1 T-15 AVA Stochastic Inversion of Pre-Stack Seismic Data and Well Logs for 3D Reservoir Modeling A. CONTRERAS 1 , C. TORRES-VERDIN 1 , K. KVIEN 2 , T. FASNACHT 3 , and W. CHESTERS 2 1 The University of Texas at Austin, Department of Petroleum and Geosystems Engineering, 1 University Station C0300, Austin, Texas 78712, USA 2 Fugro-Jason Rotterdam 3 Anadarko Petroleum Corporation Abstract This paper describes the application of a novel AVA stochastic inversion algorithm to quantitatively integrate pre-stack seismic data and well logs. The stochastic inversion algorithm is used to characterize flow units of a deep-water Miocene reservoir located in the central Gulf of Mexico. A detailed fluid/lithology sensitivity analysis is conducted to assess the nature of AVA effects in the study area. Conventional analysis indicates that the shale/sand interface represented by the top of the hydrocarbon-bearing turbidite deposits generate typical Class III AVA responses. On the other hand, layer-dependent Biot-Gassmann analysis shows significant sensitivity of the P-wave velocity and density to fluid substitution. Accordingly, AVA stochastic inversion, which combines the advantages of AVA analysis with those of geostatistical inversion, provides quantitative information about the lateral continuity of the turbidite reservoirs based on the interpretation of inverted acoustic properties (P-velocity, S-velocity, and density), and lithotype (sand-shale) distributions. The quantitative use of rock/fluid information through AVA seismic data, coupled with the implementation of co-simulation via lithotype-dependent multidimensional joint probability distributions of acoustic/petrophysical properties, provides accurate 3D models of petrophysical properties such as porosity, permeability, and water saturation. Moreover, by incorporating lithology into the inversion and fully integrating pre-stack seismic and well log data, the vertical resolution of stochastically inverted 3D reservoir models is considerably higher than that of deterministically inverted reservoir models, thereby significantly reducing development risk. Introduction 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. Hydrocarbon production originates from reservoirs consisting of Tertiary deepwater sand deposits. This paper considers a small portion of the Marco Polo Field where hydrocarbon-bearing sand units pertain to the “M” series and are buried at depths between 11500 and 12500 ft. The overall “M” series consists of sandy turbidite reservoir deposits interbedded and separated by muddy debris flows. These reservoir intervals are interpreted as stacked, progradational lobes within an overall fan complex. The massive and planar stratified sands exhibit excellent interparticle porosity. Rock-core measurements indicate excellent intrinsic properties: 30%+ porosity, and 100-4000 millidarcies of nominal permeability. We used 3D pre-stack time migrated seismic amplitude data to quantify the vertical and lateral extent of the main turbidite reservoirs. AVA fluid/lithology sensitivity was conducted as a preamble of AVA simultaneous stochastic inversion to simulate elastic and petrophysical properties in the inter-well region of the reservoir. EAGE 67 th Conference & Exhibition — Madrid, Spain, 13 - 16 June 2005