bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Impact of Gas/Oil IFT and Gas Type on the Performance of Gas, WAG and SWAG Injection Schemes in Carbonates Rocks
Authors: Shahrokhi Omid , Sohrabi Mehran , Masalmeh Shehadeh 
Published: March 2018

Abstract
Enhanced oil recovery schemes that control gas mobility (including WAG and SWAG) are often considered among viable options for oil recovery under challenging flow conditions of carbonate reservoirs. Miscible gas injection would be beneficial to oil recovery, however, in some cases, the reservoir pressure and availability of injectants are among the limiting factors. In this paper, we present the results of a series of immiscible and miscible gas injection coreflood experiments performed using a limestone reservoir core under different injection strategies. The experiments were performed under reservoir conditions using live crude oil. The core wettability was restored by ageing the core in crude oil for several weeks under reservoir temperature. Hydrocarbon gas was used as the immiscible injectant, and CO2 was used in the miscible experiments. To study the impact of the order of fluid injection, multiple WAG injection cycles were performed in separate experiments after water or gas injection. To investigate the impact of gravity on gas injection and WAG after gas injection on core scale, we have performed these experiment in both vertical and horizontal orientation. SWAG injection experiment with the same ratio of gas and water was also investigated. While saturation history affected the amount of trapped gas in the immiscible (high IFT) WAG injection experiments, only small amounts of gas were trapped regardless of injection direction. Regardless of the amount of trapped gas, no additional oil was recovered during water injection periods. Therefore, no meaningful linear relationship was observed between three-phase residual oil saturation and trapped gas saturation. Under immiscible conditions, gravity-stable gas injection recovered more than 45% of IOIP. In comparison, waterflooding produced 61% of IOIP. WAG injection after waterflooding only managed to produce 6% additional oil. Subsequent WAG cycles after first gas injection could only reduce the residual oil saturation to that observed for waterflooding (Sorw). SWAG injection improved the gas sweep efficiency considerably, however, the recovery factor at the end of the experiment was lower than waterflooding. Miscibility significantly improved the performance of WAG injection. The first miscible gas slug injected after waterflood, led to the recovery of about 70% of Sorw. Similar to WAG under immiscible conditions, trapped gas did not contribute to additional oil recovery in water injection periods thereafter. The observed difference in residual oil saturation versus trapped gas saturation relationship in carbonate rocks with those of sandstone reservoirs regardless of miscibility emphasises the importance of developing relevant three phase models specific to oil-wet carbonate reservoirs. The results provide rarely available experimental data that can help improve the available models for simulating and predicting the performance of WAG injection in oil-wet carbonates.
Implementing WRFM Well, Reservoir, Facility Management and Smart Field Best Practices for EOR Optimization
Authors: Zeidan A. A. , Redha Reeham Ali , Williams Darryl D. 
Published: March 2018

Abstract
Kuwait Oil Company (KOC) is operating two Heavy Oil fields. Field A aims at production by Cyclic Steam Stimulation (CSS), followed by steam flood. Field B envisages primary recovery through cold production, followed by non-thermal Enhanced Oil Recovery (EOR). This requires drilling and completion of large number of wells. Implementing Well, Reservoir and Facilities Management (WRFM) and Smart Field approach will be a key requirement for operation excellence in these fields.
Currently both fields have some wells in production, mostly as single isolated wells or wells in 5-acre/10-acre spacing. These pilot projects aimed at de-risking the commercial phase, which is to follow in the coming years. These wells are the training ground for young KOC staff to learn how to work in integrated teams using WRFM processes.
WRFM processes are tailor-made for KOC's operating environment. These processes include Digital Oil Field based on Exception Based Surveillance (to flag out only those wells and facilities outside of their operating envelope and/or optimization window) and Production System Optimization. This would help to eliminate operational bottlenecks, leading to optimization in manpower to deal with large number of wells. It is expected to be achieved by combining existing best practices of International Oil Companies (IOC) with existing KOC applications, leveraging successful global practices.
The paper shall highlight the timeline, activities and organizational changes underway to effect the transformation from existing operation to a larger and more complex development that includes continuous drilling, completion and well intervention (CWI) and facilities installation occurring simultaneously.
The implementation of WRFM Processes along with Digital field will achieve the production and operation goals by reducing well, artificial lift, and facility downtime. This innovative production optimization system by enabling efficient decision-making process shall lower the cost per bbl. and reduce down time by implementing automated surveillance workflow.
Water-Alternating-Gas Injection Simulation - Best Practices
Authors: Alzayer Hassan , Sohrabi Mehran 
Published: March 2018

Abstract
Water-Alternating-Gas injection is one of the most applicable EOR techniques in oil reservoirs worldwide. To optimize the WAG injection projects, numerical simulation is the best available tool to aid with such objective. In this paper, we are looking into the simulation process (from core-scale to reservoir-scale) in more details to understand the challenges and try to suggest best practices and guidelines.
The first part of this paper will discuss the role of hysteresis in WAG injection based on the results of several three-phase Water-Alternating-Gas injection experiments. Then the significance of three-phase hysteresis in simulating WAG injection will be highlighted. After establishing a good understanding of the role of three-phase hysteresis in WAG injection simulation, the second part will present sensitivity study at reservoirs-scale to identify the main differences in the simulation results. Finally, towards the end of the paper, WAG injection's best practices guideline will be suggested.
Currently, the common practice is to estimate three-phase hysteresis parameters (Land trapping parameter [C], secondary drainage gas relative permeability reduction exponent [alpha], residual oil modification factor [a], and three-phase water relative permeability [krw3ph]) from coreflood experiments. Based on several three-phase WAG injection experiments conducted at Heriot-Watt University, we came up with several conclusions. These conclusions are: If the pressure drop (DP) during the three-phase water injection experiment is significantly higher than the DP during two-phase water injection, then a lower three-phase water relative permeability is essential to match the three-phase WAG injection experimental data.If the pressure drop (DP) at the end of two-phase gas injection is lower than the DP at the end of three-phase gas injection, then alpha [α] is critical to match the three-phase WAG injection experimental data.If the experimental results showed significant gas trapping [Sgt] during water injection after gas injection, then Land's trapping parameter is essential to model such trapping behaviour at any scale.These parameters should be obtained from experiments starting with gas injection (GAW) to fit with the definitions accepted into the numerical simulations.
Many studies in the literature either ignores the effect of hysteresis in WAG injection or use invalid WAG hysteresis parameters. In this paper, we highlighted the role of hysteresis in WAG injection and clarified the confusion on the procedures to obtain the correct hysteresis parameters. Also, we provided an easy guideline to help the industry in making accurate predictions for WAG injection projects.
Experimental and Theoretical Study of Rate, Temperature and Solvent-Type Effects on Vapor Oil Gravity Drainage VOGD in Fractured Reservoirs
Authors: Anand Neha , Tang Brandon C. , Nguyen Bradley , Sie Chao-yu , Verlaan Marco , Castellanos-Diaz Orlando , Nguyen Quoc. P. 
Published: March 2018

Abstract
Application of thermal and solvent EOR technologies for heavy oil recovery in naturally fractured reservoirs is generally challenging due to low permeability, unfavorable wettability and mobility, and considerable heat losses. Vapor-Oil Gravity Drainage (VOGD) is a modified low temperature, solventonly injection technology, targeted at improving heavy oil recovery in fractured reservoirs. It utilizes high fluid conductivity in vertical fractures to establish large solvent-oil contact area rapidly and eliminates the need for massive energy and water inputs as compared to thermal processes, by operating at significantly lower temperatures with no water requirement. Investigation of the effect of solvent injection rate, temperature and solvent-type (n-Butane and dichloromethane (DCM)) on the recovery profile was carried out on a single-fracture core model. This work combines the knowledge obtained from experimental investigation and analytical modeling using Butler's correlation with validated fluid property models to understand the relative importance of various recovery mechanisms behind VOGD, namely molecular diffusion, asphaltene precipitation and deposition, capillarity, and viscosity reduction.
Experimental and analytical model studies indicated that molecular diffusion, convective dispersion, viscosity reduction via solvent dissolution and gravity drainage are dominant phenomena in the recovery process. Material balance analysis indicated limited asphaltene precipitation. High fluid transmissibility in the fracture along with gravity drainage led to early solvent breakthroughs and oil recoveries as high as 75% OOIP. Injecting butane at higher rate and operating temperature enhanced vapor solvent rate inside the core leading to highest ultimate recovery. Increasing operating temperature alone did not improve ultimate recovery due to decreased solvent solubility in the oil. Although with DCM, lower asphaltene precipitation should maximize oil recovery rate, its higher solvent (vapor)-oil interfacial tension resulted in lower ultimate recovery than butane. Ideal density and non-ideal double-log viscosity mixing rules along with molecular diffusivity as a power function of oil viscosity were used to obtain an accurate physical description of the fluids for modeling solvent-oil behavior. With critical phenomena such as capillarity and asphaltene precipitation missing, Butler's analytical model under predicts recovery rates by as much as 70%.
Field-Scale Evaluation of Re-injecting the Associated Gas to Enhance the Recovery of Oil Through the GAGD Process: A Prospective Pilot Project in A Southern Iraqi Oil Field
Authors: Al-Mudhafar Watheq J. , Al-Maliki Ali K. , Al-Tameemi Abdullah , Al-Attar Atheer , Al-Ameri Riyam H. , Hosseini-Nasab S. M. 
Published: March 2018

Abstract
The Gas-Assisted Gravity Drainage (GAGD) process has been suggested to improve oil recovery in both secondary and tertiary recovery through immiscible and miscible injection modes. In contrast of Continuous Gas Injection (CGI) and Water-Alternative Gas (WAG), the GAGD process takes advantage of the natural segregation of reservoir fluids to provide gravity-stable oil displacement and improve oil recovery. In the GAGD process, the gas is injected through vertical wells to formulate a gas cap to allow oil and water drain down to the horizontal producer (s). In this paper, a field-scale compositional reservoir simulations were conducted to study the feasibility of the GAGD process to enhance the recovery of oil in synthetic and real oil reservoirs. The GAGD process was implemented through the 5th SPE comparative solution project model (SPE5) and the heterogeneous upper sandstone oil reservoir in the South Rumaila oil field, located in Southern Iraq. Four different gas mixtures were injected: carbon dioxide, flue gas, nitrogen to methane, and associated gas (AG). In the SPE5 model, it was investigated that CO2-AGD process is much better than other gas mixtures with respect to achieving the highest oil recovery because of the influential role of CO2-rock-oil interaction to enhance the recovery of oil in this homogeneous system. The flue gas and nitrogen plus methane mixtures had similar efficiency by obtaining approximate oil recovery. However, the results of south Rumaila field GAGD evaluation indicated that the associated gas has a slight higher oil recovery than other gas mixtures including CO2 because of its compatibility with the existing reservoir and fluid properties. More specifically, the oil recovery by the end of the perdition period through the CO2, AG, flue gas, and N2+CH4 were 73.88%, 74.25%, 74.13%, and 73.91%, respectively; whereas, oil recovery at the beginning of the prediction period is 66.8%. In addition, there are many other reservoir factors have significant impact on the process efficiency and led to change the efficiency of each of the four gas mixtures, such as heterogeneity. It can be concluded that the immiscible flooding of using associated gas for re-injection in the South Rumaila field has the same effect of using the CO2 with respect to achieving a promising oil recovery. Consequently, associated gas can be efficiently utilized for a pilot EOR project implementation in the Rumaila field as a cheap solvent alternative to the carbon dioxide.
Immiscible Gas Injection Pilot on an Offshore Mature Field with Undersaturated Viscous Oil
Authors: Bourgeois Marcel J , Boot Nicolaas , Saint-Felix Martin , Boudimbou Innocent , Tollis Arnaud 
Published: March 2018

Abstract
This paper reviews the rationale and first results of the gas injection pilot that was performed in 2014-2015 on a conventional offshore mature field. This field is a low permeability heterogeneous reservoir under water-flood with undersaturated viscous oil (21°API). The objective of the pilot was to check in a low-cost environment if injecting rich hydrocarbon gas in this oil would be beneficial for oil production.
Preparatory work included PVT experiments and SCAL data. The SCAL data allowed to estimate the gas/oil relative permeabilities for gas injection. The PVT work allowed to quantify the gas-oil interactions, especially swelling and deviscosification of the viscous oil. In the field, the pilot was planned and safely implemented in a low-cost environment, using the Huff and Puff approach: an existing producer was used as a gas injector using the gas-lift facilities, and after a 2 week soaking period, it was put back on production, and production data were closely monitored for each cycle.
Pressure and Temperature conditions imply that the injected HC gas is not miscible, but since the oil is strongly undersaturated, it was found that the beneficial effect of the gas injection was quite strong on oil properties (Bo and viscosity). Moreover, the richness of the gas allowed a condensing gas drive that is more efficient in terms of deviscosification than what could be achieved with a lean gas.
In terms of implementation in the field, a phased approach was adopted. The pilot was started in 2015 using the Huff and Puff technique, with Cycle 1 & 2 showing good results: a beneficial effect has clearly been seen on the liquid and oil rates at the producer when injected gas rate was sufficient, and could be history matched sucessfully.
A way forward is also proposed, as a further cycle 3 is currently planned early 2018, in order to derisk the mechanism for larger injected gas volumes, with a possible phase 2 to be planned later on.
Impact of Salinity on Crude Oil/Brine/Rock Interfaces: A New Insight on Carbonate Wettability from Cryo-BIB-SEM
Authors: Gmira A. , Cha D. K. , Al-Enezi S. M. , Yousef A. A. 
Published: March 2018

Abstract
It is well-established that smartwater flooding through tuning of injection water chemistry and ionic composition, has a significant impact on the recovered oil, but the exact underlying mechanism by which this occur, is not well understood, and is supposed to be caused by a complex interactions occurring at the fluid/fluid and fluid/rock interfaces. Most of the laboratory studies reported so far have been focused on characterization of crude oil/brine/carbonate system and wettability alteration at micro- and macroscale using classic measurements, including contact angle, IFT, NMR, zeta potential and coreflooding. However, those techniques depend strongly on carbonate heterogeneities, roughness and fluids distribution inside the pores. Thus, a direct visualization at pore scale is needed to identify fluids distribution in-situ, wettability state at pore scale and wettability alteration by injection water composition tuning. We used Broad Ion Beam slope-cutting in combination with Scanning Electron Microscopy under Cryogenic conditions (Cryo-BIB-SEM) to study crude oil/brine/carbonate interfaces. Direct imaging at nanoscale allows investigation of the porosity, in-situ preserved fluids and, combined with energy dispersive spectroscopy (EDS) identify crude oil and brine distribution and quantifies wettability state by measuring contact angle at pore level. In this study, we compare carbonate rocks that have been aged in crude oil and saturated with brines at high and low ionic strength brines. In both samples, we investigate oil and brine distribution in the carbonate porous matrix. Results show that ion milling at cryogenic conditions allows the preparation of a large smooth cross-section. The presence of pinning points contribute to the crude oil adherence to carbonate surface. Scanning electron microscope images indicate that in presence of high ionic strength brine, large trapped oil patches have an elongated shape, following the carbonate surface morphology. While oil droplets have a pseudo-spherical shape with low ionic strength brine in addition to a distinct boundaries between oil and brine phase. Statistical analysis of in-situ contact angle and carbonate/oil/brine interface demonstrate the sensitivity of cryo-BIB-SEM approach to sub-micron scale wettability alteration caused by ionic strength variations.
Development of Thermo-Responsive Polymers for CEOR in Extreme Conditions: Applicability to Oman Oil Fields
Authors: Divers T. , Al-Hashmi A. R. , Al-Maamari R. S. , Favero C. 
Published: March 2018

Abstract
The selection of the right polymer chemistry in chemical enhanced oil recovery operations is key for a successful field implementation. Operators require guarantees on polymer robustness and efficiency in order to optimize their polymer flooding processes, especially in the current context of low oil price. We evaluated different thermo-responsive polymers dedicated to Oman fields conditions in this perspective.
Several thermo-responsive polymers were considered in this study, the properties and performances of which were assessed. The purpose was to make sure that gain in dosage brought by these structured polymers is not detrimental to polymer stability and injectivity. Consequently, polymers were characterized in terms of rheological properties, thermal stability and propagation through porous media.
Thermo-responsive polymers are characterized by a LCST (Lower Critical Solution Temperature). They behave like regular polymers below this specific temperature and like associative polymers above it. The LCST varies with several parameters, including thermo-responsive moieties composition, content and molar mass, as well as brine salinity. The viscosifying properties and overall performances of such polymers are subsequently strongly driven by field conditions. Several thermo-responsive polymers were thus designed to fit model field conditions representing Oman oil fields. Rheological properties were firstly evaluated in stationary and dynamic modes, what permitted to emphasize the unique behavior of such polymers and the gain in dosage they can bring. Core flooding tests were then performed to assess polymer injectivity in porous medium. Interestingly, thermo-responsive polymers can display very high resistance factor compared to regular ones while maintaining good transport properties. The polymer retention in the core remained low. Core flood tests also gave an idea of this chemistry limitations for an use in Oman oil fields. Polymers thermal stability was determined in several conditions, fully anaerobic or in presence of O2 and H2S. The efficiency of two protective packages against H2S induced degradation was evaluated. The results after one year aging highlight the importance to avoid oxygen ingress in the system in presence of H2S. However, it is still possible to keep an acceptable level of viscosity by fine-tuning protective additives.
This study demonstrates the applicability and limitations of thermo-responsive polymers, especially in conditions that mimic Oman oil fields. These new thermo-responsive polymers are promising candidates to keep CEOR economically viable in tough conditions.
Surfactant-Polymer EOR from Laboratory to the Pilot
Authors: Puskas S. , Vago A. , Toro M. , Ordog T. , Kalman G. , Hanzelik P. , Bihari Zs. , Blaho J. , Tabajdi R. , Dekany I. , Dudas J. , Nagy R. , Bartha L. , Lakatos I. 
Published: March 2018

Abstract
Central element of MOL Hungarian Oil and Gas Plc. (MOL) US strategy is to increase the hydrocarbon production at Hungarian oil and gas fields using technologies that are more efficient. The main goals of this activity are to increase the recovery factor in fields depleted with extensive water flooding, improving efficiency of recovery technologies. For this purpose, new materials and technologies should be developed and applied at both Hungarian and foreign matured oil fields. That is the biggest challenge of the research and development (R&D) activity of the MOL Upstream. The R&D project began more than ten years ago to meet these challenges and increase the oil recovery factor of the Algyo field, which is the largest Hungarian oil field. This paper describes how a countless number of surfactants, co-surfactants and their mixtures were synthetized, developed and tested in the laboratory to achieve the objective, developing a combined surfactant-polymer (SP) flooding technology. The most important properties of these complex fluids were the thermal stability at reservoir conditions (98°C and 170 bar), the colloid chemical stability in electrolyte medium (formation water) and the compatibility with reservoir rock and pore filling fluids. The primary findings of this job show that several surfactants were effective at high temperature; low salinity reservoir conditions and have good solubilisation and displacement effect and low interfacial tension and low reversible adsorption on reservoir rock. Synergetic effect was observed between surfactants and polymers therefore surfactant-polymer mixtures were produced and tested in core flooding tests. Based on numerous displacement tests on reservoir core plugs it can be stated that the calculated recovery factor was 20-25% using the developed SP mixtures. The successful laboratory displacement tests were also reproduced by numerical simulation on numerical core samples as well as the injectivity test on the new 3D reservoir model that was carried out to see the effect of developed SP mixture under real reservoir conditions. This paper will present the results of several years of research and development work for SP formulation targeting SP flooding in high pressure and high temperature reservoir. The field implementation through an injectivity test will also be presented demonstrating that injection of 2,000 m3 SP solution has huge effect on oil production even 3 years later. Based on the outstanding field results a SP flooding pilot was started in 2016.