Executive Summary


This is my first summary of an SPE Journal issue since becoming executive editor this past year. I am grateful to Randy Seright, a preceding and outstanding executive editor with whom I had the privilege of working as associate editor. He has been a patient mentor and one that I hope to model after. I am honored to serve along with colleagues that generously volunteer their precious time to serve our society. As a professional society, we should be thankful for counting with a staff that toils constantly to keep the operation moving forward smoothly. This is an amazing group of dedicated individuals that quietly and despite challenges maintain the highest standards of quality with a smile.

This issue presents 25 new papers in five categories as follows.


Production Engineering and Formation Damage. Mohammadzadeh et al. investigate formation damage by asphaltene precipitation using a custom-designed 60-ft slimtube-coil assembly packed with sand. Tests are performed on a well-characterized recombined live asphaltenic oil from the Gulf of Mexico (GOM), known to be problematic. The permeability and porosity of the porous medium were impaired by asphaltene as a result of pressure depletion. Extraction results confirm that the observed permeability impairment was indeed caused by asphaltene deposition in the middle and latter sections of the coil, where the pressure was less than the asphaltene onset pressure. With the success of this experiment, the same detailed analysis can be extended to a series of experiments to determine the effects of different key parameters on pressure-induced asphaltene impairment, including flow rate, wettability, and permeability.

Ratnakar et al. develop a quantitative, alternative method to determine asphaltene onset precipitation, and present new experimental data on interfacial tension/contact angle of live-oil and water systems at reservoir conditions. Their inferences indicate that near the wellbore, asphaltene deposition can lead to pore plugging, where a large number of pore volumes flow through the productive life of the well. In this scenario, the size of aggregates (of asphaltene) is an important factor, especially when the aggregates size is comparable to the pore size. In contrast, deep in the reservoir, the effects of asphaltene precipitation and deposition on interfacial properties are more important because this can lead to wettability alteration. Thus, the results of this technique can be used to assess the potential impacts deep in the reservoir.

Sun et al. investigate differences in the aggregate size and morphology of chemical additives, centered on (1) wax-particle sedimentation from diluted petroleum fluids in vial tests, (2) wax-crystal-particle-size distributions and morphology by dynamic light scattering (DLS) and polarized-light microscopy, and (3) the wetting state from the effect of water. Their study shows that a small amount of crystal modifier and dispersant can reduce crystal-particle size to the submicron scale and change the crystal morphology. They investigate the differences in the mechanisms of dispersants and crystal modifiers in bulk. Water, often coproduced with petroleum fluids, can significantly increase the effectiveness of dispersants by altering the wetting state of the wax-particle surface. Such enhancement is not found in crystal modifiers. Both additives used affect the rheology of petroleum fluids.

Vodorezov presents a new numerical model of inflow to a well with a zone of damaged permeability. The modeling strategy divides the wellbore and damaged permeability zone into numerous segments. The model is applicable for wellbores of different trajectories, including horizontal and multilateral wells. The paper presents the new approach to include depth-variable distribution of damage in skin-factor models. The provided numerical simulations show that the impact of this factor on horizontal-well productivity is significant. The results show that a skin-factor transformation proposed originally by Renard and Dupuy (1991) for a case of a uniformly damaged well can be used successfully for the referred-to analytical solutions, which makes them applicable for wells with an elliptic drainage area.

Vazquez et al. describe the automatic optimization of squeeze-treatment designs using an optimization algorithm, in particular particle-swarm optimization (PSO). The algorithm provides a number of optimal designs that result in squeeze lifetimes close to the target. To determine the most efficient design of the optimal designs identified by the algorithm, the following objectives were considered: operational-deployment costs, chemical cost, total-injected-water volume, and squeeze-treatment lifetime. Operational-deployment costs include the support vessel, pump, and tank hire. There might not be a single design optimizing all objectives, and thus the problem becomes a multiobjective optimization. Therefore, a number of Pareto optimal solutions exist. These designs are not dominated by any other design and cannot be bettered. Calculating the Pareto is essential to identify the most efficient design.

Al-Rbeawi revisits currently used techniques for analyzing reservoir performance and characterizing the horizontal-well productivity index (PI) in finite-acting oil and gas reservoirs. A practical approached is developed for (1) understanding pressure, pressure derivative, and PI behavior of bounded reservoirs drained by horizontal wells during transient- and pseudosteady-state production; (2) investigating the effects of different reservoir configurations, wellbore lengths, reservoir homogeneity or heterogeneity, reservoirs as single or dual porous media, and flow pattern in porous media whether it has undergone Darcy or non-Darcy flow; and (3) applying the concept of the PI derivative to determine the starting time of pseudosteady-state stabilized PI.


Improved Oil Recovery. Wang et al. use geochemical modeling to design and conduct a series of alkaline/surfactant/polymer corefloods to measure the surfactant retention in limestone cores using sodium hydroxide (NaOH). Two studies performed under different reservoir conditions show that NaOH significantly reduced the surfactant retention in Indiana Limestone. The NaOH solution high pH increases the negative surface charge of the carbonate and thereby favors lower adsorption of anionic surfactants. A low concentration of only approximately 0.3 wt% of NaOH can be used given its low molecular weight and its low consumption in limestone. Most carbonates contain gypsum or anhydrite, and therefore sodium carbonate (Na2CO3) is consumed by the precipitation of calcium carbonate (CaCO3). Results show that NaOH can be used in limestone reservoirs containing gypsum or anhydrite.

Shah et al. investigate the effects of the magnitude of permeability contrast on foam generation and mobilization. Experiments demonstrate foam generation during simultaneous flow of gas and surfactant solution across a sharp increase in permeability at field-like velocities. The experimental observations also validate theoretical predictions of the permeability contrast required for foam generation by “snap-off” to occur at a certain gas fractional flow. Pressure-gradient measurements across different sections of the core indicate the presence or absence of foam and the onset of foam generation at the permeability change. This is the first computed-tomography-assisted experimental study of foam generation by snap-off only, at a sharp permeability increase in a consolidated medium. The results of experiments reported in this paper have important consequences for a foam application in highly heterogeneous or layered formations. Not including the effect of heterogeneities on gas mobility reduction in the presence of surfactant could underestimate the efficiency of the displacement process.

By way of polymer flooding, Juárez-Morejón et al. study the influence of initial core wettability and flood maturity (volume of water injected before polymer injection) on final oil recovery. Model sandstone was flooded with partially hydrolyzed polyacrylamide (HPAM) at a concentration of 2,500 ppm in a moderate-salinity brine. The polymer solution was injected in the core at different waterflood-maturity times. Results show that the maturity of polymer injection plays an important role in final oil recovery, regardless of wettability. A difference of 15% in recovery is observed between early polymer flooding (0 PV) and late maturity (6.5 PV). The recovery factor obtained with water-wet cores is always lower (from 10 to 20%, depending on maturity) than the values obtained with intermediate-wet cores, raising the importance of correctly restoring core wettability. The influence of wettability can be explained by the oil-phase distribution at the pore scale. This study shows that in addition to wettability, the maturity of polymer flooding plays a dominant role in oil-displacement efficiency. Final recovery is correlated to the dispersion value at which polymer flooding starts. The highest oil recovery is obtained when the polymer is injected early.

Tang et al. investigate the effect of oil on foam through its effect on the two observed flow regimes. This research provides a practical approach and initial data for simulating foam enhanced oil recovery (EOR) in the presence of oil. A model sandstone and model oils mimicking the effect of oil on foam stability were used in this work. Coreflooding results show that oil affects both high- and low-quality regimes, with the high-quality regime being more sensitive to oil. In particular, oil increases the limiting water saturation (S*w) in the high-quality regime and also reduces gas-mobility reduction in the low-quality regime. A model fit assuming a fixed S*w and including shear thinning in the low-quality regime does not represent the two regimes when the oil effect is strong enough. In such cases, fitting S*w to each pressure-gradient contour and excluding shear thinning in the low-quality regime yield a better match to these data. The dependency of S*w on So is not yet clear because of the absence of oil-saturation data in this study. Furthermore, none of the current foam-simulation models capture the upward-tilting pressure-gradient contours in the low-quality regime.


Multiphase Flow in Porous Media. Andersen et al. present a generalized model of two-phase flow dependent on momentum equations from mixture theory that can account dynamically for viscous coupling between the phases and the porous media because of fluid/rock interaction (friction) and fluid/fluid interaction (drag). These momentum equations effectively replace and generalize Darcy’s law. The model is parameterized using experimental data from the literature. In particular, directly applying cocurrently measured relative permeability curves gives significantly different predictions than the generalized model. At high water/oil-mobility ratios, viscous coupling can lower the imbibition rate and shift the production from less countercurrent to more cocurrent compared with conventional modeling. Although the viscous-coupling effects are triggered by countercurrent flow, reducing or eliminating countercurrent production by means of the capillary backpressure does not eliminate the effects of viscous coupling that take place inside the core, which effectively lower the mobility of the system. It was further seen that viscous coupling can increase the remaining oil saturation in standard cocurrent-imbibition setups.


Kim and Kovscek study the critical gas saturation in permeable sands as a function of depletion rate and the presence of an aqueous phase. Voidage-replacement ratios (VRR = injected volume/produced volume) less than 1 were used to obtain pressure depletion with active water injection. Two of the oils are viscous Alaskan crudes with dead-oil viscosities of 87.7 and 600 cp, whereas the third is a light crude oil with a dead-oil viscosity of 9.1 cp. The critical gas saturation ranged from 4 to 16%. These values for critical gas saturation are consistent with the finding that the gas phase displayed characteristics similar to those of a foamy oil. For a given oil and depletion rate, the critical gas saturation was somewhat larger for VRR = 0 than it was for VRR = 0.7. The oil recovery correlates with the critical gas saturation. For the conditions tested, there was not a strong correlation of critical gas saturation over more than two orders of magnitude of the rate of pressure depletion, for a given VRR. Such behavior might be consistent with theoretical studies reported elsewhere that suggest that the critical gas saturation is independent of the pressure-depletion rate when the rate of depletion is small.

Hiller et al. investigate the effect of the length scale of wetting heterogeneities, close to the length scale of a pore, on capillary pressure saturation (CPS) curves and the United States Bureau of Mines (USBM) and Amott-Harvey (AH) wettability indices. Their study combines laboratory experiments and full-scale fluid-dynamics simulations using the multiphase stochastic-rotation dynamics (SRDmc) model. Four model systems were created using monodisperse glass beads. The surface properties of the beads were modified so that one-half of the surface area in each system was strongly hydrophilic and the other half was hydrophobic. An excellent agreement between the experimental and simulation results was found. All systems are classified as intermediate-wet on the basis of their AH and USBM indices. An examination of the capillary pressure curves shows that the opening of the stable hysteresis loop decreases monotonically as the length scale of the wetting heterogeneities is increased. Results suggest that macroscopic wettability indices could be used as indicators of ultimate recovery, but they are not suited to discriminate between the different flows that occur earlier in a mixed-wettability displacement process.

Deng and King present a new semianalytic method to examine the interaction between spontaneous and forced imbibition and to quantitatively represent the transient imbibition process. The methodology solves the partial-differential equation of unsteady-state immiscible, incompressible flow with arbitrary saturation-dependent functions using the normalized water flux concept, which is identical to the traditional Buckley-Leverett analysis. The result gives a universally inherent relationship between time, normalized water flux, saturation profile, and the ratio between cocurrent and total flux. The current analysis also develops a novel stability envelope outside of which the flow becomes unstable caused by strong capillary forces, and the characteristic dimensionless parameter shown in the envelope is derived from the intrinsic properties of the rock and fluid system, and it can describe the relative magnitude of capillary and viscous forces at the continuum scale. This dimensionless parameter is consistently applicable in both capillary-dominated and viscous-dominated flow conditions.

The research of Ghanbarian et al. proposes a new theoretical approach for identifying rock types on the basis of the permeability k and the formation-resistivity factor F and provides theoretical insights into, and sheds light upon, the parameters of the Winland equation, as well as those of other empirical models. They present a simple, but promising, framework and show that accurate identification of distinct petrofacies requires knowledge of the formation factor. They demonstrate that, although some rock samples might belong to the same type on the k-vs.1/F plot, they might appear scattered on the k-vs.-ϕ plot and, thus, could seemingly correspond to other types. The authors also show that each rock can be represented by a characteristic pore size Λ, which is a measure of dynamically connected pores. Accurate estimates of Λ indicate that it is highly correlated with the permeability.

Meyer uses an image-analysis technique called mathematical morphology to characterize porosity in laterally continuous pore networks from thin-section microphotographs. This study proposes a novel application of this technique and quantifies pore-throat angularity. Angularity can be measured from the throat toward the pore body so that the true geometry—biconic, parabolic, or hyperbolic—can be recognized. The technique is tested on simple geometries to demonstrate the correctness of the mathematic equations involved. Because all equations assume perfect, nonpixelated geometries while images are composed of square pixels, the accuracy of measurements depends strongly on image resolution. Pixelation causes significant fluctuations of ±2 to 10° around the correct angularity values that decrease in amplitude as image resolution increases. Finally, potential implications of this parameter on fluid-flow modeling are discussed.


Geomechanics. Nath et al. examine the effect of rock type by testing 60 samples of sandstone (Parker, Nugget, and Berea) and carbonate rocks under dry and saturated conditions with regard to lamination angle in laminated samples. A photogrammetry system is used to monitor the samples in a noncontact manner while conducting the indirect tensile experiment. The digital-image correlation (DIC) depends on the photogrammetry system, which helps to visualize and examine rock-fracture patterns from the recorded images of the rock before and after deformation by assessing the strain development in samples. Results show that (1) average tensile strength declines with increasing porosity for homogeneous, laminated, and heterogeneous rock specimens; (2) saturation reduces rock strength; (3) increase of lamination angle (from 0 to 90°) affects the tensile strength; (4) fracture patterns examined for homogeneous rocks are nearly centrally propagated and relatively linear; and (5) DIC results illustrate the fracture creation and propagation with consistent strain mapping.

To better understand multistage, multicluster hydraulic fracturing, Chen et al. develop a 2D model comprising a combination of a displacement discontinuity method for elasticity and a finite-volume method for lubrication. Furthermore, a universal tip asymptotic solution is adopted as a propagation criterion to locate the fracture front. Parametric studies reveal that the competition between simultaneous and single fracture growth is governed by dimensionless toughness, which represents the energy ratio of fracture-surface creation to fluid viscous dissipation. Numerical results also demonstrate that initial fracture geometric settings play an important role in this competition. A large initial length offset between two fractures will generate preferential growth for the longer fracture, even in the viscosity-dominated regime. The paper concludes by identifying the controlling parameters and their field applications, emphasizing that high injection rate, high fluid viscosity, and small initial fracture-size offset are beneficial to promoting the simultaneous growth at early time, which is important in enhancing reservoir permeability.

Kholy et al. propose an empirical equation to calculate the fracture-closure pressure as a function of the instantaneous shut-in pressure and the injection-formation rock properties. Such rock properties include formation permeability, formation porosity, initial pore pressure, overburden stress, formation Poisson’s ratio, and Young’s modulus. The empirical equation is developed using data obtained from geomechanical models and the core analysis of a wide range of injection horizons with different lithology types of sandstone, carbonate, and tight sandstone. The new empirical equation predicts the fracture-closure pressure using a single point of falloff-pressure data, the instantaneous shut-in pressure, without the need to conduct a conventional fracture-closure analysis. This allows the operator to avoid having to collect pressure data between shut-in and the time when the actual fracture closure occurs, which can take several days in highly damaged and/or very tight formations. Moreover, in operations with multiple-batch injection events into the same interval/perforations, as is often the case in cuttings/slurry-injection operations, the trends in closure-pressure evolution can be tracked even if the fracture is never allowed to close.

Huang et al. use a fully coupled finite-element/finite-volume code to model 3D hydraulically driven fractures that are under the influence of strong vertical variations in closure stress interacting with natural fractures. Slipping of a natural fracture, triggered by elevated fluid pressure from an intersecting hydraulic fracture, can induce both increases and decreases of normal stress in the minimum-horizontal-stress direction, toward the center and tip of the natural fracture, respectively. The interactions between hydraulic fractures, natural fractures, and geologic factors such as stress barriers in three dimensions are shown to be much more complex than in two dimensions. Although it is impossible to exhaust all the possible configurations, the ability of a 3D, fully coupled numerical model to naturally capture these processes is well-demonstrated.


Flow in Fractured Systems. Following the Cinco-Ley fracture model (Cinco-Ley et al. 1978) and the Luo-Tang wing model (Luo and Tang 2015a), Luo et al. develop a new fracture-unit model. By coupling the Fredholm integral equation for a fracture with a reservoir equation, they present a new semianalytical method in the Laplace domain, and an example of a Z-fold fracture is then presented to demonstrate the applicability of the fracture-unit model. The effects of fracture conductivity, fracture geometry, and branch length on the transient wellbore pressure are discussed in detail.

Wu et al. implement a triple-porosity conceptual model to characterize rock matrix, microvugs, and fractures. To capture the heterogeneity of fractures and vugs, macrofractures and vugs are represented explicitly with the discontinuum model. The boundaries of macrovugs and macrofractures are discretized into several elements. The boundary-element method is used to handle flow into macrofractures and vugs. The finite-difference method is applied to handle flow within macrofractures. The flow within macrovugs is assumed to be pseudosteady state. Results show that macrofractures and vugs cannot be handled with triple-continuum models analytically. The novelty of the new model is its ability to model the transient behavior of carbonate reservoirs with nonhomogeneous fractures and vugs. Furthermore, it provides an efficient method for characterizing the heterogeneity of multiscaled fractures and vugs.

Xia et al. present a new enriched and explicit method for simulation on multiscale discrete-fracture/matrix modeling (EE-DFM) on structured grids to decouple the mesh conformity between the porous media and the fractures. A hybrid structured EE-DFM is first introduced, and enrichments for different scales of fracture segments are proposed to locally enrich the conventional approximation space for representing the pressure solution surrounding multiscale fracture networks. They demonstrate the accuracy and flexibility of the method by performing a series of case studies and comparing the results with simple analytical solutions as well as with conventional numerical solutions. The results of long-term well-performance case studies are used to show the good computational efficiency of the proposed method when the complexity of fracture networks is increased. The potential of the proposed method to be incorporated into the multicontinuum concept for solving nonlinear gas transport in a shale reservoir is presented. The present study provides a promising framework for real-field multiscale discrete-fracture models for unconventional-reservoir simulations.

Chen et al. present a mesh-free approach to investigate transient behaviors in fractured media with complex fracture networks. Contributions of properties and geometries of fracture networks to the transient behaviors are analyzed systematically. The major finding is a total of eight transient behaviors in fractured porous media with complex fracture networks. Geometries of fracture networks have important impacts on the occurrence and the duration of some transient behaviors, which provide a tool to identify the fracture geometries. The fluid production in the fractured porous media is improved with high-conductivity (denser, larger) and high-complexity fracture networks.

Khanna et al. develop an analytical approach for identifying the optimal proppant column spacing that maximizes the effective conductivity. The latter parameter can guide the design of the proppant-injection schedule and well-perforation scheme. To demonstrate the approach, they conduct a parametric study under realistic field conditions and identify the folds of increase in fracture conductivity and reduction in proppant use resulting from the optimized application of the channel-fracturing technique. The study could be particularly useful in the application of the developed approach to soft rock formations.

Vladimir Alvarado, SPE J. Executive Editor,

University of Wyoming