Impact of Exceeding Predicted Performance in Kepler Field, Deepwater Gulf of Mexico - A Multi-Discipline Approach to Understanding a Turbidite Reservoir
Authors: Schott David W. , Belvedere Paul G. , Basset Nick 
Published: February 2016

Abstract
Kepler Field is located in Mississippi Canyon Block 383 in 5400' water depth, approximately 140 miles southeast of New Orleans, Louisiana, USA (Figure 1). Placed on production in April 2004, the main reservoir, the K1 Sand, was developed with two high rate horizontal wells ramped up to full rate over a period of three months (Figure 2). Due to low impedence contrast between wet sands and shales, the aquifer was not identified initially. Low primary recovery was expected. Space was allocated on the Na Kika semi-submersible platform for possible waterflood facilities. However, field performance has exceeded initial predictions. A multi-discipline integration has improved our reservoir description resulting in an expected improved primary recovery, increased reserves and a decision that waterflood is not necessary. The field has greater reservoir energy due to higher connectivity with the aquifer and higher formation compressibility.
Acoustic properties of the Late Miocene reservoir rock in the Kepler Field indicate that oil-bearing reservoir sandstone will have relatively strong negative impedance compared to surrounding shales, and water-saturated sandstone will be nearly transparent (low impedance). Therefore, the pre-production reservoir model included minimal aquifer support initially. Early production showed a rapid reservoir pressure drop suggesting the initial interpretation was correct. Since then, significant pressure support has been observed. History matching of 3 years of dynamic production data and 2 shut-in episodes due to hurricane activity indicates that greater reservoir energy exists.
Interpretation of new seismic data indicates the presence of a linear-shaped aquifer. Adding the aquifer geometry and a variable rock drive to the reservoir model produces an acceptable history match for future predictions.
Lessons learned: The first 6 months performance was not indicative of the long term performance due to aquifer shape, size, and variable rock compressibility,Dynamic models integrating all disciplines are critical to explaining past performance,Taking advantage of the Ivan and Katrina and Rita hurricane shut-ins resulted in long buildups of 30 days or more that were useful in indicating that aquifer support existed

Introduction and Pre-Production View
Kepler is the largest producing field in terms of rate and reserves in the BP/Shell Na Kika venture; both companies have approximately 50% of the Na Kika asset. Shell was the operator during the design, build and drilling phases of the project. BP took over operation at first oil in November 2003. Kepler has been on production three years, greatly exceeding initial predictions. The hydrocarbon accumulation exhibited favorable seismic response in what was thought to be the hydrocarbon area and as mentioned, the seismic image of the aquifer is nearly indistinguishable from the surrounding shales.
Analysis of core and log data indicated outstanding rock properties. These include net to gross thickness ratio greater than 95 percent, porosity of 32 percent, permeabilities of 2 to 3 darcies, net thickness of 50 feet, and grain sizes of 150 to 250 micron (pore throats approximately 40 microns).
Initial reservoir pressure was 7,200 psi with bubble point pressure near 6,700 psi and a reservoir temperature of 138 degrees F. API oil gravity is 29 degrees with a GOR of 1200 (Rs) and a viscosity of 1.1 cp. Total depth is about -12,000 feet TVDss, with water depth of 5,400 feet.
A pre-production risk assessment of compartmentalization incorporating MDT, geochemistry, PVT, and seismic data indicated low evidence of compartmentalization.
In summary, the project at sanction was a 2,200 acre bright spot with good rock drive and a small aquifer approximately 1.5 times larger than the hydrocarbons initially in place (HCIIP). The reservoir models indicated relatively lower recovery factors and high initial oil rates that would drop quickly with high gas rates. The view of the most likely case HCIIP has changed little since sanction, however, the ranges have narrowed and our view of recovery has resulted in increased reserves for the field.