Third EAGE Online Workshop on Unconventional Resources

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This research is focused on developing a methodology for estimating well production forecasting that supports conceptual field development plans in organic-rich mudstone reservoirs encompassing typical exploitation stages in these kind of reservoirs: exploratory, appraisal, commercial demonstration, and manufacturing. The forecast simultaneously involves produce fluids (oil, water and gas) from both flow-back and decline periods in multistage hydraulic fracture (MSHF) horizontal wells. This methodology is applied in new exploration areas where vertical wells are already drilled.

Estimated Ultimate Recovery (EUR) per horizontal well is estimated probabilistically combining volumetric and stochastic methods taken into account uncertainties associated with each petrophysical, fluid, and recovery factor (RF) properties. Arp´s modified Decline Curve Analysis (DCA) is applied based on typical behaviors observed from USA unconventional plays to have ranges for each DCA variables, especially initial decline (D_i) and b-factor. Thus, ranges for flow-back time, initial oil rate (Q_oi,), water oil ratio, and gas oil ratio are tuned to match the probabilistic EUR. Then, aggregation curve methods are used to obtained EUR probabilistic distribution as a function of numbers of wells.

This research is focused on analyzing the underground water resource, from shallow aquifers to deep ones in Colombia’s richest water zone. In this geographical area, important surface and underground water resources converge, as well as important hydrocarbon reserves in conventional fields, and unconventional resources. The sustainable development of hydrocarbons requires solving different questions, among the most important of which are knowing which water resource will be used for its development, or where the disposal of the effluents will take place. Within the scope of this study, these responses were included.

The area implementation is the most important hydrocarbon basin in Colombia, where more than 20 Billion barrels of oil to exploit converge. In order to have complete information on the water resource, the fundamental tools for its recognition were the generation of a hydrogeological model, with the statigraphic characterization to be able to count on the extension, composition and behavior of water units that can be contributors of this resource or storage.

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Although hydraulic fracturing of horizontal wells has already given promising results in enhancing recovery from unconventional reservoirs, drilling too many wells does not necessarily contribute to economic development. Permeability of naturally fractured porous media and the dimensions of contributing fractures are among the most important parameters in well spacing optimization. Here, we use a computationally efficient technique and examine conditions that improve the economic viability of shale gas development in a case study in the Marcellus shale. We focus on the extent to which adding more wells to a section provides a competitive advantage; maximizing hydrocarbon recovery factor and economic returns and minimizing cost. In particular, insights gained from integrating microseismic and Rate Transient Analysis (RTA) are used to refine fracture dimensions. The Net Present Value (NPV) of cash flows and the Internal Rate of Return (IRR) are then calculated based on 10-year production forecasts made by a history-matched physics-based analytical model and for a wide range of well spacings from 440 to 1760 ft. The end result is an optimum well spacing acquired by coupling the technological and economic performance of stimulation, while honouring reservoir properties, production potential, and microseismic findings.