Marco Polo Tension Leg Platform: Deepwater Completion Performance
- John W. Burman (Exploitation Technologies LLC) | Kevin Renfro (Anadarko Petroleum Corp.) | Mark A. Conrad (Anadarko Petroleum Corp.)
- Document ID
- Society of Petroleum Engineers
- SPE Drilling & Completion
- Publication Date
- September 2007
- Document Type
- Journal Paper
- 258 - 270
- 2007. Society of Petroleum Engineers
- 4.2.3 Materials and Corrosion, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 2.4.6 Frac and Pack, 3.4.1 Inhibition and Remediation of Hydrates, Scale, Paraffin / Wax and Asphaltene, 2.4.3 Sand/Solids Control, 1.6.9 Coring, Fishing, 1.6 Drilling Operations, 2.2.2 Perforating, 2.2.3 Fluid Loss Control, 5.2.1 Phase Behavior and PVT Measurements, 3.1.6 Gas Lift, 4.1.2 Separation and Treating, 4.5 Offshore Facilities and Subsea Systems, 2.7.1 Completion Fluids, 2.1.7 Deepwater Completions Design, 4.3.3 Aspaltenes, 1.3.1 Surface Wellheads, 4.1.5 Processing Equipment, 1.3.2 Subsea Wellheads, 3 Production and Well Operations, 2 Well completion, 1.7 Pressure Management, 4.2.4 Risers, 5.1.2 Faults and Fracture Characterisation, 4.2 Pipelines, Flowlines and Risers, 1.10 Drilling Equipment, 5.2 Reservoir Fluid Dynamics, 4.3.4 Scale, 2.5.2 Fracturing Materials (Fluids, Proppant), 5.6.11 Reservoir monitoring with permanent sensors, 1.8 Formation Damage, 4.3 Flow Assurance, 5.6.4 Drillstem/Well Testing, 5.1.1 Exploration, Development, Structural Geology, 1.7.5 Well Control, 5.5.2 Core Analysis, 4.5.7 Controls and Umbilicals, 2.4.5 Gravel pack design & evaluation, 4.3.1 Hydrates, 1.6.1 Drilling Operation Management, 5.6.5 Tracers
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Novel well completion techniques and exceptional field execution (per Dodson Completion Performance Database) allowed the six well completions on the Anadarko operated Marco Polo Deepwater Tension Leg Platform (TLP) project in Green Canyon (GC) block 608 to be accomplished significantly ahead of schedule. All six wells (17 frac packs) were placed on production in approximately 168 days (including 14 days lost because of storms) after riser tieback 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 17 zones in six deepwater dry-tree wells with a 1,000-hp rig were met, and will highlight a number of concepts and "technical firsts?? that can be applied to other deepwater-development projects.
Anadarko's Marco Polo deepwater-development project is located in GC block 608 in the Gulf of Mexico, approximately 175 miles south of New Orleans, in a 4,300-ft water-depth(Renfro and Burman 2004).
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 (Fig. 1). The TLP hull and deck were installed in January 2004, designed to accommodate a 1,000-hp completion rig to run riser tiebacks and perform completions. A significant issue for rig operations is adherence to United States Coast Guard rules. Only 88 persons are allowed on board the platform at a time.
Geology. The GC Block 608 field is located in the southern portion of the Marco Polo salt withdrawal minibasin. The depositional model for the field is restricted basin floor amalgamated sheet fan sand. Moderate to strong aquifer support was expected, although the potential presence of internal baffles and barriers introduced uncertainty to the extent of the aquifer support.
The trap geometry was created by salt withdrawal and extensional faulting because of 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 to southwest to east to northeast trending faults that form the graben. The updip-trap component to the west is salt/sand pinchout. The graben is further subdivided into separate compartments by additional faulting (Fig. 2).
Two main fault compartments make up the Marco Polo field. Another graben fault (downthrown to the northwest and trending in the same direction as the bounding faults) subdivides the graben into 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 (toward the 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 11,000 to 13,500 ft true vertical depth (TVD) (Fig. 3).
A complete openhole-logging suite was obtained on all discovery and development wells. Continuous whole core was obtained through both the M40 and M50 intervals in the GC 608 number 1 ST number 1 wellbore.
Reservoir. Initial reservoir pressures range from 6,700 to 7,600 psi. Reservoir temperatures range from 115to 122°F. Ambient mudline temperature is 38°F at 4,300 ft water depth. Reservoir fluids are undersaturated black oils, with API gravities ranging from 30 to 34° and gas oil ratio (GOR) ranging from 700 to 1,000 scf/bbl. During the exploratory and development drilling phases, reservoir pressures were measured on nearly all productive intervals in all wells, and reservoir fluid samples were collected in the main field pay zones and analyzed (Table 1).
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 and with a separate gas lift string terminated in a submudline or packoff-tubing hanger) were chosen as the upper completion design (Renfro and Burman 2004).
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 technology for downhole-pressure sensing and distributed temperature along the tubing string assisted in well surveillance and hydrate prevention (Fig. 4).
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