Dr. Abdulmohsin Imqam (Professor) | Missouri University of Science and Technology (original) (raw)

Papers by Dr. Abdulmohsin Imqam (Professor)

High-viscosity friction reducers (HVFRs) have been recently gaining more attention and increasing... more High-viscosity friction reducers (HVFRs) have been recently gaining more attention and increasing in use, not only as friction-reducing agents but also as proppant carriers. Reusing produced water has also been driven by both environmental and economic benefits. Currently, most friction reducers on the market are anionic friction reducers, which are fully compatible with most produced water with low to medium level of total dissolved solids (TDS) but show a significant drop at high TDS conditions in terms of their friction reduction performance in most cases. On the contrary, cationic friction reducers are believed to have better TDS tolerance and friction reduction performance under high TDS conditions. However, concerns remain about performance of using anionic and cationic HVFRs with produced water to transport proppant. The ultimate objective of this experimental study is to comparably analyze the proppant transport capabilities of anionic and cationic HVFRs in high TDS and reservoir temperature environments. An anionic HVFR and a cationic HVFR, both at 4 gallons per thousand gallons (GPT), were selected and analyzed. The rheology measurements of these anionic and cationic HVFRs were conducted in deionized (DI) water and high TDS water conditions. Static and dynamic proppant settling tests were conducted at various TDS conditions at reservoir temperature. Wall retardation and particle hindering on the performance of both anionic and cationic HVFRs were also observed and investigated using the particle image velocimetry (PIV) method. The results showed that the anionic HVFR had higher viscosity than the cationic HVFR due to larger molecular weight and had much higher elasticity. Increase in TDS concentration would decrease the viscous and elastic profiles of both anionic and cationic HVFRs. In particular, the elastic profile became negligible for both HVFRs. Besides, the "critical salinity" phenomenon was observed. Above this salinity, the viscosity of HVFRs was no longer affected by increasing TDS level. The "critical salinity" for both of the 4-GPT anionic and cationic HVFRs was in the range of 30 000 to 200 000 mg/L. Moreover, the cationic HVFR had lower "critical salinity" than the anionic HVFR. Finally, the correlation between rheology and proppant transport capabilities of HVFRs is discussed in this paper, and a simplified decision-making process of selecting fracturing fluids is proposed.

The stimulation of unconventional reservoirs to improve oil productivity in tight formations of s... more The stimulation of unconventional reservoirs to improve oil productivity in tight formations of shale basins is a key objective in hydraulic fracturing treatments. Such stimulation can be made by reliable fracture fluids that have a high viscosity and elasticity to suspend the proppant in the fracture networks. Recently, due to several operational and economic reasons, the oil industry began using highviscosity friction reducers (HVFRs) as direct replacements for linear and crosslinked gels. However, some issues can limit the capability of HVFRs to provide effective sand transport, including the high fluid temperature during fracture treatment inside the formations. This may lead to unstable fracture fluids caused by a decrease in the interconnective strength between the fluid chains, which results in reduced viscosity and elasticity. This study comprehensively investigated HVFRs in comparison with guar at various temperatures. An HVFR at 4 gallons per thousand gallons of water (gpt) and guar at 25 pounds per thousand gallons of water (ppt) were selected based on fluid rheology tests and hydraulic fracture execution field results. The rheological measurements of both fracture fluids were conducted at different temperature values (i.e., 25, 50, 75, and 100 C). Static and dynamic proppant settling tests were also conducted at the same temperatures. The results showed that the HVFR provided better proppant transport capability than the guar. The HVFR had better thermal stability than guar, but its viscosity and elasticity decreased significantly when the temperature exceeded 75 C. An HVFR can carry and hold the proppant more deeply inside the fracture than liner gel, but that ability decreases as the temperature increases. Therefore, using conditions that mimic field conditions to measure the fracture fluid rheology, proppant static settling velocity, and proppant dune development under a high temperature is crucial for enhancing the fracture treatment results.

SPE Journal, 2023

High viscosity friction reducers (HVFRs) have been used extensively as agents to reduce friction ... more High viscosity friction reducers (HVFRs) have been used extensively as agents to reduce friction and transport proppants during hydraulic fracturing. Meanwhile, the recycling of produced water has gained traction due to its environmental and economic advantages. Presently, the predominant friction reducers utilized in the fields are categorized as anionic and cationic HVFRs. Anionic HVFRs are frequently injected with fresh water, while cationic HVFRs are typically used in conjunction with high-total dissolved solids (TDS) produced water. It is believed that cationic friction reducers have better TDS tolerance, friction reduction performance, and proppant transport capabilities than their anionic counterparts under high-TDS conditions due to their better viscous and viscoelastic properties. Moreover, different cations' effects on anionic HVFR have been studied extensively, and the reduction of viscosity and viscoelasticity is mostly concluded as the result of the charge screening mechanism. However, anions' effects on cationic HVFRs still remain to be investigated. Besides, in some previous experimental studies, there may have been a lack of specificity indefining the experimental procedures or effectively controlling the experimental variables. Therefore, the ultimate objective of this experimental study is to analyze various cations' and anions' effects on the viscosity and viscoelasticity of anionic and cationic HVFRs comparably and precisely with well-controlled experimental variables. For the viscosity of HVFRs, two hypotheses based on the charge screening mechanism are proposed and will be tested in this study. The first hypothesis is that the viscosity reduction of anionic HVFRs is due to cations, whereas the viscosity reduction of cationic HVFRs is due to anions. The second hypothesis is that the viscosity reduction of HVFRs is mainly due to ions' valence instead of their types. To demonstrate both hypotheses, an anionic (FLOJET DRP 2340X) and a cationic (FLOJET DRP 419X) HVFR at 4 gallons per thousand gallons (GPT) were selected and analyzed. The rheology measurements of both anionic and cationic HVFRs were conducted with deionized (DI) water and various salts, respectively. Fe 3+ and H + (or pH) effects were specifically investigated. The results showed both hypotheses failed. First, the viscosity reduction of the cationic HVFR is mainly due to anions. However, Fe 3+ also has pronounced effects on the viscosity reduction of the cationic HVFR. Second, the charge shielding mechanism is only one of the viscosity reduction mechanisms of anions and cations for HVFRs. Cations from the same group on the periodic table seem to have similar effects on the viscosity of the anionic HVFR. For the viscoelasticity of HVFRs, cations' and anions' effects remain to be further investigated. For the cationic HVFR, results showed a similar trend to the effects on viscosity. For the anionic HVFR, monovalent cations from alkali metals had similar effects on viscoelasticity reduction. Overall, this study provided very precise and specific procedures by using molarity (M) instead of weight concentration [parts per million (ppm) or weight percent (wt%)] as a standard protocol to investigate various ions' effects on the viscosity and viscoelasticity of HVFRs and the mechanisms behind them, which may also be applied to other polyelectrolytes (i.e., Xanthan gum).

Asphaltene is a component of crude oil that has been reported to cause severe problems during pro... more Asphaltene is a component of crude oil that has been reported to cause severe problems during production and transportation of the oil from the reservoir. It is a solid component of the oil that has different structures and molecular makeup which makes it one of the most complex components of the oil. This research provides a detailed review of asphaltene properties, characteristics, and previous studies to construct a guideline to asphaltene and its impact on oil recovery. The research begins with an explanation of the main components of crude oil and their relation to asphaltene. The method by which asphaltene is quantified in the crude oil is then explained. Due to its different structures, asphaltene has been modeled using different models all of which are then discussed. All chemical analysis methods that have been used to characterize and study asphaltene are then mentioned and the most commonly used method is shown. Asphaltene will pass through several phases in the reservoir beginning from its stability phase up to its deposition in the pores, wellbore, and facilities. All these phases are explained, and the reason they may occur is mentioned. Following this, the methods by which asphaltene can damage oil recovery are presented. Asphaltene rheology and flow mechanism in the reservoir are then explained in detail including asphaltene onset pressure determination and significance and the use of micro-and nanofluidics to model asphaltene. Finally, the mathematical models, previous laboratory, and oilfield studies conducted to evaluate asphaltene are discussed. This research will help increase the understanding of asphaltene and provide a guideline to properly study and model asphaltene in future studies.

Carbon dioxide (CO 2) injection is one of the most applied enhanced oil recovery methods in the h... more Carbon dioxide (CO 2) injection is one of the most applied enhanced oil recovery methods in the hydrocarbon industry, since it has the potential to increase oil recovery significantly and can help reduce greenhouse gases through carbon storage in hydrocarbon reservoirs. Carbon dioxide injection has a severe drawback, however, since it induces asphaltene precipitation by disrupting the asphaltene stability in crude oil that bears even the slightest asphaltene concentration. This can result in severe operational problems, such as reservoir pore plugging and wellbore plugging. This research investigates some of the main factors that impact asphaltene stability in crude oil during CO 2 injection. Initially, asphaltene precipitation, flocculation, and deposition were tested using visual tests without CO 2 in order to evaluate the effect of oil viscosity and temperature on asphaltene stability and content in the crude oil. The results obtained from the visualization experiments were correlated to the Yen-Mullins asphaltene model and were used to select the proper chemical to alter the oil's viscosity without strongly affecting asphaltene stability. After performing the visual asphaltene tests, a specially designed filtration vessel was used to perform the oil filtration experiments using filter membranes with a micron and nanometer pore size. The effect of varying CO 2 injection pressure, oil viscosity, filter membrane pore size, and filter membrane thickness on asphaltene stability in crude oil was investigated. The results were then correlated with the Yen-Mullins asphaltene model to characterize the asphaltene size within the oil as well. Results showed that as the oil viscosity increased, the asphaltene concentration in the oil also increased. Also, the asphaltene concentration and filter cake thickness increased with the decrease in filter membrane pore size, since the asphaltene particles either plugged up the smaller pores, or the asphaltene nanoaggregates were larger than the pore sizes, and thus the majority of them could not pass. This research studies asphaltene instability in crude oil during CO 2 injection in different pore sizes, and correlates the results to the principle of the Yen-Mullins model for asphaltenes. The results from this research can help emphasize the factors that will impact asphaltene stability during CO 2 injection in different pore sizes in order to help reduce asphaltene-related problems that arise during CO 2 injection in hydrocarbon reservoirs.

For many years Portland cement has been used in oil well cementing. Even though Portland cement h... more For many years Portland cement has been used in oil well cementing. Even though Portland cement has been used for many years, it has several drawbacks, including operational failures and severe environmental impacts. Fly ash based geopolymer cement has been recently investigated as a low-cost, environmentally friendly alternative to Portland cement. This research develops a novel formulation of Class C fly ash based geopolymer and investigates its applicability as an alternative to Portland cement in hydrocarbon well cementing. Twenty-four variations of fly ash Class C based geopolymers were prepared, and by comparing several of their properties using API standard tests, the most favorable geopolymer formulation was determined. The effect of varying the ratios of alkaline activator to fly ash, sodium silicate to sodium hydroxide, and sodium hydroxide concentration was investigated. The selection of the formulation was based on four different tests, including rheology, density, compressive strength, and fluid loss test. Then, a comparison between the selected mix design and Portland cement was conducted using the same tests, in addition to stability tests (sedimentation test and free fluid test). Based on our results, geopolymer was found to have superior rheological and mechanical properties compared to the Portland cement. The geopolymer design, which had lower fluid loss, 93 ml after 30 min, sufficient com-pressive strength, 1195 psi in 24 h, and an acceptable density, 14.7 lb/gal, and viscosity, 50 cp, was further compared to the Portland cement. The higher mechanical strength of geopolymer using fly ash Class C compared to Portland cement is very promising for achieving long-term wellbore integrity goals and meeting regulatory criteria for zonal isolation.

The development of unconventional shales started a new era in the oil and gas industry. These res... more The development of unconventional shales started a new era in the oil and gas industry. These reservoirs represent a challenge to conventional drilling fluids since the fluid invasion, cutting dispersion, or shale swelling can lead to wellbore instability problems. Although oil-based drilling fluids (OBM) are capable to control these issues, environmental and economic concerns limit its application. Recently, nanoparticles (NPs) have introduced a new perspective in drilling fluid technology, offering a unique alternative to improve the performance of water-based drilling fluids (WBM) for shale applications. This research evaluates the potential of using silica nanoparticles (SiO 2-NPs) and graphene nanoplatelets (GNPs) to formulate a nanoparticle water-based drilling fluid (NP-WBM). The study considers a bottom-up approach, selecting the NPs based on the Woodford Shale's characterization and focuses its primary objective in finding the most suitable NP combination to enhance the rheological, filtration and inhibition properties of the customized NP-WBM. The shale characterization included X-ray diffraction (XRD), cation exchange capacity (CEC), and scanning electron microscopy (SEM). The zeta-potential technique was used to assess the stability of the NPs. The NP-WBM was evaluated by means of API filtration test (LTLP), high-temperature/high-pressure (HTHP) filtration test and rheological measurements using a conventional viscometer. Finally, the inhibition capability of the NP-WBM was tested against the Woodford shale through immersion and cutting dispersion tests. NPs' characterization revealed that both additives can provide stable suspensions with zeta-potential values < −30 mV. A total NP concentration of 0.75 wt% (0.5 wt% of SiO 2-NPs and 0.25 wt% of GNPs) yielded to the maximum reduction in filtrate volume at both, LTLP and HTHP conditions. The less permeable filter cake resulted in no spurt-losses, supporting the NPs' plugging effect. A strong cross-linked network created between the NPs and the conventional additives increased the cutting carrying capacity of the NP-WBM with slight effects on its plastic viscosity (PV). The immersion test carried out in water revealed that illitic shales might experience micro-fractures along the bedding planes in the absence of bridging materials. Contrarily, the NP-WBM provided an adequate plugging network between grain boundaries, resulting in no micro-fractures, and the reduction of the cutting erosion by 35.61%. Overall, this study highlights the capability of nanomaterials to extend the reliability of WBM to harsher environments while seeking an eco-friendlier alternative.

Preformed particle gels (PPGs) have been successfully applied as a plugging agent to solve the co... more Preformed particle gels (PPGs) have been successfully applied as a plugging agent to solve the conformance problem in fractured reservoirs. They are injected to plug fractures and then divert displacing fluid into poorly swept zones/areas. However, PPG-propagation and-plugging mechanisms through open void-space conduits (VSCs) have not been studied thoroughly. This paper investigated various situations involving heterogeneous conduits and their geometrical effect on PPG injectivity. Five-foot tubes were used to mimic VSCs. Three models were designed to gain understanding on how conduit geometry and PPG properties affect gel transportation, including a single conduit with a uniform internal diameter (ID); a single conduit with a nonuniform ID along its length; and two parallel conduits with different ID ratios with respect to each other. Results obtained from single-conduit models with uniform and nonuniform diameters showed PPG-injection pressure increased significantly as the conduit became more heterogeneous. Particle gels accumulated at the choke point within each conduit and caused injection pressure to increase accordingly. When two parallel conduits are available for flow, the relative distance of PPG penetration into the conduits depends strongly on the ratio of the conduit diameters and the gel strength. In addition, the ratio of gel-particle-size diameter to conduit diameter contributes significantly to the gel-transport selection. This paper demonstrates important impact elements of gel propagation for different heterogeneous-conduit situations.

Preformed particle gels (PPG) have been successfully applied as a plugging agent to solve the con... more Preformed particle gels (PPG) have been successfully applied as a plugging agent to solve the conformance problem in fractured reservoirs. They are injected to plug fractures and then divert displacing fluid into poorly swept zones and areas. However, PPG propagation and plugging mechanisms through open fractures have not been studied thoroughly. This paper investigated the influence of some factors (particle size, brine concentration, heterogeneity, injection flow rate, and brine salinity) on gel injectivity and plugging performance for water flow through opening fractures. Five-foot tubes were used to mimic opening fractures. Three models were designed to gain understanding on how fracture geometry and PPG properties affect gel injection and plugging efficiency, including (1) single fracture with uniform fracture width, (2) single fracture with different widths, and (3) two parallel fractures with different width ratios between each other. Results from single uniform fracture experiments showed that PPG injection pressure was more sensitive to gel strength than gel particle size. When large PPG size and high gel strength were used, high injection pressure and large injection pore volume were required for PPG and brine to reach fracture outlets. Results from single heterogeneous fracture model experiments showed PPG injection pressure increased as the fracture heterogeneity in sections increased. Particle gel accumulated at the choke point within each fracture and caused injection pressure to increase accordingly. Furthermore, results showed that having a lower salinity within a fracture, which was less than the brine salinity that was used to prepare PPG, would improve the PPG plugging efficiency for water flow. Parallel fracture models results showed that when weak PPG was used, a large volume of PPG flowed into a large fracture width and a small portion of the gel particle volume flowed into small fracture width. However, with increased gel strength and fracture width ratio, PPG only flowed through larger fracture widths. This paper demonstrates important impact elements of gel propagation and water flow for different opening fracture situations.

Millimeter-sized (10-mm to mm) preformed particle gel (PPG) has been used to control water flow t... more Millimeter-sized (10-mm to mm) preformed particle gel (PPG) has been used to control water flow through superhigh-permeability zones and fracture zones in mature oil fields. When the PPG is extruded into target zones, the gel can form a cake on the surface of low-permeability, unswept formations. This cake reduces the effectiveness of conformance control and the amount of oil that can be recovered from unswept oil formations. Thus, this study evaluated the effectiveness of using hydrochloric acid (HCl) to remove gel cakes induced during conformance-control treatments. The interactions between HCl and PPG were evaluated to understand the swelling, deswelling, and gel strength after adding acid. A Hassler core holder was then used to determine the core permeability after gel and acid treatments. Gels swollen in brine concentrations of 0.05, 1, and 10% were injected into a sandstone core having a variety of permeabilities. Brine was then injected in cycles through the gel into the core. The core permeability was measured after the gel-particle injection and after the core surface of the gel cake was soaked in the acid solution for 12 hours. The results indicate that particles swollen in brine concentrations of 0.05% caused more damage than those swollen in higher concentrations of brine. The damage increased as the core permeability increased for all the swollen gels. HCl removed the gel cake effectively; varying the HCl concentration did not cause a significant difference in the gel-cake removal efficiency. The gel was found to swell much less in HCl solutions than in brine. After the gel was deswollen in acid, the gel strengths were found to be higher than when the gel was swollen in brine. This work concludes that HCl can be used effectively to mitigate the damage induced by PPGs.

This paper was prepared for presentation at the SPE Improved Oil Recovery Symposium held in Tulsa... more This paper was prepared for presentation at the SPE Improved Oil Recovery Symposium held in Tulsa, Oklahoma, USA, 12–16 April 2014. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessar ily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohi bited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract The application of nanoparticles in enhanced oil recovery (EOR) continues to gain attention in the...

SPE/IATMI Asia Pacific Oil & Gas Conference and Exhibition, 2015

Excess water production has long been considered a major problem leading to the life-shortening o... more Excess water production has long been considered a major problem leading to the life-shortening of oil and gas wells and operational problems. High-permeability streaks, fractures, conduits, and fracture-like features can expedite an undesirable water channeling and early water breakthrough during water flooding. Preformed particle gel (PPG) is one of the commercial gels invented exclusively to plug such features to reduce excess water production, improve sweep efficiency, and increase oil production. This paper reports the results of laboratory experiments that studied the PPG's injection and placement mechanism through Super-K permeability cores to reduce unwanted water production and increase oil recovery. Extensive experiments were conducted to examine the effect of the sand permeability, PPG size, concentration, and water salinity on the PPG injection process, passing criteria, and plugging efficiency to water flow. A two foot sand pack model with four pressure taps was designed to monitor PPG transport and plugging performance. The results showed that the PPG propagated deep into the sand pack. PPG's in-depth permeability reduction to the core was dependent on the PPG size, strength, concentration, and sand permeability. Fully swollen gel particles had better injectivity than partially swollen particles with a larger diameter size; particle strength was more dominant in influencing particle movement than was particle size. The injection pressure increased as the PPG concentration, water salinity, and gel particle size increased. A large injection pore volume was required for the PPGs to be produced at effluent when both the water salinity and particle size were increased and when the PPGs concentration decreased. PPG transport through Super-K permeability sand exhibited three patterns of injection processes based on both the threshold pressure and the injection pressure measurements across the sand pack cores: low gel particle retention and pass; high gel particle retention and pass; and high gel particle retention, breaking, and pass. After the PPG injection process was completed, cycles of saline water were injected into the sand pack to test the PPG's resistance to water flow. The PPG's blocking efficiency to water flow increased as the PPG strength, size, and concentration increased. The PPG placement mechanism, such as washout, was also found to considerably affect the water injection flow processes. The results of this laboratory experiment will aid in the selection of future conformance control candidates and also optimize the particle gel treatment design for large-scale field projects.

SPE Russian Petroleum Technology Conference, 2015

Комбинирование технологии выравнивания профиля приемистости и метода контроля подвижности позволя... more Комбинирование технологии выравнивания профиля приемистости и метода контроля подвижности позволяет увеличить эффективность вытеснения нефти в неоднородных пластах без поперечных перетоков Абдулмохсин Имкам, Баоцзюнь Бай и Минчжень Вэй, Миссурийский университет науки и технологий Авторское право 2015 г., Общество инженеров нефтегазовой промышленности Этот доклад был подготовлен для презентации на Российской нефтегазовой технической конференции SPE, 26 -28 октября, 2015, Москва, Россия.

SPE Russian Petroleum Technology Conference, 2015

On water flooding process, water preferential flow through high permeability, fractures, and larg... more On water flooding process, water preferential flow through high permeability, fractures, and large channels; cause a large amount of recycling of water without much benefit to oil production. Preformed particle gels (PPGs) have drawn more attention to reduce the fluid flow in these large opening features and to improve macroscopic oil efficiency. In spite of the successful applications of using PPGs in plugging such large features, there is still need to combine PPGs with other technology to produce more oil from the low permeable rich zones. The ultimate purpose of this study is to investigate the effectiveness of combining conformance control treatment using PPGs with mobility control using polymer to enhance oil recovery from both swept and un-swept oil zones. PPGs was injected into large permeability zones to reduce their permeability while polymer injected after gel to further increase oil recovery from the low permeability zones. Two separate parallel tubes packed with different sand grain sizes were designed to emulate the case when there is non-cross flow heterogenity between the low and the high permeability layers in the reservoir. Experiments were designed to examine the effect of permeability contrast ratio on the performance of coupling PPG and polymer to increase oil recovery. The results show a significant increase in oil recovery from both low and high permeability cores after performing polymer flooding right away after gel treatment. The oil recovery incremental was varied and strongly dependent on permeability contrast ratios. PPGs improved oil sweep efficiency significantly when the core permeability layers became more heterogeneous. Injection profile was improved after the PPG treatment, thus oil recovery from the low permeability cores was increased significantly.

SPE Annual Technical Conference and Exhibition, 2015

Water channeling is caused by reservoir heterogeneities that lead to the development of high-perm... more Water channeling is caused by reservoir heterogeneities that lead to the development of high-permeability streaks. A recent interest in microgel treatment using preformed particle gels (PPGs) has drawn more attention to reducing excess water production, improving sweep efficiency, and enhancing macroscopic oil recovery. The objective of this paper is to gain an inclusive understanding of PPG transport mechanisms through heterogeneous reservoirs. A numerical simulator was developed to characterize the propagation of PPGs through given reservoir. The simulator was used to optimize the gel treatment design to enhance oil recovery from un-swept, low-permeability, and oil-rich zones. A novel core flooding experiment was conducted to validate the developed mechanistic models. The experimental results using heterogeneous permeability model without cross flow showed large incremental oil recovery from the low permeability sand pack after treatment with PPGs. The developed models were implemented into the gel transport reservoir simulator to aid in the design and to optimize the water control processes using PPGs. The results obtained from the simulator indicated a good match with core flooding experiment results. The sensitivity analysis showed incremental oil recovery was strongly dependent on the permeability contrast, PPG concentration, and PPG treatment size.

Millimeter-sized (10 m~mm) particle gels have been used widely to control water flow through supe... more Millimeter-sized (10 m~mm) particle gels have been used widely to control water flow through super-high-permeability zones and fracture zones in mature oil fields. During particle gel extrusion into target zones, the gel can form a cake on the surface of low-permeability, unswept formations. This cake reduces the effectiveness of conformance control as well as the amount of oil that can be recovered from unswept oil formations. Thus, we evaluated the effectiveness of using hydrochloric acid (HCL) to remove gel cakes induced during conformance-control treatments.

This paper was prepared for presentation at the SPE Asia Pacific Oil & Gas Conference and Exhibit... more This paper was prepared for presentation at the SPE Asia Pacific Oil & Gas Conference and Exhibition held in Adelaide, Australia, 14 –16 October 2014. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract The primary objective of particle gel treatment is to significantly reduce water ...

SPE Journal, 2023

SPE/IATMI Asia Pacific Oil & Gas Conference and Exhibition, 2015

SPE Russian Petroleum Technology Conference, 2015

SPE Annual Technical Conference and Exhibition, 2015