Search

The paper considers the use of a surfactant-polymer composition for the mobilization of light paraffinic oil from the D3-III carbonate reservoir at a reservoir temperature of 62°C, as well as the results of its tests in field conditions. Earlier, the composition showed its effectiveness on model carbonate cores with salinity from current (50-80 g/l) to reservoir (up to 170 g/l), in the presence of surfactants, type III microemulsions according to Winsor with oil were obtained. Based on the results of the filtration experiments performed on our own core from the productive formation D3-III, an increase in the displacement efficiency of surfactant-polymer compositions compared to water was obtained 11–14% (with a total surfactant concentration of 1%), irreversible surfactant losses in water-saturated rock–up to 0, 38 mg/g. Displacement efficiency after water and surfactant-polymer composition flooding was also estimated in the field conditions using SWCTT; its results were interpreted by various methods (analytical, in a hydrodynamic simulator), and also compared with laboratory results. Within a single-well tracer test, an assessment of the residual saturation after water filtration and injection of a surfactant-polymer composition was carried out under the following conditions: the target research radius is 3.5 m; porosity 10%, effective reservoir thickness 38 m. Based on the results of SWCTT, an increase in the displacement efficiency of 16.7% was obtained in comparison with water displacement (total surfactant concentration 1%) using an analytical method of interpretation. The adaptation of the SWCTT results on the hydrodynamic model was carried out, the most influencing parameters on the quality of adaptation were determined. The selection and justification of a pilot area for a multi-well pilot project was carried out, a sector hydrodynamic model of the site was built, and calculations were made to assess additional oil production.

The paper describes a methodology for assessing the impact of wax deposition in reservoir oil during cold water injection into heterogeneous carbonate reservoir D3-III of the Kharyaga field. The main goal is to determine the optimal amount of hot water that must be injected before switching to cold water without affecting the field development. The paper presents the results of laboratory studies to determine the thermophysical properties of oil, samples of net reservoir and non-reservoir rock, as well as the results of laboratory studies to determine the conditions and nature of wax deposition in oil when the temperature and pressure conditions change. Calculations were carried out to describe the physical model of oil displacement by water of various temperatures. A series of synthetic sector model runs was performed, which includes the average properties of the selected reservoir and the results of laboratory studies in order to determine the effect of cold water injection on the development performance.

The development of carbonate reservoirs using peripheral and pattern water flooding typically achieves oil recovery factors ranging from 0.3 to 0.5, which is due to some complicating factors, such as, oil-wet surface of the pore space or the surface with intermediate type of wetting, unfavorable ratio of oil and water viscosities, presence of extensive structure of fractures, and significant variations of permeability down the reservoir section. In a complex geological environment, wells display abrupt fluctuations of water production that is an evidence of formation water being by no means the most efficient displacement agent. In these conditions, low-salinity water flooding can improve oil recovery.This paper reports on SCAL results of oil recovery factor determination and spontaneous imbibition using water with different composition and total solinity for Object 2 of Kharyaga oil field. Also, report contains design of on-site determination of residual oil saturation using Single Well Chemical Tracer test technology for evaluation of EOR efficiency.Laboratory tests showed, that low-salinity Jurassic water flooding with total salinity about 5 g/l could rase recovery factor up to 4% and also give incremental recovery due to effects of spontaneous imbibition for permability lower than 100 mD, which makes the injection of Jurassic water more preferable.

A global trend to introduce enhanced oil recovery (EOR) methods at the early field development stages has been recently observed. Zarubezhneft group is no exception in this regard. Early introduction of EOR methods makes it possible to achieve higher process efficiency, and, first and foremost, economic efficiency. This article describes a pilot project involving implementation of diverter technologies at the field with complex carbonate reservoirs. The following aspects have been reviewed: the structure of the Kharyaga D3-III reservoir, main issues related to the reservoir development and ways to resolve such issues. Laboratory studies of the applied compositions’ properties, as well as filtration experiments have been described. The article also presents an overview of the available diverter technologies. The article also describes field implementation of the operations completed, namely, criteria for interface area selection, injection design development, work progress and efficiency evaluation for the EOR method applied. The operations completed on 5 injectors resulted in around 65 thousand tons of incremental oil from the producers. The operations were found successful; a new program for injection of polymer solution slugs is currently being developed.