Counter-current Imbibition Research Articles

Mathematical modeling of formation damage effect during underbalanced drilling operations

Formation damage during underbalanced drilling is created due to the spontaneous counter-current imbibition when drilling mud is in contact with saturated formations. Therefore, it should be appropriately recognized and investigated. The objective of this study is to develop a numerical model to simulate the penetration rate of drilling mud in the formation during underbalanced drilling. Modeling of this phenomenon is done by implementing its formulation through implicit pressure–explicit saturation (henceforth, IMPES) method. To validate the results of the developed model with a pilot study in this field, it is demonstrated that the model performs effectively in determining the penetration range of muds and finding the distribution of drilling mud saturation across the core. Consequently, the degree of damage to the formation through laboratory studies is usually time-consuming and therefore, the developed model can be employed for initial studies. Increasing the unbalanced pressure difference, oil viscosity and porosity will reduce the amount of drilling mud penetration in the formation during underbalanced drilling operations.

An analytical approach to investigate formation damage caused by underbalanced drilling performances

Underbalanced drilling performances have always considered as one of the proper solutions to prevent the formation damage problems during the drilling operational performances. To numerically model the spontaneous counter-current imbibition during the underbalanced drilling operational performances, different imbibition mechanism in the porous media should be taken into consideration. In this paper, a developed numerical approach was proposed to evaluate the various parameters which significantly affected the formation damage caused by underbalanced drilling performances. To verify the accuracy of the proposed model, which is analytically modeled by implicit pressure explicit saturation (henceforth; IMPES), a set of experimental CT scan data from a laboratory pilot was administered. Subsequently, the proposed analytical model is in a good agreement with CT scan laboratory data which clearly indicated the reliability of the model to evaluate filtrated mud saturation.

Modeling of influence of heterogeneity gradient for counter-current capillary imbibition

Capillary imbibition is the most important stage in many technological processes. The article is devoted to studying the special question of the influence of the non-constant slope on the solutions of counter-current capillary imbibition problem in the isothermal case.

Simulation-based enhanced oil recovery predictions from wettability alteration in the Middle Bakken tight reservoir with hydraulic fractures

Surfactant enhanced oil recovery is promising in tight formations by altering the wettability, reducing the interfacial tension, and promoting the counter-current imbibition process. In this paper, surfactant Huff-n-Puff in Bakken tight reservoir was studied based on modelling and simulation of a Middle Bakken well using actual field data. The effects of wettability alteration and interfacial reduction by surfactant solution were modeled based on laboratory data. The Embedded Discrete Fracture Model (EDFM) method was used to efficiently handle hydraulic fractures in the model in a fast way using non-neighboring connections as a new technique in this simulation study. We used a sector model with the EDFM method to conduct the surfactant Huff-n-Puff sensitivity simulation after the grid size optimization. We considered six sensitivity factors and each simulation case was conducted after history matching. Based on the simulation results, we found that the number of Huff-n-Puff cycles and the surfactant concentration are the most important factors, followed by surfactant adsorption, soaking time, injection time and injection rate. The percentage of oil recovery increase over the primary oil recovery ranges from 1.1% to 25.2%. This study can provide critical insights of key parameters affecting the surfactant flooding efficiency in Middle Bakken tight oil reservoir.

Scaling of Countercurrent Imbibition in 2D Matrix Blocks With Different Boundary Conditions

Summary Scaling of imbibition data is of essential importance in predicting oil recovery from fractured reservoirs. In this work, oil recovery by countercurrent spontaneous imbibition from 2D matrix blocks with different boundary conditions was studied using numerical calculations. The numerical results show that the shape of imbibition-recovery curves changes with different boundary conditions. Therefore, the imbibition curves could not be closely correlated with a constant parameter. A modified characteristic length was proposed by a combination of Ma et al. (1997) and theoretical characteristic length. The modified characteristic length is a function of imbibition time, and the shape of imbibition curves could be changed using the modified characteristic length. The overall imbibition curves were closely correlated using the modified characteristic length. Finally, the modified characteristic length was verified by experimental data for imbibition with different boundary conditions.

A CHANGE IN OIL VISCOSITY DURING CRUDE OIL PRODUCTION INFLUENCE ON THE SOLUTIONS OF COUNTER-CURRENT CAPILLARY

In this article we construct a modification of the model of counter-current capillary imbibition with oil viscosity dependent on dynamic water saturation. This approach corresponds to the approximate modeling of the complex composition of hydrocarbon fluid and taking into account the fact that a change in oil viscosity is recorded in some fields with an increase in the share of water in the extracted liquid at different stages of oil field development. The behavior of solutions under variation of model parameters is studied numerically. It is shown that the leaching of lighter fractions of oil at the first stages of operation as a whole increases the terms of achievement of project indicators. The influence of gravity on capillary washing of hard-to-reach places is analyzed.

Measurement of Spontaneous Imbibition Capillary Pressure, Saturation and Resistivity Index by Counter Current Technique at Net Reservoir Stress and Elevated Temperature

Capillary pressure and resistivity index spontaneous imbibition experiments by the porous plate method, in a core holder at elevated temperature and net reservoir stress, are both difficult and time consuming special core analysis measurements to perform. In this type of experiment, low capillary forces act against a low permeable porous plate and only one face of the cylindrical core sample is in capillary contact with the fluid saturated porous plate. In this paper, core samples having different lithology, petrophysical properties and wettability are analysed by counter current spontaneous imbibition, starting at initial water saturation (Swi), at net confining pressure and elevated temperature. Synthetic brine is used as the wetting phase and Isopar L mineral oil as the non-wetting phase. This methodology is applied to investigate and evaluate how to obtain more reliable, more efficient and faster saturation imbibition data combined with electrical measurements, during spontaneous imbibition measurements. Resistivity index (RI), saturation exponent (n) (by single saturation equilibrium point using Archie’s second law RI= Sw-n) and wettability information using representative fluids, confining pressure and temperature are also obtained by applying this specific counter current imbibition technique and improved procedural approach.

A novel 3D green element method to simulate counter-current spontaneous imbibition considering the effect of gravity

This paper firstly proposes a novel three-dimensional (3D) Green element method (GEM). We have proven it by theoretical error analysis that, the novel GEM with the third-order accuracy, has good convergence and stability, which are the advantages that previous GEMs do not have. This novel method is used to numerically simulate 3D core's counter-current imbibition process with gravity effect, and 1D, 2D and 3D models are implemented to depict good convergence and accuracy of proposed method. Compared with finite difference method (FDM) used by many previous studies, the novel method has the same advantage as previous GEMs, that it requires less elements to achieve a good agreement between simulation results and experiment data. Moreover, specific gravity effect is analyzed, and three typical stages of gravity effect are divided. In summary, the novel 3D GEM and corresponding 3D simulator are effective to simulate counter-current imbibition of the real 3D core considering the effect of gravity.

Surfactant Effects of Wettability Alteration and Low IFT on Countercurrent Imbibition for Tight Oil Formation

Both wettability alteration and low interfacial tension (IFT) are important mechanisms of surfactants for enhancing oil recovery. In the imbibition process, surfactant solution invades the matrix, lowering IFT and altering the contact angle; these factors change the distribution of oil as well as the magnitude and direction of capillary force. Although a lot of research has been done in modeling countercurrent imbibition, less attention has been paid to comparing which effect plays a more important role in the imbibition process. A mechanistic model was used to study the surfactant solution imbibition process in porous media with subnanometer and nanometer capillaries, and the approximated diffusion coefficient was used to simplify the calculation. The simulated calculation demonstrates that, in contrast to low IFT, the change in wettability is the major mechanism for improving tight rock imbibition recovery, and this confirms that the change in wettability contributes more than lower IFT to the ultimate imbibition recovery.

Wetting Behavior of Tight Rocks: From Core Scale to Pore Scale

AbstractPrevious measurements show mixed‐wet behavior of tight siltstone core plugs, initially saturated with air. However, the same plugs show water‐wet behavior when saturated with oil or water. This study aims at explaining these observations by investigating the effects of mineral heterogeneity and intermolecular forces acting on solid/liquid and liquid/liquid interfaces. First, we conduct pore‐scale visualizations to characterize the minerals surrounding the pores of the tight rock samples. Thin‐section and scanning electron microscopy/energy dispersive X‐ray spectroscopy analyses show the existence of multimineral pores, which can be responsible for the mixed‐wet behavior. Next, we apply the DLVO theory to investigate the intermolecular forces acting on solid/liquid and liquid/liquid interfaces. We use disjoining pressure‐distance profiles and contact angles calculated for different minerals to evaluate the stability of the thin film covering the rock grains and to explain the wettability of the core plugs during spontaneous imbibition tests. The disjoining pressure values calculated for the dry core plugs suggest similar wetting affinities toward oil and water. However, the contact angles calculated for the water‐saturated core plugs suggest the water‐wet behavior, which agrees with the countercurrent imbibition results. Finally, we measure the adhesion forces between the tip of a cantilever and (1) pure quartz slide, (2) pure calcite crystal, and (3) the rock thin section using an atomic force microscope. The values of adhesion forces measured for the thin section composed of multimineral pores are between those measured for pure quartz slide and pure calcite crystal.

Wettability Measurements on 3D Printed Sandstone Analogues and Its Implications for Fluid Transport Phenomena

Additive manufacturing technology, or 3D printing, with silica sand has enabled the manufacture of porous rock analogues for the use in experimental studies of geomechanical properties of reservoir rocks. The accurate modelling of the fluid flow phenomena within a reservoir and improving the performance of hydrocarbon recovery require an understanding of physical and chemical interactions of the reservoir fluids and the rock matrix. Therefore, for the 3D printed samples to serve as rock analogues, flow properties have to be equivalent to the petrophysical properties of their natural counterparts, such as Berea sandstone. In this study, sandstones that were 3D printed with silica sand and Poly-Furfuryl alcohol (PFA) binder, were used to investigate interactions between porous media with different fluids. Wettability preference of 3D printed samples was characterized through contact angle measurements, as well as co-current and counter-current spontaneous imbibition experiments. Results indicated that 3D printed sandstones had mixed-wet characteristics due to the high preference of silica grains for polar fluids and the affinity PFA binder to the oleic phase. Printing configurations including binder saturation were found to greatly influence the wettability preference of the 3D printed analogue rocks as higher PFA concentrations resulted in more strongly oil-wet preferences. Efforts to optimize the printing process and challenges to control the wettability preferences of the 3D printed samples are also highlighted.

Recent advances in spontaneous imbibition with different boundary conditions

Spontaneous imbibition plays an important role in many practical processes, such as oil recovery, hydrology, and environmental engineering. The development in spontaneous imbibition goes fast in the past few years. In this paper, we focus on boundary conditions of spontaneous imbibition, which has important effects on spontaneous imbibition rate and efficiency. We introduce the fundamental physical mechanism of spontaneous imbibition with different boundary conditions by capillary model. Then, the studies of spontaneous imbibition in core scale are reviewed. The feature of spontaneous imbibition with different boundary conditions is discussed and the relative permeability for co- and counter-current imbibition is analyzed. The scaling of imbibition data with different boundary condition is also discussed by combination of experimental and numerical methods. At last, the analytical model of spontaneous imbibition is discussed. Cited as : Meng, Q., Cai, J. Recent advances in spontaneous imbibition with different boundary conditions. Capillarity, 2018, 1(3): 19-26, doi: 10.26804/capi.2018.03.01

Effect of magnetic field on imbibition phenomenon in fluid flow through fractured porous media with different porous material

Abstract In this paper, the counter-current Imbibition phenomenon is considered in a fractured heterogeneous porous medium with the consideration of different porous materials like fine sand, volcanic sand and glass beads and magnetic field effect. The Homotopy analysis method is used here to derive an expression for finding the saturation profiles in a fractured heterogeneous porous medium with and without considering the magnetic field effect. Simulation results are developed for the saturation profiles to study the effect of inclination and the viscosity variation of native fluids on the saturation rate and the recovery rate of the reservoir with some interesting choices of parameters.

Effect of Viscous Fluid on the Counter-Current Imbibition Phenomenon in Two-Phase Fluid Flow Through Heterogeneous Porous Media with Magnetic Field

In this paper, the counter-current imbibition phenomenon is discussed in a heterogeneous porous medium with the consideration of magnetic field effects due to the presence of magnetic fluid particles in injected fluids. An advanced analytical approximation method, i.e., homotopy analysis method is used to derive an expression for finding the saturation profiles with and without considering the magnetic field effect with the choices of different parameters. Simulation results are developed to study the effects of different parameters on saturation rate and on recovery rate of the reservoir.

Simulation of Counter-Current Imbibition in SRVs of Tight Oil Reservoir

Simulation of Counter-Current Imbibition in SRVs of Tight Oil Reservoir

Guidelines for Numerically Modeling Co- and Counter-current Spontaneous Imbibition

We present guidelines for accurately simulating both co- and counter-current spontaneous imbibition (SI) phenomenon in 1D systems. We first consider several cases for this study, which involve strongly water-wet, weakly water-wet and mixed-wet wettability states, to simulate co- and counter-current SI in an oil–water system. We create two separate 1D models on a numerical simulator to simulate and obtain saturation profiles for the different cases. We then match simulation results with saturation profiles obtained through the capillary dominated flow semi-analytical solution proposed by Schmid et al. (Water Resour Res 47(2), 2011, SPE J 21:2–308, 2016). The numerical study evaluates the effect of model orientation and co-ordinate system on the saturation profiles. Moreover, we perform grid sensitivity analysis to choose the optimal number of grid cells, as well as the optimal time steps for the model. We find that capturing 0.25% of core volume in each grid cell is sufficient to numerically model an SI experiment within the acceptable margin of error of 5%. Simulations are performed for 23 different cases based on the SI mode, wettability and mobility ratios. The simulation results in saturation profiles have a mean absolute percentage error from the profile obtained from the semi-analytical solution between 0.14 and 5.41% for counter-current SI for the different wettability states. For most wettability states for the co-current SI, however, we do not get a close match, indicating that the semi-analytical solution does not hold for co-current SI. The paper lists some useful guidelines for simulating SI phenomenon, such as selecting the optimum number of grid cells for the SI model and accounting for capillary backpressure, which could be extended to be applied for simulating coreflooding experiments. This paper also discusses current limitations of the semi-analytical solution. These calibration and sensitivity studies can significantly improve the accuracy of the simulation results.

Models of Thermal Enhanced Oil Recovery in Fractured Reservoirs

Summary Models for steam or hot-water injection into a fractured diatomite or shale reservoir are developed from existing analytic models of energy transport and countercurrent imbibition. Radial convective heat flow through a horizontal fracture system is modeled with conductive heat flow into the low-permeability matrix. The flow geometry approximates hot-fluid injection into a five-spot pattern. Recovery mechanisms accounted for in the models include capillary imbibition and thermal expansion. Temperature dependence of viscosity and interfacial tension (IFT) are included in the imbibition estimate. Laboratory data are needed to quantify the magnitude of the imbibition mechanism, which is usually the primary contributor to oil recovery. Reservoir properties representative of either the Belridge Diatomite or the Antelope Shale, two giant fractured oil reservoirs, are used for the model forecasts. Currently, however, only temperature-dependent imbibition data for diatomite reservoirs are available. The steamflood model has been partially validated against a large-scale project in the Belridge Diatomite. By use of public-domain information, a reasonable comparison was obtained between the model and the field project during a 4-year injection period. Comparison with conventional thermal simulation was also performed, and it indicated reasonable agreement with the steamflood analytical model. The models have been used to determine the key factors determining the success of thermal recovery in fractured, low-permeability reservoirs. Steam injection is shown to be superior to hot-water injection in heating the matrix. Key factors enhancing recovery include reduced fracture spacing, increased matrix permeability, and increased injection temperature. Model results indicate that steamflood recoveries of more than 40% of the original oil in place (OOIP) may be achieved by injection in diatomite containing light oil. Application to diatomites containing heavy oil also shows good performance. Successful application in diatomite reservoirs is forecast to be possible in the current low oil-price environment. Economic application in fractured shales, assuming similar imbibition behavior as in diatomites, would require a higher oil price because of the higher well costs and lower oil content relative to diatomite projects. Because of the significant volumes of remaining oil in place (OIP) in both the diatomite and shale reservoirs, the application of thermal enhanced oil recovery (EOR) to these resources represents the logical next step in steamflood development.

Experimental Investigation of Countercurrent Spontaneous Imbibition in Tight Sandstone Using Nuclear Magnetic Resonance

Tight oil reservoirs are an unconventional hydrocarbon resource with great potential to help meet energy demands. Horizontal drilling and hydraulic fracturing has been extensively used for the exploitation of these unconventional resources, and fracturing fluids absorbed into formations by spontaneous imbibition (SI) is an important mechanism of oil production. In this paper, imbibition experiments combined with nuclear magnetic resonance were conducted to study the characteristics of fluid displacement in an oil/water system for tight sandstone. In addition, the relative contribution to oil recovery of different types of pores, effects of boundary conditions, and different surfactants on imbibition recovery was determined via the T2 spectra of each sample. The results show that the tight sandstone features a multiscale pore structure, which is dominated by micropores and small mesopores. As the imbibition process begins, white oil is preferentially displaced from these relatively small pores by water and...

Scaling of counter-current imbibition recovery curves using artificial neural networks

Scaling imbibition curves are of great importance in the characterization and simulation of oil production from naturally fractured reservoirs. Different parameters such as matrix porosity and permeability, oil and water viscosities, matrix dimensions, and oil/water interfacial tensions have an effective on the imbibition process. Studies on the scaling imbibition curves along with the consideration of different assumptions have resulted in various scaling equations. In this work, using an artificial neural network (ANN) method, a novel technique is presented for scaling imbibition recovery curves, which can be used for scaling the experimental and field-scale imbibition cases. The imbibition recovery curves for training and testing the neural network were gathered through the simulation of different scenarios using a commercial reservoir simulator. In this ANN-based method, six parameters were assumed to have an effect on the imbibition process and were considered as the inputs for training the network. Using the 'Bayesian regularization' training algorithm, the network was trained and tested. Training and testing phases showed superior results in comparison with the other scaling methods. It is concluded that using the new technique is useful for scaling imbibition recovery curves, especially for complex cases, for which the common scaling methods are not designed.

A computational framework for immiscible three-phase flow in deformable porous media

Several soil decontamination processes and enhanced oil recovery techniques involve the co-existence of three immiscible fluids, such as water, a nonaqueous phase liquid and a gas. In this work, a computational framework based on the individual mass balance of each phase is developed, aimed at simulating three-phase flow in a deformable rock through the finite element method, without resorting to specific simplifications that are usually required by standard numerical schemes. Key ingredients of the model are: expression of the residual in terms of mass contents, consistent lumping of the storage terms in the residual and algorithmic (tangent) matrix, consistent integration rules, the use of a minimum relative permeability and a time marching scheme based on trapezoidal integration. Special convective boundary conditions are adopted for pressures to be consistent with the assumed rock wettability properties during co-current imbibition. The resulting numerical scheme can deal with arbitrary saturation and/or pressure boundary conditions. The model is tested by simulating gas injection tests, and both co- and counter-current water imbibition tests, in a deformable core. To assess the performance and robustness of the whole framework, sensitivity analyses are performed upon varying key constitutive, loading and numerical parameters.