Hook hangers provide flexible reentry options, reduce multilateral risks

Aug. 25, 2003
Various applications in diverse regions of the world show the reentry flexibility and reduced completion risk of "hook hanger" junctions for completing Technical Advancement for Multilaterals (TAML) Level 3, 4, and 5 wells.

Various applications in diverse regions of the world show the reentry flexibility and reduced completion risk of "hook hanger" junctions for completing Technical Advancement for Multilaterals (TAML) Level 3, 4, and 5 wells.

Completions in Venezuela, South China Sea, Middle East, and Alaska's Cook Inlet have used hook hangers in both new and existing wells.

Some examples include a Level 3 multilateral with an intelligent completion system, a Level 3 with expandable screens, a Level 4 with an electric submersible pump (ESP), and a Level 5 with a straddle completion hydraulically isolating the junction.

Technological evolution

In the past, the complexity and operational intensity of completing multilaterals have resulted in high risks and costs that curtailed the growth of the technology in many regions.

The introduction of the hook-hanger system marked a significant step in the development of cost-effective, fit-for-purpose multilateral solutions because it offers the option for reentry into both the lateral and the mainbore.

The system is run as a liner component with a machined window for main-bore reentry. A "hook" at the bottom of the machined window hangs off the system at the bottom of the casing exit window. If desired, one option includes a liner hanger or packer assembly above the system that provides additional anchoring capability to the junction.

Click here to enlarge image

Reentry is achieved with a main-bore or lateral diverter that orients and locates within the hook-hanger system. The diverter deflects coiled tubing or coupled pipe into the desired wellbore (Fig. 1).

Hook hangers have evolved as the primary platform for a large majority of the mechanically supported, multilateral systems installed by Baker Oil Tools in both new and reentry wells. To date, Baker has installed more than 180 of these systems.

Recently, Baker has expanded the technology to a new generation of cemented or hydraulically isolated multilateral systems with more flexibility as to the placement of the junction.

In a comparison of 23 multilaterals vs. 108 single wells in Venezuela, wells with hook hangers produced up to 900 bo/d more per well and cost, on average, about 1.58 times more than single wells.

To date, the deepest hook-hanger installation is at 10,630 ft in a reentry well in the Cook Inlet off Alaska. The installation was done in January 2002.

Previous single wells in this area produced an average 150-200 bo/d. By contrast, this well produced 600 bo/d after being converted into a multilateral.

South China Sea

The first hook-hanger installation in Asia was made from a fixed platform in the South China Sea in 2001. The platform was in a field nearing the end of its development.

The operator selected multilateral technology to enhance oil recovery per wellbore. It selected the hook-hanger junction so that it could retain access to both laterals.

The completion combined the multilateral system with expandable sand screens in each lateral and an external casing packer (ECP) in the upper lateral. A straddle completion across the casing exit window and an electric submersible pump (ESP) with 27/8 in. bypass tubing enabled the operator to control flow via the pump bypass tubing.

Click here to enlarge image

In September 2002, the same operator again used the hook hanger in the same area. This time the purpose was to increase oil recovery by working over an existing well. Because the water zone was close to the casing exit window, the work included cementing the junction in place to provide additional sand control and assist in water isolation (Fig. 2).

The work involved creating a casing exit from a standard casing joint, drilling the lower lateral, and retrieving the whipstock prior to running the liner and hook-hanger assembly.

A bent joint on the bottom of the lateral liner allowed the liner assembly to "find" and enter the casing exit window, thus leading the liner equipment into the lateral without the need for a whipstock.

A lateral diverter, preinstalled in the hook-hanger assembly, blanked off the premilled window and allowed cementing of the entire liner assembly in place with conventional cementing techniques.

Following cementing operations and retrieval of the diverter, the operator regained access into the main bore without the risk and cost associated with milling-washover operations that were common to previous cemented junction multilaterals.

The operator accomplished the objective of increasing recovery and also completed the well 6.5 days ahead of schedule.

It is important to note that the cement in this well provides additional support to the junction but not hydraulic isolation. The junction would need additional straddle tubing across it to hydraulically isolate it and thus create a Level 5 multilateral, as in the third well in the operator's programs.

The third well, reentered in May 2003 for the purpose of increasing recovery, required pressure integrity at the junction because of projected well drawdown. The work involved creating a casing exit, running the hook-hanger assembly, and cementing the junction in place in the same manner as described previously.

Additionally, run in the lateral liner just below the hook hanger was an FAB mainbore permanent packer with seal-bore assembly and a scoophead diverter that straddled the junction to provide hydraulic isolation.

Click here to enlarge image

An ESP installed above the scoophead diverter lifts the commingled production to surface (Fig. 3).

Oman intelligent multilateral

In March 2003, Petroleum Development Oman (PDO) combined a hook hanger with intelligent completion technologies to help overcome difficulties and high development costs in its giant Mukhaizna oil field. The field, discovered in 1975, is the third largest oil field in south Oman.

The field has high development costs because of the technical difficulties posed by its heavy 14-16° gravity oil, unconsolidated reservoir sand, and potential early water breakthrough. These difficulties precluded the field from being developed in the past.

The project became an attractive investment after PDO finished a field appraisal, drilled horizontal and dual-lateral wells, and applied new technology.

The two oil-bearing sandstone reservoirs in the field are the Upper Gharif 2 (UG-2) and the deeper Middle Gharif (MG). The reservoirs contain about 2.35 billion bbl of stock-tank oil initially in place and are separated by laterally extensive Middle Gharif shale (MGS).

First primary oil production started in 2000 from long horizontal wells slanted through the reservoir section and oriented perpendicularly to established channel trends. The field currently produces a net 12,600 bo/d from 52 single and 4 dual-lateral horizontal wells.

Production data from five multilaterals in nearby Marmul field helped convince PDO that dual-lateral producers completed with hook hangers would improve performance as measured by accelerated production, increased recovery efficiency, optimized drilling costs, reduced operating expense, sustained well inflow, and reduced deferment of oil.

Level 3 multilateral technology also ensures well integrity by maintaining hole stability and reduces the hazards caused by the dynamic movement of sand into the wellbore.

Key benefits of a dual-lateral well in Mukhaizna are that it allows shut off of the MG zone in case of water breakthrough and provides a cost-effective method for either hoist or coiled tubing re-entry into both the lateral and the mainbore.

The completion also can accommodate commingled heavy oil production with downhole electric submersible, progressing cavity pumps (ESPCPs).

Future development plans for Mukhaizna field include steam injection that requires PDO to obtain a better understanding of reservoir pressure behavior in the UG-2 and MG sands. Because PDO was aware that reservoir monitoring and management technology lags behind drilling technology in low-cost multilaterals, it decided to initiate development of a low cost, semiselective completion that would allow flow rate testing of individual legs by differential and closed-in reservoir pressure monitoring for each leg separately.

It selected to complete three multilaterals with Level 3 hook hangers. The third well, Mukhaizna 64, included a selective completion that used a surface operated, downhole, hydraulically actuated sliding sleeve.

With the sleeve in the open position, the system allows commingled production from both reservoirs. Closing the sleeve shuts off the production from the MG, allowing only the UG-2 to produce.

The objectives of Mukhaizna 64 included:

  • Develop UG-2 and MG reserves and increase Mukhaizna field production and simultaneously provide sand control in these intervals.
  • Appraise structure and reservoir development.
  • Isolate a water aquifer from the hydrocarbon-bearing formations.
  • Appraise the potential of water breakthrough in the MG.
  • Construct a tangent section to allow installation of an ESPCP for artificial lift.
  • Confirm the suitability of hook-hanger technology for this field by maintaining access to both the main bore and the lateral leg for mechanical shut-off in case of water or sand production.
  • Test the feasibility of a selective completion with a hydraulically actuated sliding sleeve for cost-effective production allocation and zone shut-off.

Another main objective of the completion was to prove out the economics and operational feasibility of drilling and completing multilateral wells in future applications in PDO's depleting oil fields.

This completion indicated that a multilateral saves $500,000/well when compared to drilling two single horizontal producers.

In Mukhaizna 64, the mainbore was horizontal while the lateral leg slanted downwards through the reservoir. The well had a 95/8-in. casing exit window milled in the UG-1 formation to ensure the presence of a competent formation for the external casing packer (ECP) that serves to isolate annular flow.

The Level 3 hook-hanger completion with an ECP allowed for zonal isolation by providing for mechanical support at the junction with reentry diameter capabilities of 6 in. in the upper lateral and 53/4 in. in the mainbore completion.

The hook hanger integrated with the lateral liner required only a single trip for setting it in the casing window. An acid stimulation of the well followed after the installation of the multilateral hook-hanger system.

The next step, in one trip, inflated the ECP, released the lateral diverter, and opened the lower zone to production. Because of the prior placement of the whipstock assembly, gravity alone was required for reentry to the main bore.

The final step in the completion involved running the InForce intelligent completion system with an ESPCP assembly. The shrouded 55/8-in. ESPCP provides artificial lift and the hydraulically operated sliding sleeve allows for selective isolation of the main bore.

Click here to enlarge image

The shroud also prevents direct vibration to the hydraulic sliding sleeve, as was demonstrated after initiating production. Initial results showed an ESPCP vibration of less than 1 G vs. expected levels of up to 5 Gs. The well came on line at the expected 440 bo/d (Fig. 4).

Closing of the remotely operated hydraulically operated sliding sleeve will shut off the main bore in the event of water breakthrough. Once water coning dissipates, PDO can resume production from the main bore by simply opening the sleeve again from the surface.

This capability eliminates the need for shutting in production from the lateral leg and the costs and risks associated with rig intervention. Additionally, the technology nearly eliminates the wellbore storage effects during transient pressure testing.

Since the well has been on production, PDO has cycled the hydraulic sliding sleeve successfully to confirm the operability of the intelligent completion. It completed a production test and pressure build-up survey of UG-2 with the sleeve in the closed position before returning the well to commingled production.

The collected data determined production allocation split between the upper and lower producing intervals, confirmed the source of water production, and provided an estimate of the current UG-2 reservoir pressure.

Based on this success, PDO plans to retrofit with similar intelligent completion systems other multilateral wells in the field previously completed with hook-hanger systems.

Additionally, it will incorporate a line in these wells for monitoring pressure build-up in the main bore when production is isolated. This monitoring will allow for a fuller understanding of the Mukhaizna field and provide valuable input for the planned steam injection project.

Click here to enlarge image

The authors
Cliff Hogg [[email protected]] is a senior applications engineer for Baker Oil Tools, Houston, where he works in the emerging technologies and multilaterals group. He has worked as a field engineer for Baker in West Texas and Oklahoma prior to his current position. Before joining Baker, he worked as a production engineer for an independent operator in West Texas. Hogg holds a BS in petroleum engineering from Texas A&M University.

Click here to enlarge image

Dave Westgard [[email protected]] is product line manager-multilateral systems for Baker Oil Tools, Houston. His responsibilities include new systems development and marketing of multilateral systems worldwide. He has been involved with multilateral and reentry applications since joining Baker Oil Tools. Prior to Baker, he focused on drilling conventional, horizontal, and directional wells.

Click here to enlarge image

Pascal J.A. Rump [[email protected]] is a marketing engineer with Baker Oil Tools in Oman. He previously worked in the Netherlands where he was in charge of several multilateral projects. Rump holds an engineering degree from the HTS (Polytechnic) of Noorderhaaks, the Netherlands.