was designed, developed, and patented by Baker Oil Tools and uses "Mara-Split" technology, which is licensed exclusively to Baker Oil Tools by Marathon Oil Co.

TAML categorization

TAML (Technology Advancement of Multilaterals) is a group of operators with multilateral experience who adopted a categorization system for multilateral wells based on the amount and type of support provided at the junction.

This system provides operators with an easy method for recognizing and comparing the functionality and risk-to-reward of different multilateral completion designs.

Level 6 is the highest-level multilateral thus far categorized by TAML. It is defined as a multilateral completion in which pressure integrity is achieved with the casing and not by cement, which is not acceptable.

Project overview

The Belridge field has seven separate, heavy-oil sands, each of which typically requires a single horizontal well to optimize drainage. The field also has vertical steam-injection wells that maintain the reservoir temperature sufficiently high enough to allow oil to flow to rod-pumped wells.

The horizontal wells, on occasion, need to be steamed individually and/or cleaned out due to sand migration from the formation.

The dual horizontal multilateral well completed in September will replace two planned individual horizontal wells.

Re-entry into either lateral can be done at any time by installing the appropriate diverter.

Junction

The junction consists of a joint of standard 95/8-in. casing, below which is attached two 7-in. casing strings in an inverted "Y" type of configuration ( Fig. 1 [13,650 bytes]).

The longer of the two 7-in. legs is made of a malleable metal and is formed around the second, shorter 7-in. leg so that the overall OD of the two casing strings is not more than 12 in. at any point along the length of the junction.

As a result, the junction is capable of passing through 133/8-in. casing or a 121/4-in. open hole.

During installation, cementing float equipment is placed below the formed portion of the first 7-in. casing leg while the second leg is blanked off with a drillable bull plug. The float equipment allows for cementing the junction in place.

Accessory equipment for the system includes:

  • Reforming tool for opening the preformed portion of the 7-in. leg
  • Diverter tool that is run in place for guiding the reforming tool along the proper path
  • Cement/running string for activating the swage tool and also providing for a cement path through the junction and into the float equipment.
Liner hangers and additional completion equipment can also be run as needed, depending upon the requirements of a specific well.

Main bore

The construction of the Belridge well involved spudding the well and drilling a 97/8-in. hole to 1,856 ft measured depth (MD), 1,109 ft true vertical depth (TVD), with a hole inclination was 96.6°.

The curve section sustained an average dogleg severity of 13.5°/100 ft and a maximum dogleg severity of 13.5°/100 ft with a 111-ft tangent section at 79.5° inclination. The entire curve and lateral were enlarged to 13 in. with a hole opener.

In the area where the junction would be situated, the hole was underreamed to 17 in. from 1,562 ft to 1,662 ft, at an approximate hole inclination of 92.6°.

The well was circulated clean prior to pulling the drilling assembly from the hole.

A 95/8-in. casing string was run with the preformed junction landing in the 17-in. underreamed section.

The float equipment and landing collars were contained within the first 7-in. lateral leg. A diverter was preinstalled in the completion system to allow a pathway for the subsequent reforming string to complete forming the junction.

Next, an orientation anchor was made up in a measurement-while-drilling (MWD) tool. It was run and stabbed into the swage diverter to obtain the orientation of the junction key.

The reforming string was then run in, set, and the malleable leg of the junction was successfully reformed.

This stage provided useful information on the reforming process. The information led to further development work for optimizing the process.

The junction was successfully pressure tested prior to cementing.

The cement operation involved running the cementing string and stabbing it into a drillable packoff bushing. The preflush, lead, and tail-in cement were pumped after rigging up the cementing head and lines.

This was followed by the release of the drill pipe wiper plug that was pumped down until it landed and sealed in the landing collar. The casing was then prepared for the wellhead.

Laterals

The directional assembly for drilling the first lateral leg consisted of an MWD tool, mud motors with 1.83°/1.50° bent housings, and 6-in. milltooth bits. Drilling started at 3,566 ft MD (1,064 ft TVD) at a 90° inclination.

Because of an undergauged bit, a wiper trip was made with a new 6-in. bit to ensure a full-gauge hole prior to running a 41/2-in. slotted liner. The hole was reamed to TD and the mud was displaced to a 5% KCl completion fluid.

Lessons learned during the drilling phase led to additional work on the diverter system. The work involved providing for a maximum drift and also for simplifying the setting, operations, and retrieving operations of the diverters.

The liner was run to TD, with centralizers on every joint. After the liner tagged bottom, the liner seal assembly was set in the lateral leg. The running tool was released and retrieved, and the pulling tool for the diverter was made up and run in with the jars and accelerator.

The junction was circulated, and the pulling tool was stabbed into the diverter. An overpull was then applied to release the diverter.

The drilling diverter for the second (lower) lateral was run, set, and released from the running tool with the same tools and techniques as for the upper lateral. The same type of drilling assembly was run.

Drilling the second lateral included drilling out the shoe at 1,622 ft MD, 1,126 ft TVD, and then drilling the lateral to TD at 3,636 ft MD , 1,080 ft TVD, at a 90° inclination.

The drilling assembly was pulled and laid down after the hole was reamed and cleaned out.

A 6-in. hole opener was run in place of a bit to reduce the risk of sidetracking in the original well bore. After the lateral was reamed to TD, the mud was displaced to 5% KCl completion fluid.

After the 41/2-in. liner reached TD, the liner packer was set in the junction area of the lower lateral leg and the running tool was retrieved.

The drilling diverter was pulled from the well using the same tools and techniques as in previous trips. A final trip was made to displace the fluid at the junction to clean KCl.

All drill pipe was laid down on the trip out of the hole and the wellhead was installed.

The rod pump and completion equipment were installed at a later date by a completion rig.

Fig. 2 [178,707 bytes] illustrates the final well configuration.

System advantages

The junction provides a Level 6, pressure integrity at the junction with a continuous, uninterrupted metal lining. Elastomers or cement are not used to provide a pressure seal.

Standard drilling and cementing techniques during the junction and casing installation and cementing provide an overall simple process for creating a multilateral well. Therefore, the risks associated with multilateral operations are more-effectively managed.

One main contributor to effective risk management in a multilateral well is the containment and management of debris generated during junction creation.

Formed metal technology eliminates debris creation because no casing exit has to be made. The process does not require milling.

Debris creation and removal is a major topic of concern for many operators when discussing risks associated with multilateral wells. Debris, if not properly managed, can prevent completion equipment from operating as intended, thus limiting functionality of the well.

These debris can impede production by plugging or obstructing flow ports and tubulars, and can create difficulties when removing junction construction equipment such as whipstocks, mills, and anchors.

Typically debris is created during the following two segments of the multilateral construction and completion process:

  1. When the initial casing exit window is being created with mills
  2. When access to the lower bore is re-established with washovers, perforations, or milling.
Several methods and techniques can counter the debris problem. These include use of composite materials and premilled windows and the thorough applications of comprehensive debris management procedures. However, because the junction discussed in this article does not create debris, the risk inherent with debris is eliminated. 2

The flexibility provided to the drilling program is another advantage of the junction. Most multilateral systems require one or both laterals to be drilled and completed prior to completing the junction itself. As a result, any problems with the junction creation could result in loss of the previously completed laterals.

With formed metal technology, this risk is eliminated. The junction can be set, reformed, cemented in place, and pressure tested prior to drilling or completing either lateral.

Top-down construction also enables junctions to be constructed in a well while delaying the actual implementation of a multilateral for later in the well's life. This is particularly useful in injection wells, where additional injection is required as the field matures, and in fields subject to formation shifting and possible crushing of the lateral liner as formations are depleted.

Planning the use of the junction at the start of the drilling program, rather than retrofitting a system can minimize workover costs.

Based on the success of the Belridge Level 6 multilateral, Baker Oil Tools and Shell's multilateral global team are preparing a second field trial of the junction.

References

  1. Diggins, E., "Classification provides framework for ranking multilateral complexity and well type," OGJ, Dec. 29, 1997, p. 73.
  2. Hogg, C., "Managing debris in cutting multilateral well windows," Offshore, April 1998.

The Authors

Cliff Hogg is a senior applications engineer with Baker Oil Tools in Houston. He works in the emerging technologies/multilaterals group. He joined Baker in 1993 and has worked as a field engineer in West Texas and Oklahoma. Hogg has a BS in petroleum engineering from Texas A&M University.
Alan MacKenzie is multilateral systems development manager for Baker Oil Tools in Houston. His responsibilities include new systems development and marketing of multilateral systems worldwide. He has previously worked in product engineering, international operations, and marketing. MacKenzie is a graduate of Robert Gordons University, Aberdeen.
David Crews is a business development manager of multilaterals/re-entry for Baker Oil Tools in Houston. For the past 2 years, he has been involved exclusively with worldwide multilateral/re-entry strategy and implementation. Prior to that, he has held various industry positions in management, marketing, and engineering. Crews has a BS in geology from Texas A&M University.

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