bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Impact of Field Measurements and Data-Handling Procedures on Carbonate- and Sulfide-Scale Prediction
Authors: Ness Giulia , Sorbie K. S. 
Published: January 2019

Summary
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

Summary
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

Summary
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

SummaryEnhanced 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

Summary
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

Summary
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

Summary
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

SummaryReservoir 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

Summary
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

SummarySteam-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

Summary
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.