Thunder Horse Takes Reservoir Management to the Next Level
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 20396, ’Thunder Horse Takes Reservoir Management to the Next Level,’ by G.A. Arnold, S.R. Cavalero, SPE, P.J. Clifford, SPE, E.M. Goebel, D.A. Hutchinson, K.H. Leung, E.N. Paclibon, T.D. Weiss, and D.B. Grass, BP plc, prepared for the 2010 Offshore Technology Conference, Houston, 3-6 May. The paper has not been peer reviewed.

Thunder Horse is a subsea development of several large complex reservoirs in the deepwater Gulf of Mexico. Surveillance data and analysis were keys to rapid definition of the subsurface risks. Data from permanent pressure gauges were analyzed with advanced techniques. Reservoir-simulation models were calibrated to the full set of real-time data. Temperature and oil-composition data provided additional controls. Results demonstrated that faults in Thunder Horse, though sealing in some places, do not, in general, result in compartmentalization.   

Introduction

Thunder Horse was discovered in July 1999, with water depths of 5,800 to 6,500 ft. Subsea wells produce to a permanently moored semisubmersible production, drilling, and quarters facility rated at 250,000-STB/D production. The facility is equipped for more than 200,000 B/D of water injection.

Thunder Horse consists of two distinct geological structures—Thunder Horse South (THS) and Thunder Horse North (THN). Each structure contains several reservoirs. Production from THS started in June 2008, followed by THN in February 2009. Plateau production of approximately 250,000 STB/D has been maintained since THN came on production. By December 2009, nine wells were on production: four in THS and five in THN.

Thunder Horse produces 30°API sweet oil that is undersaturated with a gas/oil ratio (GOR) of approximately 1,000 scf/STB. The bubblepoint pressure is less than 5,500 psi, compared with the initial pressure that exceeded 13,000 psi, giving a high degree of undersaturation.

The two greatest subsurface risks before startup were compartmentalization and energy/aquifer strength, both of which link to water-injection needs. The full-length paper details how surveillance, data analysis, and reservoir simulation were used to characterize those risks and to drive field development.

Startup and Well Management

A document developed across the project, operations, and engineering staff specified goals for field startup including producible-well count, delivery date, operating efficiencies, plant uptime, and integrity maintenance. Clear milestones and system champions were identified. Having clear specific priorities was fundamental to managing simultaneous operations between subsea construction, drilling rigs, and production operations.

Production Readiness. The magnitude and complexity of the operation was understood early, with two fields, eight risers, and up to 33 subsea wells feeding the platform. Production-readiness efforts began 4 years before startup. Work fronts included the advanced collaborative environment, handling real-time data, multidiscipline understanding of common procedures, and minimizing production losses.