Academic literature on the topic 'Welge-JBN'

Relative permeability computation is extensively applied in petroleum engineering through the Welge-JBN’s method in unsteady-state corefloods. The purpose of this work is to determine admissible coreflood parameters that could limit the application of the Welge-JBN method. These parameters are presented through theoretical and operational criteria. The theoretical criteria include capillary number and capillary–viscous ratio. The operational criteria consist of measurement precision for pressure, volume sampling for either of phases, water cut measurement precision, and number of samples taken during one pore volume injected. The minimum core length and fluid displacement velocity for specific rock and fluid properties could be determined through these criteria. A laboratory coreflood example was performed using the proposed parameters.

Abstract Relative permeabilities are important characteristics of multiphase flow in porous media. Displacement experiments for relative permeabilities are frequently interpreted by the JBN method neglecting capillary pressure. The experiments are therefore conducted at high flooding rates, which tend to be much higher than those experienced during reservoir exploitation. Another disadvantage is that the relative permeabilities only can be determined for the usually small saturation interval outside the shock. We present a method to interpret displacement experiments with the capillary pressure included, using in-situ measurements of saturations and phase pressures. The experiments can then be run at low flow rates, and relative permeabilities can be determined for all saturations. The method is demonstrated by using simulated input data. Finally, experimental scenarios for three-phase displacement experiments are analyzed using experimental three-phase relative permeability data. Introduction Relative permeabilities are important characteristics of multiphase flow in porous media. These quantities arise from a generalization of Darcy's law, originally defined for single phase flow. Relative permeabilities are used as input to simulation studies for predicting the performance of potential strategies for hydrocarbon reservoir exploitation. The relative permeabilities are usually determined from flow experiments performed on core samples. The most direct way to measure the relative permeabilities is by the steady-state method. Each experimental run gives only one point on the relative permeability curve (relative permeability vs. saturation). To make a reasonable determination of the whole curve, the experiment has to be repeated at different flow rate fractions. To cover the saturation plane in a three-phase system, a large number of experiments have to be performed. The method is therefore very time consuming. Relative permeabilities can also be calculated from a displacement experiment. Typically, the core is initially saturated with a single-phase fluid. This phase is then displaced by injecting the other phases into the core. For the two-phase case, Welge showed how to calculate the ratio of the relative permeabilities from a displacement experiment. Efros was the first to calculate individual relative permeabilities from displacement experiments. Later, Johnson et al. presented the calculation procedure in a more rigorous manner, and the method is often referred to as the JBN method. The analysis has also been extended to three phases. In this approach, relative permeabilities are calculated at the outlet end of the core; saturations vs. time at the outlet end is determined from the cumulative volumes produced and time derivatives of the cumulative volumes produced, and relative permeabilities vs. time are calculated from measurements of pressure drop over the core and the time derivative of the pressure drop. Although the JBN method is frequently used for relative permeability determination, it has several drawbacks. The method is based on the Buckley-Leverett theory of multiphase flow in porous media. The main assumption is the neglection of capillary pressure. In homogenous cores capillary effects are most important at the outlet end of the core and over the saturation shock front. To suppress capillary effects, the experiments are performed at a high flow rate. Usually, these rates are significantly higher than those experienced in the underground reservoirs during exploitation.

Summary In this paper, we present results of an experimental investigation of the effects of variations in interfacial tension (IFT) on three-phase relative permeability. We report results that demonstrate the effect of low IFT between two of three phases on the three-phase relative permeabilities. To create three-phase systems in which IFT can be con-trolled systematically, we used a quaternary liquid system composed of hexadecane(C16), n-butanol (NBA), water (H2O), and isopropanol (IPA). Measured equilibrium phase compositions and IFTs are reported. The reported phase behavior of the quaternary system shows that the H2O-rich phase should represent the "gas" phase, the NBA-rich phase should represent the "oil" phase, and the C16-rich phase should represent the "aqueous" phase. Therefore, we used oil-wet Teflon (PTFE) bead packs to simulate the fluid flow in a water-wet oil reservoir. We determined phase saturations and three-phase relative permeabilities from recovery and pressure-drop data using an extension of the combined Welge/Johnson-Bossler-Naumann (JBN) method to three-phase flow. Measured three-phase relative permeabilities are reported. The experimental results indicate that the wetting-phase relative permeability was not affected by IFT variation, whereas the other two-phase relative permeabilities were clearly affected. As IFT decreases, the oil and gas phases become more mobile at the same phase saturations. For gas/oil IFTs in the range of 0.03 to 2.3 mN/m, we observed an approximately 10-fold increase in the oil and gas relative permeabilities against an approximately 100-fold decrease in the IFT. Introduction Variations in gas and oil relative permeabilities as a function of IFT are of particular importance in the area of compositional processes such as high-pressure gas injection, where oil and gas compositions can vary significantly both spatially and temporally. Because gas-injection processes routinely include three-phase flow (either because the reservoir has been water-flooded previously or because water is injected alternately with gas to improve overall reservoir sweep efficiency), the effect of IFT variations on three-phase relative permeabilities must be delineated if the performance of the gas-injection process is to be predicted accurately. The development of multicontact miscibility in a gas-injection process will create zones of low IFT between gas and oil phases in the presence of water. Although there have been studies of the effect of low IFT on two-phase relative permeability,1–14 there are limited experimental data published so far analyzing the effect of low IFT on three-phase relative permeabilities.15,16 Most authors have focused on the effect of IFT on oil and solvent relative permeabilities.17 Experimental results show that residual oil saturation and relative permeability are strongly affected by IFT, especially when the IFT is lower than approximately 0.1 mN/m (corresponding to a range of capillary number of 10–2 to 10–3). Bardon and Longeron3 observed that oil relative permeability increased linearly as IFT was reduced from approximately 12.5 mN/m to 0.04 mN/m and that for IFT below 0.04, the oil relative permeability curves shifted more rapidly with further reductions in IFT. Later, Asar and Handy6 showed that oil relative permeability curves began to shift as IFT was reduced below 0.18 mN/m for a gas/condensate system near the critical point. Delshad et al.15 presented experimental data for low-IFT three-phase relative permeabilities in Berea sandstone cores. They used a brine/oil/surfactant/alcohol mixture that included a microemulsion and excess oil and brine. The measurements were done at steady-state conditions with a constant capillary number of 10–2 between the microemulsion and other phases. The IFTs of microemulsion/oil and microemulsion/brine were low, whereas the IFT between oil and brine was high. They concluded that low-IFT three-phase relative permeabilities are functions of their own saturations only. Amin and Smith18 recently have published experimental data showing that the IFTs for each binary mixture of brine, oil, and gas phases vary as pressure increases(Fig. 1). Fig. 1 shows that the IFT of a gas/oil pair decreases as the pressure increases, whereas the IFTs of the gas/brine and oil/brine pairs approach each other.

This is a PhD thesis by publication that includes six published papers, five of which are journal papers and one is a full manuscript conference paper. The goal of this thesis is to investigate the effect of low salinity waterflooding (LSW) and salt ion type on enhancing oil recovery, which is implemented to select LSW reservoir candidates for a Wintershall Holding project. In addition, another aim of this thesis is to design a set of criteria to plan two-phase corefloods to accurately determine relative permeability by using Welge-JBN method. Low salinity water injection in oil fields has gained wide interest in the literature over the last two decades due to the fact that it is a cost-effective enhanced oil recovery technology. However, not only the mechanisms of LSW are not clearly understood, but there is some controversy around some LSW phenomena, especially fines migration, which is deemed to have the detrimental impact of formation damage in oil and gas reservoirs. This thesis focuses on the fines-migration mechanism of LSW and shows that it can be utilised to produce incremental oil using the induced formation damage in the reservoir. This study shows that micro-scale sweep efficiency is improved during low salinity waterflooding by flux diversion, that is caused by fines detachment and migration. Initially, clay particles are attached to the rock surface by electrostatic forces caused by the initial high-salinity formation water that saturates the rock. In this work, it is shown that injecting low salinity brine into the rock causes clay particles to be detached due to the weakening of electrostatic forces. As a result, fines migration results in blockage of high permeability water channels during high salinity water injection and diversion of the water flux to thin pores where residual oil is trapped. The results indicate that residual oil saturation was decreased by 5-18% in multiple low salinity coreflooding experiments with different salinity concentrations. Another part of this study investigates the effect of brine ion type on fines migration and oil recovery during LSW. It is demonstrated that having divalent ions such as calcium in the initial formation water, and the water injected into the porous media (including LSW), aids to stabilise fines due to the strong affinity and adsorption of such ions on the clay and rock surface. Deionised water injection confirms this, as hydrogen ions cannot exchange with calcium ions. This is confirmed by the fact that there are no clay particles in the effluent solution, no rise in pressure drop across the samples, and no detection of desorbed calcium ions in the Ion Chromatography results. Injection of low salinity sodium chloride solution, followed by deionised water flooding, induced desorption of the calcium ions, which then enabled clay particles to detach as a result of the weak electrostatic forces between clay and rock surface, that is caused by the sodium. This is important as it can be applied in controlling formation damage programs and preventing injectivity/production issues in oil and gas wells. Furthermore, enhanced oil recovery can also be achieved as proven by the incremental oil production observed when fines migration takes place in the two-phase flow tests due to the improved micro-scale sweep efficiency as explained above in the first part of the thesis. Moreover, a new set of criteria for coreflooding parameters to model relative permeability, for the experimental tests performed in this study, is introduced in this thesis and can, also, be applied in any two-phase flow experiments. These criteria are essential as they are needed for valid determination of relative permeability by the Welge-JBN method. They fulfil the assumption of low capillary-viscous ratio to achieve a large-scale approximation by optimising the core length and displacement rate. The numerical simulation results demonstrate that this ratio should not exceed 0.5 for the model to have valid relative permeability calculations by the Welge-JBN technique. The criteria include capillary number, precision of water-cut measurement, sampling period, and pressure measurement accuracy, which are critical to plan any coreflood tests to achieve accurate results.
Thesis (Ph.D.) -- University of Adelaide, Australian School of Petroleum (ASP), 2019