Pre-Engineered multilaterals provide cost effective solutions

Flexible functionality guiding multi-lateral technology evolution

Matthew Jabs, David Crews
Baker Oil Tools
Houston

• The Downhole Splitter allows for simultaneous, independent, dual-bore production (Illustration courtesy of Baker Oil Tools). [31,952 bytes]
• The DeepSet Splitter may be used as a single producer/injector with commingled flow (Illustration courtesy of Baker Oil Tools). [26,200 bytes]
• The FORMation Junction can provide commingled or isolated flow with re-entry capability (Illustration courtesy of Baker Oil Tools). [24,188 bytes]

Recently, higher hydrocarbon-to-market costs and greatly reduced prices for oil and gas have caused operators' EBIDT (earnings before interest, tax, and depreciation) to suffer. Various drilling and completion technologies, such as pre-engineered multilateral (PEML) junctions, have proven beneficial in improving a field's overall producing economics and the operator's ultimate earnings.

Prior to the development of PEML junctions, most multilateral systems called for a casing string to be suspended from the cased mainbore. This required exiting the casing from the mainbore. Inherent to these multilateral and casing exit systems are: 1) more incremental trips and on-bottom time; 2) increased risk due to creation of metal debris; 3) increased equipment/installation costs; and 4) increased risk of losing the lateral or mainbore due to equipment failure.

Due to the large number and varying functionality of multilateral systems available, the TAML (Technical Advance ment of Multi laterals) level definitions were established as a means of categorizing a system based on the amount of junction support required. By definition, TAML levels 3 through 5 require a casing string to be suspended from the mainbore. Also by definition, TAML Levels 6 and 6s are pre-engineered multilateral junctions which have full pressure integrity across the junction area achieved with the casing. Level 6 and 6s technology junctions provide a fundamentally different way of achieving a hydraulically sealed junction with a minimal amount of risk.

These junctions dramatically reduce construction/completion complexity and relative cost while affording a great deal of flexibility.

During a multilateral screening process, an operator may perceive, based on current lifting costs and anticipated future production, that a particular project does not justify an "exotic" PEML system and only requires a mechanically supported junction. However, many operators are now realizing that a level 6 junction which was once considered "exotic", offers what they have long sought: a low-risk, highly flexible and economic solution that is applicable in both traditional level 3, economically weighted environments as well as in higher-cost, higher-risk level 5 environments. Therefore, level 6 and 6s junctions should no longer be thought of as extreme applications, but as methods of achieving a mechanically and hydraulically sound junction without the high associated risk and cost of previous multilateral systems.

Level 6 technology junctions possess many advantageous design features. Pre-constructing the junction allows it to be run on the bottom of conventional casing strings and drifted through conventional casing strings or open-hole sections. One type of level 6 junction uses formed metal technology and involves re-forming of one of the lateral legs downhole, which allows the junction to be drifted through casing or open hole with internal diameters less than the effective outside diameters of both of the junction's lateral legs combined.

Level 6 technology junctions offer a considerable amount of construction flexibility allowing operators the options of constructing the laterals from the top down and deferring drilling of the laterals until later. Delaying lateral construction can be useful to reservoirs that benefit from injection or re-pressurization later in a field's life. These options contrast with conventional multilateral junction construction which requires exiting from the casing and having at least part of the build section(s) or lateral(s) drilled and completed immediately.

Level 6 technology junctions also allow selective or through-tubing re-entry capability through simple installation of diverting and isolation devices that result in high or low-pressure completions with flow control capability. Flow control capability is achieved by installing a choke or isolation sleeve on either wireline or jointed or continuous pipe. Because installation procedures for level 6 technology junctions are orders of magnitude less complex than for other conventional multilateral systems, the inherent risk associated with installation is greatly minimized. This reduction in risk results from the fact that the PEML junction is pre-constructed prior to running it in the hole, so risks associated with a conventional casing exit are eliminated.

Because a level 6 junction is pre-fabricated at the surface, debris creation and removal are not major risk factors as they are when creating a conventional multilateral junction. Debris can be created during the initial milling process in a casing exit or during washover or perforating to regain lower bore access. Regardless of its origin, debris can be detrimental to the functionality of a well by hindering the operation of downhole equipment, plugging tubulars and flow control devices, and preventing completion equipment from operating as designed.

Since by definition, level 6 technology junctions are completely sealed from the formation, well control and washout during the junction creation process are of significantly less concern. The junctions can be placed in unstable formations such as heaving shales, unconsolidated sands, or lost circulation zones which may not be conducive to a conventional casing exit. In simplest terms, a level 6 junction can be thought of as just another joint of casing that has two cased legs on the bottom. Although some versions have slightly reduced burst and collapse ratings, pressure ratings are a real concern only during the initial installation process, assuming pressure differentials are properly balanced. The junctions are also run as a liner, or as part of the intermediate string in a vertical, deviated, or horizontal well profile. Finally, no specialized cement is required to cement PEML junctions in place. Therefore, level 6 junctions have the potential of being completely compatible with an operator's current casing and cementing programs.

In some applications, interference from crossflow during production is a concern. Optimal productivity of many reservoirs has suffered due to an inability to effectively isolate communication between two open holes of close proximity. Having the ability to case one of the open holes and inhibit communication between them (crossflow), substantially decreases the potential for production interference. Level 6 technology junctions incorporate a feature that allows a standard string of casing to be run on the bottom of one of the lateral legs during initial installation, thereby minimizing the effect of crossflow from the adjacent lateral leg.

Three different Baker Hughes, level 6 junction systems are currently available. The Downhole Splittertrademark system, which is a downhole multiwell drilling template, allows two wells to be drilled, cased and completed from one wellbore. After completion, each well can be produced, serviced and worked over independently of the other. The DeepSet Splittertrademark system is also a downhole multiwell drilling template, but it is typically run on the bottom of intermediate casing or may be hung off as a liner. The FORMation Junctiontrademark system utilizes new malleable casing shaping technology in which one lateral casing leg is "shaped" around the adjacent leg. This allows the outer diameter (OD) of the pre-engineered junction to be less than in an equivalent Downhole Splittertrademark design. This reduced OD allows the junction to pass through a casing conduit with a smaller inner diameter (ID) and drilled open hole for placement at the junction point. Similar to the DeepSet Splittertrademark, the FORMation Junctiontrademark is typically run on the bottom of intermediate casing or may be hung off as a liner.

The Downhole Splittertrademark is run in the well on the bottom of casing (conductor pipe) which is then hung off in the wellhead. Once in place, a riser assembly and anchor latch seal assembly, are landed in the first lateral leg side of the splitter, containing conventional cement float equipment. All well construction processes are performed through the riser. With the riser landed, the splitter is then cemented in place. After the cement has set, the first well is directionally drilled to total depth and logged. Then a conventional liner, with a no-go hanger and liner top packer, is run to depth and hung off in the splitter. The liner is cemented in place, and the liner top packer is set. Well construction for the first lateral is now complete, and the riser is released from the first side and oriented 180 degrees, through use of a downhole orienting cam, to align with the second wellbore. The riser is stung into the second bore, and the well is directionally drilled to total depth and logged. A second liner is run and cemented as previously outlined. The riser is pulled, and both wells are tied back to surface using conventional casing that lands in the seal bore section at the top of each lateral with seal assemblies and is hung off in a special dual-bore wellhead at the surface. The wells are now ready for standard production completion as two individual wells.

The DeepSet Splittertrademark is similar in concept to the junction system except that no metal reforming is required. The splitter is run in the well on the bottom of a standard casing string, which is then hung off in the intermediate casing string or tied back to surface. Once in place, a diverter is landed and a cement stinger assembly is run in and landed in the first side of the splitter, which contains conventional cement float equipment, and is cemented in place. The first lateral is then directionally drilled to total depth and logged. Then a conventional liner, with liner hanger and liner top packer, can be run to depth and hung off in the splitter. The liner is cemented and the liner top packer is set. The diverter is then retrieved from the well and reset in the second bore. This well is directionally drilled to total depth and logged. A second liner is run and cemented as previously outlined. The well may be completed as a single or dual producer/injector using additional completion equipment providing commingled or independent flow, flow control, and selective through-tubing re-entry.

The basic function and deployment of the FORMation Junctiontrademark is the same as for a DeepSet Splittertrademark; however, the system uses diverters instead of a riser for directing assemblies into the desired wellbore. The junction device is designed for deployment in an underreamed section of an open wellbore. The device is run in the well on the bottom of a standard casing string with the first well selection diverter installed. Once in place, a reshaping tool is run to re-form the pre-formed leg to standard casing OD and ID. The device is then cemented in place utilizing a cementing string landed in the first wellbore side containing conventional cement float equipment. Once the device is secured in place, the first lateral is drilled and logged to depth, then a slotted liner or screen assembly with a no-go hanger is run to depth and hung off in the leg. The diverter is then retrieved from the well, and an alternate diverter is then reset in the second bore. This well is directionally drilled, logged, and completed as the first well. The well may be completed as a producer using additional completion equipment providing commingled or isolated flow. Re-entry options range from full-wellbore ID equipment via pulling the completion string and re-running the diverters, to selective through-tubing re-entry.

Future Development focused on DeepSet and FORMation Junctiontrademark

There have been three field deployments of the Downhole Splittertrademark system to date. These three deployments were in central USA, Gulf of Mexico, and North Sea. All three junctions were deployed at depths ranging from 650 ft (197m) to 4,750 ft (1,439m). The North America applications utilized two equal-sized well legs and were drilled for production purposes. Both projects reached the proposed drilling targets for each leg and completed back to surface the commercially viable zones. The Gulf of Mexico project achieved estimated cost savings of $1 million US by constructing two wellbores from the Downhole Splittertrademark rather than drilling two independent wells. The North Sea splitter project was slightly different from the North American projects in that it was deployed in a well that was reclaimed from a slot on the platform and utilized a splitter that had two different sized well legs. This application allowed the operator to retain the well's injection capability while acquiring an additional producer well, all from a single slot on the platform. A recent workover to replace one of the lateral's tieback strings has been performed on this well without incident.

The FORMation Junctiontrademark has had one recent field deployment to date in the western USA. This deployment was in a heavy oil field and allowed the operator to reach two separate production zones from a single mainbore set horizontally. The device was deployed in an underreamed horizontal section of the main wellbore. Each leg was drilled horizontally, for 1,715 ft and 2,015 ft respectively, and a slotted liner was set in the open hole section of each leg. The slotted liners were tied back to the junction device with a liner top packer. A rod pump was then run into the well and landed above the junction area to facilitate extraction of the hydrocarbons. Well production was noted as being twice the rate of a standard, single horizontal well.

Level 6 junctions are an evolutionary technology that continue to improve in reliability and variety of application. A host of operators have seen the benefits of utilizing these junctions to effectively manage fluid movement within a variety of reservoirs, even in technically challenging environments. This increase in interest by the operators for these junctions is due primarily to minimal installation risks, equipment reliability, and favorable installation economics. Ongoing and future development of PEML junctions is being concentrated on the DeepSet Splittertrademark and FORMation Junctiontrademark systems.

A Deepset Splittertrademark system is currently being developed for a major operator in a 13-3/8-in. x 7-5/8-in. x 7-5/8-in., 7,000-psi version for installation in late summer 1999 in prominent onshore and offshore West African fields. This version places a minimal impact on the operator's current casing and cementing programs by allowing the system to be drifted through 17-1/2-in. openhole or 18-5/8-in. casing. This configuration also allows the operator to efficiently manage drainage of the reservoir by positioning two independent, horizontal wellbores in the payzone from a single parent wellbore and allows a 5-1/2-in. casing string to be landed horizontally in the reservoir.

FORMation Junctiontrademark systems are currently being developed for several operators in three configurations: 1) 13-3/8-in. x 9-5/8-in. x 9-5/8-in., 1,000-psi version for drifting through 17-1/2-in. openhole or 18-5/8-in. casing; 2) 10-3/4-in. x 8-5/8-in. x 8-5/8-in., 2,500-psi version for drifting through 14-3/4-in. openhole or 16-in. casing; and 3) 9-5/8-in. x 7-in. x 7-in., 1,000-psi version for drifting through 12-1/4-in. openhole or 13-3/8-in. casing. The 10-3/4-in. x 8-5/8-in. x 8-5/8-in. version places minimal impact on a deepwater operator's casing and cementing programs in Brazil by allowing the system to be drifted through 16-in. casing. This configuration also allows the operator to efficiently manage drainage of the reservoir by positioning two independent, horizontal wellbores in the similar TVD plane in the payzone from a single parent wellbore, and allows a 5-1/2-in. premium screen assembly to be landed in the reservoir.

Level 6 technology junctions exert significant, positive impact on overall field economics by allowing the operator to utilize a low-risk, cost-attractive solution for optimizing management of reservoirs. Due to innovative design and installation simplicity, PEML junctions are no longer considered as "exotic" systems, but are increasingly recognized as viable technology substitutes for a wide range of multilateral applications.

Acknowledgments

The authors would like to thank Baker Oil Tools for permission to publish this article. The Downhole Splittertrademark and BH DeepSet Splittertrademark systems were jointly designed, developed, and patented by Marathon Oil Co. and Baker Hughes, and are manufactured under exclusive license from Marathon Oil Co. The FORMation Junction system was designed, developed, and patented by Baker Oil Tools; and is manufactured under exclusive license from Marathon Oil Co.

References

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2. Hogg, C., Mackenzie, A., "Multilateral classification system with example applications," World Oil, Jan. 1999
3. Sund, G.V., Wenande, B., Weaver, C.L., Addams, J.M., "Downhole splitter well for simultaneous injection and production in the Valhall Field," SPE 38498, 1997.
4. Collins, G., Bennett, R., "Two wells drilled from one surface bore with downhole splitter," OGJ, Oct. 3, 1994
5. Diggins, E., "Classification provides framework for ranking multilateral complexity and well type," OGJ, Dec. 29, 1997, p.73.
6. Hogg, C., "Completing the world's first Level 5 multi lateral from a floater," Offshore, Nov. 98, 1998, p. 142.

Copyright 1999 Oil & Gas Journal. All Rights Reserved.