Marco Polo Deepwater TLP Completion Implementation and Performance

SPE 95331 Marco Polo Deepwater TLP: Completion Implementation and Performance J. Burman, SPE, Exploitation Technologies LLC, and K. Renfro, SPE, and M. Conrad, SPE, Anadarko Petroleum Copyright 2005, Society of Petroleum Engineers This paper was prepared for presentation at the 2005 SPE Annual Technical Conference and Exhibition held in Dallas, Texas, U.S.A., 9 – 12 October 2005. This paper was selected for presentation by an SPE Program Committee following review of information contained in a proposal submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to a proposal of not more than 300 words; illustrations may not be copied. The proposal must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

Abstract Novel well completion techniques and exceptional field execution allowed the six well completions on the Anadarko operated Marco Polo Deepwater TLP project in Green Canyon 608 to be accomplished in world-class fashion. All six wells (seventeen frac packs) were placed on production in only 168 days, including 14 days lost due to storms, after riser tie-back operations were complete. An operational efficiency of 85%, with weather downtime accounting for 9% and other lost time accounting for 6%, was obtained during the completion campaign. This paper will focus on how the implementation challenges of completing seventeen zones in six deepwater dry-tree wells with a 1000 hp rig were met, and will highlight a number of concepts and technical firsts that can be applied to other deepwater development projects. Background Anadarko’s Marco Polo deepwater development project is located in Green Canyon Block 608 in the Gulf of Mexico, approximately 175 miles south of New Orleans, in a 4300’ water depth environment. Field Development The Marco Polo Field was discovered in 2000, and the project was sanctioned for development in 2001. Six development wells were drilled in 2002 and 2003, and were temporarily abandoned to await completion after installation of the TLP in 2004 (Refer to Figure 1, Marco Polo TLP). The TLP hull and deck were installed in January 2004, and were designed to accommodate a 1000-hp completion rig to run riser tiebacks and perform completions. Only 88 persons are allowed on the platform at a time (maximum POB) due to USCG rules, a significant issue for rig operations.

Geological The Green Canyon Block 608 (Marco Polo) field is located in the southern portion of the Marco Polo salt withdrawal minibasin. The depositional model for the field is a restricted basin floor amalgamated sheet fan sand. Moderate to strong aquifer support was expected, although the potential presence of internal baffles and barriers introduce uncertainty to the extent of the aquifer support. The trap geometry was created by salt withdrawal and extensional faulting due to sediment loading on the eastern side of the salt ridge. The primary trap consists of a fault bounded graben dipping away from the salt ridge. The main faults are west-southwest to east-northeast trending faults that form the graben. The updip trap component to the west is salt and/or sand punch-out. The graben is further subdivided into separate compartments by additional faulting. Refer to Figure 2, Marco Polo M10 Sand Structure Map. Two main fault compartments make up the Marco Polo field. Another graben fault, downthrown to the north west and trending in the same direction as the bounding faults, subdivides the graben into these two main compartments, designated as Fault Block I and Fault Block II. The two main compartments are further subdivided into two additional compartments by faults that are trending northwest to southeast and downthrown to the west (towards salt). The four main producing compartments for the Marco Polo field are designated FB IA, FB IB, FB IIA and FB IIB (Updip compartments are denoted “A”). The productive horizons at the Marco Polo Field consist of seven stacked Lower Pliocene sandstone reservoirs; the M10, M20, M30, M40, M50, M60, and M70; 75% of the reserves are concentrated in the M40 and M50 Sands. Reservoir depths range from 11000 to 13500’ tvd-ss. Refer to Figure 3, Marco Polo Type Log. A complete open hole logging suite was obtained on all discovery and development wells. Continuous whole core was obtained through both the M-40 and M-50 intervals in the GC 608 #1 ST#1 wellbore. Reservoir Initial reservoir pressures range from 6700 to 7600 psi. Reservoir temperatures range from 115 to 122 oF. Ambient mudline temperature is 38 oF at 4300’ water depth. Reservoir fluids are undersaturated black oils, with API gravities ranging from 30-34 and GOR’s ranging from 700 to 1000 scf/stb. During the exploratory and development drilling phases, reservoir pressures were measured on nearly all productive intervals in all wells, and reservoir fluid samples were

2

collected and analyzed in the main field pay zones. Refer to Table 1, Marco Polo Reservoir Fluid Properties. Completion Design Overview Multiple pay sands, low reservoir temperatures, the requirement to gas lift the wells, and the deepwater environment drove the design of the Marco Polo completions. After significant flow assurance modeling and evaluation, dual barrier risers with insulating gel in all annular spaces with a separate gas lift string (terminated in a sub-mudline or packoff tubing hanger) were chosen as the upper completion design. Refer to OTC 16642, “Influence of Field Development and Flow Assurance Issues on Well Completion Design at Marco Polo Field” by K.D. Renfro and J.W. Burman for additional information on the methodology used.1 The sandface completion design focused on risk management during completion operations with the hardware designed to minimize future intervention risk. In brief, the 17 pay intervals in six wells were developed with multi-zone, selective single, stacked frac pack completions, using sliding sleeves with a concentric isolation string for zonal isolation. Multiple chemical injection points are installed for hydrate, paraffin, asphaltene, and scale prevention. The installation of fiber optic technology for downhole pressure sensing and distributed temperature along the tubing string assisted in well surveillance and hydrate prevention. Refer to Figure 4 for Marco Polo Generalized Wellbore Schematic. Wellbore Construction All wells were drilled, cased (9-5/8” 53.5# P-110, 8.5” drift), and suspended with water based mud and surface cement plug. Maximum hole angle is 36 degrees. Insulation placed on the LPWHH and 36” casing above the mudline reduced heat loss in this area. For additional information on the design and installation of Marco Polo development wells, refer to SPE/IADC 79809, “An Innovative Approach to Development Drilling in the Deep Water Gulf of Mexico” by Watson et al.2 The dual casing risers, 13-3/8” 0.514” wall X-80 outer riser with 9-5/8” 0.545” wall P-110 (8.5” drift) inner riser were installed. The 13-3/8” by 9-5/8” riser annulus was filled with insulating gelled fluid prior to make up of the 9-5/8” internal tie back connector (ITBC). The riser tieback operations were accomplished in batch mode over a period of 44 days (including 9 days lost due to weather). After installing the outer risers in sequential slots, the inner risers were installed in reverse order. Following riser installation, the individual tree access platforms and flexible production flowlines were installed on the first three wells to be completed and all dynamic control umbilicals installed. Completion Operation Efficiency and Well Productivity All six Marco Polo wells were successfully completed and placed on production in only 168 days. Two wells with three frac packs each were completed in under 22 days, rig skid to rig skid. Refer to Figure 5 for Marco Polo Completion Operations Timeline. Operational efficiency for the project averaged 85% uptime. The unplanned downtime broke down as follows:

SPE 95331

weather - 58% (including three tropical storm/hurricane evacuations), unavoidable issues - 25% (downtime due to helicopter, crane, fire drills and alarms, flaring), and avoidable issues - 17% (stuck guns, misruns, damaged equipment, re-centering the rig, etc). Refer to Figure 6 for Marco Polo Completions Operational Efficiency. Initial rates and drawdowns (determined from ten minute buildup pressures) for the various wells can be found in Table 2, Marco Polo Initial Well Productivity. Average initial productivity for the 6 wells was 9,000 BOPD with an average drawdown of 227 psi, and an average productivity index of 39.7 bbl/day/psi. Completion Time Saving Strategy Some early decisions significantly contributed to the successful reduction in operational time required for the project. These included the completion order, the workstring selection, prefabrication of tree instrumentation, preinstallation of fiber optic infrastructure on the facility, riser and tubing installation SIT during rig upgrade, a novel rig hurricane evacuation plan, and offline wellbore commissioning (operations took place off the rig critical path). Completion Order Completion order was determined considering reservoir issues and the rig/well/platform arrangement. Due to rig design and space limitations, no bridge crane exists below the rig substructure for manipulating the tree, flowlines or umbilical. If the rig is moved two slots, one of the two platform cranes could access a given well. Refer to Figure 7, Marco Polo Mudline and Surface Wellhead Locations. Wells identified as being in common fault blocks were intentionally completed together to minimize the effects of reservoir depletion on completion operations. Also, as one well, A-5, was “only” a two zone frac pack, it was completed first and the remaining five, three zone frac wells, subsequently. The resulting plan was that the wells were completed in an alternating fashion (i.e. completion order by slot of 1-3-5-26-4) to allow the platform crane to perform offline well commissioning activities. Crane operations included installation of the tree and flowlines. Workstring Selection A significant effort was made early in the planning process to determine the type of worksting to be used on the completions. The rig only had the capacity to rack back a full workstring of 3-1/2” IF for the deepest well. Any larger workstring would require picking up and laying down workstring on every trip. Extensive fracture modeling, using log derived and core measurements of shale and reservoir material, provided pump rate requirements for the unconsolidated intervals. Two design cases reviewed were the zone with the longest perforated interval (170 feet) and the zone with the highest “kh” (32,000 md-ft). Thermal and flow modeling was done using different workstring sizes and fracturing fluid types to estimate the effect of temperature and friction on pump rate through the different workstrings. Hydraulic calculations indicated (and subsequent field observations confirmed) that a 3-1/2” 13.3# IF string would be

SPE 95331

sufficient for displacement and frac packing operations at up to 25 bpm maximum rate on pad. An internally plastic coated workstring was used for the completion operations. This minimized pipe debris (scale) issues3 and reduced internal friction pressure for the pumping and displacement operations at planned rates. Prefabrication of Tree Instrumentation One unique quality of TLP and spar completions is the requirement to have a flexible flowline and dynamic control umbilical. A major goal of the operation plan is to minimize the time an operator has to go onto an individual tree platform for routine monitoring. As a result, remote sensing is used so that routine pressure and temperature monitoring can be conducted from the platform control room. Every one of these functions was conveyed from the tree to the platform via the dynamic control umbilical. An extensive amount of time and labor was required to route the various fiber optic, electric, hydraulic, and chemical control lines from the tree or downhole line to the umbilical (and from the end of the umbilical to the individual well junction box). It was determined that significant time and cost savings could be achieved if the various lines were preinstalled on the wellhead access platform, then disassembled and marked for re-installation after the well was completed. Use of this technique allowed the well to be ready for production 7-10 days earlier than if the lines were totally installed on location, at a much lower cost, and with less personnel. Pre-Installation of Fiber Optic Infrastructure The use of fiber optic downhole sensing technology in all the initial development wells at Marco Polo was an industry first. Planning for the successful implementation of this system “downstream” of the well were divided into two categories, hardware installation on the facility and obtaining the software and data storage capability to utilize and manage the data. The optimal fiber optic connection fuses the glass fibers together to obtain a low loss of light energy due to reflection. Since the fusion process is an ignition source, running and connection of the bus and gathering lines was done prior to the facility leaving the fabrication yard. After the dynamic control umbilicals installation following riser installation, a crew went out to the platform to install a jumper from the well outlet area through the designated hose in the umbilical. The lines were then fusion spliced in the individual well junction boxes. This left one fusion splice at the wellhead outlet after the well was completed; this splice was accomplished while wells were shut in due to rig skidding and BOP installation on the next well. All wells were configured with one downhole pressure temperature gauge at the lower end of the production tubing, and two distributed temperature sensing (DTS) lines to monitor the external tubing temperature4. Riser and Tubing Installation SIT After planned rig modifications had been completed, a short three day SIT (system integration test) of the proposed riser and dual tubing installation equipment was performed in the contractor’s yard in Harvey, LA. The riser installation

3

equipment was installed on the rig and components were checked for fit and function. Mobile cranes were located to simulate actual rig crane location and function. Tubing installation equipment was then installed, including equipment required for control line installation. Actual joints of tubing were made up and control lines and clamps installed on the spider deck. The exercise revealed quite a few opportunities for improvement to equipment layout and modification, which were successfully implemented prior to start of actual operations. Many other issues addressed during the rig modification period to optimize operations included: BOP re-certification, dual shear ram testing with actual tubing and flatpacks, fabrication of three part adjustable bell nipple assembly (with lubricator lockdown flange), installation of clamps and lines for derrick deluge system, relocation of fluid pit drain valves to optimize cleanout, lining of v-door and piperack to protect tubulars, pre-fitting of frac pack treating lines, and installation of frac pack hose hangers on substructure. Hurricane Evacuation Plan The temporary abandonment plan of these TLP wells in the event of a hurricane was thoroughly evaluated. Storm loads evaluated by global and rig structure analysis dictated that no setback load could be allowed in the derrick during a hurricane. Two days was estimated to be required to evacuate the rig because of the time it takes the crew and cranes to move the drill pipe from the v-door to the piperack and remove excess variable deck load to workboats. In the event a storm formed in the Gulf of Mexico or Caribbean Sea, the window of time available to lay down pipe from the derrick is determined by how long the cranes can operate due to increased swing motor loads caused by TLP platform acceleration and wind. In order to improve the probability that the well, rig and platform could be safely secured in the event of a quickly developing storm, detailed analysis was undertaken to determine if the riser/BOP system could be suspended with workstring hanging below a test plug in the wellhead. By placing standard spiral drill pipe protectors at mid joint and at the tool joint above and below the keel and stress joint regions, the load exerted on the inner riser was reduced from 2800 lbs to 270 lbs (reduction factor of 10.37), resulting in no damage to the inner riser. No incremental loads were exerted on the wellhead or riser tensioning system by the 3-1/2” 13.3 ppf IF workstring. This procedure proved very valuable when during preparations to frac pack the lower zone in the A-8 completion, Tropical Storm Bonnie formed in the Yucatan Strait and was headed directly for the platform. The decision was made to proceed with the frac pack operation before securing the rig for the storm. The frac pack was performed trouble free (the minifrac was omitted to save valuable time). After successful completion of the frac pack, the well and rig secured and all rig personnel evacuated in a total of only 14 hours. The procedure also proved to be valuable on the other two storm evacuations during the completion campaign.

4

Offline Well Commissioning Significant rig time, estimated at 4 to 6 days per well, were saved by skidding the rig after landing the tubing hanger and finishing required downhole and surface well work while doing the initial wellbore cleanout and displacement on the following well. A third pump (high pressure, low volume) was used specifically for this work. Specific operations accomplished during this time included: terminating the control lines, landing and testing the tree, removing back pressure valves, attaching and testing the flowline and dynamic umbilical, displacing the upper annulus to insulating fluid, displacing the lower annulus above the SCSSV to a hydrate proof fluid, displacing and commissioning the downhole chemical injection lines, and establishing flow from the well. These operations are discussed further later in this paper. This procedure also reduced the labor requirement on the platform, since the wellbore cleanout phase had the lowest rig personnel requirement. Additional personnel for well commissioning were easily accommodated on the platform. Completion Operation Discussion Operation planning focused on efficiently performing the job as planned, and providing for contingency plans in the event of an unplanned event. Proven technology was employed, and procedures were worked to minimize downhole and safety risk as well as personnel requirements. The high points of the major completion operations (wellbore cleanout, perforating, frac packing, tubing installation, and well commissioning) are discussed. Efforts to speed up the implementation of these operations, without compromising productivity or adding undue risk, are addressed. Rig Procedures and Operational Management Procedures were kept short and concise. A well specific portion contained pertinent data and objectives for the well being completed. Operational procedures were maintained for planned operations and contingencies. These procedures were reviewed at a pre-completion meeting held a short time prior to commencement of completion operations with the involved parties. Minor revisions were made after the first well completion to reflect lessons learned. Operational supervision was shared among three engineers who also developed the completion design and managed component selection and manufacture. Clear lines of authority and communication expedited decision-making and maintained continuity during the project. QA Procedure All components used in the Marco Polo completions were manufactured using a specific QA/QC plan and audited on site by third party inspectors. In addition, the proposed completion design and implementation procedure were audited by both internal and external peer reviews. All components were drift tested with the actual tools, profile locks, and shifting tools to be used in the well to assure future access and function was possible in all envisioned situations. A dimensionally correct dummy insert SCSSV was used to minimize cost.

SPE 95331

Wellbore Displacement All wells were successfully cleaned out and indirectly displaced to calcium chloride/bromide completion fluid in one trip. All had been temporarily abandoned after drilling with water based mud to TD and a surface cement plug. Non-rotating brushes and scrapers were used with various downhole combinations of bits, mills and drill collars to drill the surface plug and wash settled barite. The optimal toolstring was a standard rock bit and 6-1/2” drill collars. Bentonite gel sweeps were used while pumping at 10-12 bpm and rotating the drill string with the kelly at +70 rpm to achieve efficient mud and cement cleanout from the wellbore. Once the wellbore was washed out to PBTD and displaced to treated salt water (TSW; treated with oxygen scavenger), chemical sweeps were pumped, a short trip made to the upper scraper/brush (generally four were spaced out in the string), and the well displaced again with TSW followed by calcium chloride/bromide completion fluid. The brush scraper system employed was of a robust design, which allowed continuous rotation and not cause casing damage or component failure. The internal diameter of the tools would allow the passage of electric line severing or cutting tools to the end of the workstring, should an unforeseen event occur. All wells used calcium bromide-calcium chloride (CaBr2CaCl2) blend with a density of between 11.7 and 12.6 ppg, and contained 0.5% of a non-ionic surfactant to reduce emulsion potential. Target true crystallization temperature (TCT) was below 20 oF, and pressure crystallization temperature (PCT) was below 32 oF at 10,000 psi. All completion fluids and reservoir fluids were tested for compatibility in the laboratory prior to completion operations, and confirmed after first production. Perforating Strategy The Marco Polo perforating strategy achieved a balance between operational efficiency and perforation performance by perforating all individual zones overbalanced. A 6-1/2” gun (with integral tandem centralizers; collapse rating of 12,000 psi) with 14 shot per foot, big hole charges using sintered zinc casing and liners was used. The firing system employed redundant pressure delay firing heads to eliminate drop bar retrieval issues. The firing heads were both placed at the top of the gun to keep the distance from the bottom shot to the sump packer to a minimum. This reduced the probability of the packer plug-running tool damaging the packer plug when the guns fired, or having a void in the bottom of the frac pack due to a longer interval from the bottom shot to the sump packer. Intervals to be perforated ranged from 21’ to 170’ measured depth in length, and from 19 to 35 degree deviation. In all cases the top 5 foot of reservoir quality sand was not perforated to assist in frac pack containment. A packer plug was used to isolate and prevent debris from falling into the prior completed interval when perforating the upper zone(s) in a well. Overbalanced perforating minimizes the risk of gun sanding, minimizes risks with packer plug retrieval, has lower operational cost, reduces the probability of hydrate formation, and has been documented to not reduce frac pack

SPE 95331

productivity5,6. The 6-1/2” guns with tandem centralizers are also easier to wash over and recover from the 9-5/8” 53.5# casing than 7” guns. This minimizes the potential of generating non-fishable debris (“slabbed” perf gun) and washpipe connection torque failure should washing over be required. A contingency plan to wash over and recover stuck perforating guns was generated prior to starting completion operations. Drill Stem Test tools and retrievable packer were used in the perforating string to control losses and isolate the zone. Bottom hole pressure gauges below the isolation valve were utilized to obtain a formation and baseline hydrostatic pressure. Fast reading bottom hole gauges were used additionally on the first two wells to better understand the dynamic underbalance to which the zones were exposed during the overbalanced perforating procedure. On one occasion, when perforating the longest zone of the program (170’), the guns were stuck following firing the guns and reversing out using the DST tools in the string. After confirming the packer was released, the below packer safety joint was backed out and the upper toolstring recovered. The guns were then successfully washed over with one trip (fill found over the bottom 36’ of gun assembly), and then recovered with an overshot (with one misrun). The packer plug was then recovered (also with one misrun). This event accounted for a total of 112 hours unplanned downtime. On 16 of 17 perforating runs, fluid losses to the formation were less than 10 barrels per hour after reversing out the workstring and before POOH. In one instance (A-4 M-40 zone) the losses exceeded 10 bph, and a 15 bbl HEC pill was successfully utilized to reduce losses to ½ bph. An additional HEC pill was required during a cleanout trip on the A-7 M-40 sand (after reversing fill, losses increased to over 10 bph). Generally post perforating losses were on the order of 2 bph or less. All tool strings were preassembled and pressure tested in rig compatible lengths prior to shipment, and fully disassembled after being shipped in from the rig. Overbalanced perforating is estimated to have saved 6 rig days over the course of the project versus a 250-500 psi underbalance procedure, with no sacrifice in well productivity, as evidenced by the high productivity and low skins obtained (Refer to Table 2). Refer to Table 3 for Marco Polo Perforating Summary for actual perforating zone data. Downhole Frac Pack Equipment The Marco Polo frac pack strategy was to use a system which was compatible with multiple stacked completions, provided pressure isolation after the individual frac pack, and would allow any debris to fall through the assemblies. A stretch goal during the design phase was to include the ability to open the zones initially intended to flow in a particular well without the use of wireline or coiled tubing intervention. Each interval utilizes concentric isolation tubing with mechanical sliding sleeves to provide positive zonal isolation. Two sleeves are manipulated during the frac pack operation: one at the frac pack tool (slurry exit port from the service tool) and one below the bottom perforation in the isolation tubing (to provide a return fluid and pressure path, as well as assisting in slurry dehydration during proppant placement).

5

The lower sleeve also provides live annulus monitoring of downhole treating pressure to the annulus above the frac pack packer via the washpipe and crossover tool. These sleeves are closed by removing the crossover tool after the frac pack treatment has been completed. Fluid loss control and zonal isolation is achieved after closing both sleeves. This provides well control when completing uphole zones and while installing production tubing. Refer to Figure 4, Marco Polo Wellbore Schematic. In all wells, at least one zone was equipped with a pressure actuated sliding sleeve which was opened during well commissioning operations to provide a flow path without requiring any intervention. The valve is opened when sufficient surface pressure is applied and then bled off (with an underbalanced tubing string) so the sleeve will open (sleeve will not open unless the wellbore is underbalanced). When multiple zones were required to be opened in a given well, the sleeve system provided pressure balance between adjacent zones, preventing the lower sleeve from opening during the frac pack operations. In the three zone completions, the bottom pressure actuated sleeve was shear pinned sufficiently high to prevent shearing during frac pack operations of the top zone, as it was not pressure balanced with the upper zone7. The actual wireline profiles and sliding sleeves utilized were also designed to allow concentric isolation strings to be installed (if required) by wireline or concentric tubing. The seal bores used were “staged” (i.e. seal bore size decreases with depth) to minimize wear on the seals during potential future installation. A combination of proven upper no-go and selective type locking profiles were used. This sliding sleeve system allowed future control of the completed zones in a given well by manipulating the individual sleeves with standard wireline methods or with a pump-open coil tubing deployed shifting tool. All sliding sleeves operated as planned during the completion program. The comprehensive contingency flowchart developed for troubleshooting the sandface completion (should pressure integrity not be achieved following an individual zone completion) was never required. For Marco Polo completions, the screen and blank utilized 5-1/2” 20ppf 13CRM-110 material (collapse rating of +11,000 psi, minimizing the potential of equipment failure during screen out of the frac pack). Two zones were not equipped with any blank pipe; minimum distance between perforated intervals was 56 feet. The screen used was of the wire wrapped type, using Alloy 825 0.008” gauge wire. Screen (0.090” x 0.140”) keystone wrap and rod (0.160”) wires were used to improve the erosion resistance of the screen and reduce plugging tendencies8. The OD of the screen was 6.10”; with 1-3/8” bladed centralizers designed for 1” minimum radial clearance between the screen OD to the casing wall. Water analysis from the exploration wells indicated that inorganic (mineral) scale formation was likely in these wells. Wire wrapped screen exhibit lower pressure drop across the screen in the production direction, reducing the probability of inorganic scale formation in the perforated blank tubing and screen perforations. Proppant sizing was determined after evaluation of particle size analysis performed on whole and sidewall core

6

samples of the various reservoirs. Most of the reservoirs completed had lobes of differing size distributions, as is common throughout the Gulf of Mexico. The 30-50 mesh gravel was determined to be able to provide sand control all of the intervals; standardization on one size prevented pumping of an incorrectly sized proppant. The screen was sized to retain the 30-50 mesh ceramic proppant. The isolation tubing was 3-1/2” 9.3# 13Cr85 material, with blast joints used across from the perforated intervals. All sliding sleeves and locking profiles were drifted and functionally tested in the horizontal position with the components that would have to pass through in the completed wellbore. All sliding sleeves (a total of 51 were installed in the individual frac pack assemblies) operated as designed (closed and held pressure or opened when required) during project execution. The frac pack service tool used was a proven weight down live annulus tool, with recent refinements to reduce the chance of service tool drag caused by proppant entrapment at the below frac port seal. Both 6” and 4-3/4” bore tools were used for the project. Significant modeling was preformed to evaluate the best way to manage workstring stretch and pressure when moving the tool to reverse position following the frac job, especially for the 6” bore jobs. Rig timesavings were achieved by pre-assembling as many components as possible on shore prior to shipment to the rig. Where required, the assemblies were pressure tested. To eliminate confusion on the rig with three different sets of tools (and back-ups), a color coding convention was adopted. A “stop light” analog was used, so the lower zone specific components were green, the middle zone were yellow and the upper zone specific tools were marked with red. The same type screen, blank and isolation tubing was used for all intervals which allowed for a sparing plan to be developed after the perforating zones were determined during the planning phase. The resulting plan used 40, 30, 20 and 10 foot joints of screen and blank, with combo joints (combination of screen and blank) configured to allow a target of 6 to 10 foot of screen above the top perforation. The plan provided that there always was backup of any given component, but minimized the amount of surplus material at the end of the project. Backup equipment on one job was generally installed as the primary equipment on the next well. Over the course of the project, no service tools were stuck and no tools were lost downhole. Frac Packing Operations Proven tip screen out (TSO) frac packing technology using conventional crosslinked borate fracturing fluids were successfully used on the Marco Polo project. The design objective for Marco Polo frac packs was to obtain a TSO followed by a +500 psi net pressure gain, and ending with a packed casing annulus. Frac packing for improving well productivity has been While arguably a mature documented since 19649. technology, optimizing the frac pack process in deepwater wells still requires diligent effort to optimize performance and to avoid operational pitfalls. Specifically, cold riser

SPE 95331

temperatures will result in increased gel efficiency10 and directly affects the ability to achieve a TSO. A continuous engineering effort was used to better understand the system and improve process performance. Laboratory work had been done prior to operations to quantify the effects of temperature as it relates to crosslinking and breaking the selected gel systems, and to investigate rock parameters. The Marco Polo formation had an estimated Young’s Modulus of 300,000 psi. During the frac treatments on the first well (A-5), retrievable pressure-temperature gauges were placed just below the mud line and above the gravel pack packer in the workstring, and in the washpipe to record temperature and pressure data. Permanent sensors were also installed in the treating vessel to define the temperature of the gelled fluids being pumped. This data was used to refine future job designs and better understand temperature issues with the system. Refer to Table 4 for Frac Pack Temperature Data. On subsequent wells, only washpipe gauges were used. Generalized Frac Pack Procedure 1. Tag sump packer, space out workstring, set gravel pack packer. 2. Release service tool, locate positions. 3. Pickle (if bottom zone) or reverse bottoms up (or until returns are clean); establish reverse rates and pressures. 4. Obtain circulation rates thru screen at 1 and 2 bpm. 5. R/U frac iron and test to 11,000 psi; set pop-off valve. 6. Spot acid (if HEC spotted) into workstring and minifrac fluid (after going overboard and until good crosslink fluid observed) at 10 bpm minimum rate. 7. Pump minifrac at directed rate, displace directly with the step rate test fluid. Get hard shutdown when displaced to bottom perforation, monitor decline. 8. Pump Step Rate Test as directed; last half of fluid to contain enzyme and organic acid breaker. Immediately pull service tool to reverse position and reverse out workstring. Change to long way and continue to circulate (keeping riser warm) until ready to spot frac job. 9. Spot Frac Job pad after going overboard and establishing good crosslink at 10 bpm minimum rate. 10. Pump frac pack as directed; monitor boat pressure at pop-off valve; reduce rate when within 500 psi of pop-off setting or per pre-determined slow down schedule. 11. After sandout, communicate pressures needed on drill pipe and annulus. Pull workstring as required to see pressure change on tubing. 12. Reverse out until proppant clears up and then one more bottoms up. 13. Slowly POOH with service tool until shifting tool is above the isolation assembly. Pressure test down annulus to 500 psi, monitor 10 minutes to insure all sleeves closed and were holding pressure. Acid was pumped ahead of the minifrac only when a HEC pill had been spotted during the perforating operations. This only occurred two times over the seventeen zones completed.

SPE 95331

Using a 6 inch OD service tool with a 3-1/2” workstring posed considerable challenges. Surface stretch varied in different wells due to slightly different directional plans. Stripping the workstring through the annular BOP added more variability (annular control pressure was minimized to minimize the additional drag of 35-40 klbs determined from pull tests). All interested parties were aware of maximum surface overpull at each job offset. All fracs were successfully reversed out with no stuck crossover tools over the 17 frac packs of the project. During the frac pack operation, all jobs were tagged with zone specific non-radioactive chemical tracers11 to provide a means to confirm which zones were flowing from a specific well during flowback. Water samples were taken during the flow back phase, and analyzed to determine the presence of the discrete water-soluble tracers to confirm that all pressure actuated sleeves had opened as planned. Timesavings were achieved for the frac pack operations during the rig up, reduced workstring pickling, and by establishing common processes during the mini frac and frac pack operations. Hose hangers were mounted on the rig substructure to allow the treating boat to maintain station at the platform for virtually all weather conditions, and not interfere with crane operations. Semi-permanently installed chicksan was located and secured with whip-checks and isolated from vibration damage by oak “cradles” from the hose hanger to the rig floor. The line was rinsed clean with fresh water after every job and some connections broken to allow the line to drain and dry completely. Worksting pickling was only performed on the first job in a specific well. Only a pipe dope solvent was pumped and captured on reverse out. Acid was not deemed to be required to clean the internally plastic coated workstring. Common practices were established for the frac pack operations to improve efficiency and provide continuity. A zone specific “cheat sheet” was generated prior to the frac boat arriving on location for every well so all involved parties understood the basic well data and job expectations. Engineering staff were present onsite for the initial and critical jobs, and were present in the service company remote data transmission room. The service company dedicated one pumping vessel to the project, so only two pumping crews were involved in all frac packs. In most cases, the pumping crew had the final frac design before the rig had reversed out the workstring following the minifrac and step rate test, saving considerable rig time. The total rig time required for sand control operations (including trouble time) for the project, i.e. perforating, packer plug retrieval for the upper one or two zones, and frac packing, was 75.1 days for 17 zones in the six wells. This averages out to 4.4 days/zone. Refer to Table 5 for Marco Polo Sand Control Installation Days. Refer to Table 6 for Marco Polo Frac Pack Summary. Production Tubing Installation Primary objectives for tubing installation was to not damage the control lines, not have any tubing leaks, install all components at their objective depths, and to be able to rotate

7

the tubing string and land the tubing hanger without damaging any components. All wells utilized 4-1/2” 13Cr85 12.75# production tubing with a proven two-step, low makeup torque thread. Range two length joints were used between the production seal assembly and the packoff tubing hanger (POTH) set below the mudline. The 4-1/2” tubing above the POTH was controlled length (all joints of the same length, +/-0.025’), and were internally coated with a phenolic compound which can reduce tubing friction and potentially reduce paraffin deposition The gas lift string tubing used above the pack off tubing hanger (POTH) is 1.9” L-80 2.9# with the same two-step thread, and is also virtually the same controlled length as the 4-1/2” tubing. The dual tubing strings were installed using only a single 4-1/2” elevator. The 1.9” tubing was clamped to the 4-1/2” tubing mid-joint using a non-metallic bolt fastened centralizer which kept the production tubing from contacting the riser casing wall. Short one and two foot pups were installed in the 1.9” string to keep the two strings at a convenient height while running in hole. All tubing and tubing accessories arrived at the rig in “as run” condition with respect to thread compound (no cleaning required). Accessories were preassembled with handling pups. Following the final frac pack and pressure testing of sliding sleeves in a given well, the well was displaced with corrosion inhibitor treated packer fluid. On the trip out of the hole, all drill pipe from 200’ below the mud line was laid down in order to provide room on the limited drill floor and to allow setting of the storm packer on drill pipe should a rig evacuation during tubing installation be required. Rig Preparations The rig preparations to run tubing included modifications to the bell nipple (upper section removed and replaced with funnel to obtain spider deck access), installation of the control line manipulator, changing one set of pipe rams to dual rams (and testing), and placement of material and equipment on the pipe rack. Only two control line spooling units were required, and were located on the piperack. A novel split drum held the upper (three component) and lower (two component) sections of Flatpack A (containing the encapsulated Fiber Optic cable, lower CIM control line and POTH control line), reducing equipment and personnel requirements. The other unit held the three component Flatpack B, which consists of SCSSV and upper CIM control lines. Refer to Figure 10, Flatpack Layout. Control lines were installed on the spider deck of the rig, which is 13’8” below the drill floor. Cameras, radio and intercom were used to prevent miscommunication between the driller and the installation crew. A hydraulically operated traveling sheave assembly placed the control lines on the tubing wall. This arrangement proved to be effective on this installation due to the limited space on the rig floor by separating the tubing make up and clamp installation operations.

8

Tubing Hanger Dummy Run The first operation was a dummy run with the tubing hanger. The hanger and running tool (right hand release) was made up to the landing string (without seals). The stack was drained to allow a visual confirmation that the hanger was landed. For Marco Polo, the fitting for the ½” chemical injection line acted as an installation aid because it aligned with the casing valve outlet. Paint was applied to show a horizontal line thru the casing valve when the hanger was in position. Once the hanger was landed, orientation marks were made on the landing string at the spider deck funnel and drill floor for both height and angular orientation. Orientation marks were also placed on the tubing hanger running tool before disassembly. The two joint landing string with running tool was stored in the derrick. Tubing Assembly to Packoff Tubing Hanger After the production seals were made up, an assembly of a downhole optical pressure/temperature gauge4 and chemical injection mandrel was made up and lowered to the spider deck. The assembly was then rotated to be aligned with the control line manipulator. The permanent downhole pressure gauge (PDHG) allowed downhole pressure monitoring during installation and throughout the well’s productive life. Two DTS fibers installed in the control line provided a wellbore temperature snapshot during transient and steady state production. Marco Polo is the first known application of this technology in all the initial completions of a dry tree (DVA) deepwater development. The fiber optic lines were connected in the field (at the PDHG and above and below the packoff tubing hanger) with plug in type connectors. All plug-in connectors were preinstalled and tested except for where the line connected to the bottom of the packoff tubing hanger assembly. After testing the PDHG, the lower chemical injection mandrel was connected to the other component in Flatpack A (refer to Figure 9), a 3/8” Alloy 825 control line, with a testable fitting. The chemical injection mandrels used for the project were one inch (1”) side pocket mandrels equipped with chemical injection valves with double checks and a shear disk (which allowed 1500 psi to applied and monitored during installation). The lower mandrel was designed to mitigate for paraffin or asphaltene early in life and inorganic scale (if needed) later in life. The two upper mandrels (one equipped with a ½” line and the other with a 3/8” line) were placed just above the surface controlled subsurface safety valve (SCSSV), and were be used primarily for hydrate prevention/mitigation. Cross coupling protectors of the stamped low carbon steel variety were designed and fabricated to provide protection for the control lines at every tubing connection. Special protectors were fabricated to protect the lines at gas lift mandrels, chemical injection mandrels and SCSSV. A set of protectors were also designed to protect a control line splice, should unforeseen damage occur or if the lines had to be cut so the well could be suspended due to an impending storm. These protectors were installed on the spider deck, after the tubing had been assembled and torqued on the drill floor. Safety and efficiency were improved as a result of having these two operations on separate locations. The driller could observe the

SPE 95331

operations on the spider deck via a video monitor, and communication was provided with hand held radios. Side pocket Gas Lift Mandrels (GLM’s) were installed as required in the tubing between the pack-off tubing hanger (POTH) and lower CIM. Because the aquifer strength in the various reservoirs was uncertain and productivity index (PI) is variable, mandrel spacing was modeled to accommodate both high PI, high FBHP early production and low PI, low FBHP late production. The resulting plan had mandrel spacing that was of a 500 to 550’ ft TVD spacing above the SCSSV (and below POTH) and of a 550-600’ TVD spacing below the SCSSV. The GLM’s utilized a 1-1/2” pocket to allow maximum gas lift injection rates (up to 6 MMCF/D at Marco Polo system pressures) from either pressure or orifice valves. Since downhole drag had to be managed to allow rotating the string to land the tubing hanger, the gas lift mandrels, SCSSV, upper chemical injection mandrels and packoff tubing hanger (POTH) were aligned using eight-foot pup joints of known angular makeup. After the last joint before a given component made up, the thread was gauged to determine the make up point. This point was compared to the make up point on the bottom of the component assembly. A criteria of +/- 45 degrees was used for the installation window of a component relative to the control line manipulator; therefore only pup joints of 90, 180 and 270 degrees were required for orientation. An additional downhole control line bundle was used to connect the SCSSV and upper chemical injection mandrels (1/4”, 3/8” and ½” lines in Flatpack B; refer to Figure 9). The tubing retrievable SCSSV was placed approximately 4200 ft below mud line, where the flowing and shut-in tubing temperature is higher than the critical hydrate formation point (~62 oF) and anticipated wax appearance temperature (WAT; 90 oF). A spring type valve was used, requiring only one ¼” Alloy 825 control line for operation. No elastomeric seals are used in the valve. The valve used is capable of having a wireline insert SCSSV installed in the future should the original tubing retrievable valve become inoperative. This feature also allowed the use of higher SCSSV hold open pressures during the well commissioning phase. Control line pressure was used to keep the SCSSV in the open position during the tubing installation process. After the remaining tubing and gas lift mandrels were installed, the POTH assembly was picked up. Packoff Tubing Hanger The dual bore packoff tubing hanger (POTH) allows the riser by production tubing annulus to be filled with an insulating gelled fluid. A 1.9” gas lift string provides a conduit for gas lift gas through the riser area, improving flow assurance by reducing heat loss from the production tubing by convection of high pressure gas. The POTH was placed approximately 150’ below mud line. Since the POTH is set via a ¼” control line after the tubing is landed, subsequent fluid displacements and effective surface tension were extensively modeled to insure that upper gravel pack packer seals do not move during production or

SPE 95331

shut-in cycles, and that allowable tubing stress is not exceeded. The packer installed has a differential rating of 5000 psi from above and 7500 psi from below. The packer incorporates basket type slips to maximize contact area with the casing, reducing packer to casing stresses and decreasing the chance for reduction in collapse resistance of the production casing. A debris ring above the slips increases retrieval reliability. Two release mechanisms are incorporated into the POTH design. An overdrift profile (with pup joint below) is installed above the POTH in the 4-1/2” tubing string. The pup joint is of predetermined length to allow a standard chemical cutter to positively locate in the overdrift profile and affect a cut in the target cut zone of the mandrel. In the 1.9” gas lift string side, a jar to release feature is included at the packer “end of tubing”. To facilitate field installation, splice subs were oriented and installed above and below the packer. The assembly then had short sections of the control lines and fiber optic cable installed through the pass thru ports on the packer and the bulkhead fittings are pressure tested. The control line sections are terminated into splice blocks in the splice sub and tested; the fiber optic cable connectors are installed and tested. This allowed for quicker connection offshore, reducing risk of control line damage and personnel requirements. Refer to Figure 9, POTH Schematic. Once the POTH assembly was oriented (if required) and made up, the assembly was lowered to the spider deck and a critical measurement made for placement of the lower POTH fiber optic connector. The packoff tubing hanger was then picked up into the derrick, allowing the lines to spool back up on the spooling units. The splice cabin was relocated as close as possible to the rig on the pipe rack and the lower flat pack containing the fiber optic gauge line cut. The installation of the fiber optic connector was a tedious and time consuming process due to significant quality assurance procedure. Significant improvement in time required was made from the initial to final well of the project. During this time the tong for the 1.9” gas lift string was rigged up and the floor prepared to run the dual string. Once fiber optic splicing was completed, the POTH was lowered to the spider deck, and the fiber optic connector attached to confirm the spacing. The other lines were then terminated; some adjustability existed as the splice blocks could be exchanged with longer blocks if the initial connection leaked and was irreparable. The assembly was then lowered and control lines terminated into the top splice block. The same three part line was used to the SCSSV and upper chemical injection lines, and the third flatpack section was used. This section was stored on the same drum as the lower section of Flatpack A, and was separated using a butterfly flange. This allowed the use of only two spooling units, significantly reducing space requirements on the pipe rack. The pre-installed fiber optic connector was attached and the system function tested. The other lines were attached as on the lower splice block. Internal pressure was reapplied to re-open the SCSSV and 1500 psi applied to the chemical injection valve lines. No pressure was applied to the POTH setting line.

9

The design of the POTH had the short string connection 2.5 ft lower than the 4-1/2” production string connection to prevent interference with the 4-1/2” single elevator used to run the string. One and two foot long pups were added as needed (as mentioned previously) to adjust the height of the 1.9” connection to account for stretch in the 4-1/2” tubing. Tubing centralizers for the riser area were manufactured out of an elastomeric material that exhibits excellent thermal insulation and no swelling due to gas permeation. Additional centralizers were added above and below the stress joint area (located just above the sub sea wellhead) to improve fatigue life of the tubing connections. The 1.9” string was attached to the 4-1/2” string by these centralizers. Therefore, the tubing was always installed using one elevator and spider, simplifying installation and eliminating change out of equipment during the operation. These centralizers also served to centralize the two strings in the riser section to reduce heat transfer due to tubing to casing contact and to reduce bending at the couplings in the subsea wellhead area. Dual Tubing Hanger Installation The Marco Polo project utilizes a 4-1/16” x 2-1/16” 10M dual bore type tree. The 11” tubing hanger was installed on 4-1/2” tubing and incorporates an adjustable mandrel (8” of adjustment) to facilitate the attachment of the 1.9” string. Six penetrations exist in the tubing hanger. The three ¼” (SCSSV, POTH, and gauge cable) lines and two 3/8” chemical injection lines are secured at the hanger but pass through to terminate in the valve bodies outside the tubing spool. The ½” chemical injection line terminates at the bottom of the tubing hanger in a pressure testable connection. A pre-installed and tested elbow on the top of the hanger connects the downhole line via a 3/8” jumper to the external valve body. Backpressure valve profiles for each string exist in the tubing hanger, and an additional profile nipple located directly below the hanger in the 4-1/2” allows a wireline retrievable backpressure valve to be installed via the tubing landing string or thru the tree should the primary back pressure valve profile become damaged. After the tubing was landed and a spaceout measurement was made, the tubing was spaced out for attachment of the tubing hanger assembly. A final 8-foot pup was allocated to orient the hanger with the gas lift string. These joints were manufactured in 30 degree increments to facilitate orientation. The 1.9” pups were installed and the hanger made up and orientation confirmed. The 1.9” side was then connected using an upper/lower mandrel assembly and locked in place with a hold down plate. The 1.9” landing was removed and back pressure valve installed. The landing string was then re-attached to the tubing hanger and the assembly lowered to the spider deck. Control lines were then cut (with the required excess) and the assembly picked back up to the drill floor to allow the ½” control line to be terminated into the bottom of the hanger with a testable fitting and the other lines to be passed through and packed off above and below the hanger. After pressure testing, the assembly was lowered so the landing string was landed in the spider, and the rotary was unlocked. At this point the seal assembly had not entered the packer bore and

10

the tubing hanger and tubing hanger running tool had not entered the bell nipple and could be monitored. The entire tubing assembly was then rotated to align for tubing hanger landing. This was consistently accomplished for all 6 wells by hand from the drill floor with right hand rotation. Four different orientations were required for the landing of the tubing hanger due to TLP design. At this point the BOP stack tensioners was adjusted to center the tubing hanger as much as possible. The spider was also removed to give more freedom of movement as the hanger traveled past the BOP stack, minimizing potential seal damage. The SCSSV line was then re-attached and the SCSSV opened, the stack drained, and the tubing hanger landed with visual confirmation via the casing valve. After testing the hanger void and backside, the running tool was retrieved and a backpressure valve installed in the 4-1/2” tubing. Well Commissioning After the tubing was installed and hanger landed, adjacent wells were shut-in (if producing) and the rig was skidded at least two slots. This allowed crane access to the well slot just completed. The control lines were then terminated in the tubing head outlet valves and the fiber optic fusion splice performed while BOP nipple up operations were underway on the next well to be completed. All remaining completion operations were not on the critical path, saving four to six rig days per well completion. The tree was installed by the platform crane. Methods were employed to assist in alignment and to mitigate TLP/crane motion. After the tree was tested, the back pressure valves were removed. The pre-installed flowlines and umbilical were then connected and tested. The SCSSV was then function tested and opened from the tree outlet. The downhole fiber optic gauges were also connected, tested and monitored. A three way manifold was then rigged up to the tubing, gas lift wing, and casing valve. The tree instrumentation lines, which had been pre-fitted to the individual tree and platforms, were then installed and tested with a separate crew. At this point the completion fluid in the inner riser by tubing annulus above the POTH was displaced to treated seawater down the casing valve, taking returns up the gas lift line. The circulation path was then changed and the riser annulus circulated with additional treated seawater to insure all traces of calcium bromide were removed from the well. This pumping was performed by a third pumping unit while the next completion was being displaced with treated sea water using the two main rig pumps. The 9.0 ppg gelled insulating fluid12, which was brought on board out of the critical path and stored in the reserve completion fluid tanks, was circulated in place in the same direction. The POTH was then control line set while monitoring the volume of fluid pumped and pressure tested (first from above and then from below). The pressure was then increased to shear a dump-kill valve installed in the GLM directly above the SCSSV. The completion fluid below the POTH and above the SCSSV was then displaced with a hydrate-proof 8.7 ppg fluid. This was a new composition13 designed to underbalance the well for flowback

SPE 95331

(approximately 1000 psi) and to maintain fail-safe operating conditions at the SCSSV. After the control tubing installation was complete, the chemical injection mandrels were commissioned by first shearing the disk in the downhole valve, and then purging the control lines as required to eliminate incompatibilities between the control line installation fluid and the fluid to be injected. At this point, the well is ready for production. Equipment to treat the water based flowback fluids had previously been semi-permanently installed on the lower cellar deck (tied into the water dump of the test separator and facility safety and electrical distribution systems). Surface tubing pressure was then applied (while monitoring the PDHG) to exceed the differential value of the pressure actuated sliding sleeve. The applied pressure was then bled down to open the sleeves in the intervals so equipped. The well was immediately flowed back, and the flowback fluid sampled at proscribed intervals for analysis of the zone specific chemical tracers added to the frac fluid. In all six Marco Polo wells, production was successfully established in this method, reducing risk and potential intervention cost by not requiring the use of wireline or coiled tubing intervention. Conclusions 1. Operational execution and well functionality will benefit when risk mitigation is considered throughout the completion design. 2. Completion design must address field implementation and rig limitations for efficiency and reliability. 3. Multiple stacked zones can successfully be completed economically and with minimum risk by using overbalanced perforating and sliding sleeve technology. 4. Commissioning activities not requiring a rig can successfully be performed offline, saving considerable time and expense. 5. Intervention-less opening of sliding sleeves successfully established production while lowering project risk and improving economics. Acknowledgements The authors want to thank Anadarko Petroleum Corporation for giving us permission to publish this paper. We also want to thank all the operating and service company personnel who have contributed to the comprehensive planning and execution of the successful deepwater development program. References 1.

2.

3.

K. Renfro and J. Burman, “Influence of Field Development and Flow Assurance Issues on Well Completion Design at Marco Polo Field”, OTC 16642, presented at the 2004 OTC held in Houston, TX, 3-6 May. P. Watson, E. Kolstad, R. Borstmayer, T. Pope, A. Reseigh, “An Innovative Approach to Development Drilling in Deepwater Gulf of Mexico”, SPE/IADC 79809, presented at the 2003 SPE/IADC Drilling Conference, Amsterdam, The Netherlands, 19-21 February. Robert D. Pourciau, “Case History: Internally Coated Completion Workstring Successes”, presented at the 2002 ATCE, San Antonio, TX, 29 September – 2 October.

SPE 95331

4.

5.

6 .

7.

8.

9. 10.

11.

12.

13.

M. Weaver, T. Kragas, J. Burman. D. Copeland, B. Phillips, R. Seagraves, “Installation and Application of Permanent Downhole Optical Pressure/Temperature Gauges and Distributed Temperature Sensing in Producing Deepwater Wells at Marco Polo”, SPE 95798, presented at the 2005 ATCE, Dallas, TX, 9-12 October. L.F. Neumann, C.A. Pedroso, L. Moreira, R.C. Bezerra de Melo, “Lessons Learned from a Hundred Frac Packs in the Campos Basin”, SPE 73722, presented at the 2002 SPE Intl Syposium and Exhibition for Formation Damage Control. Lafayette, LA, February 20-21. R. D. Pourciau, J.H. Fisk, F.J. Descant, R. B. Waltman, “Completion and Well Performance Results, Genesis Field, Deepwater Gulf of Mexico”, SPE 84415, presented at the 2003 SPE ATCE, Denver, Colorado, 5-8 October. J. W. Burman, B. Franklin, D. Turner, et al, “Design Considerations for Interventionless, Commingled Multizone Selective Sand Control Deepwater Completions” SPE 95598, presented at the 2005 ATCE, Dallas, TX, 9-12 October. H.C. Lau, and C.L Davis, “Laboratory Studies of Plugging and Clean-Up of Production Screens in Horizontal Wellbores”, SPE 38638, presented at 1997 SPE Annual Technical Conference, San Antonio , TX, 5-8 October. B. R. Jackson, “Frac Packing for Sand Control Pays Off for Mobil in California”, World Oil, June 1964, pp 126-128. P.S. Rovina, C.A. Pedroso, A.B. Coutinho, L.F. Neumann, “Triple Frac-Packing in a Ultra-deepwater Subsea Well in Roncador Field, Campos Basin – Maximizing the Production Rate”, SPE 63110, presented at the 2000 Annual Technical Conference, Dallas, TX, 1-4 October. R.A. Woodroof, M. Asadi, R.S. Leonard, M. Rainbolt, “Monitoring Fracturing Fluid Flowback and Optimizing Fracturing Fluid Cleanup in the Bossier Sand Using Chemical Frac Tracers”, SPE 84486, presented at the 2003 SPE ATCE, Denver Colorado, 5-8 October. P. Javora, X. Wang, J. Burman, K. Renfro, M. Weaver, R. Pearcy, Q. Qu, “Managing Deepwater Flow Assurance: Unique Riser Design Allows Dual Annuli Thermal Insulating Fluid Installation”, SPE 96123, presented at the 2005 ATCE, Dallas, TX, 9-12 October. M. Pakulski, Q. Qi, R.Pearcy, “Gulf of Mexico Deepwater Well Completion Fluid with Hydrate Inhibitors”, SPE 92971, presented at the 2005 SPE Symposium on Oilfield Chemistry, Houston, TX, February 2-4.

Figure 1 Marco Polo TLP

11 Figure 2 Marco Polo M-10 Sand Structure Map

Figure 3 Marco Polo Type Log

12

Figure 4 Marco Polo Generalized Wellbore Schematic

SPE 95331

SPE 95331

13

Figure 5 Marco Polo Completion Operations Timeline

Figure 6 Marco Polo Completions Operational Effiency

Weather

Planned Unplanned 139 days (85%)

24 days (15%)

14 days (9%)

Unavoidable

6 days (4%) Avoidable

4 days (2%)

14

SPE 95331

Figure 7 Marco Polo Mudline and Surface Wellhead Locations

o •

Figure 9 Flatpack Layout

Slot/Keel Location Mudline (Sub Surface) Wellhead Location

Figure 8 POTH Schematic

Table 1 Marco Polo Reservoir Fluid Properties Property GOR (SCF/STB) API Reservoir Temperature (deg. F) Initial Reservoir Pressure (psia) Bubble-Point Pressure (psia) CO2 Reservoir Fluid Mole %

M10 1209 29.7

M40 1156 33.5

M50 742 31.7

M60 745 31.4

115

119

121

122

7087

7368

7433

7477

5596

4188

2771

3154

0.06

0.21

0.20

0.24

Table 2 Marco Polo Initial Well Productivity Well A-3 A-4 A-5 A-6 A-7 A-8

Initial Rate 7,000 BOPD 3,500 BOPD 9,000 BOPD 11,500 BOPD 11,000 BOPD 12,000 BOPD

Drawdown 281 psi 100 psi 201 psi 251 psi 277 psi 249 psi

PI (bbl/d/psi) 24.9 35.0 44.8 45.8 39.7 48.1

Skin -2.1 -2.3 -2.7 0.1 -2.8 1.1

SPE 95331

15

Table 3 Marco Polo Perforating Data Summary

Well # A-5 A-6

A-4

A-3

A-8

A-7

Sand M-50 M-40 M-60 M-50 M-40 M-60 M-50 M-40 M-70 M-50 M-40 M-60 M-50 M-40 M-40 M-20 M-10

Mid Perf (MD) 12,354 12,215 12,993 12,765 12,530 12,470 12,357 12,230 12,192 11,738 11,630 11,935 11,788 11,641 12,540 12,234 11,960

Hole Angle @ Perfs 23 22 31 30 30 19 19 19 35 34 34 32 32 31 27 26 27

Gross Perfs 92 50 35 170 60 21 83 40 28 64 40 30 105 49 80 60 64

BHP (psi) 7,397 7,335 7,501 7,459 7,368 7,358 7,326 7,368 7,381 6,943 6,877 7,235 7,224 7,190 6,900 7,336 6,872

Temp (deg F) 117 115 121 117 115 121 116 113 118 113 112 120 116 111 123 112 113

OB* (psi) 578 523 508 364 368 430 483 450 280 425 465 347 267 237 1,064 477 700

* OB is the hydrostatic pressure before perforating minus the reservoir pressure Table 4 Marco Polo Frac Pack Temperature Data

Operation On Bottom Pickle Mini Frac SRT Frac

Boat 74 79 79 79 79

@ Mudline (4,344 ft) Begin End 43 43 45 51 51 73 67 71 63 79

@ XO tool (12, 146’ ft) Begin End 118 119 117 111 111 103 97 99 100 89

Table 5 Marco Polo Total Sand Control Installation Days

Days to Perf & Frac Number of Zones Average Days/Zone

A-5

A-6 A-4 A-3

A-8

A-7

Total

9.9

17.9 12.3 10.9 11.5

12.6

75.1

2

3

3

3

3

3

17

4.9

6.0

4.1

3.6

3.8

4.2

4.4

16

SPE 95331

Table 6 Marco Polo Frac Pack Summary Well # A-5 A-6

A-4

A-3

A-8

A-7

Sand M-50 M-40 M-60 M-50 M-40 M-60 M-50 M-40 M-70 M-50 M-40 M-60 M-50 M-40 M-40 M-20

Closure psi 8,545 8,441 9,069 9,100 8,752 8,400 8,518 8,384 8,161 7,886 8,091 NA 8,377 8,067 8,433 8,348

Fluid Efficiency 21% 15% 17% 14% 10% 46% 30% 20% 51% 14% 27% NA 15% 19% 35% 14%

%Pad 13% 31% 30% 37% 56% 14% 17% 27% 19% 38% 25% 34% 40% 27% 13% 24%

bpm 15 18 15 25 18 15 15 15 15 15 15 15 15 12 12 15

Net psi 428 996 552 221 302 461 328 134 294 465 602 286 214 938 146 0

lbs/ft(md) Behind Pipe 465 1,057 895 362 464 3,022 1,228 2,636 2,141 504 1,927 1,017 563 820 828 1,233