In developing heavy oil from thin bottom water reservoirs, horizontal wells are mostly used in Bohai Bay, China. To maximize oil production and avoid early water coning/cresting, horizontal wells are usually placed near the top of pay sands and wells are initially produced with small pressure drawdown. However, the production responses from different wells display significant variations even though they are operated under similar conditions. Some wells show premature water coning and rapid water cut rising although high quality sands are targeted, while others show much delayed water breakthrough and slower water cut increases.
A series of reservoir simulations have been conducted to investigate the observed differences. The simulation results reveal that the existence of thin low permeable flow barriers with limited lateral extension/continuity between the wellbore and water/oil contact plays the most crucial role impacting the water coning characteristics. Wells with such flow barriers display later water breakthrough with steady increase of water cut after breakthrough, while wells without such barriers show quick water coning with water cut reaching more than 90% rapidly. The existence of low permeability barriers between the water/oil contact and horizontal wells could slow down water coning and result in much favorable production performance. This phenomenon is then verified by simulations and actual field data from QHD32–6 field. The accurate predictions of production performance rely on the knowledge of physical distribution of flow barriers relative to the wellbore location. In practice, lateral thin flow barriers are usually at sub-seismic scales, and thus hard to identify for a green field. However, for infill drilling in mature fields with many vertical wells drilled, it is possible to predict/correlate the spatial distribution of such flow barriers from the logs of existing wells. Based on such analysis, we can optimize the locations of horizontal infill wells to make full use of the flow barriers for improving production.
A number of horizontal infill wells were optimized and drilled in QHD32–6 field, Bohai Bay, China after identifying flow barriers from the nearby vertical wells. These wells display good production performance having significant higher oil production with delayed water breakthrough and slower increase of water cut.
Introduction
The use of horizontal wells to enhance oil production from water drive reservoirs had been widely appreciated around the world 1–8. For thin bottom water reservoirs, the use of conventional vertical wells creates severe coning problems in most cases. This is because the actual rate of production usually substantially exceeds the critical rate defined as a rate above which the flat surface of water/oil contact starts to deform 9–13. Wells producing at critical water-free rates are usually unprofitable in practice. Horizontal wells are considered as a better alternative than conventional vertical wells to develop such reservoirs with better economics, improved oil recovery and higher development efficiency. Long horizontal wellbores would be able to contact large reservoir area. Therefore, for a given rate, horizontal well requires a lower drawdown, resulting in a less degree of coning/cresting.
After large-scale and long-term waterflooding, reservoir physical properties such as the pore throat structure and rock wettability may change. In this paper, the relative permeability curves under different water injection volumes through core-flood experiments were used to characterize the comprehensive changes of various reservoir physical properties at high water-cut stage. The novel concept of "water cross-surface flux" was proposed to characterize the cumulative flushing effect on the reservoir by injected water, and a novel method for inverted five-spot reservoir simulation at high water-cut stage based on time-varying relative permeability curves was established. From the relative permeability curves measured through two cores from the X oilfield under different water injection volumes (100, 500, 1000, 1500, and 2000 PV), it is found that with the increase of injected water volume, the two-phase co-flow zone becomes wider, the water permeability under residual oil saturation increases, and the residual oil saturation decreases. A waterflooding core model was established, simulated, and verified by the method proposed in this paper. It is found that using time-varying permeability curves for simulation, the highest oil recovery factor (61.58%) can be obtained with injected water volume up to 2000 PV, and the purpose of improved oil recovery (IOR) can be achieved by high water injection volume, but the increment is only approximately 10%. Besides, a waterflooding model of an inverted five-spot reservoir unit based on the X oilfield was also established, simulated, and analyzed. Simulation results have shown that no matter which set of core permeability curves measured from 100 to 2000 PV is directly used alone, the oil recovery factor will be simulated inaccurately. The findings of this study can help in better understanding the quantitative description of the oil recovery changes with time-varying reservoir physical properties in high water-cut reservoirs during waterflooding.
In order to clarify the major influence factors of resistance coefficient and residual resistance coefficient, so as to provide the basis for optimizing the polymer flooding schemes in oilfield Z of Bohai Sea, artificial cores were made by simulated the characteristic parameters of real reservoir and the spacing of production-injection wells. The main parameters considered include reservoir permeability, polymer solution concentration and polymer injection rate. Core experiment of polymer flooding was taken by considering all the main parameters. The result showed that resistance coefficient and residual resistance coefficient decrease with the increase of core permeability. Resistance coefficient and residual resistance coefficient increase with the increase of concentration of polymer solution. The increment of displacement pressure in low permeability core is higher than in medium and high permeability core. The resistance coefficient increase with higher displacing velocity, and the increment in high permeability core is higher than in low permeability core. The displacement velocity has little effect on the residual resistance coefficient. The experimental results can effectively guide the formulation of polymer flooding scheme in offshore oilfields, and optimize the appropriate injection rate and concentration of polymer solution for different properties of reservoirs, thus ensuring the effectiveness of polymer flooding in offshore oilfields.
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