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Guest Editorial

J. Energy Resour. Technol. 2014;136(4):040301-040301-2. doi:10.1115/1.4029005.
Commentary by Dr. Valentin Fuster

Research Papers

J. Energy Resour. Technol. 2014;136(4):041001-041001-8. doi:10.1115/1.4028271.

The effect of free gas on electrical submersible pump (ESP) performance is well known. At a constant rotational speed and constant liquid flow rate, a small amount of gas causes a mild head reduction when compared to the single phase liquid head. However, at higher gas rates, a drastic reduction in the head is observed. This critical condition, known as the surging point, is a combination of liquid and gas flow rates that cause a maximum in the head performance curve. The first derivative of the head with respect to the liquid flow rate changes sign as the liquid flow rate crosses the surging point. In several works on ESP two-phase flow performance, production conditions to the left of the surging region are described or reported as unstable operational conditions. This paper reviews basic concepts on stability of dynamical systems and shows through simulation that ESP oscillatory behavior may result from two-phase flow conditions. A specific drift flux computation code was developed to simulate the dynamic behavior of ESP wells producing without packers.

Commentary by Dr. Valentin Fuster

Research Papers: Petroleum Engineering

J. Energy Resour. Technol. 2014;136(4):042901-042901-6. doi:10.1115/1.4027567.

Shale caprock integrity is critical in ensuring that subsurface injection and storage of anthropogenic carbon dioxide (CO2) is permanent. The interaction of clay-rich rock with aqueous CO2 under dynamic conditions requires characterization at the nanoscale level due to the low-reactivity of clay minerals. Geochemical mineral–fluid interaction can impact properties of shale rocks primarily through changes in pore geometry/connectivity. The experimental work reported in this paper applied specific analytical techniques in investigating changes in surface/near-surface properties of crushed shale rocks after exposure (by flooding) to CO2–brine for a time frame ranging between 30 days and 92 days at elevated pressure and fractional flow rate. The intrinsically low permeability in shale may be altered by changes in surface properties as the effective permeability of any porous medium is largely a function of its global pore geometry. Diffusive transport of CO2 as well as carbon accounting could be significantly affected over the long term. The estimation of permeability ratio indicated that petrophysical properties of shale caprock can be doubled.

Commentary by Dr. Valentin Fuster
J. Energy Resour. Technol. 2014;136(4):042902-042902-8. doi:10.1115/1.4027691.

Numerous multizone multistage hydraulic fracturing treatments are now being executed in low permeability oil and gas fields around the world. Due to the limited access to the subsurface, post-treatment assessments are mainly limited to few techniques such as tiltmeter, microseismic, and tracer-logs. The first two techniques are mainly used to determine fracture extension; however, fracture height and fracture initiation at all perforation clusters could only be confirmed through radioactive tracer logs or detailed pressure analysis. In this paper, we consider real examples from a field from Central America and investigate potential problems that led to the limited generation of fractures in multizone treatments. For instance, some of the postfrac radioactive logs show very low concentration of tracers at some perforated zones in comparison with other zones. On the other hand in some cases, tracer logs indicate the presence of tracers in deeper or shallower zones. Different reasons could cause fracture growth in nonperforated zones, including but not limited to: perforation design problems, casing/cement integrity problems, lack of containment, instability of fracture growth in one or some of the zones, and finally making a mistake in selecting lithology for fracturing. In this paper, some of these issues have been examined for a few sample wells using treatment pressure data, petrophysical logs, and postfrac tracer logs. Some recommendations in designing the length and arrangement of perforations to avoid these problems in future fracturing jobs are provided at the end of this paper.

Commentary by Dr. Valentin Fuster
J. Energy Resour. Technol. 2014;136(4):042903-042903-9. doi:10.1115/1.4027572.

Over the past two decades, the modeling of flow in a perforated pipe with influx through wall openings has been recognized as a key topic especially in the field of horizontal wells. In this paper, based on the theoretical analysis and previous research achievements, combining with the new measured data sets stemming from the large-scale experimental apparatus designed and constructed recently at China University of Petroleum (CUP), a new comprehensive model has been developed for the prediction of pressure drop regarding single-phase flow in horizontal perforated pipes with wall influx, in which new correlations for calculating the hydraulic friction factor and momentum correction factor of variable mass flow are given. The presented model is then implemented using the visual basic.net package and validated against two data sets obtained on single-phase water flow and single-phase oil flow. Predictions of the new model and frequently used Ouyang model are also compared based on the new experimental data. Results show that the model given in this article can not only properly represent the complex mechanisms of flow in the horizontal wellbore, such as the resistance caused by wall perforations and the drag reduction or so-called lubrication effect caused by wall injection, but also has a preferable prediction accuracy. Compared with the water flow data and the oil flow data, the absolute average percentage errors of the proposed model are, respectively, 4.5% and 5.0%, which demonstrates better performance and wider application range than Ouyang model.

Commentary by Dr. Valentin Fuster
J. Energy Resour. Technol. 2014;136(4):042904-042904-11. doi:10.1115/1.4028692.

In this paper, results of a numerical study on pore continuity, permeability and durability of cementitious slurries for carbon sequestration projects are presented. The hydration model Hymostruc is used to simulate and visualize 3D virtual microstructures which are used to demonstrate the contribution of capillary pores to the continuity of the capillary pore system embedded in an evolving cementitious microstructure. Once capillary pores are blocked due to ongoing hydration, transport of CO2 species through the microstructure is avoided which may protect the slurry from leakage. Evaluating the pore continuity of the capillary pore system during hydration of the microstructure is therefore indispensable for a robust cementitious sealing material and is the main objective for slurry design. Simulations are conducted on slurries exposed to ambient temperatures of 20 °C, 40 °C, and 60 °C, and a durability outlook regarding the CO2 ingress is given as well. Aggregates and associated interfacial transition zones (ITZs) are introduced in the slurry system that may cause alternative porous path ways through the system. Pore continuity analysis shows the relevance of numerical simulations for assessing the capillary pore structure inside an evolving microstructure in relation to its sealing and durability performance.

Commentary by Dr. Valentin Fuster
J. Energy Resour. Technol. 2014;136(4):042905-042905-9. doi:10.1115/1.4028690.

The creation of large complex fracture networks by hydraulic fracturing is imperative for enhanced oil recovery from tight sand or shale reservoirs, tight gas extraction, and hot-dry-rock (HDR) geothermal systems to improve the contact area to the rock matrix. Although conventional fracturing treatments may result in biwing fractures, there is evidence by microseismic mapping that fracture networks can develop in many unconventional reservoirs, especially when natural fracture systems are present and the differences between the principle stresses are low. However, not much insight is gained about fracture development as well as fluid and proppant transport in naturally fractured tight formations. In order to clarify the relationship between rock and treatment parameters, and resulting fracture properties, numerical simulations were performed using a commercial discrete fracture network (DFN) simulator. A comprehensive sensitivity analysis is presented to identify typical fracture network patterns resulting from massive water fracturing treatments in different geological conditions. It is shown how the treatment parameters influence the fracture development and what type of fracture patterns may result from different treatment designs. The focus of this study is on complex fracture network development in different natural fracture systems. Additionally, the applicability of the DFN simulator for modeling shale gas stimulation and HDR stimulation is critically discussed. The approach stated above gives an insight into the relationships between rock properties (specifically matrix properties and characteristics of natural fracture systems) and the properties of developed fracture networks. Various simulated scenarios show typical conditions under which different complex fracture patterns can develop and prescribe efficient treatment designs to generate these fracture systems. Hydraulic stimulation is essential for the production of oil, gas, or heat from ultratight formations like shales and basement rocks (mainly granite). If natural fracture systems are present, the fracturing process becomes more complex to simulate. Our simulations suggest that stress state, in situ fracture networks, and fluid type are the main parameters influencing hydraulic fracture network development. Major factors leading to more complex fracture networks are an extensive pre-existing natural fracture network, small fracture spacings, low differences between the principle stresses, well contained formations, high tensile strength, high Young’s modulus, low viscosity fracturing fluid, and large fluid volumes. The differences between 5 km deep granitic HDR and 2.5 km deep shale gas stimulations are the following: (1) the reservoir temperature in granites is higher, (2) the pressures and stresses in granites are higher, (3) surface treatment pressures in granites are higher, (4) the fluid leak-off in granites is less, and (5) the mechanical parameters tensile strength and Young’s modulus of granites are usually higher than those of shales.

Commentary by Dr. Valentin Fuster
J. Energy Resour. Technol. 2014;136(4):042906-042906-7. doi:10.1115/1.4028691.

Field trials and physical modeling of wells with downhole water sink (DWS) completions have demonstrated controlled water coning and increased oil production rate. However, no field trials were long enough to show DWS potential in improving of oil recovery in comparison with conventional wells. Presented here are theoretical and experimental results from a DWS recovery performance study. The recovery study involved experiments with a physical model and computer simulations. The experimental results reveal that DWS dramatically accelerates the recovery process; a fivefold increase of the oil production rate was reached by adjusting the water drainage rate at the bottom completion. The results also show a 70% increase of oil recovery; from 0.52 to 0.88 for conventional and DWS completions, respectively. The computer-simulated experiments with commercial reservoir simulator demonstrate progressive improvement of recovery with downhole water drainage from 0.61 to 0.79 with no drainage and maximum drainage, respectively—a 24% increase of recovery factor, and a fivefold reduction of the time required to reach the limiting value of water cut, 0.98. However, the accelerated recovery process with DWS requires a substantial, up to 3.5-fold, increase of total water production. The simulation experiments also show that the main advantage of using DWS is its flexibility in controlling the recovery process. For conventional completions, recovery could be slightly increased by reducing production rates and largely increasing production times. For DWS, a combination of the top and bottom rates could be optimized for maximum recovery and minimum production time.

Commentary by Dr. Valentin Fuster
J. Energy Resour. Technol. 2014;136(4):042907-042907-7. doi:10.1115/1.4028770.

In this study, the authors have attempted to present five different profiles for a uniform radial influx through a perforated wellbore. The total pressure drop is not only frictional, accelerational and gravitational pressure drops, but also by the inflow pressure drop that is caused by the inflow through the perforation. The inflow through the wellbore model affects the shear stress due to the wall friction. The influence of inflow depends on the flow regime present in the wellbore. Numerical simulations were performed using ansys fluent 14-cfx, where the governing equations of mass and momentum were solved simultaneously, using the two equations of a standard k–ε turbulence model. The results proved that the behavior of wall shear stress followed the shape of the radial inflow, i.e., the shear stress increased with the increase of radial flow and decreased with the decrease of radial flow. It was found that the fluid influx has increased the apparent friction factor along the horizontal wellbore, but in some cases the influx is decreased.

Commentary by Dr. Valentin Fuster
J. Energy Resour. Technol. 2014;136(4):042908-042908-5. doi:10.1115/1.4027566.

Flood experiments were conducted over 30-day periods at 14.48 MPa (2100 psi) confining pressure and temperature of 22 °C (72 °F) with cement–sandstone composite cores and brine at a flow rate of 1 ml/min. Higher pH values were observed in the effluent brine from the 10% mud contaminated core than the 0% mud contaminated core due to increased dissolution of cement. Microtomography revealed higher porosity at the interface zone of the 10% mud contaminated core. These show that mud contamination has a deleterious effect on the cement–sandstone interface and may create pathways for interzonal communication as well as sustained casing pressure.

Commentary by Dr. Valentin Fuster
J. Energy Resour. Technol. 2014;136(4):042909-042909-10. doi:10.1115/1.4027565.

Keeping the drilling fluid equivalent circulating density in the operating window between the pore and fracture pressure is a challenge, particularly when the gap between these two is narrow, such as in offshore, extended reach, and slim hole drilling applications usually encountered in shale gas and/or oil drilling. To overcome this challenge, accurate estimation of frictional pressure loss in the annulus is essential. A better estimation of frictional pressure losses will enable improved well control, optimized bit hydraulics, a better drilling fluid program, and pump selection. Field and experimental measurements show that pressure loss in annuli is strongly affected by the pipe rotation and eccentricity. The major focus of this project is on a horizontal well setup with drillstring under compression, considering the influence of rotation on frictional pressure losses of yield power law fluids. The test matrix includes flow through the annulus for various buckling modes with and without the rotation of the inner pipe. Sinusoidal, helical, and transition from sinusoidal to helical configurations with and without the drillstring rotation were investigated. Helical configurations with two different pitch lengths are compared. Eight yield power law fluids are tested and consistent results are observed. The drillstring rotation patterns and buckling can be observed due to experimental facility's relatively longer and transparent test section. At the initial position, inner pipe is lying at the bottom due to its extensive length, suggesting a fully eccentric annular geometry. When the drillstring is rotated, whirling, snaking, irregular motions are observed. This state is considered as a free drillstring configuration since there is no prefixed eccentricity imposed on the drillstring. The reason for such design is to simulate the actual drilling operations, especially the highly inclined and horizontal drilling operations. Results show that rotating the drillstring can either increase or decrease the frictional pressure losses. The most pronounced effect of rotation is observed in the transition region from laminar to turbulent flow. The experiments with the buckled drillstring showed significantly reduced frictional pressure losses compared to the free drillstring configuration. Decreasing the length of the pitch caused a further reduction in pressure losses. Using the experimental database, turbulent friction factors for buckled and rotating drillstrings are presented. The drilling industry has recently been involved in incidents that show the need for critical improvements for evaluating and avoiding risks in oil/gas drilling. The information obtained from this study can be used to improve the control of bottomhole pressures during extended reach, horizontal, managed pressure, offshore, and slim hole drilling applications. This will lead to improved safety and enhanced optimization of drilling operations.

Commentary by Dr. Valentin Fuster
J. Energy Resour. Technol. 2014;136(4):042910-042910-5. doi:10.1115/1.4027570.

Polymer gel has been widely used to control excessive water production in many mature oilfields; however, there still exist some problems concerning the differences between gelation behavior in bulk and porous media. In this paper, the gelation time and microstructures of chromium gel and phenolic resin gel in bulk and porous media were studied. Results showed that for chromium gel, the initial gelation time in porous media was about 2.5–3.5 times of that in bulk and final gelation time in porous media was about 6.0–7.0 times of that in bulk. While for phenolic resin gel, the initial gelation time in porous media was about 1.0–1.5 times of that in bulk, and final gelation time in porous media was about 1.5–2.0 times of that in bulk. The morphology of chromium gel and phenolic resin gel in bulk were dendritic shape structure and 3D network structure, respectively. However, the morphology of chromium gel and phenolic resin gel in porous media were both dense gel membranes at low magnification. While at higher magnification, compared with the branchlike cluster structure of chromium gel in porous media, the network of phenolic resin gel was more developed. The experimental results can provide the basis for determining well shut off time and reveal the differences of gel microstructures between the chromium gel and phenolic gel in bulk and porous media.

Commentary by Dr. Valentin Fuster
J. Energy Resour. Technol. 2014;136(4):042911-042911-6. doi:10.1115/1.4027851.

Pore-scale coupled flow of gas and condensate is believed to be the main mechanism for condensate production in low interfacial tension (IFT) gas condensate reservoirs. While coupling enhances condensate flow due to transport of condensate lenses by the gas, it dramatically reduces gas permeability by introducing capillary resistance against gas flow. In this study, a dynamic wetting approach is used to investigate the effect of viscous resistance, IFT and disjoining pressure on pore-scale coupling of gas and condensate. Disjoining pressure arises from van der Waals interactions between gas and solid through thin liquid films, e.g., condensate films on pore walls. Low values of IFT and small pore diameters, as involved in many gas condensate reservoirs, give rise to importance of disjoining pressure. Calculations show that disjoining pressure postpones gas condensate coupling to higher condensate flow fractions-from about 0.08 for vanishing disjoining effect to more than 0.16 for strong disjoining effect. Results also suggest that strong disjoining effect will result in higher gas relative permeability after coupling. Finally, the positive rate effect on gas permeability is only observed when disjoining effects are weak.

Commentary by Dr. Valentin Fuster

Technical Brief

J. Energy Resour. Technol. 2014;136(4):044501-044501-5. doi:10.1115/1.4028860.

In recent years, the oil industry has used various methodologies to solve numerical coupling of reservoirs and production systems to properly model complex projects needing an integrated solution of computational models that represent the fluid flow through the reservoir up to the surface. We present a study of explicit coupling methodology testing the production system on common operating conditions, verifying the benefits and quantifying limitations of explicit methodology, due to numerical stability errors reported in literature.

Commentary by Dr. Valentin Fuster

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