Relative Permeability Behavior of Oil- Water Systems in Wolfcamp and Eagle Ford Fractures

Presently, two-phase flow behavior through propped and unpropped fractures is poorly understood, and due to this fact, reservoir modeling using numerical simulation for the domain that contains fractures typically assumes straight-line relative permeability curves and zero capillary pressure in the fractures. However, there have been several studies demonstrating that both viscous and capillary dominated flow can be expected in fractured reservoirs, where non-linear fracture relative permeabilities must be used to accurately model these reservoirs. The objective of this study is to develop an understanding of the relative permeability of oil-water systems in fractures through experimental study. The experimental measurements conducted in this study were done using downhole cores from the Wolfcamp and the Eagle Ford Shale formations. The cores were cut to 1.5-in diameter and 6-in length testing samples. The specimens are saw-cut to generate a fracture along each sample first, and then conditioned in the reservoir fluid at the reservoir temperature for a minimum of 30 days prior to any testing. Wolfcamp and Eagle Ford formation oil and reconstituted brine with and without surfactants are used as the test fluids. The measurements were recorded at effective fracture closure stress and reservoir temperature. Also, real-time measurements of density, pressure, and flow rate are recorded throughout the duration of each test. Fluid saturation within the fracture was calculated using the mass continuity equation. The oil-water relative permeability was measured using the steady-state method. All measurements were conducted at reservoir temperature and at representative effective fracture closure stress. The data from the experimental measurements was analyzed using Darcy's law, and a clear relationship between relative permeability and saturation was observed. The calculated relative permeability curves closely follow the generalized Brooks-Corey correlation for oil-water systems. Furthermore, there was a significant difference in the relative permeability curves between the oil-water only systems and the oil-water surfactant systems. The result of this study is useful for estimating the expected oil production more realistically. It also provides information about the effect of surfactants on oil-water relative permeability for optimal design of fracture fluids.

Artificial Neural Network Model Prediction of Bitumen/Light Oil Mixture Viscosity under Reservoir Temperature and Pressure Conditions as a Superior Alternative to Empirical Models

Herein, we show the prediction of the viscosity of a binary mixture of bitumen and light oil using a feedforward neural network with backpropagation model, as compared to empirical models such as the reworked van der Wijk model (RVDM), modified van der Wijk model (MVDM), and Al-Besharah. The accuracy of the ANN was based on all of the samples, while that of the empirical models was analyzed based on experimental results obtained from rheological studies of three binary mixtures of light oil (API 32°) and bitumen (API 7.39°). The classical Mehrotra–Svrcek model to predict the viscosity of bitumen under temperature and pressure, which estimated bitumen results with an %AAD of 3.86, was used along with either the RVDM or the MVDM to estimate the viscosity of the bitumen and light oil under reservoir temperature and pressure conditions. When both the experimental and literature data were used for comparison to an artificial neural network (ANN) model, the MVDM, RVDM and Al-Besharah had higher R2 values.

Enhanced Foam Stability Using Nanoparticle in High Salinity High Temperature Condition for Eor Application

The capability of commercial nanoparticles to perform as foam stabilizer were investigated at reservoir temperature of 96°C. Al2O3, Fe3O4, Co3O4, CuO, MgO, NiO, ZrO2, ZnO and SiO2 nanoparticles that were characterized using XRD, FTIR, FESEM-EDX, TEM and PSA, were blended in the in-house formulated surfactant named IVF respectively at a particular ratio. The test was performed with and without the presence of reservoir crude oil. Results showed that formulation with nanoparticles enhanced foam stability by having longer foam half-life than the IVF surfactant alone, especially in the absence of oil. Only SiO2 nanoparticles were observed to have improved the foam stability in both test conditions. The unique properties of SiO2 as a semi-metal oxide material may have contributed to the insensitivity of SiO2 nanoparticle towards crude oil which is known as a foam destabilizer. The physical barrier that was formed by SiO2 nanoparticles at the foam lamella were probably unaffected by the presence of crude oil, thus allowing the foams to maintain its stability. In thermal stability tests, we observed the instability of all nanoparticles in the IVF formulation at 96°C. Nanoparticles were observed to have separated and settled within 24 hours. Therefore, surface modification of nanoparticle was done to establish steric stabilization by grafting macro-molecule of polymer onto the surface of SiO2. This in-house developed polymer grafted silica nanoparticles are named ZPG nanoparticles. The ZPG nanoparticles passed the thermal stability test at 96°C for a duration of 3 months. In the foam wetness analysis, ZPG nanoparticles were observed to have produced more wet foams than IVF formulation alone, indicating that ZPG is suitable to be used as foam stabilizer for EOR process as it showed catalytic behaviour and thermally well-stable at reservoir temperature.

Water Compatibility and Scale Risk Evaluation by Integrating Scale Prediction of Fluid Modelling, Reservoir Simulation and Laboratory Coreflood Experiment for a Giant Oil Field in Offshore Abu Dhabi

An offshore field is producing oil from multiple reservoirs with peripheral water injection scheme. Seawater is injected through a subsea network and wellhead towers located along the original reservoir edge. However, because its OWC has moved upward, wells from wellhead towers are too remote to inject seawater effectively, with some portion going to the aquifer rather than oil pool. Therefore, it is planned to migrate injection strategy from peripheral to mid-dip pattern. An expected risk is scaling by mixing incompatible seawater and formation water. Such risk and mitigation measures were evaluated. To achieve the objective, the following methodology was applied: 1. Scale modelling based on water chemical analysis. 2. Define scale risk envelope with three risk categories 3. Tracer dynamic reservoir simulation to track formation water, connate water, dump flood water, injection seawater and treated seawater. 4. Review the past field scale history data 5. Coreflood experiment to observe actual phenomena inside the reservoir with various parameters such as water mixing ratio, sulphate concentration, temperature and chemical inhibitor 6. Consolidate all study results, conclude field scale risk and impact of mitigation measures. Scale prediction modelling, verified by coreflood tests, found that mixing reservoir formation water and injection seawater causes a sulphate scale risk, with risk severity depending on mixing ratio and sulphate concentration. Reservoir temperature was also found to correlate strongly with scale risk. Therefore, each reservoir should have different water management strategy. Scale impact is limited in the shallower wide reservoir with cooler reservoir temperature. Such reservoir should therefore have mid-dip pattern water injection to avoid low water injection efficiency with possible scale inhibitor squeezing as a contingency option. On the other hand, deeper reservoir has higher risk of scaling due to its higher temperature, causing scale plugging easily in reservoir pores and production wells. For such reservoir, peripheral aquifer water injection, treated low-sulphate seawater with sulphate-removal system, or no water injection development concept should be selected. By using modelling and experiment to quantify the scale risk over a range of conditions, the field operator has identified opportunities to optimize the water injection strategy. The temperature dependence of the scale risk means, in principal, that different injection strategy for each reservoir can minimize flow assurance challenges and maximize return on investment in scale mitigation measures.

Quantum Coherence of Atoms with Dipole–Dipole Interaction and Collective Damping in the Presence of an Optical Field

We investigate the effect of the interatomic distances and thermal reservoir on the coherence dynamics of the atoms considering the dipole–dipole interaction (DDI) and collective damping effect (CDE). We show that the control and protection of the coherence are very sensitive to the interatomic distances and reservoir temperature. Furthermore, we explore the distance effect between atoms and reservoir temperature on the time evolution of the total quantum correlation between the two atoms. The obtained results could be useful to execute these quantum phenomena and also considered as a good indication to implement realistic experiments with optimal conditions.

A new desorption-induced permeability dynamic model and its application in primary coalbed methane recovery

In the process of dewatering and recovery of coalbed methane, coal permeability exhibits a quite unique feature due to the interference of matrix shrinkage and stress effects. A new theoretical dynamic model was proposed for coal permeability based on the assumptions of matchstick geometry of the coal and uniaxial strain condition. Distinct from previous models such as P&M and S&D models, our model relates the gas-sorption-reduced strain to the change of surface energy of coal solids. One of the advantages of this model is that it does not require the sorption-reduced strain as an essential input, and therefore eliminates the related laborious and expensive laboratory measurement. The model was validated by fitting it to two sets of public data and shows an excellent match with the observed data. The results also indicate that our model has a better performance in predicting the permeability dynamics than P&M and S&D models. Additionally, a sensitivity analysis of the effect of input parameters on permeability dynamics was conducted by gray-relation theory, and the initial porosity and reservoir temperature are demonstrated to exert a most distinguished effect on the permeability dynamics. Finally, the proposed model was incorporated into a numerical simulator and successfully applied to conduct a history match of the gas and water production rate in a developed territory.

A hydrogeochemical approach to the characterization of low-enthalpy geothermal systems: the Scordia – Lentini graben (Sicily, Italy)

We describe the geochemical characteristics of groundwater samples collected in 23 water wells located on the northern margin of the Hyblean plateau (East Sicily). This area, mostly made of highly permeable carbonate rocks, is rich in low temperature (T < 50° C) hydrothermal groundwaters, distributed in an active sismogenetic zone, with several ENE-WSW-directed tectonic structures that drove magma to the surface during Upper Pliocene and Pleistocene. The chemical features suggest complex mixing between rainwater, CO2-rich groundwater, steam-heated groundwater and geothermal brines, as highlighted by Principal Component Analysis (PCA). Some parameters, however, indicate widespread pollution of the aquifers from human activities. Stable isotopes analysis confirms the meteoric origin of groundwater and supports the origin of dissolved CO2 mostly from mantle degassing through deep tectonic faults. Geothermometric estimates, mostly based on quartz and Saturation Indexes geothermometers, suggest minimum reservoir temperature between 100 and 120° C.