Optimization of shale gas reservoir evaluation and assessment of shale gas resources in the Oriente Basin in Ecuador

The petroleum geological features of hydrocarbon source rocks in the Oriente Basin in Ecuador are studied in detail to determine the potential of shale gas resources in the basin. The favorable shale gas layer in the vertical direction is optimized by combining logging identification and comprehensive geological analysis. The thickness in this layer is obtained by logging interpretation in the basin. The favorable shale gas accumulation area is selected by referring to thickness and depth data. Furthermore, the shale gas resource amount of the layer in the favorable area is calculated using the analogy method. Results show that among the five potential hydrocarbon source rocks, the lower Napo Formation is the most likely shale gas layer. The west and northwest zones, which are in the deep-sea slope and shelf sedimentary environments, respectively, are the favorable areas for shale gas accumulation. The favorable sedimentary environment formed thick black shale that is rich in organic matter. The black shale generated hydrocarbon, which migrated laterally to the eastern shallow water shelf to form numerous oil fields. The result of the shale gas resource in the two favorable areas,as calculated by the analogy method, is 55,500×10;m;. This finding shows the high exploration and development potential of shale gas in the basin.

Geochemistry of Heavy Oil in the T Block,Oriente Basin and its Origin Mechanism

Exploration and development experience show that there is obvious oil gravity difference between the southern part and northern part of the ＂M1＂reservoir in the Fanny oil field in the slope of the Oriente Basin, Ecuador. The American Petroleum Institute Gravity （API） values of oils in the northern part are higher than the one in the southern part of the Fanny oil field, with the values of 20° and 10.0°-13.0°, respectively. So the primary purpose of this study was to analyze the heavy oil characteristics of biodegradation and the oil-oil correlation according to the biomarker data and the δ^13C signature of oil samples from T block. The results of the hydrocarbon gas chromatography fingermark and the inversion attribute characteristics indicated that there are fluid compartments between the ＂M1＂ reservoir of Fanny south. Finally, the models of oil-gas accumulation under the control of multiple-activities of complicated fault systems, as well as the origin of heavy oil, are contended. The early stage oils from the western part of the basin were biodegraded heavily in varying degrees in the whole basin, and the later stage oils were derived from the southern part in a large scale and were mature and lighter. Generally, oil mixing is the primary control of net oil properties, such as API gravity in Oriente Basin. We therefore predicted that the API gravity variation of oil pools radically depends on the injection amount of the later stage oil. Because of the shale barrier in the ＂M1＂reservoir of Fanny south, the later stage hydrocarbon could not pass through and contribute to increase the oil API value.

Production data-based facies analysis for well placement in thinlayered reservoir

The exploitation of a thin-layered reservoir with thickness less than 5 m(16 ft)needs to rely upon sedimentary facies analysis,due to the low resolution of seismic data and sparse well data.However,the ambiguity of facies interpretation creates uncertainty in facies and reservoir mapping.The study aims to better define facies distribution,predict sand-body architecture,and consequently reduce risks in planning development wells,by integrating production data(dynamic)with conceptual geological models(static).An example is shown from the M1 Member of the Napo Formation in the B and G Oilfields(Block J),Oriente Basin,Ecuador.The M1 reservoir is a thin-layered sandstone reservoir below seismic resolution.Core and well-log facies interpretation indicates depositional facies of a tidedominated estuary.Production data during the water injection phase of field development can delineate the detailed geometry of the sand bodies.The injector-producer rate responses can determine the connectivity of sand bodies.Well performance during primary recovery can capture the scale of single reservoirs because the initial production rates and the cumulative oil production of individual wells are generally proportional to the size of sand bodies.A facies model was thereby generated.Two step-out wells were planned using this model and drilled successfully.The results demonstrate that the integration of dynamic and static data is critical to understanding reservoir facies distribution.