bluuebunny/crossref_metadata_2025_split huggingface dataset:
ASP Flood After a Polymer Flood vs. ASP Flood After a Water Flood
Authors: Aitkulov Almas , Dao Eric , Mohanty Kishore K. 
Published: March 2018

Abstract
Alkaline-surfactant-polymer (ASP) flooding is an effective technique to improve oil recovery. It has been applied typically after a water flood. Recently, there has been a successful field test where an ASP flood was conducted after a polymer flood. Is the ASP flood after a polymer flood more effective than an ASP flood after a water flood? It is difficult to conduct this experiment in exactly the same location in a field. The goal of this study is to answer this question in a laboratory heterogeneous quarter 5-spot model. A heterogeneous quarter 5-spot sand pack of size 10″ × 10″ × 1″ was constructed. Two sands with a permeability contrast of 10:1 were packed into a 2D square steel cell. An alkali-surfactant formulation was identified that produced ultra-low interfacial tension with the reservoir oil (27 cp). In one experiment (WF-ASP), waterflood was conducted first followed by the ASP flood. In a second experiment (PF-ASP), polymer flood was conducted first followed by the ASP flood. The ASP formulation and slug size were kept the same. Secondary water flood of the heterogeneous quarter 5-spot recovered 22% OOIP. Post-waterflood ASP flood recovered 32% OOIP additional oil with a cumulative (WF-ASP) oil recovery of 54%. Secondary polymer flood of the same heterogeneous quarter 5-spot yielded 50% OOIP. Post-polymerflood ASP flood recovered 32% OOIP additional oil with a cumulative (PF-ASP) oil recovery of 82% OOIP. The water flood and the subsequent ASP flood swept a large part of the high permeability region and a small part of the low permeability region. The polymer flood swept all of the high permeability region and most of the low permeability region. The subsequent ASP flood swept the polymer-swept regions. These experiments demonstrate that the polymer flood - ASP flood combination is more effective than the water flood - ASP flood combination.
The Analysis of Compositional Effects on Global Flow Regimes in CO2 Near-Miscible Displacements in Heterogeneous Systems
Authors: Wang G. , Pickup G. E. , Sorbie K. S. , Mackay E. J. 
Published: March 2018

Abstract
This study investigates how compositional effects interact with the flow behavior during near miscible (and immiscible) CO2-oil displacements in heterogeneous systems. A series of numerical simulations modeling 1D slim-tube and 2D areal systems were performed using a fully compositional simulator. With negligible numerical dispersion, the fine-scale (Δx=0.005m) slim-tube simulations were performed to provide the "truth case" in terms of the compositional effects and oil/component recovery. A number of grid resolutions were tested to examine cell-size effects on the simulation accuracy. It was found that coarse cell size not only leads to spreading of the displacing front, but also lowers the displacement efficiency by reducing the component stripping effects, as noted by Orr (2007). The corresponding 2D cases are based on a small heterogeneous sector model of dimensions 50m × 10m, in order that the finest scale displacement physics can be modelled accurately. We investigated various flow regimes ranging from viscous fingering to channeling displacements within heterogeneous random correlated fields. CO2 dissolves in oil at near-miscible conditions and improves the mobility of the oil, but leads to earlier breakthrough of CO2 in both fingering and channeling flow. It was also found that the instability of fingering flow could introduce considerable variation in the composition paths during oil displacement by CO2, compared with the slim-tube simulations, particularly in the later stages of the flood. For this reason, heavier component recovery is more likely to be affected and reduced by viscous instability. In the case of channeling flow, compositional effects were less important since the permeability channel dominated the displacement. Both the ultimate oil recovery and component recovery are significantly and about equally reduced, when the underlying heterogeneity is of dominant influence.
To summarize, compositional effects can have a very significant impact on the prediction of near-miscible CO2 EOR projects. Issues such as front stability, local displacement efficiency and formation of fingering/channeling during CO2 near-miscible displacement can lead to behavior that is significantly different from immiscible flooding in these systems. The process of mass transfer between CO2 and oil can be hampered to a certain degree by unstable flow depending on the level of heterogeneity. This leads to a further reduction in component recovery, particularly of the heavier components. Lastly, the appropriate upscaling methods considering mass transfer still require further investigation for CO2 near-miscible displacement in field-scale applications. The complete dataset and results of this study are available online as a model case example for testing out potential upscaling techniques for compositional flows in heterogeneous systems (Wang et al. 2019).
Modeling and Simulation of Smart Gels for Conformance Improvement in Waterflooding
Authors: Temizel Cenk , Putra Dike , Alklih Mohamad Y. , Najy Anas Khaled , Jia Bao , Yang Gang 
Published: March 2018

Abstract
Recent studies have shown that enhanced oil recovery will be the focal point for approximately 50% of the global oil production in the upcoming two-three decades. According to the several ballpark studies conducted on EOR techniques, results show that for reservoirs with oil viscosities ranging from 10 to 150 m Pa.s., polymer flooding seems to be an ideal development strategy. However, when the oil viscosities exceed 150 m Pa.s., polymer injectivity and pumping efficiencies can turn out to be major inhibiting factors, thereby limiting the range of oil viscosities for which polymer flooding can be utilized. The core reason for this is that the values of viscosity for the injected water containing polymer, calculated for the beneficial mobility ratio, can lead to the inhibiting factor stated above.
Previously conducted lab studies have shown that supramolecular systems are very resistant in high temperature - high salinity systems. To be able to achieve the easier injection, the injected supramolecular viscosity will be kept at lower values and then increased to the levels right before or upon contacting the oil in the reservoir.
The core difference between conventional polymer systems and supramolecular polymer systems is that the latter disassemble and re-assemble as opposed to degradation when exposed to extreme shear stress and temperatures. It can therefore be said that supramolecular polymer systems are self-healing in nature. The phenomenon has been observed in cases where polymers with high molecular weight are forced through narrow flow channels. Though molecular division takes place, supramolecular systems have shown a tendency of reassembly later on. Therefore, adaptability of these systems to bounded or restricted environments can be established.
This study will add the modeling and simulation components of supramolecular systems which can be effectively utilized in high temperature-high salinity conditions through adjustments to viscosities and interfacial properties of these assemblies. This will help compare the displacement efficiency of supramolecular systems which efficiently perform in a wide range of reservoirs such as thin zones, and reservoirs within permafrost conditions. This can significantly benefit the oil and gas companies worldwide in preparing a technically feasible, but also, a cost effective EOR development strategy, whenever polymer injection is of consideration.
An Investigation on the Feasibility of Combined Refracturing of Horizontal Wells and Huff and Puff Gas Injection for Improving Oil Recovery from Shale Petroleum Reservoirs
Authors: Fragoso Alfonso , Selvan Karthik , Aguilera Roberto 
Published: March 2018

Abstract
Huff and Puff gas injection through horizontal wells in shale petroleum reservoirs is moving cautiously from being a promising theoretical possibility, to becoming a reality for increasing oil recovery. This study investigates how oil recoveries from shales can be increased by (1) a combination of refracturing and huff and puff gas injection, and (2) huff and puff gas injection when the length of the gas injection and production cycles are increased over time.
The possibility of improving oil recoveries from shales by a combination of refracturing and huff and puff gas injection is investigated using a compositional simulation approach. Previous studies published in the literature, have considered the implementation of regular constant-time cycles throughout the huff and puff process. This may not be the optimum strategy. In this work, the use of cycles with increasing time-lengths is investigated with a view to maximize the oil recovery by huff and puff gas injection.
The combination of (1) huff and puff gas injection followed by (2) refracturing and (3) stopping gas injection is found to be a good option to increase oil recovery from shale petroleum reservoirs when the initial hydraulic fracturing (IHF) has been successful. The benefits of this approach are demonstrated through a comparison made when refracturing is carried out without previous huff and puff injection. If the IHF has not been implemented properly, the huff and puff gas injection does not provide attractive recoveries. In this case, a refracturing job followed by huff and puff gas injection is shown to improve recoveries significantly. A comparison of the different scenarios considered in this paper shows that proper design of the injection and production schedule is very important in the development of a huff and puff gas injection. Optimizing the schedule by using the appropriate cycles with variable increasing-time spans can lead to improving the huff and puff performance.
This study investigates how to increase oil recovery from shale petroleum reservoirs by (1) the combined use of refracturing and huff and puff gas injection, and (2) the use of cycles of variable length as opposed to the regular-length constant-time cycles considered in previous publications. To the best of our knowledge, the two cases considered in this paper are novel and have not been published previously in the literature.
Laboratory Studies of Ternary Surfactant Formulation for EOR in Oil-Wet, High-Temperature Carbonate Formations
Authors: Puerto Maura C. , Lopez-Salinas Jose Luis , Jian Guoqing , Hirasaki George J. , Miller Clarence A. 
Published: March 2018

Abstract
The objective of this research was to develop a surfactant formulation for EOR in an oil-wet, high-salinity, fractured dolomite reservoir at ~100°C. A key requirement was achievement of interfacial tension (IFT) sufficiently low to spontaneously displace oil from the matrix by buoyancy. The formulation developed to do so was a blend of lauryl betaine and C15-18 internal olefin sulfonate, supplemented by a smaller amount of i-C13 ethoxylated carboxylate, all thermally stable and commercially available surfactants although the carboxylate not in quantities required for largescale EOR processes. Proportions of the three surfactants for injection in hard sea water were selected using equilibrium phase behavior results and estimates of IFT obtained by a novel technique based on the manner in which oil exits a small, vertically-oriented, rectangular oil-wet capillary cell as it is displaced upward in the cell by surfactant solution. The ability to recover oil from an oil-wet dolomite core was confirmed by an Amott imbibition cell experiment in which 50% recovery was observed for a core initially fully saturated with oil. The formulation's ability to generate strong foam in porous media was presented earlier in SPE-181732-MS. Research at Rice for three additional projects having carbonate reservoirs but different crude oils, brines, and temperatures of at least 60°C demonstrated formulation versatility by showing good oil recovery by core floods with modestly adjusted proportions of the same three surfactants (SPE-184569-MS, 2017; SPE-190259-MS 2018, US Patent 9,856,412). In the first two of these cited studies, the foamed formulation was injected to recover crude oils from a novel model fracture-matrix system.
Surfactant Flooding in Offshore Environments
Authors: Southwick J. G. , Pol E. van , Rijn C. H. , Batenburg D. W. , Manap Arif Azhan , Mastan Ahmad Anis , Zulkifli Nazliah Nazma 
Published: March 2018

Abstract
A low complexity chemical flooding formulation has been developed for application in offshore environments. The formulation uses seawater with no additional water treatment beyond that which is normally performed for water flooding (filtration, de-oxygenation, etc.). The formulation is a mixture of an alkyl propoxy sulfate (APS) and an alkyl ethoxy sulfate (AES) with no cosolvent. With seawater only (no salinity gradient) the blend of APS and AES gives substantially higher oil recovery than a blend of APS and internal olefin sulfonate (IOS) in outcrop sandstone.
It is shown that the highest oil recovery is obtained with surfactant blends that produce formulations that are underoptimum (Winsor Type 1 phase behavior) with reservoir crude oil. Also, these underoptimum formulations avoid high injection pressures seen with optimum formulations in low permeability outcrop rock. The formulation recovers a similar amount of oil in reservoir rock in the swept zone. Overall recovery in reservoir rock is lower than outcrop sandstone due to greater heterogeneity, which causes bypassing of crude oil.
An Integrated Flow-Geomechanical Analysis of Flue Gas Injection in Cranfield
Authors: Lu Xueying , Lotfollahi Mohammad , Ganis Benjamin , Min Baehyun , Wheeler Mary F. 
Published: March 2018

Abstract
CO2 capture and sequestration in subsurface reserves are expensive processes. Therefore flue gas can be directly injected into the oil and gas reservoirs to eliminate the cost of CO2 separation from power plant emissions and simultaneously enhance hydrocarbon production that may offset the cost of gas compression. However, gas injection in subsurface resources is often subject to poor volumetric sweep efficiency caused by low viscosity and low density of the injection fluid and formation heterogeneity. This paper aims to study gas mobility control techniques of water alternating gas (WAG) and foam in Cranfield via field-scale simulations. A coupled compositional flow and geomechanics simulator, IPARS, is used to accurately simulate the underlying physical processes. A hysteretic relative permeability model enables modeling local capillary trapping. Foam mobility control technique is examined to investigate the eminent level of CO2 capillary trapping by an implicit texture foam model. The coupled flow-geomechanics model can detect the effect of the plausible interaction of geomechanics and fluid flow on CO2 plume extension by analyzing the critical pressure that could induce hydraulic fracturing. Field-scale simulations indicate that during WAG and foam processes, the oil recovery increased 1.35 times and 1.6 times; and CO2 storage increased by 13.6% and 38.7% of total gas injection during the injection period compared to continuous gas flooding, respectively. During SAG process, coupling geomechanics will significantly increase the predicted gas storage volume, as a result of reservoir pore volume increase. Furthermore, analysis of the pressure margin for inducing hydraulic fracturing ensured the safety of SAG operation.
Optimizing CO2 and Field Gas Injection EOR in Unconventional Reservoirs Using the Fast Marching Method
Authors: Iino Atsushi , Datta-Gupta Akhil 
Published: March 2018

Abstract
Recently there has been an increasing interest in Enhanced Oil Recovery (EOR) from shale oil reservoirs, including CO2 and field gas injection. For the performance assessment and optimization of CO2 and gas injection processes, compositional simulation is a powerful and versatile tool because of the capability to incorporate reservoir heterogeneity, complex fracture geometry, multi-phase and multi-component effects in nano-porous rocks. However, flow simulation accounting for such complex physics can be computationally expensive. In particular, field scale optimization studies requiring large number of high resolution compositional simulations can be challenging and sometimes computationally prohibitive. In this paper, we present a rapid and efficient approach for optimization of CO2 and gas injection EOR in unconventional reservoirs using the Fast Marching Method (FMM)-based flow simulation.
The FMM-based simulation is analogous to streamline simulation and utilizes the concept of ‘Diffusive Time-of-Flight (DTOF)’. The DTOF is a representation of the travel time of pressure ‘front’ propagation and accounts for geological heterogeneity, well architecture and complex fracture geometry. The DTOF can be efficiently obtained by solving the ‘Eikonal equation’ using the FMM. The 3-D flow equation is then decoupled into equivalent 1-D equation using the DTOF as a spatial coordinate, leading to orders of magnitude faster computation for high-resolution and compositional models as compared to full 3-D simulations. The speed of computation enables the use of robust population-based optimization techniques such as genetic or evolutionary-based algorithm that typically require large number simulation runs to optimize the operational and process parameters.
We demonstrated the efficiency and robustness of our proposed approach using synthetic and field scale examples. We first illustrate the validation of FMM-based simulation approach using an example of CO2 Huff-n-Puff for a synthetic dual-porosity and heterogeneous model with a multi-stage hydraulically fractured well. In the field-scale application, we present an optimization of operating strategies for gas injection EOR for a depleted shale oil reservoir in the Eagle Ford formation. The rapid computation of the FMM-based approach enabled intensive simulation study involving high-resolution geological models with million cells resulting in a comprehensive evaluation of the EOR project including sensitivity studies, parameter importance analysis and optimal operating strategies.
This study shows the novelty and efficiency of the systematic optimization workflow incorporating the FMM-based compositional simulation for the field-scale modeling of CO2 and gas injection in shale oil reservoirs. Not only can it account for relevant physics such as reservoir heterogeneity, fracture geometry and fluid phase behavior but also lead to orders of magnitude saving in computational time over commercial finite difference simulators.
Surveillance Using Dimensionless Variables in the Mature Oil Field La Cira Infantas
Authors: Morales Victor Alfonso , Ramirez Leyla Kristle 
Published: March 2018

Abstract
La Cira Infantas is the oldest oil field in Colombia. It has approximately 100 years of production, and it is located in the Middle Magdalena Valley Basin, producing from a black oil multilayered and heterogeneous sandstone reservoir. Primary production began in 1918 until 1959 when the first water flooding process began. In 2005, Oxy Colombia and Ecopetrol initiated a joint venture of a new redeveloped water flooding process. Since the joint venture, the field has expanded to 400 patterns and 1,000 active producer wells, 95% of which are under a water flooding process. The redesign of the field considers 20-acre to 25-acre on average and 5-spot to 7-spot inverted patterns. Injector wells have a selective string completion, with mandrels and packers that allow having control on the vertical distribution of the volume of water per mandrel group. In order to monitor water flood performance in the field, a reservoir surveillance methodology, based on dimensionless variables, has been implemented.
The methodology was originally applied for a CO2 flood surveillance and was later extended to fit water flooding monitoring purposes. The paper presents the application of the dimensionless methodology, which allows the evaluation of water flood areas independently of their pattern configuration. This allows the comparison between patterns, sector or areas versus a theoretical ideal performance curve and quickly identify underperforming patterns in order to propose remedial actions.
The application of this methodology has opened new opportunities in the field including the identification of well candidates for chemical stimulation jobs and conformance jobs, isolation jobs in producer wells as well as pump upsize opportunities. Additionally, it has improved the technical evaluation of workover jobs. Because of this, in the last four years La Cira Infantas has extended its portfolio activity, executing over 400 workover jobs. More importantly, it has allowed the transfer of more than 20MMBO into PDP reserves, and the production of 3,000BOPD of incremental oil production per year since 2014.
This paper will provide an insight into the water flooding surveillance carried out in La Cira Infantas, which has proven to be very successful in Oxy's business units.