Managing Retrieval of Triple-Zone Intelligent Completions in Offshore Extended-Reach Well

C o m p l e t i o n s Managing retrieval of triple-zone intelligent completions in offshore extended-reach well

By L. Izquierdo, T.U. Ceccarelli, Schlumberger; G.P. Hertfelder, Items to be replaced K. Koerner, Plains E&P; S. Pace, Chevron Description Comments An independent operator The multiport packer is a cut-to-release packer, meaning offshore California has successfully achieved triple-zone intelligent well com- Multiport isolation that the mandrel is severed in order to release the packer. pletions in an extended-reach drilling packer, 7 in. x 3.5 in. This, in conjunction with the replacement seals, means that (ERD) campaign in its Rocky Point field. it’s uneconomic to redress this packer. To date, two workover interventions The multiport packer is a cut-to-release packer, meaning have been performed in five deployments Multiport production that the mandrel is severed in order to release the packer. in the field, of which three are currently packer, 7 in. x 3.5 in. This, in conjunction with the replacement seals, means that fully operational. it’s uneconomic to redress this packer. The Rocky Point reservoir is a highly 3 ½-in. swivel Uneconomic to refurb this item. fractured carbonate and can rapidly initiate water production. Achieving It may be possible to salvage a small number of the protec- zonal isolation in the wellbore and at the 3 ½-in. cable protector tors retrieved from the well, but based on experience, 80% reservoir level is critical. During the pro- of the protectors will need to be replaced. duction stage, it was recognized that two of the wells did not achieve the required It may be possible to salvage a small number of the protec- zonal isolation evident by increasing 4 ½-in. cable protector tors retrieved from the well, but based on experience, 80% water cut. The operator decided to of the protectors will need to be replaced. retrieve these completions to conduct Due to the uncertainty of the condition of the control lines liner cement repairs. Hydraulic control lines and the inability to perform suitable integrity tests, it is These triple-zone completions are recommended to replace all the control lines. controlled by 3½-in. tubing-retrievable Cable splice will be required to have connectivity between flow-control valves, open/close and Electric cable splice the gauges. Removal and redress of the blocks is not multiple-position, that work with dedi- cated gauges for monitoring of pressure economical. and temperature. Each of the productive Due to the uncertainty of the condition of the instrument zones was isolated by three multiple- Tubing electric cable cable and the inability to perform suitable integrity tests, it port retrievable production packers. is recommend to replace all the instrument cable. The main challenges in retrieving these completions were: Items to be refurbished • Conveyance of the cutting tools to depth (due to ERD profile). Description Comments • Accurate location of the cutting tar- Tubing retrievable subsurface Requires replacement of all elastomers, full FAT and gets (+/- 6 in. at 18,000 ft MD). safety valve re-certification. • Severing all control/electric lines and Thread inspection, pocket inspection. Valves pulling all three packers in the same Gas lift mandrel system removal and inspection, redress seals, valve set-up, trip. valve loading and function test. • Re-dressing and re-running the com- 3 ½-in. tubing retrievable flow pletions within two weeks of retrieval. control valves – open/close and Replacement of all elastomers, function test and FAT. This paper describes the feasibility variable of deploying explosive jet cutters by Monitoring system – gauges Thread inspection. Function test and cable head pumping wireline conveyed assemblies and mandrels redress, re-calibration. to locator profiles above each packer, which allowed for simple, cost-effective Pipe accessories Thread inspection and hydro-test. intervention, avoiding costly mobiliza- tion of tractors or coiled tubing. Lessons (e.g., minimum distance of control valves tions), there is limited experience with learned are shown on how completions from packers) that will be implemented the managed retrieval of these complex components were affected by the cut- in future installations. systems. This paper highlights the ting operation and the extent of their methodology, procedures and lessons refurbishment before re-completion. The Introduction learned associated with the retrieval of paper also identifies modifications to intelligent completions installed in ERD Even though the intelligent completion intelligent completion design parameters wells. industry is maturing (500-plus installa-

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ERD wells complicate retrieval due to The initial completion was installed as a) The workover program preparation the fact that the applied forces down- a triple-zone intelligent completion in scope to provide the following services hole are drastically reduced, and thus the operator’s Hidalgo C-13 oil producer and deliverables: reduces the potential to the successful well. Zonal isolation was achieved using • Decision tree/flow chart and risk retrieval of pull-to-release devices. two 3 ½-in. open/close flow control analysis (DRA) for the workover valves and one 3 ½-in. variable flow The Rocky Point Field is located six operation (completion retrieval control valve with annular isolation miles northwest of Point Conception, off- options and risks). by using 7-in. feed through, multi-port shore California. Geologically, it consists packers with cut-to-release mechanisms. • Preparation of workover procedures of a series of complexly faulted anti- Monitoring of the respective zones was (retrieval and completion re-run, clines, which tend northwest-southeast. achieved in the upper two zones with including fishing operation contin- The reservoir is normally pressurized two dual gauge carriers with one quartz gencies). with oil-bearing, highly fractured inter- gauge reading annular conditions, and, vals. These formations are complex in the lower zone, a single gauge carrier • Identify and locate/source third- lithologically with calcareous-siliceous with a single quartz annular gauge. party retrieval service equipment. and clayey-siliceous lenses. 5/ • Determine potential re-usability Wells were cased with 9 8-in. 43.5-lb Permeability is largely derived from of equipment to be retrieved and casing to an approximate depth of 19,422 natural fractures, with little effective establish equipment requirements ft MD. The 7-in. liner was hung off with a contribution from the matrix rock. The for each re-completion scenario. reservoir is underlain by a large infinite liner top packer. acting aquifer providing sustained pres- • Plan for equipment redress logis- A tapered 4 ½-in. to 3 ½-in. produc- tics. sure support; water/oil contact varies tion tubing string was run to maintain between fault blocks. strength of completion whilst allowing • Prepare schedules for equipment The development plan for Rocky Point for optimal gas lift efficiency. 4 ½-in. tub- sourcing, reworking, redressing. 5/ included drilling eight deviated wells ing was run to the 9 8-in. above the liner • To assist in the re-completion design from the Hidalgo, Harvest and Hermosa with 3 ½-in. below. and in the secondary work scope platforms (Gary P. Hertfelder et al, 2007). (production analysis), a review of The main objectives of installing “intel- Workover Scope well construction data required ligent completions” (“IC”) in these devi- The objectives of the workover were: (includes directional survey, open ated wells were to minimize intervention hole logs, drilling tour sheets, casing 1. Pulling the existing completion. whilst maintaining the ability to control tallies, casing ancillary equipment water production and maximize the pro- 2. Surveying the wellbore to determine list, cement bond logs, cement vol- duction from each of up to four zones. the source of the water production. ume logs, cement job reports). Other well objectives were: 3. Implementing a plan to address and b) The production analysis scope to gen- • Provide economic commingled produc- achieve zonal isolation between pro- erate: tion from up to four oil zones driven duction zones. • Analysis of available production by strong water drive allied to the 4. Re-completing as required. data from C13. constraints of topside infrastructure in • Compare C13 production data pre- highly fractured sandstone. To understand completely the impact and post-acid stimulation. • Maintain simplicity of installation and of any engineering and workover plan- operation. ning, a separate production analysis was • Prepare diagnostic plots and per- conducted to gather and analyze data form a diagnostic analysis. • Reliable design to afford required lon- to determine the potential source of the • Evaluate intervention options to gevity and minimize total life of well water influx. costs. shut-off water production (through- tubing or confirm the necessity for a • Maximize recovery from highly frac- This data may deliver an alternate solu- workover). tured strong water drive reservoir. tion to pulling the existing completion or assist in planning likely scenario of • Maximize early production. • Perform DRA on success and poten- re-completion equipment configurations. tial costs of treatment vs re-comple- • Minimize potential for early water Possible solutions could involve pumping tion. breakthrough. treatments, which would be evaluated in terms of cost and risk compared with • Selectively control water breakthrough pulling the completion. The study would Refurbishment per zone either by shut-off or, if draw- also gather sufficient data to make an /Replacement Planning down dependent, by zonal pressure informed decision about the likely suc- control. Each completion component was evalu- cess of any water shut-off treatments ated for either refurbishment or replace- • Maximize PI in 8 ½-in. hole. and costs associated with re-installation ment. In some cases, refurbishment of a suitable completion. • Minimize intervention. costs exceeded replacement costs or vice versa. The table on Page 132 lists the • Maintain an adequate means for isola- The scope of work focuses on two activi- completion components to be replaced tion between producing zones. ties to be carried out in parallel and to be led and coordinated under a proj- and components that could be refur- • Minimize risk exposure associated ect management strategy (PMI 2000). bished. with completion technology new to the Preliminary work scope covered: Point Arguello asset.

134 September/October 2008 Drilling contractor C o m p l e t i o n s Workover objective of a cutting method limits the choice of Wireline (E-line) conveyance method, so each had to be The objective was to release three carefully evaluated. Wireline works well with explosive and production/isolation multiport pack- chemical methods. Again, high devia- ers deployed in the Hidalgo intelligent tions are difficult and require wireline completion wells by cutting each packer Cutting Methods tractors or other TLC (tough-logging- mandrel with an explosive jet cutter run Explosive jet cutting conditions) equipment to motivate the on wireline. cutting string into position. One concern Explosive jet cutting (EJC) uses a in using wireline is accurate position- Above each packer, the completion circular-shaped charge to create a ing, providing a path for the wireline to design included 2.813-in. nipple profiles radial jet to cut through a tubing wall. reach the firing mechanism after passing to efficiently locate and cut each target. Temperature limits are determined by through the wireline head and locating Each packer has, from the locator to the the lifetime at temperature of the deto- mandrel. target window, an exact known distance. nators and explosives. In order to minimize running time for Coiled tubing the cutting of each packer, an equivalent The EJC method requires live explo- target was defined to comply with the sives handling. Safety issues must be Coiled tubing (CT) is compatible with cutting objective for all three packers, addressed in transport and use. If EJC abrasive jet cutters and mechanical cut- allowing a common tool deployment con- cutting is planned, explosives specialists ters. It is capable of conveying a cutting figuration. must be on hand or directly available to string into highly deviated wells and can the job site. be used with standard slickline equip- 11/ 7/ The target window to perform the cut ment (1 16-in. to 2 8-in. slickline tool was 19.6 in. Radioactive pip-tags were Abrasive jet cutting diameters). The preferred landing provi- part of each of the locators at the bottom This method cuts by directing a rotating sion for use with CT is a no-go restric- of each nipple sub and in the top gauge high-pressure, high-velocity jet of sand tion. CT requires provisions allowing for ring of each packer in order to accurate- suspended in gel against the tubing wall. the flow of returns generated by the cut- ly correlate the exact location of each It requires the availability of coiled tub- ting process in smaller tubing diameters profile and packer by using a gamma-ray ing for conveyance. to avoid deadheading into the reservoir tool, run as part of the explosive jet cut- formation. ter bottomhole assembly (BHA). Mechanical milling Jointed tubing As a reference, the packers and locator Mechanical cutting is a service per- profiles were installed at the following formed by reputable fishing tool compa- Straight jointed tubing can conduct and depths: nies to release cut-to-release packers. operate mechanical and abrasive jet This method uses sharp-edged tools cutters into low-deviation wells. Jointed • Lower packer top at 19,243 ft MD - rotating against the target walls to sever tubing has good control in up-hole and isolation packer. the target. down-hole directions and allows the rotation and torque transmission from • Middle packer top at 19,073 ft MD - Chemical-cutting surface. There are similar concerns isolation packer. with return flows as with coil tubing in Metallurgy and well chemistry can limit • Upper packer top at 18,658 ft MD - smaller production tubing sizes. Jointed the effectiveness of attempts to chemical- production packer. tubing may be the preferred conveyance cutting. The maximum temperature for a method in large-diameter tubulars and Locator profiles top were 22.7-22.9 ft chemical-cutting operation is 300°F. The for landing on top of seal-bore latches. from the packer target. Locator profiles solid bromine trifluoride will detonate bottom were 19.8-20.0 ft from packer tar- at 310-320°F. Centralization is impor- get. The packers were located on inclina- tant, and should the cut fail, the second Retrieval Method tions of approximately 80°. cut must not be made in the same area All retrieval options were investigated because chemical contamination will and selected using a decision tree analy- prevent the second reaction. For these sis tool. The decision tree resulted in the Safety Precautions reasons, chemical-cutting is discouraged recommendation to use EJC, which are To achieve a successful retrieval of as a cut-to-release method for cut-to- placed across the packer cutting target the intelligent completion, safe operat- release packers. with the assistance of a locator device ing and personnel practices were put that’s engaged in a locator sub above in place and acknowledged across all each packer. involved parties. This was the first Conveyance Methods intelligent completion workover for the Several conveyance methods are avail- The primary conveyance method for operator on the project. able, and each was taken into consider- the locator tool and cutter assembly ation for intervening with the cutters in was chosen to be wireline. The wireline Well C-13. choice required pumping the BHA in Retrieval method order to carry it through the S-shaped options Slickline profile of the well, with a maximum incli- The retrieval of the intelligent comple- Slickline is very compatible with explo- nation of 82°. A contingency 1 ¾-in. CT tion wells installed in the Hidalgo sive jet cutters. Its use is limited in reel and unit were mobilized in case the Platform were dependent on the success- highly deviated wells similar to wireline. pumping down of wireline was unsuc- ful release of each of the three multiport Slickline is the preferred conveyance cessful in conveying the cutter BHA to cut-to-release packers. The selection method for non-deviated wells. the depth of the deepest XMP packer.

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the electronic release disconnect device In order to quantify specific pump-down was dictated by the S-shaped wellbore rate to deploy the tools, the injectivity and the amount of friction involved with capacity of the reservoir and the limita- pulling the wireline from TD, which tions associated with the cups in the would have exceeded the shearing force wireline cutting string had to be continu- of a conventional mechanical emergency ously monitored. A rate of 5 bbl/min was disconnect device. established as the ideal rate to ensure the tools would not affect the reservoir Workover execution by inducing fractures and efficiently The following equipment requirements allow the displacement of the tools were established for the workover execu- through the highly deviated zones in the tion and procured during onshore prepa- ERD well profile. rations: Operational summary • Tubing retrievable safety valve protec- The cutting operation was performed as tive sleeve. per procedures. • Wireline unit equipped with min. An initial dummy run was performed 20,000-ft 7-46XS cable. to verify the effectiveness of the pump- • 2.75-in. EJC 38 gr explosive cutter. down operation. During this run, a com- bination of GR-CCL and spinner tools • Shock Sub, 2.00 OD for HPHT cutter. were run with the nipple profile locator tool, spacers and a dummy jet cutter. • Centralizers. One risk associated with the pump-down • Spacers. procedure is excessive pump-down force, • Adapters. which may release the cutter BHA when The cut-to-release locating profile and the BHA passes from the 4 ½-in. tubing target. • Trip selective locating tool (for nipple section to the 3 ½-in. section. By measur- profiles). ing the fluid pump-down rate at the BHA The selection of the conveyance method using the spinner, the wireline operator • Electric firing head. for the ERD Well C-13 was made based could verify the flow velocity drop-off on computer simulations, equipment • Electronic release disconnect. delay at the BHA when the pumping was availability and comparative costs. reduced to enter the 3 ½-in. tubing sec- • Gamma-ray, PPL and casing collar tion. An initial computer simulation for CT locator logging tools. and wireline showed that very little Another objective of the dummy run was weight down was available through • Pump-down mandrels. to verify that the locator profiles could coiled tubing when trying to locate the be easily identified and that enough Certain preparations were carried out lower-most packer. This did not favour pump-down force was available to pass offshore well in advance of the pulling the choice of coiled tubing because of through and pick up into each profile, operation (e.g., cycling of downhole con- the risk of not being able to determine if even with the ERD S-profile wellbore. trol valve tools to required positions for the BHA landed on a locator or if it sim- pulling). During the dummy run, the BHA was ply stopped because of friction. The CT left free-falling down to 3,600 ft. At this option would be feasible if some means The variable downhole valve deployed in depth, pumping was initiated to carry of reducing CT-to-tubing wall friction the lower-most zone was set in the fully the BHA. Pump rates inside the 4 ½-in. could be achieved. open position to allow well control. Well tubing section were taken up to 4 BPM, parameters (temperature and bottom- Wireline simulations showed that gravity observing 300-psi injection pressure. hole pressure) were recorded as base- alone was insufficient to convey the BHA line for the operation. Logging was performed to observe the across the long and highly deviated sec- drop-off of the fluid rate at the tool tion of the wellbore (82°). The advantage Downhole pressure gauges were intend- before reaching the tubing crossover to of the wireline solution, however, was the ed to be used to monitor wellbore condi- 3 ½-in. at 15,283 ft. The BHA was picked possibility of using pump-down cups to tions during packer cutting. up to 15,100 ft, and pump rates were help convey the BHA to TD. As an alter- reduced from 3 to 2 to 0 BPM. The BHA native, an e-line tractor could be used. Well pressure and volume of each control was then pumped through the crossover Due to the faster and least expensive line were verified and recorded prior to at 1 BPM. This rate was maintained up option of pumping the wireline BHA to and after each packer was cut to ensure to 17,000-ft depth. At this point, pumping depth, the tractor option was kept as a control line integrity. was stopped, and the tool was lowered contingency option. The two upper open/close flow control by free-fall. Another factor that precluded the tractor valves were part of the contingency The BHA was lowered to 18,290 ft, past option from being the primary method strategy when the wireline cutting tool the lower packer and locating profile. It was uncertainty about the reliability of was pumped down the well. Cycling the was then picked up through the packer the tractor system in conjunction with valves allowed achieving the required and profile. The packer radioactive pip- the electronic release disconnect device pump rates to deploy the tools at the tag was observed while picking up. The and the electronic firing head. The use of required position.

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Choke mandrel damage was observed.

locator tool pin sheared, and the BHA When running in hole the first jet cut- were lost, indicating that the TEC line was picked up at 17,900 ft. The BHA ter, the pump rate in the 4 ½-in. tubing had been severed again during the cutter was run in hole again and landed on the section was taken up to 5 BPM with 370 detonation. locating profile at 18,228 ft. psi of surface injection pressure, then lowered to 2 BPM while in the 3 ½-in. The entire wireline operation (total of The dummy BHA was then picked up tubing, down to 17,000 ft. one dummy run and four cutter runs) through the other upper packers and took 29 hrs. profiles, and each time it was landed After the first cutter detonation, gauge in each of the two other profiles, one at data from the lower gauge was lost, After all three packer cuts had been 17,691 ft and the last one at 17,248 ft. indicating that the explosive had cut performed, the wireline equipment was the packer mandrel target and the TEC rigged down, the wellhead was removed During this run, the radioactive pip-tags line through the packer by-passes at the and the rig BOPs installed. in the packers and locator subs were same time. identified with the GR tool and when Once the tubing hanger was connected landing down on each profile, and the During the second cutter run, the BHA to the rig elevators, the hook weight wireline was flagged at surface to mark would not free-fall through the upper observed was 48,000 lbs. The comple- the position of each pip-tag. Subsequent packer, and 1.5-BPM pumping had to be tion started pulling out of the hole with runs were performed with the actual used to get the BHA past the top packer 230,000 lbs overpull, and the entire com- 2.75-in. explosive jet cutters to the fol- and down to the middle packer. After pletion was retrieved over 4 ½ days. The lowing targets: detonation of the cutter, no hydraulic POOH operation was interrupted twice line pressure was lost and the gauge due to well kicking, and approximately Lower packer top at 18,219.92 ft MD: data from the middle gauge was still vis- 17 hrs were spent killing the well in order to resume the retrieval operation. • Locator profile top is 22.8 ft from ible. This was an indication that neither packer target. the TEC line nor the CLs had been cut. All completion sub-assemblies were laid When the BHA was retrieved at surface, down and loaded in baskets for transpor- • Locator profile bottom is 20.2 ft from tation to shore for equipment conditions packer target. it was observed that the jet cutter had not fired. The problem was identified in assessment. Middle packer top at 17,682.41 ft MD: a faulty primer cord connection between the detonator and the jet cutter. The det- Refurbishment, Assessment • Locator profile top is 21.7 ft from onator was run and successfully fired. packer target. of retrieved equipment The middle packer run was repeated Flow control valves assessment • Locator profile bottom is 20.2 ft from with a new detonator, primer cord and packer target. jet cutter assembly. This time, both the Lower zone, variable flow control valve. This on/off-type flow control valve Lower packer top at 17,238.12 ft MD: gauge data and the CL (common-off line) hydraulic pressure were lost, indicating was backed off from the pup joint below • Locator profile top is 22.8 ft from that the cutter had fired and severed the it and the swivel connector above it. packer target. TEC line and one of the control lines. The valve itself was observed to have • Locator profile bottom is 20.2 ft from The upper packer run was flawless, and, 6 ea choke inserts missing from the packer target. immediately after firing, all gauge data choke mandrel at the time that the valve

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the rest of its sub-assembly components. The sub-assembly was then hydro-tested and drifted prior to wrapping the pack- ers with protective material for trans- portation inside the 50-ft basket back to location.

Monitoring assemblies assessment Lower zone. The single gauge mandrel was shipped to the manufacturer’s prod- There was evidence of fluid invasion between the filler and the insulator as indicated by uct center with the gauge still installed a change of color. in the mandrel. Once at the product cen- ter, the single gauge and a TEC pig-tail surfaced the rotary table. Several other a pressure spike through the valve, caus- attached to it were removed and sent for choke inserts were partially unseated ing the upper inserts to be removed. recalibration of the gauge. from the choke mandrel, and some had The mandrel itself was sent to a third- to be pushed in in order to disassemble Based on the investigation, it was rec- party contractor for cleaning and sand the valve. ommended that the following actions be taken to prevent future problems: blasting. A phosphate coating was The entire valve was disassembled, and also applied to prevent corrosion once the following parts were found damaged: • The use of explosive cutters may not cleaned. be suitable for completions where sen- • Choke mandrel. sitive equipment is deployed. Pressure The single gauge mandrel was hydro- sensors, flow control valves and the tested and drifted prior to wrapping in • Primary and secondary seats. likes may not be re-usable if they are protective material for transportation inside the 50-ft basket back to location. • Metal seal gland. not protected from the pressure wave originating from the EJC. The gauge itself did not pass the calibra- • Ring seals. • Concepts for attenuating the pressure tion procedure and had to be substituted • Indexing pin. wave or alternative cutting methods with a new gauge that was sent straight should be looked at, if damage to other to location from the operations support • Indexer mandrel. parts of the completion is a concern. district. These were replaced with new parts, Middle zone, open/close flow control After the calibration, a more detailed with the exception of the indexer man- valve. This valve was backed off from evaluation was carried out on the gauge drel, which could be re-worked and made the pup joint above and below, and the to identify the failure. Under the evalu- good. entire valve was stripped down and ation, fluid invasion in the TEC line was identified. Once the line was cut closer to All elastomers within the valve were also inspected for damage. No damage to any the connector, fluid drops could be seen changed out as per the valve’s redress of the valve components was detected. coming out of the line between the armor kit. The valve was re-dressed by changing and the filler. The valve was put through a series of out all critical components and was sub- The section that was cut was also exam- function tests as per the valve’s FAT jected to a FAT as per the valve QA/QC ined, and there was evidence of fluid procedure. This was done at the manu- manufacturing requirements. invasion between the filler and the insu- facturer’s test facility. After the valve successfully passed the lator as indicated by a change of color. Once the valve successfully passed the FAT, it was made up and torqued up to Middle zone. The dual gauge mandrel FAT, it was made up and torqued up to the rest of its sub-assembly components. was shipped to the manufacturer’s prod- the other components of sub-assembly The sub-assembly was then hydro-tested uct center with the gauge and Y-block #1, and the entire sub-assembly was and drifted prior to wrapping the pack- still installed in the mandrel. Once at hydro-tested and drifted. The valve was ers with protective material for trans- the product center, the single gauge, then wrapped in protective material for portation inside the 50-ft basket back to Y-block and a TEC pig-tail attached to transportation inside the 50-ft basket location. the Y-block were removed and sent for back to location. Upper zone, open/close flow control recalibration of the gauge. An investigation on the valve damage valve. This valve was backed off from The mandrel itself was send to a third- was performed, and the results were the pup joint above and below, and the party contractor for cleaning and sand documented by the manufacturer’s flow entire valve was stripped down and blasting. A phosphate coating was management engineering department. inspected for damage. No damage to any of the valve components was detected. applied to prevent corrosion. From this analysis, it was concluded that The dual gauge mandrel was hydro-test- there was considerable evidence attrib- The valve was re-dressed by changing ed and drifted prior to wrapping in pro- uting the failure of the inserts within the out all critical components and was sub- tective material for transportation inside 3 ½-in. flow control valve to the presence jected to a FAT as per the valve QA/QC the 50-ft basket back to location. of a pressure wave resulting from the manufacturing requirements. use of an explosive packer cutter 30 ft After the valve successfully passed the This gauge passed the calibration proce- above the valve. The explosion directed FAT, it was made up and torqued up to dure and was packaged with the Y-block

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The retrieved multiport packer element.

profile were removed at the rig-site by a wireline operator prior to off-loading the sub-assembly from the rig. The packer sub-assemblies were un- torqued and disassembled. The released multi-port packers were substituted with 7-in. x 3 ½-in. 26-29 ppf multi-port packers. These new packers were shear- to-release type, and the shear setting for each was set at 140,000 lbs. This was the maximum recommended shear setting for 7-in. L80 casing (above this shear setting value, the packer slips would never release from the casing walls). Each of the multi-port packers were con- verted from 32-35 ppf packers to 26-29 Retrieved multiport packer slips. ppf that were made available from anoth- er location. This was necessary due to and its TEC line pig-tail. It was sent to the Y-block were removed and sent for the extensive lead time required for the location ready for installation during the recalibration of the gauge. manufacturing of new multi-port packers re-completion operation. (five to six months). Additionally, these The mandrel itself was sent to a third- particular packers’ mandrels and upper An additional test was performed with party contractor for cleaning and sand and lower housings had to be substituted the retrieved gauge and the other two to blasting. A phosphate coating was in order to comply with NACE materi- see if all gauges were working properly. applied to prevent corrosion. als regulations for sour gas service as All gauges performed as expected, but to per the Hidalgo C-13 well conditions. the evidence of fluid invasion in the low- The dual gauge mandrel was hydro-test- ed and drifted prior to wrapping in pro- Crossovers from 3 ½-in. Vam Top to the er-most gauge. It was agreed with PXP packers’ 3 ½-in. New Vam connections to completely change the gauge system tective material for transportation inside the 50-ft basket back to location. were installed to make up the packers to and individually evaluate the gauges. the existing 3 ½-in. Vam Top pup joints The objective was to minimize any future This gauge passed the calibration proce- equipment. risk of gauge failure with any potential dure and was packaged with the Y-block moisture in the TEC line. and its TEC line pig-tail. It was sent to These sub-assemblies were made up with the multi-port packer and the cross- Upper zone. The dual gauge mandrel location, ready for installation during the re-completion operation. overs above and below the packer, and was shipped to the manufacturer’s prod- the sub-assemblies were hydro-tested uct center with the gauge and Y-block Packer assemblies assessment and drifted prior to wrapping the pack- still installed in the mandrel. Once at ers with protective material for trans- the product center, the single gauge, The radioactive pip-tags in the packer portation inside the 50-ft basket back to Y-block and a TEC pig-tail attached to upper gauge mandrel and the locator location.

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blies and issued a recommendation for further metallurgical testing to deter- mine possible corrosion inhibitor solu- tions, as it was determined that the gas lift mandrels were undergoing consider- able corrosion, and the life expectancy of the completion was compromised if subjected to the same environment on the next completion. The gas lift mandrels were sent to the manufacturer’s service facility in Tyler, Texas, where the gas lift valve itself was pulled from the mandrel and completely redressed by changing packings, all elas- tomers, Ventury orifice and RK latch. The valve was reset and re-installed in each mandrel, and the mandrel sub-assem- blies were hydro-tested and drifted. The gas lift mandrel sub-assemblies were then loaded in the 35-ft basket for The corrosion-pitted gas lift mandrel. transportation to the well site. One of the gas lift mandrel sub-assemblies was inspected and found to have significant pitting due to sour gas corrosion in one of the pup joints. The pitted pup-joint was backed off and replaced with a new one.

Subsurface safety valve assembly assessment The safety valve was backed off from its flow couplings and pup joints above and below it, and the valve itself was trans- ported to the manufacturer’s facility in Houston, where it was completely re- dressed, FAT’ed and re-certified. The valve was then returned to the prod- uct center, where it was made up and torqued up to the flow couplings and pup joints again. The entire sub-assembly was then hydro-tested and drifted while the flapper valve was held open with hydraulic line pressure. The valve was Retrieved cross-coupling protector clamps. then wrapped with protective material and loaded in the 35-ft basket for trans- Chemical injection damaged 4-ft pup joint was replaced with portation to location. assembly assessment a new one. Hydraulic and electric lines The DCIN was backed off from the two The sub-assembly was wrapped in pro- assessment pup joints above and below it. The DCIN tective material and loaded into the 35-ft mandrel by itself was then transported basket for transportation to the well site. Hydraulic control lines. All control to the manufacturer’s facility in Houston, lines (flat packs and single encapsu- where it was completely redressed and Gas lift assemblies assessment lated lines), as well as the TEC line and FAT’ed. The DCIN was then sent to a chemical injection line, were spooled The gas lift mandrel sub-assemblies back onto their reels during retrieval. third-party facility for making up to were inspected for damage and were its pup joints above and below and for However, new lines were procured for re- found to have some significant pitting installation of the completion. the connections to be hydro-tested and due to sour gas corrosion in one of the drifted. pup joints. The pitted pup joint was None of the lines was recommended to One of the pup joints retrieved from the backed off and replaced with a new one. be used again due to potential deforma- well was found damaged, probably by tion each time they are spooled into the Experts from the manufacturer’s metal- well and out of the well, and the higher rig tongs while breaking off the sub- lurgy department inspected the corro- assembly from the tubing string. The risk of failure if the line is subjected to sion on all gas lift mandrel sub-assem- this spooling cycle more than once.

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Many of the encapsulations were found the entire IC completion in one trip • Gary. P. Hertfelder, SPE; Kurt Koerner, SPE, to contain wellbore fluids, including gas. is facilitated by the nature of the cut- Plains Exploration and Production Company; For this reason, they required cleaning, to-release design, and explosive jet Allen Wilkins, SPE, Easywell, and Lilian straightening and pressure-testing by a cutters can effectively sever control Izquierdo, SPE, Schlumberger, 2007, Are qualified third-party company. In theory, lines and electric lines to facilitate the Swelling Elastomer Technology, Preperforated Liner, and Intelligent Well Technology if this is done and the lines pass the retrieval. pressure testing, they may be used for Suitable Alternatives to Conventional Completion Architecture?, Paper AI IADC/SPE re-installation in another completion. 2. Intervention to cut the packer targets 105443, presented at at the 2007 SPE/IADC The actual feasibility and cost of this can be effectively performed using Drilling Conference, held in Amsterdam, the wireline as a conveying string, and the refurbishment would have to be veri- Netherlands, 20–22 February 2007. fied with proficient third-party services pump-down method is a cost-effective should the need arise to make use of the alternative to e-line tractors, even in Acknowledgments retrieved control lines. ERD well trajectories. The authors would like to thank the manage- A third-party company was approached 3. The use of explosive jet cutters is ment of Plains Exploration and Production for the re-spool of the lines as single(s), very efficient in cutting the packer Company and Schlumberger Corporation for clean up jacket, and for NAS Class certi- targets, but the shock from the explo- their permission to publish this paper. fication. sive charge can affect the integrity of Special thanks for their contribution to the gauges and/or flow control valves that success of this project go to: Burt Elliot, of The effect of moisture invasion of the are placed in proximity of the packers. TEC line is also a likely potential risk Schlumberger Wireline Ventura for the flaw- It is recommended that a minimum less planning and wellsite execution of the that may influence premature failure of distance of 20 ft be kept between a Cut to Release Operation; Steve Emerick and the TEC cable should it be run back into cut-to-release packer and a flow con- Farrel Pitts of Schlumberger Well Services a well. trol valve or gauge if explosive jet cut- Ventura for continous support during the design and planning of the intervention Protective clamps assessment ters are planned to be used during the retrieval operation. program; Steve Grayson of Schlumberger All protector clamps retrieved from Wireline Ventura for his technical contribu- C-13 were shipped back to the manufac- 4. The compatibility of wireline tractors, tion and support during the design phase of turer. Some clamps have been damaged electronic release disconnect and the intervention; Ken Gade of Schlumberger beyond repair, but the majority were explosive firing system has not been Wireline Ventura for the logistics and found to be in good condition and would tested before, and therefore precluded operational support during the planning and execution phases of the Cut to Release require sand-blasting and refurbishment the tractor option to be selected as Operation; Brad Moulsberry, Jeremy Fould, of the compression indents and possibly one of the back-up contingency meth- Al Adam and David Harris of Schlumberger some hinges. ods. Further stack-up testing of these Completions Houma and Project Support components could facilitate alternative A new set of clamps was procured to Group for the flawless retrieval, redress and options in future IC completions work- be used for the re-completion of C-13. recompletion operations; Randy Cox and his over or intervention operations. An additional set of splice protectors team at Schlumberger Rosharon Reservoir Completions Testing Facility for support was designed and built to accommodate IADC/SPE 112115, “Managing the Retrieval and expedite testing of all the redressed the four additional splices in the C-13 of Triple-Zone Intelligent Completions in Extended-Reach Wells Offshore California,” assemblies; Bunker Hill, Ken Rohde and Jo re-completions that connect the gauge Lafleur at Schlumberger Rosharon Reservoir Y-block pig-tails to the main TEC line. was presented at the 2008 IADC/SPE Drilling Conference, 4-6 March 2008, Orlando, Fla. Completions for accelerated repair and redressing of the flow control valves; Preston Lessons Learned, References Green of Schlumberger Artificial List Tyler TX Conclusions • PMI, 2000, A Guide to the Project for technical support and accelerated redress- Management Body of Knowledge (PMBOK ing of all gas lift equipment; Steve Kramer of 1. Cut-to-retrieve multiport packers are Guide) 2000 Edition, Project Management Schlumberger Completions Houston for tech- an effective choice when stacking Institute, Four Campus Boulevard, Newton nical and logistics support with the safety isolation packers for ICs. Retrieval of Square, PA 19073-3299 USA. valveand DCIN redressing operation.

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