Optimization Strategies Proposed for Improving Well Performance and Pressure Transient Analysis in Bottom Water Reservoirs

In the upstream petroleum sector, water coning is an undesirable phenomenon that has posed serious challenges to reservoir engineers. Several studies have been carried out to investigate diverse approaches that can mitigate the water-coning problem in order to maximize oil recovery and lower the operating cost that is associated with the problem of handling a large volume of water. So far, no single approach has been able to adequately address this daunting problem. Thus, excessive water production arising from water coning has been a long-standing issue for the oil and gas industry. The source of coning during production may be either the upward rising of the formation water or the injected water used for reservoir pressure maintenance purposes (referred to as water coning), as well as the downward dipping of the gas cap (gas coning). A physical (laboratory scaled) and field case model was developed to investigate the optimization techniques proposed in this work. Several simulation runs were performed to observe the following: water-cut, cumulative oil production, water-oil ratio, production rate and percent oil recovery factor before and after water breakthrough.;A field-scale model is used to demonstrate the potential of the approach presented in this study. A producing asset located in the Boquer6n block within the Upper Magdalena Basin in Colombia was used as the site for a field-scale simulation. The results of this simulation enabled the assessment of the potential benefits of the optimization strategies presented in this study. Primarily, they can be utilized to economically mitigate water coning in a bottom-water reservoir. Natural flow barriers generally affect reservoir transport properties significantly and may act as local no-flow barriers within sand units or may be used to subdivide fundamental sand units into separate hydrodynamic units. Therefore, quantifying the potential benefits of such naturally occurring or induced flow barriers on well performance is warranted.;The design and construction of the 3D physical model was achieved using a CMG(TM) 2007 simulator to obtain reliable parameters upon which future experimental work could be anchored. The effect of an artificial flow barrier on horizontal well performance in bottom-water reservoirs was extensively investigated and analyzed under different operating conditions, and its potential impact on incremental oil recovery was quantified. It is, therefore, imperative to put in place operating strategies that could help economically combat the water-coning phenomenon and prevent unprecedented increases in water production that can potentially shorten the lifespan of producing wells. The optimization technique proposed and presented in this thesis utilizes horizontal well technology and the positive influence of the artificial flow barrier, which can either be induced mechanically or chemically in the reservoir. In theory, oil recovery is expected to improve significantly when this approach is implemented in the field, provided the intrinsic assumptions in this study hold. In addition, a numerical model was developed utilizing the fundamental fluid flow diffusivity equations for radial flow systems (reservoir-aquifer). The resulting numerical model was adapted to the traditional well testing method to study and be able to interpret the pressure transient behaviour of the vertical movement of bottom water. It is worth noting that many sandstone or carbonate reservoirs occurring in stratified sequences of channel sand-cuts through previously deposited marine sediments in vertical sand-shale sequences generally exhibit very low permeability and are often referred to as naturally occurring flow barriers.