Influence of Capillary Pressure on Estimation of Relative Permeability for Immiscible WAG Processes

Capillary pressure is one of the important parameters when describing flow in porous media. This parameter is nevertheless in some cases neglected, especially if no reliable measured data is available. The purpose of this work was to investigate how capillary pressure influences reservoir behaviour. The key question has been if the capillary pressure could be neglected when simulating reservoir production or if the capillary pressure has significant impact on the production performance. This problem was addressed by comparing the production from simulations of core floods without capillary pressure to simulations with capillary pressure included. A match without capillary pressure included was achieved by tuning the relative permeability curves. Then capillary pressure was introduced while keeping the other parameters identical. The total oil production was significantly lower when capillary pressure was included. The relative permeability of oil had to be increased and the relative permeability of the injected fluids had to be reduced to get a new match with capillary pressure. The relative permeability for the match with zero capillary pressure was then compared to the relative permeability for the match with capillary pressure included. The difference in relative permeability was found to be significant. The relative permeability of oil had to be increased and the relative permeability of the injected fluids had to be reduced in the match with capillary pressure included. It was concluded that the capillary pressure had an important 2 impact on production behaviour and therefore also on history matching of relative permeability. If capillary pressure is not included the relative permeability of oil will be underestimated and the relative permeability of the injected fluids, gas and water, will be overestimated.Draf

Influence of Capillary Pressure on Estimation of Relative Permeability for Immiscible WAG Processes

Capillary pressure is one of the important parameters when describing flow in porous media. This parameter is nevertheless in some cases neglected, especially if no reliable measured data is available. The purpose of this work was to investigate how capillary pressure influences reservoir behaviour. The key question has been if the capillary pressure could be neglected when simulating reservoir production or if the capillary pressure has significant impact on the production performance. This problem was addressed by comparing the production from simulations of core floods without capillary pressure to simulations with capillary pressure included. A match without capillary pressure included was achieved by tuning the relative permeability curves. Then capillary pressure was introduced while keeping the other parameters identical. The total oil production was significantly lower when capillary pressure was included. The relative permeability of oil had to be increased and the relative permeability of the injected fluids had to be reduced to get a new match with capillary pressure. The relative permeability for the match with zero capillary pressure was then compared to the relative permeability for the match with capillary pressure included. The difference in relative permeability was found to be significant. The relative permeability of oil had to be increased and the relative permeability of the injected fluids had to be reduced in the match with capillary pressure included. It was concluded that the capillary pressure had an important 2 impact on production behaviour and therefore also on history matching of relative permeability. If capillary pressure is not included the relative permeability of oil will be underestimated and the relative permeability of the injected fluids, gas and water, will be overestimated

On the Modelling of Immiscible Viscous Fingering in Two Phase Flow in Porous Media

Viscous fingering in porous media is an instability which occurs when a low-viscosity injected fluid displaces a much more viscous resident fluid, under miscible or immiscible conditions. Immiscible viscous fingering is more complex and has been found to be difficult to simulate numerically and is the main focus of this paper. Many researchers have identified the source of the problem of simulating realistic immiscible fingering as being in the numerics of the process, and a large number of studies have appeared applying high-order numerical schemes to the problem with some limited success. We believe that this view is incorrect and that the solution to the problem of modelling immiscible viscous fingering lies in the physics and related mathematical formulation of the problem. At the heart of our approach is what we describe as the resolution of the “M-paradox”, where M is the mobility ratio, as explained below. In this paper, we present a new 4-stage approach to the modelling of realistic two-phase immiscible viscous fingering by (1) formulating the problem based on the experimentally observed fractional flows in the fingers, which we denote as f∗w, and which is the chosen simulation input; (2) from the infinite choice of relative permeability (RP) functions, k∗rw and k∗ro, which yield the same f∗w, we choose the set which maximises the total mobility function, λT (where λT=λo+λw), i.e. minimises the pressure drop across the fingering system; (3) the permeability structure of the heterogeneous domain (the porous medium) is then chosen based on a random correlated field (RCF) in this case; and finally, (4) using a sufficiently fine numerical grid, but with simple transport numerics. Using our approach, realistic immiscible fingering can be simulated using elementary numerical methods (e.g. single-point upstreaming) for the solution of the two-phase fluid transport equations. The method is illustrated by simulating the type of immiscible viscous fingering observed in many experiments in 2D slabs of rock where water displaces very viscous oil where the oil/water viscosity ratio is (μo/μw)=1600. Simulations are presented for two example cases, for different levels of water saturation in the main viscous finger (i.e. for 2 different underlying f∗w functions) produce very realistic fingering patterns which are qualitatively similar to observations in several respects, as discussed. Additional simulations of tertiary polymer flooding are also presented for which good experimental data are available for displacements in 2D rock slabs (Skauge et al., in: Presented at SPE Improved Oil Recovery Symposium, 14–18 April, Tulsa, Oklahoma, USA, SPE-154292-MS, 2012. https://doi.org/10.2118/154292-MS, EAGE 17th European Symposium on Improved Oil Recovery, St. Petersburg, Russia, 2013; Vik et al., in: Presented at SPE Europec featured at 80th EAGE Conference and Exhibition, Copenhagen, Denmark, SPE-190866-MS, 2018. https://doi.org/10.2118/190866-MS). The finger patterns for the polymer displacements and the magnitude and timing of the oil displacement response show excellent qualitative agreement with experiment, and indeed, they fully explain the observations in terms of an enhanced viscous crossflow mechanism (Sorbie and Skauge, in: Proceedings of the EAGE 20th Symposium on IOR, Pau, France, 2019). As a sensitivity, we also present some example results where the adjusted fractional flow (f∗w) can give a chosen frontal shock saturation, S∗wf, but at different frontal mobility ratios, M(S∗wf). Finally, two tests on the robustness of the method are presented on the effect of both rescaling the permeability field and on grid coarsening. It is demonstrated that our approach is very robust to both permeability field rescaling, i.e. where the (kmax/kmin) ratio in the RCF goes from 100 to 3, and also under numerical grid coarsening.publishedVersio

Analysis and Simulation of Polymer Injectivity Test in a High Temperature High Salinity Carbonate Reservoir

Polymer flooding has gained much interest within the oil industry in the past few decades as one of the most successful chemical enhanced oil recovery (CEOR) methods. The injectivity of polymer solutions in porous media is a key factor in polymer flooding projects. The main challenge that faces prediction of polymer injectivity in field applications is the inherent non-Newtonian behavior of polymer solutions. Polymer in situ rheology in porous media may exhibit complex behavior that encompasses shear thickening at high flow rates in addition to the typical shear thinning at low rates. This shear-dependent behavior is usually measured in lab core flood experiments. However, data from field applications are usually limited to the well bottom-hole pressure (BHP) as the sole source of information. In this paper, we analyze BHP data from field polymer injectivity test conducted in a Middle Eastern heterogeneous carbonate reservoir characterized by high-temperature and high-salinity (HTHS) conditions. The analysis involved incorporating available data to build a single-well model to simulate the injectivity test. Several generic sensitivities were tested to investigate the impact of stepwise variation in injection flow rate and polymer concentration. Polymer injection was reflected in a non-linear increase in pressure with injection, and longer transient behavior toward steady state. The results differ from water injection which have linear pressure response to rate variation, and quick stabilization of pressure after rate change. The best match of the polymer injection was obtained with complex rheology, that means the combined shear thickening at high rate near the well and moving through apparent Newtonian and shear thinning at low rate.publishedVersio

Absolute pore size distributions from NMR

NMR measurements on core samples saturated with brine returns valuable information on the porous structure of the rock core. Monitoring a single fluid component in a relaxation experiment reflects the pore size distribution and thus the degree of sorting of the porous rock. The basic assumptions are that the mobility of the component confined in the porous rock is of such a value that a small fraction of the probing molecules experience the surfaces of the pores and that the surface relaxation strength is fairly independent of pore size. Then one may combine diffusion measurements at short observation times returning a value for the average surface to volume ratio with ordinary relaxation time measurements to obtain an absolute pore size distribution instead of the standard T2 distributions or T1-T2 correlated two dimensional distributions

EFFECT OF WETTABILITY ON OIL RECOVERY FROM CARBONATE MATERIAL REPRESENTING DIFFERENT PORE CLASSES

ABSTRACT This paper discusses experimental studies of waterflooding native state cores and also waterflooding results for the same cores after aging in crude oil. The topics discussed are related to the effect of wettability change on relative permeability and oil recovery for different carbonate core materials. The unsteady state method was used as experimental procedure for measuring relative permeability and obtaining oil recovery data. The wettability was measured after aging, using the combined Amott / USBM method. The core material used in this study represents different pore classes within carbonate reservoirs. The cores used represent outcrop and gas well cores and had an initial waterwet state. Different carbonate pore classes showed large variation in properties with regard to two-phase flow properties. The waterflood experiments showed that low permeable carbonate (K << 1 mD) may still display a high oil recovery efficiency. The wettability of the cores after aging was intermediate towards oil wet, and nearly all the material displayed a mixed-wet small behaviour. The initial water saturation (S wi ) was very similar for the water-wet cores and the same cores after aging, which is essential for comparing the different wetting states. A strong increase in oil recovery after aging was observed in most cases, except for the cores that showed no spontaneous imbibition after aging. These cores had a lower oil recovery for aged cores compared to waterflood at initial water-wet conditions

Polymer Injectivity Test Design Using Numerical Simulation

Polymer flooding is an enhanced oil recovery (EOR) process, which has received increasing interest in the industry. In this process, water-soluble polymers are used to increase injected water viscosity in order to improve mobility ratio and hence improve reservoir sweep. Polymer solutions are non-Newtonian fluids, i.e., their viscosities are shear dependent. Polymers may exhibit an increase in viscosity at high shear rates in porous media, which can cause injectivity loss. In contrast, at low shear rates they may observe viscosity loss and hence enhance the injectivity. Therefore, due to the complex non-Newtonian rheology of polymers, it is necessary to optimize the design of polymer injectivity tests in order to improve our understanding of the rheology behavior and enhance the design of polymer flood projects. This study has been addressing what information that can be gained from polymer injectivity tests, and how to design the test for maximizing information. The main source of information in the field is from the injection bottom-hole pressure (BHP). Simulation studies have analyzed the response of different non-Newtonian rheology on BHP with variations of rate and time. The results have shown that BHP from injectivity tests can be used to detect in-situ polymer rheology.publishedVersio

Effect of Implementing Three-Phase Flow Characteristics and Capillary Pressure in Simulation of Immiscible WAG

The effect of including a three-phase representation of the flow parameters and capillary pressure has been investigated using a black oil simulator. The simulation approaches include the complexity of three-phase flow, relative permeability hysteresis, dynamic phase trapping functions and capillary pressure. A WAG simulation case was used to study the effect of three-phase flow parameters and capillary pressure on the size of the three-phase zone, breakthrough time of the injected fluids and oil recovery. Three-phase flow WAG processes are characterised by lower relative permeability of the injected fluids, because of flow path hysteresis and trapping of phases. It is important to incorporate these effects to have a correct description of the physics of multi-phase flow. The results from this study showed that the size of the three-phase zone was considerably larger when a three-phase description of the flow was implemented. The reduced relative permeability of gas and water in the three-phase zone leads to slower segregation of gas and water. The breakthrough time of gas and water was delayed and the oil recovery was increased when hysteresis and trapping functions were included. Including capillary pressure seems to further delay the breakthrough of the injected phases and the result is higher oil recovery. When including capillary pressure effects on the relative permeability, the three-phase zone was further extended and the oil recovery was increased. These studies show the importance of using a more detailed fluid flow description in simulation of immiscible WAG processes

Fluid Flow Properties of WAG Injection Processes

Immiscible water-alternating-gas (IWAG) experiments performed on equilibrated fluids are summarised together with the corresponding two-phase gas-oil and water-oil displacements. Experimental studies at reservoir condition and also mechanistic experiments over many years have shown accelerated oil production and higher core flood oil recovery as a result of three-phase flow. The three-phase effects that are included and analysed are; trapped gas, and mobility for secondary processes (ex. water after gas injection). The oil recovery from the different oil recovery processes represented by; gas, water, and WAG core displacements are also compared. The oil recovery has been related to the trapped gas saturation, and the efficiency of the trapped gas on oil recovery is found to be varying with core wettability. Experimental results have shown that both gas and water relative permeability generally is reduced during three-phase flow. Multivariate analysis has been used to investigate relations between variables like Sgt = f(k, , Sgi, krwe), Sorm = f(k, WI, Sorw, Sgt) and Sorg = f(k, WI, Sorw, krge). The paper tries to address the question of what three-phase parameters influence oil recovery, and how these parameters are related. This is an important question for modelling and optimising the WAG process

Features concerning capillary pressure and the effect on two-phase and three-phase flow

The effect of capillary pressure related to immiscible WAG (Water Alternate Gas) is studied by use of a numerical simulator. The capillary pressure is found to have a significant effect on the pressure gradient and the total oil production both in two-phase and three-phase flow situations. When the capillary pressure is included in the simulation the total oil production is considerably lower than when the capillary pressure is neglected. Experimentally measured two-phase capillary pressure was used as input to the numerical simulator. The two-phase capillary pressure was further used to estimate three-phase flow, related to WAG processes. A network model was applied to generate a consistent set of two-phase and three-phase capillary pressure. The network model was anchored to measured two-phase data, and threephase capillary pressure was constructed. The gas-oil and mercury capillary pressure anchored the pore structure parameters, while water-oil capillary pressure anchors the wettability parameters in the network model. The network model quantifies the difference between three-phase and two-phase capillary pressure, and in the cases studied the difference between two-phase and three-phase capillary pressure was significant