Movement behavior of residual oil droplets and CO2: insights from molecular dynamics simulations

After primary and secondary recovery of tight reservoirs, it becomes increasingly challenging to recover the remaining oil. Therefore, improving the recovery of the remaining oil is of great importance. Herein, molecular dynamics simulation (MD) of residual oil droplet movement behavior under CO2 displacement was conducted in a silica nanopores model. In this research, the movement behavior of CO2 in contact with residual oil droplets under different temperatures was analyzed, and the distribution of molecules number of CO2 and residual oil droplets was investigated. Then, the changes in pressure, kinetic energy, potential energy, van der Waals' force, Coulomb energy, long-range Coulomb potential, bond energy, and angular energy with time in the system after the contact between CO2 and residual oil droplets were studied. At last, the g(r) distribution of CO2–CO2, CO2-oil molecules, and oil molecules-oil molecules at different temperatures was deliberated. According to the results, the diffusion of CO2 can destroy residual oil droplets formed by the n-nonane and simultaneously peel off the n-nonane molecules that attach to SiO2 and graphene nanosheets (GN). The cutoff radius r of the CO2–CO2 is approximately 0.255 nm and that of the C–CO2 is 0.285 nm. The atomic force between CO2 and CO2 is relatively stronger. There is little effect caused by changing temperature on the radius where the maximum peak occurs in the radial distribution function (RDF)-g(r) of CO2–CO2 and C–CO2. The maximum peak of g(r) distribution of the CO2–CO2 in the system declines first and then rises with increasing temperature, while that of g(r) distribution of C–CO2 changes in the opposite way. At different temperatures, after the peak of g(r), its curve decreases with the increase in radius. The coordination number around C9H20 decreases, and the distribution of C9H20 becomes loose.

Case Studies of Digitalized Locate the Remaining Oil Workflows Powered by Hybrid Data & Physics Methods

Mature fields already account for about 70% of the hydrocarbon liquids produced globally. Since the average recovery factor for oil fields is 30 to 35%, there is substantial quantities of remaining oil at stake. Conventional simulation-based development planning approaches are well established, but their implementation on large, complex mature oil fields remains challenging given their resource, time, and cost intensity. In addition, increased attention towards reduce carbon emissions makes the case for alternative, computationally-light techniques, as part of a global digitalisation drive, leveraging modern analytics and machine learning methods. This work describes a modern digital workflow to identify and quantify by-passed oil targets. The workflow leverages an innovative hybrid physics-guided data-driven, which generates historical phase saturation maps, forecasts future fluid movements and locate infill opportunities. As deliverables, a fully probabilistic production forecast is obtained for each drilling location, as a function of the well type, its geometry, and position in the field. The new workflow can unlock remaining potential of mature fields in a shorter time-frame and generally very cost-effectively compared to the advanced dynamic reservoir modelling and history-match workflows. Over the last 5 years, this workflow has been applied to more than 30 mature oil fields in Europe, Africa, the Middle East, Asia, Australia, and New Zealand. Three case studies’ examples and application environments of applied digital workflow are described in this paper. This study demonstrates that it is now possible to deliver digitalized locating the remaining oil projects, capturing the full uncertainty ranges, including leveraging complex multi-vintage spatial 4D datasets, providing reliable non-simulation physics-compliant data-driven production forecasts within weeks.

Recent Advances in Capillary Desaturation Curves for Sandstone and Carbonate Reservoirs

Different enhanced oil recovery (EOR) methods are usually applied to target remaining oil saturation in a reservoir after both conventional primary and secondary recovery stages. The remaining oil in the reservoir is classified into capillary trapped residual oil and unswept /bypassed oil. Mobilizing the residual oil in the reservoir is usually achieved through either decreasing the capillary forces and/or increasing the viscous or gravitational forces. The recovery of the microscopically trapped residual oil is mainly studied using capillary desaturation curve (CDC). Hence, a fundamental understanding of the CDC is needed for optimizing the design and application of different EOR methods in both sandstone and carbonate reservoirs. For sandstone reservoirs, especially water-water rocks, determining the residual oil saturation and generating CDC has been widely studied and documented in literature. On the other hand, very few studies have been conducted on carbonate rocks and less data is available. Therefore, this paper provides a comprehensive review of several important research studies published on CDC over the past few decades for both sandstone and carbonate reservoirs. We critically analyzed and discussed theses CDC studies based on capillary number, Bond number, and trapping number ranges. The effect of different factors on CDC were further investigated including interfacial tension, heterogeneity, permeability, and wettability. This comparative review shows that capillary desaturation curves in carbonates are shallower as opposed to these in sandstones. This is due to different factors such as the presence of high fracture density, presence of micropores, large pore size distribution, mixed-to-oil wetting nature, high permeability, and heterogeneity. In general, the critical capillary number reported in literature for sandstone rocks is in the range of 10−5 to 10−2. However, for carbonate rocks, that number ranges between 10−8 and 10−5. In addition, the wettability has been shown to have a major effect on the shape of CDC in both sandstone and carbonate rocks; different CDCs have been reported for water-wet, mixed-wet, and oil-wet rocks. The CDC shape is broader and the capillary number values are higher in oil-wet rocks compared to mixed-wet and water-wet rocks. This study provides a comprehensive and comparative analysis of CDC in both sandstone and carbonate rocks, which serves as a guide in understanding different CDCs and hence, better screening of different EOR methods for different types of reservoirs.

An integrated approach to evaluating the effectiveness of infill drilling of the Ust-Tegusskoye field

The article considers the experience of using infill well patten in the territory of Western Siberia. The justification of geological and geotechnical factors affecting the efficiency of infill drilling with the subsequent use of a sector-crushed hydrodynamic model of the field site is given. With the help of the identified criteria, promising areas of infill drilling of wells are mapped, and it is established that increasing the detail of the grid of the hydrodynamic model makes it possible to clarify the localization of remaining oil in place. Based on the obtained results from the hydrodynamic model, variants of adjusted planned well count are compared according to accumulated and annual indicators. Thus, the infill well drilling program is optimized. The implementation of an integrated approach to the selection of sites for compaction drilling and the use of a detailed hydrodynamic model of this site allows to increase the production efficiency of recoverable remaining oil in place, as well as to level the risks of oil production.

Experimental Study on Optimization of Polymer Preslug Viscosity of ASP Flooding in Interlayer Heterogeneous Well Group Artificial Sandstone Core

An artificial sandstone core model of large well group of positive rhythmic heterogeneous reservoir was designed and made for the simulation of ASP flooding experiment in the moderate heterogeneous reservoir. The well layout of one injection and one production was employed for the core model, to simulate the influence of polymer preslugs with different viscosity on ASP flooding effect. The experimental results show that the injectability of the polymer preslug and the effect of relieving the conflict of remaining oil production in each layer are related to the viscosity of the system. In the heterogeneous core model with the coefficient of variation of 0.65, under the constraint of the same amount of polymer agent, the ASP flooding effect of the 0.075 PV, 60 mPa·s polymer preslug was better than that of the 0.093 PV, 40 mPa·s and 0.064 PV, 80 mPa·s polymer preslugs. The change in the viscosity of the polymer preslug did not enable the ASP system to effectively exploit the low-permeability layer though. As the viscosity increased, the pressure difference between injection and production increased; the remaining oil could be exploited effectively at the bottom of the high-permeability layer and the medium-permeability layer as well as the injection end of the medium-permeability layer. If the viscosity is too small, the high-permeability area cannot be effectively blocked by the injected chemical agent, and if the viscosity is too large, the injected chemical agent cannot produce good elastic displacement relationship, which will lead to ineffective chemical agent flow. Therefore, the polymer preslug viscosity of the ASP flooding system should be moderate, and cores with different heterogeneity should have a reasonable viscosity matching range.

Interrelationship of Capillary Number, Interfacial Tension, Injection Flow Rate and Temperature by Surfactant Flooding for Oil-wet Carbonate Reservoirs

After water flooding in carbonate reservoirs, a significant fraction of the original oil as remaining oil is left in the swept zone. The remaining oil in the pore, trapped by viscous and capillary forces, is to target for improved and enhanced oil recovery. The mobilization of remaining oil can be predicted by a dimensionless parameter called capillary number. The interfacial tension and injection flow rate strongly affect the capillary number. Unfortunately, the interrelationship between capillary number, interfacial tension, injection flow rate, and the temperature has been poorly studied for carbonate reservoirs. This paper focuses on studying the remaining oil saturations at different orders of magnitude capillary numbers related to interfacial tension, injection flow rate, and temperature by seawater and surfactant flooding. Several core flooding experiments were performed by changing the injection rate and surfactant concentrations at evaluated conditions. Four displacement experiments of seawater/oil and surfactant solution/oil were performed using oil-wet carbonate cores to obtain the relationship between the residual oil saturation vs. the capillary number. The surfactant flooding experiments with different concentrations of 0.01 and 0.2 wt% were conducted when the remaining oil saturation was reached after water flooding. Three core flooding experiments were conducted at ambient conditions, and one was under evaluated conditions of a temperature of 100° and pore pressure of 3200 psi. Several injection rates were selected to experiment with a 0.2 wt% surfactant solution, which is to study the effect of injection rate on the capillary number and residual oil saturation. The experimental findings show that some remaining oil can be recovered from oil-wet carbonate cores if the capillary number increases by a critical Nc =2.1E-05 by surfactant flooding at reservoir conditions. After water flooding, the remaining oil saturation was decreased from 51% to 16% with 0.01wt% surfactant flooding. The reduction of interfacial tension from 6.77dyne/cm to 0.017dyne/cm led to an increased capillary number. It decreased the remaining oil saturation by about 5% OOIP when the capillary number increases three magnitudes. The effect of temperature and injection rate on the capillary number was observed based on experimental displacement results. Compared with results between the ambient and specified conditions, the effect of temperature on the capillary number is significant. Under the same capillary number, the remaining oil recovered by surfactant flooding at HPHT conditions was higher than that at ambient conditions. Also, the effect of the injection flow rate on the capillary number was observed by 0.2wt % surfactant flooding for all experiments. The capillary number increased with an increase in the injection rate for both ambient and evaluated conditions. This paper provides valuable results to evaluate the interrelationship between remaining oil and capillary numbers by surfactant flooding and design field application for oil-wet carbonate reservoirs.

Physical simulation of residual oil displacement production in offshore strong bottom water reservoir

The C oilfield is located in the Bohai Bay Basin, a typical strong bottom water reservoir. Oilfield reservoir and oil–water distribution are complex. At present, the C oilfield has entered the high water cut development stage, and it is challenging to stabilize oil and control water. The reservoir with an imperfect well pattern has dominant bottom water ridge channels, uneven oil–water interface uplift, limited water drive sweep range, and low inter-well reservoir production degree. The oil layer between the horizontal section of the production well and the top of the reservoir cannot be effectively developed, and the remaining oil is enriched. Therefore, it is urgent to explore new energy supplement methods to improve inter-well and vertical remaining oil production in the C oilfield. In this study, the displacement medium is optimized through indoor experimental simulation. From the experimental results, the remaining oil between the sand bodies can be used in heavy oil reservoirs, and the residual oil between wells can be significantly utilized in the alternate displacement of gas and foam, and the recovery degree of the reservoir is increased by 12.44%. The remaining oil at the top of the reservoir can be used in the upper reservoir to increase the remaining oil in the top of the reservoir by injecting gas and foam alternately in the new reservoir. The final recovery of the reservoir is increased by 6.00%. This experimental study guides tapping the potential of the remaining oil in the offshore strong bottom water reservoir.