bluuebunny/crossref_metadata_2025 huggingface dataset:
Experimental Investigation of the Effects of Asphaltene Stability on Interfacial Behavior of Live-Reservoir-Fluid Systems
Authors: Ratnakar Ram R. , Mantilla Cesar A. , Dindoruk Birol
Published: January 2019

Wettability alteration resulting from asphaltene precipitation in a reservoir affects rock/fluid interactions that have a potential impact on oil production, recovery, and flow in the production network. The current predictive wettability models are inherently inaccurate and do not consider asphaltene stability. This study investigates the impact of pressure-depletion-induced asphaltene precipitation on interfacial tension (IFT) and contact angle for live-oil and water systems at reservoir conditions (high pressure, high temperature), and it presents a graphical (quantitative) method for determining asphaltene onset pressure (AOP) based on interfacial behavior.

Water/oil IFT was measured at reservoir temperature using a pendant-drop-shape method for a system of live oils over a range of pressures above and below the AOP, which was already independently determined by means of particle-size-distribution and solid-detection-system techniques. The same pressure and temperature conditions were used to measure contact angle with quartz in the presence of deionized (DI) water as the surrounding medium. The temperature was controlled with an accuracy of ±0.1°C. Some measurements were performed twice to ensure the reproducibility of the experiments and methodology.

This work presents the experimental study to quantify the change in interfacial behavior because of asphaltene precipitation and deposition. IFT/contact-angle measurements above and below AOP show that the interfacial behavior follows the normal trends above AOP as observed in other water/hydrocarbon systems. However, as evident when the pressure was reduced below the AOP, a relatively sharp change in the trend is observed in both the IFT and contact angle, which is caused by asphaltene migration to the interface in a way that acts as a natural surfactant. As asphaltenes precipitate and deposit in the mineral substrate, the surface turns less water-wet and the contact angle naturally increases to balance the equilibrium forces.

This study sets a quantitative and alternative method to determine AOP, and presents new experimental data on IFT/contact angle of live-oil and water systems at reservoir conditions. 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 it is comparable with the pore size. On the other hand, 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.
Wettability Estimation Using Surface-Complexation Simulations
Authors: Erzuah Samuel , Fjelde Ingebret , Omekeh Aruoture Voke
Published: January 2019

Wettability controls the fluid-phase distribution and flow properties in the reservoir. The ionic compositions of brine, the oil chemistry, and the reservoir-rock mineralogy have profound effects on wettability. Wettability measurement can be obtained from special core analysis (SCAL), but those data are not readily available, and the cost and time of analyzing different possible injection waters can be excessive. There is thus a need for early evaluation of wettability because it is crucial for selecting optimal field-development options. Information about wettability can be indirectly obtained from logging of other rock properties, but the uncertainty in the estimated wettability range is often high. In addition, wettability alteration by injection brines cannot be analyzed by logging. This study seeks to estimate the wettability by assessing the electrostatic interactions existing between the mineral/brine and the oil/brine interfaces using a surface-complexation model (SCM) supported with relatively simple and fast flotation experiments.

The SCM is a chemical equilibrium technique of characterizing surface adsorption phenomenon. The SCM provides a cost-effective technique of characterizing the wettability of minerals at reservoir conditions. Ionic composition of the brine and the properties of the minerals were used as input to the model. In addition, the polar oil components in the crude oil were converted into their equivalent organic acid and base concentrations to be incorporated into the model. The electric-double-layer model that was used in the SCM was the diffuse-layer model. The SCM simulation is a fast and inexpensive wettability-characterization tool if reservoir cores and crude oil required in conventional wettability measurements are not readily available.

From the flotation and SCM results, it could be concluded that the latter could capture the oil-adhesion tendencies of the former. Not only does the SCM predict the wetting tendencies of the minerals, but also it has the capacity to evaluate the mechanisms that led to their wetting preferences. For instance, the SCM results reveal that for negatively charged mineral/brine and oil/brine interfaces, divalent cations such as Ca2+ and Mg2+ can serve as a bridge between the two interfaces, thereby leading to oil adhesion. On the other hand, for positively charged mineral/brine interfaces such as calcite, direct adsorption of the carboxylic oil component was the dominant mechanism for oil adhesion. The SCM technique of characterizing wettability can be used to screen possible injection-water compositions to assess their potential to alter the wettability to more water-wet. Finally, the SCM technique could capture the trend of ζ-potential measurements from literature.
Effect of Fluid Type and Multiphase Flow on Sand Production in Oil and Gas Wells
Authors: Wang Haotian , Gala Deepen P. , Sharma Mukul M.
Published: January 2019

Controlled laboratory experiments and some field studies have shown that the onset of sand production in gas wells differs from that in oil wells. Results from a general 3D sand-production numerical model are presented to explain the differences in the onset of sanding and sand-production volume for different fluids and under different flow and in-situ stress conditions. The sand-production model accounts for multiphase-fluid flow and is fully coupled with an elasto-plastic geomechanical model. The sanding criterion considers both mechanical failure and sand erosion by fluid flow. Non-Darcy flow is implemented to account for the high flow rates. The drag forces on the sand grains are computed on the basis of the in-situ Reynolds number. Both the intact rock strength and the residual rock strength depend on water saturation. Water evaporation (drying) resulting from gas flow is modeled using phase equilibrium calculations.

The onset of sand production is compared for different fluid types (oil and gas). Model results are shown to be consistent with experimental observations reported in the literature. For example, the onset of sanding is observed at higher compressive stresses for gas wells as compared with oil wells. The primary mechanism for this is for the first time shown to be sand strengthening induced by evaporation of water. This effect is not observed in oil wells. The sand-production rate when non-Darcy effects are considered is lower than for Darcy flow. The reason for this is the lower fluid velocity (for the same drawdown) and, consequently, smaller drag forces on the failed sand grains. The effect of water breakthrough and water cut on sand production is studied from both mechanical and erosion perspectives. The model is shown to be capable of accurately predicting the onset of sanding and sand production induced by multiphase- and compressible-fluid flows, helping us to predict sanding issues in both oil and gas wells.
Combining Passive and Autonomous Inflow-Control Devices in a Trilateral Horizontal Well in the Alvheim Field
Authors: Langaas Kåre , Jeurissen Emile J. , Abay Hailu Kebede
Published: January 2019

In this paper we describe the analysis, test, and design work to deliver an optimal lower completion for a trilateral well by integrating passive and autonomous inflow-control devices (ICDs) (AICDs) at the Alvheim Field offshore Norway.

In 2015, both passive ICDs and AICDs were tested in the laboratory with Alvheim fluids at reservoir conditions. The experimental flow testing demonstrated that the AICD chokes gas more efficiently than the passive ICD. The experimental results enabled correct modeling of AICDs in both the reservoir-simulation model and the simpler steady-state inflow model. The following lower-completion strategy was established for the new well: Where the well was close to the overlying gas cap, AICDs should be used, whereas passive ICDs with variable strength were to be used elsewhere to optimize the inflow.

During the drilling phase, the steady-state model was updated with the as-drilled information; the lower-completion design for each branch focused on obtaining what was estimated to be an optimal inflow depending on the oil volume per drainage area. A key uncertainty in the design work was whether shaly zones along the wellbore would creep/collapse with time and act effectively as packers.

The lower completion covered 7 km of reservoir penetration in the three branches, and 15 unique oil tracers were installed to evaluate the cleanup and the inflow profile along the well. The well started producing in May 2016 and a successful cleanup was confirmed by oil-tracer responses. In August 2016, a restart-tracer-sampling campaign was performed after a 12-day shut-in, and this formed the basis for a “chemical production log.”

The tracer-based inflow interpretation was compared quantitatively with the model-predicted inflow and qualitatively to the tracer responses seen during the cleanup. The comparison confirmed that the lower completion works as initially planned. The interpretation further indicated that the upper zone has a lower degree of pressure support than the lower zone, and that the larger shaly sections have creeped/collapsed and act as packers.

The well has exceeded predrill production expectations, with an average oil rate of 3375 std m3/d (21,240 STB/D) during the first production year. A large part of exceeding the predrill expectations is attributed to the lower-completion design, where the focus has been to optimize such that the whole well contributes, from the heel to all toes.
Real-Time Formation Evaluation and Contamination Prediction Through Inversion of Downhole Fluid-Sampling Measurements
Authors: Kristensen Morten , Chugunov Nikita , Gisolf Adriaan , Biagi Mario , Dubost Francois
Published: January 2019

Acquisition of fluid samples using wireline-formation testers (WFTs) is an integral part of reservoir evaluation and fluid characterization. Recent developments in formation-tester hardware have enabled wireline-based fluid sampling in a wide range of downhole conditions. However, accurate quantification of oil-based-mud (OBM) filtrate contamination using data from downhole-fluid-analysis (DFA) sensors alone remains challenging, especially in difficult sampling environments and for advanced sampling tools that have complex inflow geometries and active guarding of filtrate flows. Such tools and conditions lead to contamination behaviors that do not follow simple power-law models that are commonly assumed in OBM-contamination-monitoring (OCM) algorithms.

In this paper, we introduce a new OCM algorithm derived from an inversion of DFA data using a full 3D numerical flow model of the contamination-cleanup process. Using formation and fluid properties and operational tool settings, the model predicts the evolution of filtrate contamination as a function of time and pumped volume, and can thus be used to forward model the DFA sensor responses. Sensor data are then inverted in real time to provide contamination predictions. Real-time computation is enabled through fast, high-fidelity proxy models for the cleanup process. The proxy models are trained on and thoroughly vetted against a large number of full-scale numerical simulations. Compared with existing algorithms, the new OCM method is now applicable for all types of sampling hardware and a wider set of operating conditions. By directly relying on a model of the cleanup process, the physical properties of the formation and fluids (such as porosity, permeability, viscosity, and depth of filtrate invasion) are estimated during the inversion, thus providing additional valuable information for formation evaluation.

The new method is demonstrated by practical application in both synthetic and field examples of oil sampling in OBM. The synthetic examples demonstrate the robustness of the algorithm and show that the true formation and fluid properties can be recovered from noise-corrupted sensor data. The field example presented demonstrates that contamination predictions are in good agreement with results from laboratory analysis, and the inverted formation properties are consistent with estimates derived from openhole logs and pressure measurements.
Development of an Empirical Equation To Predict Hydraulic-Fracture Closure Pressure From the Instantaneous Shut-In Pressure Using Subsurface Solids-Injection Data
Authors: Kholy S. M. , Mohamed I. M. , Loloi M.. , Abou-Sayed O.. , Abou-Sayed A..
Published: January 2019

During hydraulic-fracturing operations, conventional pressure-falloff analyses (G-function, square root of time, and other diagnostic plots) are the main methods for estimating fracture-closure pressure. However, there are situations when it is not practical to determine the fracture-closure pressure using these analyses. These conditions occur when closure time is long, such as in mini-fracture tests in very tight formations, or in slurry-waste-injection applications where the injected waste forms impermeable filter cake on the fracture faces that delays fracture closure because of slower liquid leakoff into the formation. In these situations, applying the conventional analyses could require several days of well shut-in to collect enough pressure-falloff data during which the fracture closure can be detected. The objective of the present study is to attempt to correlate the fracture-closure pressure to the early-time falloff data using the field-measured instantaneous shut-in pressure (ISIP) and the petrophysical/mechanical properties of the injection formation.

A study of the injection-pressure history of many injection wells with multiple hydraulic fractures in a variety of rock lithologies shows a relationship between the fracture-closure pressure and the ISIP. An empirical equation is proposed in this study to calculate the fracture-closure pressure as a function of the ISIP 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 was 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 empirical equation was validated using different case studies by comparing the measured fracture-closure-pressure values with those predicted by using the developed empirical equation. In all cases, the new method predicted the fracture-closure pressure with a relative error of less than 6%.

The new empirical equation predicts the fracture-closure pressure using a single point of falloff-pressure data, the ISIP, 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.
The Impact of Field Measurements and Data-Handling Procedures on Carbonate- and Sulfide-Scale Prediction
Authors: Ness Giulia , Sorbie K. S.
Published: January 2019

Carbonate and sulfide scales are directly coupled together and differ from other inorganic scales because they are intimately linked to the in-situ concentrations of carbon dioxide (CO2) and hydrogen sulfide (H2S), which influence the local pH and availability of reactive species.

The CO2 in aqueous solutions has the most significant effect on the system pH, on the solution content of bicarbonate ion (HCO3–), and on the final alkalinity. However, the presence of H2S in the system also has a direct and important effect on the total-system alkalinity. When calcium carbonate deposition occurs in a depressurized aqueous fluid, the amount of scale (CaCO3) that forms depends on the initial (prescaling) solution alkalinity. Thus, the occurrence and severity of carbonate scale are linked to both the solution carbonate system (CO2/HCO3–/CO32–) and the sulfide system (H2S/HS–/S2–).

In previous publications, we have described a rigorous work flow (step-by-step procedure) to accurately predict carbonate- and sulfide-scaling profiles from reservoir to separator using commonly available field data (Verri et al. 2017a). Although, with perfect data, the work flow is rigorous [i.e., it will correctly predict the types and amounts of scale that can occur in some carbonate systems (e.g., CaCO3, FeCO3, FeS)], the numerical results produced are, of course, subject to errors of different types.

In this paper, we identify and describe three key categories of data and procedures that must be correctly gathered and used to obtain accurate carbonate- and sulfide-scale predictions: These relate to field measurements, data-handling procedures, choice of software, model equations, and parameters. Moreover, in this work, the impact of unreliable field measurements on the final carbonate and sulfide scaling profiles is estimated, with a specific focus on gas- and water-chemistry errors. By varying important parameters such as Ca2+ concentration and gas-phase CO2 and H2S, it is possible to assess the impact that errors in these measurements have on the final scale-prediction profiles. Because of the closely coupled nature of the carbonate and sulfide systems, it is essential to consider “groups” of variables that change together.
Hydraulic-Fracture-Height Growth Under the Combined Influence of Stress Barriers and Natural Fractures
Authors: Huang Jixiang , Morris Joseph P. , Fu Pengcheng , Settgast Randolph R. , Sherman Christopher S. , Ryerson Frederick J.
Published: January 2019

A fully coupled finite-element/finite-volume code is used to model 3D hydraulically driven fractures under the influence of strong vertical variations in closure stress interacting with natural fractures. Previously unknown 3D interaction mechanisms on fracture-height growth are revealed. 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. Consequently, natural fractures are expected to be able to both encourage and inhibit the progress of hydraulic fractures propagating through stress barriers, depending on the relative locations between the intersecting fractures. Once the hydraulic fracture propagates above the stress barrier through the weakened segment near a favorably located natural fracture, a configuration consisting of two opposing fractures cuts the stress barrier from above and below. The fluid pressure required to break the stress barrier under such opposing-fracture configurations is substantially lower than that required by a fracture penetrating the same barrier from one side. Sensitivity studies of geologic conditions and operational parameters have also been performed to explore the feasibility of controlled fracture height. 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.
Foam Generation by Capillary Snap-Off in Flow Across a Sharp Permeability Transition
Authors: Shah Swej Y. , Wolf Karl-Heinz , Pilus Rashidah M. , Rossen William R.
Published: January 2019

Foam reduces gas mobility and can improve sweep efficiency in an enhanced-oil-recovery (EOR) process. Previous studies show that foam can be generated in porous media by exceeding a critical velocity or pressure gradient. This requirement is typically met only near the wellbore, and it is uncertain whether foam can propagate several tens of meters away from wells as the local pressure gradient and superficial velocity decreases. Theoretical studies show that foam can be generated, independent of pressure gradient, during flow across an abrupt increase in permeability. In this study, we validate theoretical predictions through a variety of experimental evidence. Coreflood experiments involving simultaneous injection of gas and surfactant solution at field-like velocities are presented. We use model consolidated porous media made out of sintered glass, with a well-characterized permeability transition in each core. The change in permeability in these artificial cores is analogous to sharp, small-scale heterogeneities, such as laminations and cross laminations. Pressure gradient is measured across several sections of the core to identify foam-generation events and the subsequent propagation of foam. X-ray computed tomography (CT) provides dynamic images of the coreflood with an indication of foam presence through phase saturations. We 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. There is no foam present in the system before generation at the boundary. CT measurements help visualize foam generation and propagation in terms of a region of high gas saturation developing at the permeability transition and moving downstream. If coarse foam is formed upstream, then it is transformed into stronger foam at the transition. Significant fluctuations are observed in the pressure gradient across the permeability transition, suggesting intermittent plugging and mobilization of flow there. This is the first CT-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.
Diffusion-Dominated Proxy Model for Solvent Injection in Ultratight Oil Reservoirs
Authors: Cronin Michael , Emami-Meybodi Hamid , Johns Russell T.
Published: January 2019

Enhanced oil recovery (EOR) by solvent injection offers significant potential to increase recovery from shale oil reservoirs, which is typically between 3 and 7% original oil in place (OOIP). The rather sparse literature on this topic typically models these tight reservoirs on the basis of conventional-reservoir processes and mechanisms, such as by convective transport using Darcy's law, even though there is little physical justification for this treatment. The literature also downplays the importance of the soaking period in huff ’n’ puff.

In this paper, we propose, for the first time, a more physically realistic recovery mechanism based on solely diffusion-dominated transport. We develop a diffusion-dominated proxy model assuming first-contact miscibility (FCM) to provide rapid estimates of oil recovery for both primary production and the solvent huff ’n’ soak ’n’ puff (HSP) process in ultratight oil reservoirs. Simplified proxy models are developed to represent the major features of the fracture network.

The key results show that diffusion-transport considered solely can reproduce the primary-production period within the Eagle Ford Shale and can model the HSP process well, without the need to use Darcy's law. The minimum miscibility pressure (MMP) concept is not important for ultratight shales where diffusion dominates because MMP is based on advection-dominated conditions. The mechanism for recovery is based solely on density and concentration gradients. Primary production is modeled as a self-diffusion process, whereas the HSP process is modeled as a counter-diffusion process. Incremental recoveries by HSP are several times greater than primary-production recoveries, showing significant promise in increasing oil recoveries. We calculate ultimate recoveries for both primary production and for the HSP process, and show that methane injection is preferred over carbon dioxide injection. We also show that the proxy model, to be accurate, must match the total matrix-contact area and the ratio of effective area to total contact area with time. These two parameters should be maximized for best recovery.
Theoretical Investigation of the Transition From Spontaneous to Forced Imbibition
Authors: Deng Lichi , King Michael J.
Published: January 2019

Spontaneous and forced imbibition are recognized as important recovery mechanisms in naturally fractured reservoirs because the capillary force controls the movement of the fluid between the matrix and the fracture. For unconventional reservoirs, imbibition is also important because the capillary pressure is more dominant in these tighter formations, and a theoretical understanding of the flow mechanism for the imbibition process will benefit the understanding of important multiphase-flow phenomena such as waterblocking. In this paper, a new semianalytic method is presented to examine the interaction between spontaneous and forced imbibition and to quantitatively represent the transient imbibition process. The methodology solves the partial-differential equation (PDE) of unsteady-state immiscible, incompressible flow with arbitrary saturation-dependent functions using the normalized water flux concept, which is identical to the fractional-flow terminology used in the traditional Buckley-Leverett analysis. The result gives a universal 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.
Iron Sulfide Inhibition and Interaction With Zinc and Lead Sulfides
Authors: Al-Harbi B. G. , Graham A. J. , Sorbie K. S.
Published: January 2019

Iron sulfide (FeS), zinc sulfide (ZnS), and lead sulfide (PbS) are considered to be among the most challenging scales in terms of inhibition and removal. They can form by the direct reaction of aqueous sulfide species with dissolved Fe, Zn, and/or Pb and by the exchange between aqueous sulfide species with preformed Fe compounds, such as Fe oxide hydroxide. These existing Fe compounds might have formed during production or intervention, such as an acid treatment. Similarly, PbS and ZnS can form by extracting sulfide from a more soluble sulfide scale (i.e., Zn exchanging with Fe in FeS). The objective of this work was to investigate FeS formation and inhibition under a range of conditions, including pH, temperature, and salinity, and to propose a mode of formation. In addition, the interaction between Fe, Zn, and Pb within solutions containing sulfide species was investigated.

The majority of this study was conducted under anaerobic conditions, with the scale-formation/inhibition experiments being monitored by inductively coupled plasma (ICP) analysis and pH and particle-size measurements. Among the tested scale inhibitors (SIs), two showed high efficiency against FeS, but high pH and salinity had detrimental effects on the performance of one of these products. Interestingly, these SIs prevented FeS deposition even under aerobic conditions (i.e., Fe hydroxide partially preformed). Moreover, at sufficiently high concentrations of SI, the deposition of ZnS and PbS was prevented even when these scales were formed by means of cation displacement (i.e., displaced ZnS and PbS ions from preformed FeS). The route of formation for FeS, ZnS, and PbS was seen to have a significant effect on the inhibition process.

The particle sizes of inhibited (suspended) FeS were significantly lower than those of the blank FeS samples, with this effect increasing with increased SI concentration. This difference in particle size might have an important influence on in-line filter-blocking tests and produced-water quality issues.
A New Approach to Polymer Flooding: Effects of Early Polymer Injection and Wettability on Final Oil Recovery
Authors: Juárez-Morejón J. L. , Bertin H.. , Omari A.. , Hamon G.. , Cottin C.. , Morel D.. , Romero C.. , Bourdarot G..
Published: January 2019

An experimental study of polymer flooding is presented here, focusing on the influence of initial core wettability and flood maturity (volume of water injected before polymer injection) on final oil recovery. Experiments were performed using homogeneous Bentheimer Sandstone samples of similar properties. The cores were oilflooded using mineral oil for water-wet conditions and crude oil (after an aging period) for intermediate-wet conditions; the viscosity ratio between oil and polymer was kept constant in all experiments. Polymer, which is a partially hydrolyzed polyacrylamide (HPAM), was used 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 [breakthrough (BT) and 0, 1, 1.75, 2.5, 4, and 6.5 pore volumes (PV)].

Coreflood results show that the maturity of polymer injection plays an important role in final oil recovery, regardless of wettability. The waterflood-maturity time 0 PV (polymer injection without initial waterflooding) leads to the best sweep efficiency, whereas final oil production decreases when the polymer-flood maturity is high (late polymer injection after waterflooding). A difference of 15% in recovery is observed between early polymer flooding (0 PV) and late maturity (6.5 PV). Concerning the effect of wettability, 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 to obtain representative values of polymer incremental recovery. The influence of wettability can be explained by the oil-phase distribution at the pore scale. Considering that the waterflooding period leads to different values of the oil saturation at which polymer flooding starts, we measured the core dispersivity using a tracer method at different states. The two-phase dispersivity decreases when water saturation increases, which is favorable for polymer sweep.

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.
An Experimental Investigation of Immiscible-CO2-Flooding Efficiency in Sandstone Reservoirs: Influence of Permeability Heterogeneity
Authors: Al-Bayati Duraid , Saeedi Ali , Myers Matthew , White Cameron , Xie Quan
Published: January 2019

Reservoir heterogeneity plays a critical role in determining the success of enhanced-oil-recovery (EOR) processes, but its effect rarely has been comprehensively quantified in the laboratory. This work presents the results of an experimental study on the effects of various carbon dioxide (CO2) injection modes on immiscible-flooding performance in heterogeneous-sandstone porous media. Thus, the results of this study can be insightful in overcoming the current challenges in capturing the importance of geological uncertainties in current and future EOR projects.

Coreflooding experiments were conducted for n-decane/synthetic-brine/CO2 systems at a 9.6-MPa backpressure and at 343 K to attain immiscible-flooding conditions [minimum-miscibility pressure (MMP) of CO2 in n-decane is 12.4 MPa]. For this purpose, two sets of heterogeneous-sandstone core samples were assembled with heterogeneity either parallel to (layered samples) or perpendicular to (composite samples) the flow. The results obtained for both composite and layered core samples indicated that heterogeneity tremendously influences the outcome of the CO2 EOR. Oil recovery decreases dramatically with an increase in the heterogeneity level or permeability ratio (PR). In addition, the crossflow in the layered core sample is found to have a noticeable effect on the ultimate oil recovery (increasing oil recovery up to 5%). Also, it is worth noting that for the composite samples, when we arranged the plugs by putting the low-permeability segments closer to the sample outlets, the recovery factor increased. However, regardless of the segment arrangements, the recoveries in composite cores are lower than those obtained from the homogeneous core sample.
Induction vs. Permanent-Magnet Motors for ESP Applications
Authors: Xiao J. J. , Lastra R..
Published: January 2019

In this paper we provide an overview comparing induction motors (IMs) and permanent-magnet motors (PMMs) for electrical-submersible-pump (ESP) applications. The design and performance differences of the two types of motors are compared and discussed. The PMM advantage and unique applications are highlighted. The requirement of a different control strategy to operate a PMM is described. Some key safety aspects that field engineers need to be aware of with PMMs are also addressed in this paper.

The information we present includes a literature review and the latest research and development results. We cover the operating principles of the IM and the PMM, selection of permanent-magnet materials, operating frequency, stator windings, and magnetic poles. PMMs offer better efficiency, higher power-factor performance, and compactness. Ideal applications include slim-well applications, through-tubing rigless deployment, Y-tool completion, and electric-submersible-progressive cavity pumps (ESPCPs). We will also shed some light on why conventional IMs cannot be used to drive ESPCPs directly without speed-reduction gearboxes.

It is very likely that the use of PMMs will increase for ESP applications in the near future, and this will require engineers to acquire a basic understanding of this technology. This paper intends to provide a high-level comparison between IMs and PMMs in the ESP industry.
Approximate Physics-Discrete Simulation of the Steam-Chamber Evolution in Steam-Assisted Gravity Drainage
Authors: Gallardo Enrique , Deutsch Clayton V.
Published: January 2019

Steam-assisted gravity drainage (SAGD) is a thermal-recovery process to produce bitumen from oil sands. In this technology, steam injected in the reservoir creates a constantly evolving steam chamber while heated bitumen drains to a production well. Understanding the geometry and the rate of growth of the steam chamber is necessary to manage an economically successful SAGD project. This work introduces an approximate physics-discrete simulator (APDS) to model the steam-chamber evolution. The algorithm is formulated and implemented using graph theory, simplified porous-media flow equations, heat-transfer concepts, and ideas from discrete simulation. The APDS predicts the steam-chamber evolution in heterogeneous reservoirs and is computationally efficient enough to be applied over multiple geostatistical realizations to support decisions in the presence of geological uncertainty. The APDS is expected to be useful for selecting well-pair locations and operational strategies, 4D-seismic integration in SAGD-reservoir characterization, and caprock-integrity assessment.
Modeling of Nanoparticle-Stabilized CO2 Foam Enhanced Oil Recovery
Authors: Ortiz D.. , Izadi M.. , Kam S. I.
Published: January 2019

Previous experimental studies show that “nanoparticle-stabilized” supercritical carbon dioxide (CO2) foams (NP-stabilized CO2 foams or NP CO2 foams in this paper) can be applied as an alternative to surfactant foams, to reduce CO2 mobility in gas-injection enhanced oil recovery (EOR). The NPs, if chosen correctly, can be effective foam stabilizers attached at the fluid interface in a wide range of physicochemical conditions.

By using NP CO2 foam experiments available in the literature, this study investigates the applicability of NP foams for mobility control and, thus, improved sweep efficiency. This study consists of two tasks: (1) presenting how a population-balance mechanistic foam model can be used to fit experimental data and determine required model parameters and (2) examining sweep efficiency in a condition resembling Lisama Field (a five-spot pattern with four producers and one injector in the middle), by using relevant gas mobility-reduction factors (MRFs) derived from the mechanistic-modeling technique. The field-scale simulations are conducted with Computer Modeling Group (CMG) software, contrasting NP and surfactant foams (in both dry and wet foam-injection conditions) to a gas-only injection and a gas/water coinjection (no foam).

The results show how the model can successfully reproduce coreflood experimental data, creating three different foam states (weak foam, strong foam, and intermediate) and two steady-state strong-foam regimes (high quality and low quality). When the gas-phase MRFs, ranging up to 10 from the model fit, are applied in the field-scale simulations, the use of NPs improves oil recovery compared with a gas/water coinjection, but not as efficiently as a successful surfactant foam injection does. This implies that, although NP-stabilized foams do provide some benefits, there still seems to be some room to improve the stability and the strength of resulting foams.
A Semianalytical Model for Simulating Fluid Flow in Naturally Fractured Reservoirs With Nonhomogeneous Vugs and Fractures
Authors: Wu Yonghui , Cheng Linsong , Huang Shijun , Fang Sidong , Jia Pin , Wang Suran
Published: January 2019

Carbonate reservoirs comprise fractures, vugs, and cavities. Vugs have a large contribution to reserves of oil and gas, and the fractures provide effective paths for fluid flow in the reservoir. The triple-porosity (TP) model is an effective conceptual method for capturing rock matrix and vugs and the microfractures connecting them. However, these fractures and vugs are always nonhomogeneous. Macrofractures and vugs cannot be handled with a continuum scheme because of their low density and high conductivity.

In this approach, the TP conceptual model is implemented 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 (BEM) 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.

With a simple discretization of the boundaries of macrovugs and macrofractures, the proposed model is shown to efficiently simulate the behavior of fractured carbonate reservoirs with heterogeneity. The computational accuracy is demonstrated using an analytical model and numerical simulation. On the basis of the proposed model, the effect of the heterogeneity of macrofractures and vugs on pressure-transient behavior is analyzed. The results show that macrofractures and vugs cannot be handled with triple-continuum models analytically. There will be several “dips” on the derivative of the pressure curve if macrovugs are discretely handled. Also, discretely handling the fractures and vugs will make the calculated dimensionless pressure and the derivative pressure lower than those calculated with the triple-continuum models. After increasing the porosity of macrovugs, the pressure and the derivative will go down in the flow regimes dominated by macrovugs. The conductivity of macrofractures has a great impact on almost all the flow regimes except for boundary-dominated flow. Finally, a field case is used to show the application of the proposed semianalytical model.

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.
A New Fracture-Unit Model and Its Application to a Z-Fold Fracture
Authors: Luo Wanjing , Tang Changfu , Zhou Yingfang
Published: January 2019

Following the Cinco-Ley fracture model (Cinco-Ley et al. 1978) and the Luo-Tang wing model (Luo and Tang 2015a), we developed a new fracture-unit model. By coupling the Fredholm integral equation for a fracture with a reservoir equation, we 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. Our work provides a novel forward model to implement the law of fluid flow in complex fractures.
Numerical Investigation Into the Simultaneous Growth of Two Closely Spaced Fluid-Driven Fractures
Authors: Chen Xiyu , Zhao Jinzhou , Yan Wenyi , Zhang Xi
Published: January 2019

Multistage, multicluster hydraulic fracturing is a widespread method used in the petroleum industry to enhance the hydrocarbon production of low-permeability unconventional reservoirs. The core for fracturing-treatment success is achieving the simultaneous propagation of multiple closely spaced hydraulic fractures to enlarge the fracture surface. To better understand this coupled elasto-hydrodynamics mechanics, a 2D model comprising a combination of a displacement discontinuity method for elasticity and a finite volume method for lubrication is presented in this paper. Furthermore, a universal tip asymptotic solution, reflecting the unique multiscale tip behavior for fluid-driven fractures, is adopted as a propagation criterion to locate the fracture front. Numerical examples are fully implemented to investigate the competition in the growth of two closely spaced fluid-driven fractures at different initial lengths. 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. The simultaneous growth will be promoted when the fluid viscous dissipation is dominant, while, with increasing rock toughness, the tendency for single-fracture growth will increase correspondingly. 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. Furthermore, this paper provides dimensionless parameters characterizing fracture deflection caused by fracture interaction. 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.
Pressure-Transient Behavior of Partially Penetrating Inclined Fractures With a Finite Conductivity
Authors: Teng Bailu , Andy Li Huazhou
Published: January 2019

Field studies have shown that, if an inclined fracture has a significant inclination angle from the vertical direction or the fracture has a poor growth along the inclined direction, this fracture probably cannot fully penetrate the formation, resulting in a partially penetrating inclined fracture (PPIF) in these formations. It is necessary for the petroleum industry to conduct a pressure-transient analysis on such fractures to properly understand the major mechanisms governing the oil production from them. In this work, we develop a semianalytical model to characterize the pressure-transient behavior of a finite-conductivity PPIF. We discretize the fracture into small panels, and each of these panels is treated as a plane source. The fluid flow in the fracture system is numerically characterized with a finite-difference method, whereas the fluid flow in the matrix system is analytically characterized on the basis of the Green's-function method. As such, a semianalytical model for characterizing the transient-flow behavior of a PPIF can be readily constructed by coupling the transient flow in the fracture and that in the matrix. With the aid of the proposed model, we conduct a detailed study on the transient-flow behavior of the PPIFs. Our calculation results show that a PPIF with a finite conductivity in a bounded reservoir can exhibit the following flow regimes: wellbore afterflow, fracture radial flow, bilinear flow, inclined-formation linear flow, vertical elliptical flow, vertical pseudoradial flow, inclined pseudoradial flow, horizontal-formation linear flow, horizontal elliptical flow, horizontal pseudoradial flow, and boundary-dominated flow. A negative-slope period can appear on the pressure-derivative curve, which is attributed to a converging flow near the wellbore. Even with a small dimensionless fracture conductivity, a PPIF can exhibit a horizontal-formation linear flow. In addition to PPIFs, the proposed model also can be used to simulate the pressure-transient behavior of fully penetrating vertical fractures (FPVFs), partially penetrating vertical fractures (PPVFs), fully penetrating inclined fractures (FPIFs), and horizontal fractures (HFs).