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Well placement decisions are routinely made on the basis of simulation models that are created before production operations begin. Real-time downhole pressure data and surface flow rate information can provide a significant set of calibration information early in the life of the reservoir. In this paper we describe a method for comparing a set of assumed reservoir parameters, especially the presence of a connected aquifer and its size, with a set of simulation models to assist with well placement decisions. In the South Timbalier 316 block, a delineation well penetrated the steeply dipping B4 reservoir near the oil/water contact. Based on a comparison of downhole pressure data, with data from simulation models, the operator concluded that a connected aquifer was present and estimated its size. This information was sufficient for the operator to know that the well would not be needed as a water injector and to justify a sidetrack from the downdip location to an updip location. When the updip sidetrack well was drilled, reservoir rock quality was below the minimum for a commercial completion. This brought into question the viability of any hydrocarbon storage capacity in the northern portion of the field. As soon as the updip sidetrack well was logged, a "what-if" reservoir model was run to simulate a no-hydrocarbon-reservoir scenario in the northern portion of the field. This reduction represented approximately 25% of the reservoir hydrocarbon pore volume. The model results clearly indicated that this was not a reasonable model and gave the operator confidence to sidetrack the well directly to the west, to a slightly downstructure position, whereby a successful completion was made. Without this "quick-response reservoir model" the well may have been sidetracked to the south, resulting in a less-than-optimal well location. Introduction The implementation of permanent downhole pressure gauges (PDGs) has provided a new source of highly valuable pressure transient data. In this paper we demonstrate a method to maximize the value of that information through the appropriate application of pressure transient analysis (PTA) and its incorporation into a full-field numerical simulation model. A practical application of this technology is demonstrated with an example from the South Timbalier 316 field. The South Timbalier 316 field is located in U.S. Federal waters offshore Louisiana in the Gulf of Mexico. The discovery well, A1, was drilled into the distal end of a deepwater turbidite fan. The turbidite mass transport phenomenon provided for the elimination of fines, leaving a blocky, unconsolidated sandstone as the reservoir. Between thicker sand-dominated depositional events a fine shale layer was deposited that separates the Upper B4 from the Lower B4 reservoir horizon. The original mini-basin appears to have been uplifted by deeper salt intrusion, leaving the present reservoir at a very steep 45°slope. The reservoir is highly overpressured, exhibiting a pressure gradient of 0.7 psi/ft. Real-Time Data Transmission During the completion design process, the operator decided to introduce one PDG in each of the final wells (Fig. 1). A high-resolution quartz gauge was positioned on the exterior of the tubing string and exposed to wellbore pressure by a port; then it was connected to surface by shielded wiring, which provides a continuous readout of gauge pressure once every second. At the surface, these data are temporarily stored on a computer, the Acquisition Surface Unit (ASU) (which connects the input data streams from all the various surface and downhole sources), and are transmitted via satellite to shore at 15-sec intervals. Once on shore, the data are verified at the Data Management Center. On occasion, due to weather or other events, the data stream is interrupted. The data management engineers can then retrieve the missing data from the ASU and repair the interrupted interval. The data are routinely archived and backed up to multiple locations for data security.

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