Oil recovery in fractured reservoirs by water flooding critically depends on the wetting properties of the matrix blocks between the fractures. The recovery from oil-wet reservoirs is small. In incompletely oil-wet systems, the presence of initial water may change the wettability characteristics so that imbibition and some oil recovery can occur. The hypothesis in this work is that water-soluble solvent (diethyl ether) improve the ultimate recovery and the imbibition rate in partially and completely water-wet cores. The main recovery mechanisms are the wettability change of the partially water-wet cores and oil swelling and the oil viscosity reduction in both partially and completely water-wet cores. This paper reports an experimental study concerning the recovery enhancement by water-soluble solvent (diethyl ether). We used an Amott imbibition cell studying oil saturated samples of various wettabilities, permeabilities using oils of different viscosities and two different diethyl ether (solvent) concentrations in the aqueous phase. In the first stage of the experiment, the completely water-wet core was exposed to brine without solvent. In a second stage, the core was put in a new Amott cell that was filled with solvent/ brine mixture. The extra recovery by solvent/brine mixture strongly depends on the residual oil saturation after brine imbibition and it is relatively insensitive to the permeability of the core or the oil viscosity. Therefore, larger residual oil saturation resulted in a higher extra recovery. For the partially water-wet samples, we also started with exposing the core to pure brine without solvent. Contrary to the completely water-wet samples, there was a significant increase in recovery rate when the sample is transferred to another Amott cell where it is exposed to a mixture of solvent and brine. In view of large values of the inverse Bond number in both partially and completely water-wet cores, the transfer between matrix and fracture capillary driven.

No abstract

High-viscosity oils classified as hard-to-recover oil reserves, where they differ from traditional oils with increased viscosity in reservoir conditions. There is about 0.7 billion tons of high-viscosity oils in Kazakhstan. Development of fields with high-viscosity oils is an urgent task for oil and gas engineers not only in Kazakhstan but also all over the world. This article is concerned with estimation of the efficiency of known in the oil and gas industry technologies aimed at intensifying production and increasing oil recovery in fields with hard-to-recover reserves. One of the types of such technologies is thermal recovery. This paper presents cyclic steam simulation. Estimation of the efficiency of the cyclic steam simulation based on the hydrodynamic model of the East Moldabek deposit of Kenbai filed. As a result of modeling, the current state of field development has been analyzed, reservoir simulation model has been history matched and different production forecast estimations have been made.

Most of Kazakhstans oil fields are mature ones. However, wells are still drilled in these fields (annually ~ 500 wells in JSC NC KazMunayGas). Well drilling forms a certain well spacing density at the fields. This article is concerned with the influence of well spacing density on the oil recovery factor in channel sandstones. The problem of how well spacing density (WSD) influences oil recovery factor (ORF) is one of the most studied and debated in forecasting oil production levels. In the course of studying existing scientific works on this topic, we understood that there is no uniform function of well spacing density and oil recovery factor. Today, when developing a field, it is relevant to search for new approaches to choose the optimal WSD taking into account all aspects of the geological structure based on hydrodynamic modeling. This article provides verification for the optimal WSD in channel sandstones choosing as an example sector model of horizon 13 of the Ozen field in two stages. During modeling we analyzed the current conditions of field development, and identified WSD with high values. Then a list of highly watered (unprofitable) wells was identified and recommended for shutdown. According to simulation, it is possible to maintain the base level of oil production by shutting off high water cut wells thereby decreasing well spacing density and optimizing fluid production on the remaining stock.