Completing the world's first Level 5 multilateral from a floater

Full integrity casing exit created

Cliff Hogg
Baker Oil Tools

This TAML Level 5 multilateral completion was successfully installed in a deepwater environment for Petrobras, in the Campos Basin 100 miles off the coast of Brazil. [23,011 bytes]
In September, a TAML Level 5 multilateral completion was successfully installed in a deepwater environment for Brazilian state operator Petrobras, in the Campos Basin 100 miles off the coast of Brazil. The completion represented the first use of a Level 5 system on a semisubmersible rig and demonstrated the feasibility and value of this advanced level of multilateral technology for deepwater applications. A number of new technologies contributed to the success of this project.

The Voador No. 8-VD 6HP-RJS/7HPA-RJS multilateral well was drilled and completed as dual horizontal lateral injectors emanating from a single wellbore and subsea location in an effort to optimize injectivity and longevity while substantially reducing cost over two independent wells. The project was under taken from the semi submersible drilling rig Ocean Yorktown in 565 meters of water.

The well was completed in 60 days with minimal difficulties. In addition to being the first Level 5 ever completed from a floating rig, the well was also the deepest Level 5 ever completed. Total vertical depth was 2,804 meters. The junction of the two wellbores was placed at 1,650 meters measured depth, with full mech anical support provided with casing in both the main bore and the lateral bore.

Hydraulic isolation of the junction area was achieved with the use of completion equipment that included a Baker Hughes Selective Re-Entry Tool (SRT). The selective re-entry tool allows for commingled flow of the injection fluid down to the junction point, where the flow is then diverted into each lateral.

The 60-day completion time exceeded the original estimated time by 15 days, with the majority of the extra time required for an extended fishing operation. The well has been temporarily abandoned as Petrobras awaits the need for injection support in the field. Based on the success of this project, the operator and service company are now at work on other Level 5 multilateral completion projects.

The process

Construction of the primary wellbore followed conventional Petrobras drilling and completion practices. A Petrobras-provided screen assembly was installed in the 8-1/2-in. horizontal bore and hung off in the 9-5/8-in. main wellbore casing with a standard seal bore packer.

A knock-out isolation valve installed in the packer provided isolation of the injection zone prior to running the multilateral equipment.

With the main wellbore completed and isolated, preparation began for creating the second lateral bore. After confirming good cement at the intended casing exit depth of 1,650 meters, a Baker ML Torquemaster packer and 152 meters of tailpipe and a seal assembly were run into the hole. The ML Torquemaster packer was developed specifically for multilateral applications. An internal profile rated for 20,000 plus ft/lbs of torque provides a permanent orientation reference point for the intended casing exit.

After tagging the knock-out isolation valve, the flapper of the valve was broken off as intended to stab the seals into the existing packer. The seals were then successfully tested with backside pressure. With the Torquemaster packer at proper setting depth, it was set using a combination of drill pipe pressure and tensile force.

Next, an orientation sub containing a matching profile to the packer was run along with a surface readout gyro on wireline. The anchor was landed in the packer, orientation was taken with the gyro, and the process was repeated several times until consistent readings were obtained.

Once orientation of the downhole packer was confirmed, the milling anchor and a multilateral whipstock were then easily aligned at surface to allow proper orientation of the whipstock when landed downhole. The anchor, whipstock, and starter mill were then run and landed in the orientation packer downhole; orientation was reconfirmed with another gyro run; and finally slack-off weight sheared the starter mill from the whipstock and milling of the casing exit began.

After initial milling with the starter mill, second and third trips were run with watermelon mills to complete the casing exit. With the casing exit successfully created, a wash trip was made in order to remove debris from downhole and from around the BOP stack.

Milling from a semi

Cutting an optimum window in the casing is vital to avoid difficulties with later multilateral operations. The techniques used to create the window exit in the Voador multilateral project were designed to be compatible with floater rigs and the potential movement changes occurring during the process. First, the milling system itself uses proprietary cutting technology that is not dependent upon large weight-on-bit numbers.

The cutting surfaces of the bits cut rather than grind away and thus depend more on revolutions per minute than on weight applied. In an effort to improve the consistency of the weight that was being applied in this instance, long-stroke drilling bumper subs were used in the milling string above the drill collars. The drill collars provided the necessary weight on bit, and the long stroke drilling bumper subs absorbed the movements of the surface rig during the milling operation. The casing exit was created without difficulty or a clean-out trip.

Once the casing exit was created, Petrobras drilled an 8-1/2-in. open hole to a point immediately above the reservoir utilizing their standard drilling programs and technologies.

With the 8-1/2-in. open hole completed, the 7-in. casing containing conventional float equipment was run and landed at bottom. The 7-in. lateral casing string served two purposes on this project:

The casing provided the shoe strength necessary to drill the 6-1/8-in. hole through the reservoir.
The 7-in. casing is run and cemented through the 9-5/8-in. casing exit and provides the mechanical support required at the multilateral junction point.

Approximately five meters of the 7-in. casing was left extending into the 9-5/8-in. mainbore casing. This portion of the liner contained integral casing centralizers to provide standoff of the casing inside the main bore. This standoff improves both the cementing ability and washover capability of the casing.

Cementing the lateral

Due to hole pack-off, the 7-in. casing could not easily be cemented in place. With minimal circulation ability, the liner shoe was cemented in place using a conventional liner wiper plug and float equipment.

A cement squeeze job was then performed 100 meters out from the casing exit. This procedure ensured that the 7-in. liner was properly cemented in place at the multilateral junction point. A subsequent cement bond log verified that good, strong cement was in place around the multilateral junction area.

With the lateral casing properly cemented in place, the 6-1/8-in. hole was drilled into the target formation. Unfortunately, the anticipated injection sand was not found in sufficient quantity.

As a result, the decision was made to set a cement plug and sidetrack the well into a more favorable injector location. This sidetrack was completed with only minor directional drilling difficulties, and the 6-1/8-in. open hole was now ready for sand screens.

Installing sand screens

The Baker Oil Tool Excluder screens were run into the upper lateral 6-1/8-in. open hole and hung off using a packer assembly. Once the packer was set, a full range of injection tests was conducted on the upper lateral's injection zone.

To minimize corrosion effects in the well, all sand screens run were manufactured from 13% chrome material. The tubulars run to surface however were manufactured with standard 80-40 metal to improve the economics of the project. The point at which these two metals connect was therefore susceptible to increased corrosion effects due to galvanic reactions. Petrobras solved this problem by using "sacrifice" packers.

These "sacrifice" packers contain the 13 chrome to 80-40 material contact point and are therefore not being counted on to provide long term integrity. The "sacrifice" packers however were run directly below standard 80-40 material packers and as a result, corrosion of the "sacrifice" packers will not have an impact on the wellbore's overall integrity.

Junction integrity

To provide the full mechanical support required at the junction point, the 7-in. upper lateral casing had been left extending back into the main bore and had been cemented in place in this condition. It was now time to regain access to the lower lateral by washing over the liner stub in the mainbore casing.

Prior to performing this washover operation, a permanent seal bore packer was set in the 7-in. upper lateral casing string approximately 12 meters from the casing exit. This packer, along with the existing orientation anchor in the main bore and a packer to be set above the junction, were to be used as isolation points in creating the hydraulic integrity required at the junction area.

With the upper lateral packer set, a pilot mill assembly was run in the hole and tagged the top of the 7-in. liner at a depth of 1,646 meters. After milling away the liner running sleeve, the pilot mill was retrieved and a washover assembly was run back in the hole. This washover assembly "swallowed" the multilateral whipstock and continued washing over the rest of the liner stub.

With the liner stub cut through at the casing exit point, the washover assembly was pulled from the hole. A casing spear was used to retrieve the liner stub from the wellbore. Inspection at surface revealed a casing stub in excellent condition with a very smooth cut along the casing exit point.

At this point, the washover assembly was run back in the hole with the intention of removing the multilateral whipstock and bottom hole assembly. The washover shoe was able to again "swallow" the whipstock and latch into a special control dogs sub installed below the whipstock.

An overpull of 60,000 lb was required to shear the anchor from the orientation packer, and the entire bottom hole assembly was carefully pulled from the well. The well was now considered a successful TAML Level 4 multilateral system offering full mechanical integrity at the junction.

Debris management

Failure to properly remove or manage debris can have catastrophic consequences during a complex multilateral completion project. Much effort has been devoted, therefore, to properly controlling debris. Among steps typically taken to control debris in these types of projects are the following:

During milling operations, ditch magnets and screens are placed downstream of shale shakers to collect cuttings. Any debris removed from downhole in junk subs and other debris-catching devices are also collected and weighed.
Fluid yield points of at least 40 are maintained to carry the milled cuttings from the well. High viscous sweeps are also used periodically to aid cleaning.
Preference is to use advanced milling technologies that cut rather than grind, resulting in very fine, easily-removed cuttings.
A debris catcher is used below the mainbore orientation packer to catch any debris that otherwise would continue downhole. This debris catcher is recovered after the multilateral junction has been created and all cleanout trips have been made.
Washover trips are recommended after every operation in which debris has been created.

During the Voador No. 8-VD 6HP-RJS/7HPA-RJS project, in addition to the above debris management policies, a new debris removal tool called a VACS junk basket was used for the first time. The VACS junk basket allows for conventional circulation through the work string while performing a reverse circulating action downhole.

This reverse circulating action acts as a vacuum that efficiently removes cuttings and stores them in a debris basket that is part of the tool. Because the cuttings are captured downhole where they are generated, fluid properties and circulation rates are not nearly as critical, and the loss of annular velocity from the casing annulus to the riser annulus ceases to be a problem in cuttings removal.

The VACS tool was run above the pilot mill during initial milling of the liner top. During this process, over 95% of the calculated milled material was recovered in the tool. The VACS tool was also used in several cleanout trips into both the main bore and the lateral bore after the multilateral junction washover process was complete. During these cleanout trips, additional metal debris, rubber cuttings, cement and sand fines were recovered from both wellbores.

After washing over and retrieving the liner stub and whipstock, a image of the casing exit was obtained using a Baker Atlas CBIL log. This log was evaluated for window size and position in preparation for re-entry into the lateral bore for cleanout purposes.

The image log was clear enough to show the casing exit with an anticipated gap at the top due to bit walkoff action. Also seen in the image log was the 7-in. casing wall located within the window exit. This image indicated that the window was in optimum condition and was properly shaped and sized.

Final completion

At this point in the well construction process, the multilateral junction area had full mechanical integrity as provided by the 9-5/8-in. and 7-in. casing strings cemented in place. However, hydraulic isolation was still required at the junction area to completely isolate the junction from injection pressures. This hydraulic integrity was achieved through the use of additional completion equipment designed to straddle the junction and keep it isolated from pressure changes throughout the life of the well.

The orientation packer below the casing exit in the main bore was to provide one isolation point; the permanent packer in the lateral bore was to provide the second isolation point, and a hydraulic set packer above the casing exit was to provide the third and final isolation point. As a first step in tying these three isolation points together, a two-trip scoophead diverter attached to a multilateral orientation anchor was run and landed in the mainbore orientation packer.

The scoophead diverter is simply described as a tubing sub with a diverter face attached. The tool should be landed so that the diverter face is aligned with the casing exit, allowing the lateral production tubing to then be run and kicked off into the permanent packer located in the lateral bore. The use of the orientation packer and anchor system in the Voador well were to ensure that the diverter would indeed be facing in the proper direction. However, to confirm this orientation, a gyro run was made prior to landing of the anchor in the orientation packer.

In addition to proper orientation, it is also vital that the scoophead diverter be landed with proper spaceout. If it is landed even a little too low, the lateral production tubing may hang up against the bottom of the casing window. If it is landed too high, there may not be enough clearance between the tool and the casing exit to allow the lateral production string to be run. With these consequences in mind, several techniques were used to calculate and verify the proper depth needed to land the scoophead diverter:

The original dimension between the multi lateral whipstock and no-go on the Torquemaster milling anchor used when drilling the lateral provided a length to the original drilled hole.
The 7-in. washed over lateral casing stub retrieved to surface provided a mirror image of the 7-in. casing window. Dimensions from this image were used to establish the window profile and size.
An imaging log provided an image of the drilled hole and washed over casing at depth. This showed shape, depth and angular correlation.
The recovered multilateral whipstock showed marks, which indicated the position of the casing window.

Using data from all sources, a 3D computer model of the junction area was made. This model allowed the Baker Oil Tools project coordinator to place 3D models of the completion equipment in the wellbore, move it around and define the spaceout window, before actually running any tools in the hole. The modeling proved successful, as there was never any difficulty entering the lateral bore once the scoophead diverter was in place.

With the scoophead diverter landed, an attempt was made using the running string to pressure test the seals of the orientation packer. Unfortunately, a leak in the running string prevented the seals from being fully tested. The leak was later found to have occurred in the long stroke bumper sub rather than in the packer seals.

Commingling strings

The next step in the multilateral completion process was to run the lateral production tubing and tie the two production strings together into a single injector string to surface. The commingling of the two strings was achieved through the use of a selective re-entry tool (SRT).

The SRT tool consists of a specialized inverted "IYI" block that is run above the scoophead diverter. Attached to one leg of the SRT is the lateral production tubing which deflects against the scoophead diverter face, enters the lateral wellbore, and then seals off in the lateral permanent packer. The other leg of the SRT latches into the seal bore of the scoophead diverter which, in turn, ties into the mainbore orientation packer. Above the SRT, a hydraulic set single string packer is used to provide the final isolation point of the junction area.

The lateral production tubing, SRT, hydraulic set single string packer and Petrobras-provided tubing seal receptacle were run to depth without difficulty. As the lateral production string kicked off into the lateral, no drag was seen at surface. The seal assembly on this production string was protected with a seal protection sleeve during the running process.

This sleeve prevented the seals from being damaged during the kick-off process. As the string continued downhole, the seal assembly entered the lateral packer, and the seal protection sleeve automatically sheared back, allowing the seal assembly to engage the packer seal bore.

At this point, the running string was pressured up to test the seal assembly against the lateral packer bore seals and the knock-out isolation valve below the lateral packer. The tests indicated proper placement of the seal assembly. Next, a pump-open test tool installed in the SRT was activated, allowing pressure testing of the seals in the mainbore production string. Again, all seals tested OK.

At this point, difficulties were encountered setting the single string hydraulic set packer. Sufficient pressure could not be maintained in the running string to set the single string packer. The source of the leak was unknown.

With a leak occurring somewhere in the string, the decision was made to pull the tubing seal receptacle mandrel, SRT and lateral production string. After several trips, fishing personnel recovered the bottom hole assembly. Inspection of the assembly at surface revealed that the bottom portion of the pump-out test tool had backed off and was still downhole. An impression packer run indicated that the fish had landed on top of the standing valve located in the mainbore orientation packer. This fish was eventually recovered from the well after the SRT assembly had been successfully landed.

A second attempt was made to run the lateral production string, SRT, and hydraulic set, single string packer. Again, the assembly was run to depth but began to leak while attempting to set the packer. The assembly was again retrieved from the wellbore.

After evaluating the pressure leak, it was determined that insufficient set-down weight was being applied (in conjunction with the use of the motion compensator), allowing the seals to be pumped out of the seal bore in the scoophead diverter.

As a result, the single string, hydraulic set packer was replaced with another packer that could be set without pumping the seals out of the scoophead. This new bottom hole assembly was run to depth, all seals were tested to 1,000 psi, and the packer was then successfully set. Finally, a latch seal assembly and 5-1/2-in. production tubing were run from surface and latched into the upper packer. The entire system was then tested with no leaks detected. The well was then spaced out and hung off awaiting injection.

Highlights

Overall, this project was considered by all parties to be a success. The highlights of the job include:

A casing exit of optimum size and shape was successfully created off of a semisubmersible rig without difficulty.
The new VACS debris removal tool successfully removed large amounts of debris from the wellbores that otherwise would have been difficult to flow to surface.
The lateral liner stub extending into the mainbore casing was washed over and a Cemented Root junction was created without major difficulties.
Imaging technology provided by Baker Atlas proved to be a valuable diagnostic tool when determining the condition of the casing exit.
The two-trip scoophead diverter was successfully spaced out with no difficulties encountered re-entering the upper lateral.
The minor problems and tool failures that did occur were quickly addressed and had been previously considered in the project's contingency plans.
The well is now the world's first TAML

Level 5 multilateral completed off a semisubmersible rig.

Author

Cliff Hogg is based in Houston with Baker Oil Tools where he works as a Senior Applications Engineer in the emerging technologies/multilaterals group. Cliff joined Baker in 1993 and has worked as a field engineer in West Texas and Oklahoma prior to his current position. He holds a BS in Petroleum Engineering from Texas A&M University.

Acknowledgement

Baker Oil Tools and the author would like to thank the following Petrobras personnel: Gabriel Sotomayor, Ivan Albes, and Ronaldo Luiz Lopes de Oliveria of divisions E&P/GERPRO/ GETEP/GEPEC for their support and assistance throughout the implementation and evaluation process of this project.