TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe Na Kika project, located in the deepwater Gulf of Mexico, is a unique development which ties-back six small to mediumsized oil and gas fields to the world's second deepest permanently moored production facility. Production from 12 subsea wells, in water depths ranging from 5800 to 7000 feet is routed to the production host through three flowline loops and one separate flowline. The project has been an economic and technological success. The application of intelligent well technology has enabled co-owners, Shell and BP, to successfully develop Na Kika with a minimum number of wells, and continues to help provide world-class reservoir surveillance data and ensure high standards of reservoir management.The fields are in a complex deepwater turbidite environment. Many of the reservoirs are highly faulted and compartmentalized due to salt movement, and several extend beneath salt structures and are difficult to image. Permanent downhole pressure and temperature sensors have been installed in all Na Kika wells. Additionally, four wells have been completed with interval control valves (ICVs) to enable 11 separate stacked reservoirs in two complex fields to be concurrently depleted.Intelligent well technology has provided dynamic performance data at the reservoir level that has been critical to improving reservoir characterization, reducing forecast uncertainty and enabled the operator to optimize production offtake. Downhole sensors provide well performance information such as permeability, skin and productivity index, on a real-time basis. Bottomhole pressure buildup (PBU) data are available on most well closures and have helped characterize reservoir barriers, zones of changing fluid mobility and levels of aquifer support. ICVs have enabled well testing at the reservoir level in multi-zone wells and have improved production allocation. This paper demonstrates how these surveillance data have been used to improve reservoir management and decision making.

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The Na Kika project, located in the deepwater Gulf of Mexico, is a unique development which ties-back six small to medium-sized oil and gas fields to the world's second deepest permanently moored production facility. Production from 12 subsea wells, in water depths ranging from 5800 to 7000 feet is routed to the production host through three flowline loops and one separate flowline. The project has been an economic and technological success. The application of intelligent well technology has enabled co-owners, Shell and BP, to successfully develop Na Kika with a minimum number of wells, and continues to help provide world-class reservoir surveillance data and ensure high standards of reservoir management. The fields are in a complex deepwater turbidite environment. Many of the reservoirs are highly faulted and compartmentalized due to salt movement, and several extend beneath salt structures and are difficult to image. Permanent downhole pressure and temperature sensors have been installed in all Na Kika wells. Additionally, four wells have been completed with interval control valves (ICVs) to enable 11 separate stacked reservoirs in two complex fields to be concurrently depleted. Intelligent well technology has provided dynamic performance data at the reservoir level that has been critical to improving reservoir characterization, reducing forecast uncertainty and enabled the operator to optimize production offtake. Downhole sensors provide well performance information such as permeability, skin and productivity index, on a real-time basis. Bottomhole pressure buildup (PBU) data are available on most well closures and have helped characterize reservoir barriers, zones of changing fluid mobility and levels of aquifer support. ICVs have enabled well testing at the reservoir level in multi-zone wells and have improved production allocation. This paper demonstrates how these surveillance data have been used to improve reservoir management and decision making. Introduction The Na Kika development is located in the Mississippi Canyon (MC) area in the deepwater Gulf of Mexico, USA, approximately 140 miles southeast of New Orleans and 60 miles offshore (Fig. 1). The Na Kika project consists of a semi-submersible production system connected via flow lines and umbilicals to six remote fields (Fig. 2). The non-drilling platform is located in MC block 474. Fig. 1 Na Kika location map. Reservoir sands in Na Kika typically have good to excellent rock quality, with porosity generally averaging 30% or more and permeability ranging between 100 to 1000 md. Gross thickness of the individual reservoirs ranges from 25 to 300 ft. Net to gross ratios are high (0.9) in the sheet-like deposits, low (0.2–0.4) in the thin-bedded levee; and ranges from 0.4 to 0.6 in the hybrid channel-levee deposits. Ariel and Fourier fields feature multiple stacked reservoirs which required multiple-completion wells to make Na Kika an economic project. Differential pressure, crossflow, or early water breakthrough were the main risks identified with producing multiple-completion wells that might lead to costly well interventions (Glandt 2005).

Noble Energy, Inc. successfully drilled a deepwater exploration Middle Miocene well in November 2012 and discovered the Big Bend Field, located in the Gulf of Mexico Mississippi Canyon Block 698. As the production liner was being run in the MC 698 No. 1 discovery well, tight hole conditions were encountered near total depth. While pumping the primary cement job, lost returns were observed. Prior to the drilling rig leaving location, a cement bond log was run to evaluate the primary cement job. There was no evidence of cement bond across the main oil-bearing zone or directly above it. This was a concern since there are water sands above the main oil-bearing zone which could compromise future production with behind pipe communication issues, in addition to potentially complicating the completion. Plans were made to pump squeeze cement to remediate the primary cement job. When the rig returned to complete the well, a second cement bond log was run February 2014 and compared to the original cement bond log. The second cement bond log showed a zone of sufficient bonding above the main oil-bearing zone, where no bonding was evident on the previous bond log. There was still no evidence of cement across the main oil-bearing sand. Even though preparations were made to remedial squeeze the primary cement job, the decision was made to not engage in remedial cement operations and to continue with the completion. This paper compares the two cement bond logs and discusses the operational considerations leading to the successful completion of the well and producing a prolific oil well safely with no water production.