The technique of using a "live annulus" for data collection analysis during frac pack sand control completions has evolved quite extensively over the past few years. Field case studies have revealed several anomalies in this data collection and analysis. The following discussion covers more than 100 wells completed in the Gulf of Mexico using mini frac data analysis on both the workstring and "live annulus" data and their relationship to the bottomhole gauge data. The ability to incorporate this "live annulus" data has been facilitated by downhole tool development. The use of "live annulus" data has been viewed by many as being the single most important factor in the successful interpretation of pressure analysis during frac pack operations. Certainly, the elimination of friction in trying to interpret real time data enhanced the ability to make "on-the-fly" decisions. Having a "live annulus" also may help in overcoming some of the water hammer problems in rapid closure situations. However, caution must be used in relying on "live annulus" data. A close look at this summary of data completed in the Gulf of Mexico highlights the need for this caution and questions the degree of it s use. Introduction In the last decade, the evolution of frac packs in high permeability environments have been influenced by lessons learned from data analysis of live surface data and enhanced by bottomhole gauge data. Numerous techniques for analyzing data and designing treatments such as those by Nolte1 and Smith2 have been put into practice for success in frac pack sand control completions. "Live annulus" data analysis has greatly influenced the decision making process for frac pack sand control completions in the Gulf of Mexico. One aspect of "live annulus" data is that during pumping operations, the friction factor for fluids being pumped down a workstring is left out and a more representative profile of bottomhole pressure response is seen less the hydrostatic pressure from the static fluid in the annulus. This is possible from the developments of downhole frac pack packers in the industry that enable the annulus and workstring environments to be in communication with each other simultaneously. As seen in Figure 1, while pumping a Step-Rate-Test, the annulus data is much easier to use for the pressure analysis than the pressure data from the workstring. This is because the dynamically changing friction pressure effects of the fluids in the workstring would be hard to model. Again, the annulus data is simply the bottomhole pressure response less some hydrostatic pressure and as seen in Figure 2, closely follows the recorded bottomhole gauge data. There are instances where data analyzed during mini frac analysis will be performed with "live annulus" data in order to eliminate the early time water hammer effect, that is present with workstring data, hindering the analysis effort in determining closure pressure. Figure 3 is an example of the water hammer effect on workstring data and how it relates to the annulus and bottomhole gauge data. In some situations, closure can happen during this time period due to high leakoff and interpretation of the workstring data can be very difficult. However, caution must be used in deciding that annulus data interpretation will be used under these circumstances. The water hammer effect sometimes can also be seen as illustrated in Figure 4 with "live annulus" data. Figure 5 is an example of how specific tool designs dictate that the annulus data will closely follow the bottomhole gauge data while pumping and when pumping is stopped, the annulus data does not continue to follow the same profile as the bottomhole gauge data. This happens because the specific tool design does not allow for a full flow of pressure in the reverse direction, thus creating a "check valve" or choke affect. Figure 6 is an example of a case where the "live annulus" pressure falloff data did not match that seen by the workstring data or the bottomhole gauge data. Herein lies the dilemma of which data do you use at the time of treatment execution and which is most accurate or meaningful.

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 mini-basin.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.

Summary 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. Background 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).

As the semiconductor device technology is moving toward increasingly smaller nodes, it is becoming more challenging to keep the wafers free from contamination of even smaller particles. Wet cleaning process takes a major role in keeping the wafers clean, especially in post-RIE cleans. However, as every other process, wet cleaning also contributes some defects as adders which can potentially cause significant yield killer defects. A cluster of defects, classified as incomplete etch, was observed at the center of the wafer with a wet clean recipe (CIP1) since the adders from this recipe were not allowing the etch process and rendering incomplete etch defects. In this work, we optimized this CIP1 recipe to eliminate defects with the bull’s eye signature at the wafer center and widened the process window of this type of wet cleaning process. The new recipe (CIP2) showed 100% success rate while CIP1 recipe had an occurrence of 35% failure for the bull’s eye signature on the similar quality and quantity of wafers.

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