Development Of Petroleum Reservoirs Research Articles

Effect of Crosslinker Types on Temporary Plugging Performance of Degradable Preformed Particle Gels for Unconventional Petroleum Reservoir Development

Temporary plugging agents (TPAs) have been widely used in unconventional petroleum reservoirs to increase the stimulated reservoir volume and generate an easier flow of oil and gas into the production well. The properties of particle-gel-based TPAs include a straightforward injection procedure, excellent deformation, strong plugging strength, and total self-degradation. This study prepared degradable preformed particle gel (DPPG) samples polymerized by two types of crosslinkers (i.e., alcohol ester and alkenoic acid ester) for low-temperature (less than 40 °C) reservoirs. The effects of different crosslinkers in the DPPG compositions on the temporary plugging performance were investigated. Infrared spectrum analysis, differential calorimetry scanning evaluation, static particle gel swelling and degradation performance assessment experiments, and dynamic temporary plugging performance tests were all employed. The results showed that the swelling ratio of DPPGs prepared by the crosslinker containing alcohol ester was larger than that of alkenoate acid ester, but the degradation rate was slower. Among them, when the amount of crosslinker was 0.01 g, the swelling ratio of DPPG prepared using the alcohol ester crosslinker was as high as 40 times, and the complete degradation time could be regulated between 80 and 360 h. When the type of crosslinker was the same, the influence of its molecular weight also significantly affected the performance of the particle gel. The plugging strength of DPPG prepared by different crosslinkers in cores was as high as 20 MPa. The DPPG prepared from the alcohol ester crosslinker caused less damage to the core after being self-degraded and was used as an ideal crosslinker. Infrared spectroscopy and differential scanning calorimetry analysis at the molecular level verified that different types of crosslinkers had apparent effects on the chemical structure stability of the DPPG. In this paper, the influence of the type of crosslinker on the performance of the DPPG was studied, which provides a new idea and theoretical basis for developing a particle gel-based TPA system with programmed self-degradation time at low temperatures.

Fault and top seals thematic collection: a perspective

Predicting the sealing capacity of faults and caprocks has been a long-standing uncertainty for those involved in the exploration, appraisal and development of petroleum reservoirs. In more recent years, interest in the topic has increased in a wide range of other applications, particularly those related to the decarbonization of our energy supply such as carbon capture and storage (CCS), radioactive waste disposal, geothermal energy production and underground energy storage (e.g. compressed air, hydrogen). Knowledge of how faults impact fluid flow is also important for management of drinking water supplies. To communicate new advances in research in these areas, the EAGE organized the first international conference on Fault and Top Seals in 2003. These conferences have continued to be held at roughly 4 yearly intervals and have brought together scientists from a wide range of disciplines to discuss new research findings and workflows relevant to predicting fault and top seal behaviour, as well as presenting case studies covering both successful and unsuccessful attempts to predict sealing capacity.Thematic collection: This article is part of the Fault and top seals collection available at: https://www.lyellcollection.org/cc/fault-and-top-seals-2019

A lateral photovoltaic detection for the anisotropic response of invisible-bedding tight shale

As the cap rock for oil and natural gas traps, tight shale with small interstitial spaces and invisible beddings were found to have large reserves and rich mining value. Precise identification of feature anisotropy in tight shale is of significance in the development of petroleum reservoirs. Here in this work, we demonstrate an application of a 532-nm laser to measure the lateral photovoltaic (LPV) response of a tight shale with the beddings invisible at different directions inside the upper surface. Although the layer orientations were not obviously for the tight shale, anisotropic response of LPV signals was observed with different peak amplitudes (Vp) as well as lateral and surface distributions. The bedding direction revealed by SEM was consistent with the LPV test results; meanwhile, a trigonometric angular-dependent Vp was observed, proving that the LPV measurements were able to predict the configuration orientation of tight shale with invisible beddings. Our results proved that the lateral photovoltaic response is sensitive to the structure of materials and thus has a great potential in the characterization of shale reservoirs.

A gradient boosting decision tree algorithm combining synthetic minority oversampling technique for lithology identification

Lithology identification based on conventional well-logging data is of great importance for geologic features characterization and reservoir quality evaluation in the exploration and production development of petroleum reservoirs. However, there are some limitations in the traditional lithology identification process: (1) It is very time consuming to build a model so that it cannot realize real-time lithology identification during well drilling, (2) it must be modeled by experienced geologists, which consumes a lot of manpower and material resources, and (3) the imbalance of labeled data in well-log data may reduce the classification performance of the model. We have developed a gradient boosting decision tree (GBDT) algorithm combining synthetic minority oversampling technique (SMOTE) to realize fast and automatic lithology identification. First, the raw well-log data are normalized by maximum and minimum normalization algorithm. Then, SMOTE is adopted to balance the number of samples in each class in training process. Next, a lithology identification model is built by GBDT to fit the preprocessed training data set. Finally, the built model is verified with the testing data set. The experimental results indicate that the proposed approach improves the lithology identification performance compared with other machine-learning approaches.

Permeability Evolution of Shear Failing Chalk Cores under Thermochemical Influence.

Development of petroleum reservoirs, including primary depletion of the pore pressure and repressurization during water injection naturally, leads to changes in effective stresses of the formations. These changes impose mechanical deformation of the rock mass with subsequent altering of its petrophysical properties. Besides mechanical compaction, chalk reservoirs on the Norwegian Continental Shelf also seem susceptible to mineralogical and textural changes as an effect of the injecting fluid’s chemical composition and temperature. Understanding such chemical and thermal effects and how they interplay with the mechanical response to changes in effective stresses could contribute to improved prediction of permeability development during field life. This article presents results from mechanical testing of chalk cores of medium-porosity (32%) outcrop chalk (Niobrara Formation, Kansas) in triaxial cells. The experimental setup allows systematic combinations of fluctuating deviatoric stress, temperature (50 and 130 °C), and injecting fluid (calcite-equilibrated sodium chloride, calcite-equilibrated sodium sulfate, and reactive synthetic seawater) intended to replicate in situ processes, relevant to the North Sea chalk reservoirs. Deviatoric loading above yield resulted in a shear failure with a steeply dipping fracture of the core and a simultaneous increase in permeability. This occurred regardless of the brine composition. The second and third deviatoric loadings above yield did not have the same strong effect on permeability. During creep and unloading, the permeability changes were minor such that the end permeability remained higher than the initial values. However, sodium sulfate-injected cores retained most of the permeability gain after shear fracturing compared to sodium chloride and synthetic seawater series at both temperatures. Synthetic seawater-injected cores registered the most permeability loss compared to the other brines at 130 °C. The results indicate that repulsive forces generated by sulfate adsorption contribute to maintain the fracture permeability.

Detailed Description of the Geomechanical Interaction Between a Cohesive Hydraulic Fracture and a Natural Fracture in Saturated Poroelastic Media

Hydraulic fracturing is an important technique in unconventional petroleum reservoir development. In this paper, a numerical algorithm is used to study the interaction of a propagating hydraulic fracture with a natural fracture in an infinite saturated porous domain. It is shown that this model can appropriately simulate two possibilities which might occur during the hydraulic fracturing of naturally fractured reservoirs. The variations of bottom-hole pressure and crack mouth opening displacement through time are completely described. It is shown that how the coupling between fluid pressure and discontinuities deformation influences the variation of bottom-hole pressure as a measurable parameter through time.

A novel approach to assessing the anisotropic permeability parameters of fractured media

The fracture permeability in is very high and directional, which brings a series of problems for the petroleum reservoir development, such as earlier water breakthrough and low sweep efficiency. It is vital to accurately characterize fractures and acquire the parameters of fracture permeability to alleviate these issues, which are favorable for well pattern design and flow modeling. Permeability tensor is employed to comprehensively and expediently reflect the effect of fracture anisotropy on the fluid diversion. Based on information of fracture log and production, the complete permeability tensors of single group fractures and multiple group fractures are identified, where the coordinate transformation theory and tensor property are used. With the simplified form of the derived full permeability tensor, the anisotropic parameters, principal values and principal directions of permeability for the fractured reservoir, can then be calculated. The proposed method integrates the static characterization and percolation feature of fractures and can be applied merely into field practices of naturally fractured reservoir. This work is beneficial for the management of fractured reservoir and optimization of field development.

Ensemble-based big data analytics of lithofacies for automatic development of petroleum reservoirs

Big data-driven ensemble learning is explored in this paper for quantitative geological lithofacies modeling, which is an integral and challenging part of petroleum reservoir development and characterization. Quantitative lithofacies modeling involves detection and recognition of underlying subsurface rock’s lithofacies. It requires real-time data acquisition, handling, storage, conditioning, analysis, and interpretation of raw sensory petroleum logging data. The real-time well-logs data collected from the sensor-based tools suffer from complications such as noise, nonlinearity, imbalance, and high-dimensionality which makes the prediction task more challenging. The existing literature on quantitative lithofacies modeling includes several data-driven techniques ranging from conventional well-logs to artificial intelligence (AI). Recently, multiple classifiers based Ensemble learners have been found to be more robust and reliable paradigms for detection and identification tasks in various machine learning applications, however, these are not well embraced in the petroleum industry. Ensemble methodology combines diverse expert’s opinions to obtain overall ensemble decision which in turn reduces the risk of a wrong decision. Thus, the uncertainties associated with complex reservoir data can be better handled by the use of Ensemble learners than the existing single learner based conventional models. Ensemble-based big data analytics, proposed in the paper, includes development and comparative performance testing of five popular ensemble methods (viz. Bagging, AdaBoost, Rotation forest, Random subspace, and DECORATE) for quantitative lithofacies modeling. Seven state-of-the-art base classifiers were used as members of different Ensemble learners for the analysis of Kansas (U.S.A.) oil-field data. The proposed techniques have been implemented on the widely used WEKA platform. The comparative performance analysis of the proposed techniques, presented in the paper, confirms its supremacy over the existing techniques used for quantitative lithofacies modeling.

Decision-theoretic sensitivity analysis for reservoir development under uncertainty using multilevel quasi-Monte Carlo methods

At various stages of petroleum reservoir development, we encounter a large degree of geological uncertainty under which a rational decision has to be made. In order to identify which parameter or group of parameters significantly affects the output of a decision model, we investigate decision-theoretic sensitivity analysis and its computational issues in this paper. In particular, we employ the so-called expected value of partial perfect information (EVPPI) as a sensitivity index and apply multilevel Monte Carlo (MLMC) methods to efficient estimation of EVPPI. In a recent paper by Giles and Goda, an antithetic MLMC estimator for EVPPI is proposed and its variance analysis is conducted under some assumptions on a decision model. In this paper, for an improvement on the performance of the MLMC estimator, we incorporate randomized quasi-Monte Carlo methods within the inner sampling, which results in an multilevel quasi-Monte Carlo (MLQMC) estimator. We apply both the antithetic MLMC and MLQMC estimators to a simple waterflooding decision problem under uncertainty on absolute permeability and relative permeability curves. Through numerical experiments, we compare the performances of the MLMC and MLQMC estimators and confirm a significant advantage of the MLQMC estimator.

Subsidence transition during the post-rift stage of the Dongpu Sag, Bohai Bay Basin, NE China: A new geodynamic model

The Dongpu Sag, located in the Bohai Bay Basin, NE China, is a Cenozoic continental rift basin. The post-rift evolution of the Dongpu Sag is associated with the development of petroleum reservoirs and has implications for Neogene–Quaternary basin evolution along the eastern margin of Eurasia. To determine the nature and origin of post-rift subsidence in the Dongpu Sag, we apply backstripping, modified strain-rate inversion, and revised finite extension modelling techniques, using data from 14 real and synthetic wells that are intersected by three seismic lines. Our results reveal discrepancies by subsidence based on backstripping of well data (the observed subsidence) minus that predicted by modified strain-rate inversion and revised finite extension modelling (the predicted subsidence). During the Miocene, the observed subsidence was smaller than the predicted subsidence, leaving negative discrepancies referred to here as “insufficient subsidence” ranging from −343 to −96 m. In contrast, during the Pliocene–Quaternary the observed subsidence was greater than the predicted subsidence by +123 to +407 m, which left positive discrepancies referred to as “over-sufficient subsidence”. Therefore, we infer a transition from insufficient to over-sufficient subsidence during the post-rift stage. Normal faulting that started at ca. 5.3 Ma is estimated to have produced only ∼20% of the over-sufficient subsidence. Therefore, the remaining over-sufficient subsidence, as well as the preceding insufficient subsidence and the transition between the two, were likely controlled by lithosphere processes. We propose a new tectonic model in which variations in the conditions (e.g. rate, direction, and angle) associated with subduction of the Pacific plate resulted in a change of heat flow decreasing from a linear to a curvilinear pattern, leading to a transition from insufficient to over-sufficient subsidence.

Absolute Permeability Upscaling for Superelement Modeling of Petroleum Reservoir

A technique for local upscaling of absolute permeability is proposed intended for the superelement modeling of petroleum reservoir development. The upscaling is performed for every block of an unstructured superelement grid based on solving a series of stationary one-phase flow in reservoir problems on a refined grid with the initial permeability field under various boundary conditions reflecting the characteristic structural variants of the filtrational flow and taking into account the presence or absence of wells inside the block. The resulting components of the effective permeability tensor in each superelement are sought from the solution of the problem on minimizing the deviations of the normal flows through the faces of the superelement averaged on a refined computational grid from those approximated on a coarse superelement grid. The application of the method is demonstrated by examples of the reservoir of the periodic and nonperiodic structure. The method is compared with the traditional techniques for local upscaling.

An integrated approach in determination of elastic rock properties from well log data in a heterogeneous carbonate reservoir

Elastic rock properties are of particular importance for development of petroleum reservoirs. This paper demonstrates the adoption of an integrated multi-disciplinary practice workflow for determination of rock elastic properties. Since the availability of reliable sonic wave velocity leads to the improvement of determination of elastic rock properties, a rigorous data mining procedure is established to predict compressional wave velocity (Zoveidavianpoor et al., 2013a, 2013b; Zoveidavianpoor, 2014). Then, two empirical correlations are developed for measurement of shear wave velocity (Vs) and static Young's modulus (Es) and the results were compared with the literature. Correlation coefficients are used as criteria for checking whether the given results are appropriate for the purpose. The proposed framework has been applied successfully to a heterogeneous Middle Eastern carbonate reservoir. The predictions were in excellent agreement with the core data. Also, it was observed that the proposed correlations for Vs and Es provide better estimation when compared with the commonly used correlations in carbonate reservoirs. The results support the robustness of the proposed integrated approach for production decisions in developing a mature heterogeneous carbonate reservoir, which had previously not been possible.

Virtual multi-offset reflection profiling with interferometric imaging for borehole radar

Interferometry is one of the most advanced signal-processing and imaging techniques. It is widely used in geophysical detection and remote sensing. Application of interferometric processing significantly improves the resolution in geophysical imaging. This paper reports the application of an interferometric imaging approach to cross-hole multi-offset transmission (CHMOT) borehole radar data to generate a virtual single-hole, multi-offset reflection (SHMOR) profile with the validation of a real SHMOR data set. In subsurface material property imaging, SHMOR is an effective technique for interface and fracture detection. However, borehole radar survey in SHMOR fashion is not practical for most cases. Transforming cross-hole transmission mode radar data to virtual single-hole, multi-offset reflection data using a wave interferometric virtual source (WIVS) approach was proposed previously but not fully validated with real SHMOR data. In this study, we compare WIVS-derived virtual SHMOR to real SHMOR profiles using data sets acquired in two boreholes (SIMA1 and SIMA2) drilled into crystalline igneous bedrocks. As the calibration and validation, the reflection from borehole SIMA2 (as the known object) is clearly imaged by both the real and WIVS-derived virtual SHMOR profiles in SIMA1. The diffractions and amplitude decay from sharp stratigraphic change also registered at both the real and WIVS-derived virtual SHMOR profiles. The results of this study demonstrate the potential of the WIVS approach to improve structural imaging in bedrocks for hydrogeological, geothermal, and petroleum reservoir development applications.

A multi-continuum multiple flow mechanism simulator for unconventional oil and gas recovery

Reservoir simulator constitutes the core of data analysis in petroleum reservoir development. With industry's advancements in unconventional resources, such as CBM, shale gas and shale oil, new recovery mechanisms have been identified. However, it may be impractical to implement some of the relevant mathematical models in simulators that are originally designed for conventional problems. In this work, we developed the UNConventional Oil and Gas simulator (UNCONG) under a more flexible architecture. UNCONG is based on the black oil model and the compositional model but does more than just to cover the aspects of traditional models. It possesses several noticeable features, which enable it to handle unconventional oil and gas problems more properly: 1) it provides multiple ways to model fractures and allows to mix structured and unstructured grid; 2) it uses the multi-point flux approximation (MPFA) to guarantee the accuracy of flow terms in non-K-orthogonal grid; 3) it realizes a flexible flow equation framework to incorporate various permeability models, in which the diffusion and the geomechanic effects can be considered; and 4) the linear solver is tailored for problems containing MPFA and complex wells. UNCONG is parallelized on shared memories, and has shown good acceleration ratio in limited tests. UNCONG has been validated with commercial simulators in conventional problems and successfully applied in studying the mechanisms of unconventional oil and gas recovery, producing reasonable and self-consistent results. Moreover, owing to its robustness, efficiency, and user-friendliness, UNCONG is in fact applicable to more realistic industrial problems.

Unconformities and their influence on lower Paleozoic petroleum reservoir development in the Tarim Basin

Abstract Ten regional unconformities punctuate the Lower Paleozoic carbonate succession of Tarim Basin. They can be divided into three orders and include four unconformity types. According to their extents and intensities of development, they can be categorized into three orders, a first-order unconformity of great lateral extent and depth of erosion, and second-order and third-order unconformities of lesser extent and erosional intensity. From the viewpoint of their origins, these unconformities can be classified into four types, structural unconformities, long-term exposure unconformities, synchronous sedimentary exposure unconformities and superimposed unconformities that include combinations of the previous three types. Through analyses of the geographic distribution of unconformity types across the geographic extents of the 10 unconformities and their temporal evolution, it was determined that unconformities of various orders have different effects on the development of carbonate reservoir beneath these unconformities. First-order and second-order unconformities are prominent in the development of karst reservoir of the Tarim Basin. Periodic exposure of carbonate rocks which occurs during erosion that generated third-order unconformities contributed to the development of multiple karst intervals. In addition, the abundance and size of karst intervals in progradational strata increased during sea level falls. Origins of unconformities control scales and types of karst reservoirs. Tectonic (angular) unconformities developed during tectonic uplift and denudation, which controlled the development of weathering crust karst reservoirs within zones containing buried-hill (e.g. low paleo-uplift). Long-term exposure (parallel) unconformities formed during long-term sea level fall which controlled the development of regional interlayer karst reservoirs within the platform. Synchronous sedimentary exposure unconformities formed due to intermittent exposure caused by sedimentary basinal infilling and subdued sea level fluctuations which controlled the development of penecontemporaneous karst reservoirs of smaller geographic extent along platform margins. Superimposed unconformities formed due to multiple superposed tectonic movements, which caused the superposition of multiple weathering crusts as individual karst reservoirs, or the stacking of karst reservoirs developed beneath different unconformity types.

Development of a Capillary Rheometer for the Characterization of Heavy and Extra-Heavy Oils

Viscosity and flow behavior of crude oils are key properties for the characterization, management, and development of petroleum reservoirs. To measure the rheological properties of heavy crude oils with a high accuracy, a capillary rheometer was designed and built at the Ruhr University in Bochum (RUB), Germany. The capillary rheometer was calibrated with three Newtonian reference blends of 1000, 10 000, and 50 000 mPa s. For these standards, the viscosity tables have been extended up to 1000 bar in the temperature range of 20–120 °C. The extended viscosity data were determined with a falling body viscometer at the Universidad Nacional Autónoma de México (UNAM), obtaining average deviations better than 2.0% at high pressure. The capillary rheometer is then calibrated with the same reference fluids at 40, 60, 80, and 100 °C at pressures from 1 to 260 bar. The deviation from the reference value was found to be lower than 3% at high pressure. The flow behavior of a heavy oil sample is determined at 80, 100, and 120 °C at atmospheric pressure. Furthermore, the viscosity is measured from atmospheric pressure to 180 bar. The investigated heavy oil shows a Newtonian behavior at high temperatures. This is consistent with rheological measurement carried out at UNAM. The viscosity increases with increasing pressure at all temperatures. For example, at 40 °C, the viscosity increases by about 35% by increasing the pressure from 1 to 100 bar.

A viscosity prediction model for Kuwaiti heavy crude oils at elevated temperatures

Abstract Viscosity is a key fluid property for characterization, evaluation, management and development of petroleum reservoirs. The accurate prediction of dynamic viscosity will be helpful for heavy oil recovery methods including primary production, thermal production, and enhanced oil recovery (EOR). Reservoir oil viscosity is usually measured isothermally at reservoir temperature. However, at temperatures other than reservoir, dynamic viscosity is estimated by empirical correlations. Most of the published correlations have been performing well at the reservoir temperature, especially for conventional crudes. However, the published literature has lack of reliable methods for viscosity estimation due to an acute shortage of dead oil data at elevated temperatures. These methods are essential and employed in planning thermal recovery methods (Kuwait as well as worldwide). In this study, the API gravity and viscosity of 50 dead crude oil samples collected from various areas of Kuwaiti oil fields were measured. These oil samples have API gravity ranging from 10° to 20°. The viscosities were determined at temperatures ranging from 20 °C to 160 °C. Consequently the results of the heavy oil viscosity data were used to develop a reliable model and to compare the proposed model with the published models. Both quantitative and qualitative analytical methods were implemented using statistical parameters and performance plot, respectively. From the general evaluation it has been shown that the proposed model has the lowest average absolute error of 11.04% and highest coefficients of correlation of 92% for training and 96% for the testing data. The performance of the proposed correlation has also been tested using dead heavy crude oil data from the region as well as various parts of the world. Compositional data of heavy oil viscosity has been used to compare predicted viscosity from the proposed correlation with that from Lorenz–Bray–Clark (LBC) and Pederson models. These comparisons show that the proposed correlation performed better than the other correlations, corresponding state and EOS-based methods for the dead heavy crude oils considered.

A transient fully coupled thermo-poroelastic finite element analysis of wellbore stability

Stress variations around wellbores and in the reservoirs are of much interest in subsequent drilling operations, future production, and petroleum reservoir development. Stress variations induced by in situ stresses, pore pressure, and temperature changes during drilling operations may lead to various modes of instabilities in forms of induced fractures and borehole breakouts. Previous studies of thermally induced stresses were primarily based on either assumptions of heat conduction through rock matrix or heat convection, in this case, without considering the effect of solid grain thermal conductivity. To analyze wellbore stability, in the present work, a thermo-poro-mechanical model that is fully coupled to conductive and convective transport processes is employed. Then using a two-dimensional finite element method, the stress distribution around an open borehole is investigated. Further, four rock strength criteria, Mohr–Coulomb, Drucker–Prager, modified Lade, and Mogi–Coulomb, are used to examine wellbore stability of both vertical and inclined boreholes. Results show that there are considerable differences between radial and tangential stresses simulated from models containing coupled conductive and conductive-convective transport processes. Shear stress distribution around borehole, resulted from interaction of borehole inclination and in situ stresses, is found to be an important factor affecting stability conditions of inclined wellbore. In the case of rock failure criteria, Mohr–Coulomb results in the highest values of the minimum mud weight required for wellbore stability; Drucker–Prager gives the lowest values, modified Lade, and Mogi–Coulomb result in mean values for the minimum mud weight required for wellbore stability.

Automatic Calibrate Map System of Logging Curves Based on C/S

The calibration of the depth of well logging curves peak is an important process of perforation, the rational selection and depth identification accuracy of the peak is the key of calibrated map. A method of automatic calibrated map of logging curves based on C/S is put forward in this paper. In this method, the logging curve data is loaded and saved through the analysis of data, and the position of the peak is judged on the method of relative value, then, the precise peak depth value is calculated. The experimental results demonstrate that the method of automatic calibrated map has better speed and high accuracy, and it provides reliable and accurate data for petroleum reservoir development.

Experimental investigation of nonequilibrium capillarity effects: Fluid viscosity effects

Numerical models have been widely used to simulate multiphase flow in porous media for a variety of applications (e.g., NAPL migration in subsurface aquifers, carbon sequestration, agriculture, paper production, and petroleum reservoir development). The relationship between the difference in phase pressures and saturation is used as one of the important constitutive relationships in numerical models. Theoretical studies have suggested that this relationship should include a damping coefficient or capillarity coefficient () on the basis of thermodynamic considerations. A literature review suggests that the magnitude of this capillarity coefficient varies by over three orders of magnitude. While recent experimental studies have explored the effect of porous medium properties, effect of domain size, hysteresis, and the imposed boundary conditions on the magnitude of , there has been no experimental study investigating the impact of fluid viscosity on . This study reports on a series of primary drainage experiments conducted under both static and dynamic conditions in F70 silica sand. Fluid pairs used included water and silicone oil with two differing viscosities and slightly different densities (used as model nonaqueous phase liquids) in addition to air. Water saturation and both wetting and nonwetting phase pressures were measured in a custom‐built aluminum column using EC‐5 probes and tensiometers at three levels. Results show a strong dependence of the magnitude of the capillarity coefficient on effective fluid viscosity. This implies that consideration should be given for the inclusion of a capillarity coefficient in modeling tools used to simulate multiphase flow when fluids saturations are changing rapidly and when fluids have a large viscosity ratio.