Search

Wax precipitation has become a serious problem for the petroleum industry. The problem occurs when there is equilibrium disturbance on the pressure and temperature as well as crude oil composition. Wax deposits will eventually result in restriction of the fluid flow inside the pipeline, and severe deposition will cause blockage. The chemical additives currently being implemented in the industry have various limitations including the high cost and the irreversible impact it has on the environment. Therefore, the use of cheaper organic wax inhibitor obtained from crude palm oil (CPO) and crude palm kernel oil (CPKO) on the rheology and deposition of wax was investigated by using Chenor waxy crude oil from the Penyu basin, Pahang, Malaysia. To compare the efficiency of palm oil additives in inhibiting wax deposition, currently utilized chemical additives such as triethanolamine (TEA) and ethylene vinyl acetate (EVA) were also examined. The pour point of the crude oil was determined using SETA cloud & cryostat, while the rheological behavior of the crude was determined using a rotational Fann viscometer. The results obtained from this study reveal that CPO and CPKO could be used to improve the flow of crude oil, especially when 1 wt.% CPO or when 0.5 wt. % CPKO is used. It was also noted that the palm-based additives were much more effective at reducing the viscosity of the Chenor crude oil than the commercial wax inhibitor tested (TEA and EVA).

Excessive water production is a significant challenge during hydrocarbon production from oil and gas reservoirs, and it is typically controlled by polymer gel placement. However, the fundamental pr...

Conformance control in fractured tight formations remains a challenge because of large permeability contrasts between fractures and the matrix. Therefore, there is an emerging interest in particle ...

Multiphase fluid flow characteristics of a reservoir rock, such as capillary pressure, displacement efficiency, relative permeability, and saturation distribution are substantially influenced by th...

SummaryRecent reports have demonstrated that carbon dioxide (CO2) injection can further raise the oil recovery of fractured tight reservoirs after natural depletion, with major projects in progress worldwide. There is, however, a lack of understanding of the mass-exchange process between the matrix and fracture at pore scale. In this study, a matrix (0.8 md)/fracture model was designed to experimentally simulate a CO2-cyclic-injection process at 80°C and 35 MPa (Lucaogou tight formation). The oil (dead-oil) concentration in the matrix and fracture was continuously monitored online using a low-field nuclear-magnetic-resonance (NMR) technique aiming to quantify the oil recovery in situ and clarify the mass-exchange behaviors. The results showed that CO2 cyclic injection was promising in improving the oil recovery of fractured tight reservoirs. Nevertheless, the oil-recovery rates rapidly declined with the cycle of CO2 injection and the incremental oil was primarily produced by large pores with 100 ms > T2 > 3.0 ms. The NMR T2 profiles of the model evidenced the drainage of the matrix oil by CO2 toward the fracture. Because of the light-hydrocarbon extraction, the produced oils became lighter than the original oil. We noted that the main driving forces of the incremental oil recovery were CO2 displacement, CO2/oil interactions (mainly extraction and solubility), and pressure gradient (depressurization). In the first cycle, the CO2/oil interactions driven by CO2 diffusion during soaking enhanced the mass exchange between the matrix and the fracture. However, from the second cycle, CO2/oil interactions and CO2 displacement became insignificant. The results of this study supplement earlier findings and can provide insights into the CO2-enhanced-oil- recovery (EOR) mechanisms in fractured tight reservoirs.NOTE: Supporting information available.

Escalating global temperatures have spurred the development of various CO2 sorbents. Liquid amines are the most widely employed sorbent but they exhibit multiples drawbacks including low absorption capacity, high regeneration energy and degradation of the amine. This work presents the performance of an entirely new CO2 absorbent that is prepared by simply adding commercial or synthesized hydrogels into a solution of a standard liquid amine, diethanolamine (DEA) solution with a low concentration (5.0 wt. %, 10.0 wt. % and 20.0 wt. %) to generate DEA-infused hydrogels. This new material can rapidly capture CO2 even with relatively low amounts of DEA Higher overall uptake has been achieved compared to the commonly used DEA solutions. Moreover, hydrogels with various crosslinking degrees were prepared and employed for preparing the DEA infused hydrogels. It was found that the overall CO2 absorption was largely independent of the crosslinking degree, but the absorption kinetics generally improved with a higher crosslinking degree. In addition, breakthrough experiments demonstrate the outstanding performance of this proposed material for CO2 removal from flue gas. The absorption capacity of the DEA-infused hydrogels is well maintained after multiple regeneration cycles especially with the addition of polyethylenimine (PEI) so the hydrogels can easily be recovered and reused. This new material shows promise as a new CO2 absorbent in the CO2 capture industry.

Recent reports have demonstrated that gas injection can improve oil recovery of tight reservoirs after natural depletion, with major projects in progress worldwide. There is however a lack of understanding of the gas displacement behaviors at pore-scale especially under reservoir conditions. Herein we conducted an experimental investigation of CO2 and N2 flooding in the Lucaogou tight formation at 35.0 MPa and 80 °C. The flooding dynamics were continuously monitored by use of low-field nuclear magnetic resonance (NMR) to map the displacement processes at pore-scale and quantify the reduction of oil saturation in-situ. We observed that the overall oil recoveries of CO2 and N2 flooding were 38.4% and 35.1%, respectively. Due to the interactions between the oil phase and CO2, a uniform displacement along the core plug was yielded by CO2 flushing, indicated by the 1D spatial distribution of local oil saturation and 2D transverse images. Interestingly, during CO2 flooding, the major reduction of NMR T2 signals occurred in the large pores (4.2 ms

Water production is one of the common problems that is faced in mature gas reservoirs. A number of methods exist to tackle this problem, including injecting polymer that can selectively reduce wate...

Among the various flow assurance problems that the petroleum industry faces, the deposition of paraffin waxes on to the wall of the pipeline is the most challenging. The challenge arises when the crude oil temperature decreases below the wax appearance temperature (WAT) which leads to the wax crystal in the crude oil to crystallize. An efficient method in remedying paraffin wax deposition is the utilization of chemical inhibitors. However, currently used chemical inhibitors are costly and environmentally harmful if a spillage occurs. Therefore, the use of biodegradable or environmently friendly inhibitors as potential chemical inhibitors are being studied by various researchers. This study investigated oleic acid, poly (ethylene-co-vinyl acetate) (EVA) and triethanolamine (TEA) as inhibitors that perform based on the van der Waals intermolecular interaction between the main wax component molecule eicosane C20H42 using the molecular dynamics simulation (MD) procedure via Material Studio 8.0 software package. In order to analyse the desired structural property which is the Radial Distribution Function (RDF), COMPASS force field was used. The RDF and g(r) function portrayed the functional atoms which aid in inhibiting the agglomeration and crystallization of the wax crystal formation. The presence of a carbonyl oxygen in oleic acid plays a vital role to inhibit the wax formation through the van der Waals interaction between active hydrogen atoms in eicosane molecule. Therefore, the chances of wax inhibition in eicosane is higher by introducing oleic acid as an inhibitor as compared to EVA and TEA. The results were then validated experimentally utilizing a cold finger technique under static condition.

As the oil and gas industry produces hydrocarbons from deeper waters and colder regions the issue of hydrate formation becomes more serious. As a result, hydrate inhibition has focused on kinetic hydrate inhibitors (KHI) and anti-agglomerants (AA) as an alternative to the existing approaches which involves injecting vast quantities of thermodynamic inhibitors. In this research, we evaluated the effect of different architectures (linear and branched) of poly(N-isopropylacrylamide) (PNIPAM) polymers synthesized using reversible addition−fragmentation chain-transfer (RAFT) polymerization. Unlike non-reversible deactivation radical polymerisation (RDRP) synthetic routes this generates accurately controlled KHI candidates with target molecular weight, narrow molecular weight distributions and controlled architecture, so that the effect on hydrate inhibition can be more accurately assessed. The RAFT-based polymers (linear and branched) were compared to a commercially available linear PNIPAM synthesized via non-RDRP radical polymerization and control groups (pure water, PVP, and Luvicap). The hydrate experiments were performed in a high pressure autoclave with continuous cooling under different cooling rates (0.25 K/min, 0.033 K/min, and 0.017 K/min). In addition, a cold restart was simulated using constant subcooling. The results regarding subcooling temperature, onset time, and hydrate fraction with resistance-to-flow were compared to known KHIs. These revealed that a linear PNIPAM-MacroRAFT polymer delayed the hydrate nucleation with similar performance to known KHIs (eg., PVP and Luvicap). However, a branched polymer showed the best performance in terms of hydrate fraction and resistance-to-flow among all of the systems tested in this study. These data provide valuable information regarding linear and branched PNIPAM-MacroRAFT polymers by demonstrating their ability to delay hydrate formation but also in preventing hydrate agglomeration. These findings confirm that polymer architecture can effect hydrate inhibition.

Nanocellulose was surface-functionalized toward the applications in enhanced oil recovery (EOR) as a green alternative. The focus of this paper is on the effect of this material based nanofluid (NF) on foam lamella stabilization through studying its bubble breakup dynamics and flow behaviors in constricted mircofluidic devices. The NF stabilized foam produced an improved flow resistance across the capillary largely due to the capillary trapped bubbles at the contraction. The “snap-off” caused the NF stabilized foam to produce finer textured bubbles, which can migrate readily forward to the deep porous media, as revealed by the pressure profiles.

The geochemistry of a reservoir is of great significance for CO2 Enhanced Oil Recovery (CO2-EOR) and CO2 geosequestration operations. However, due to the massive diversity in mineralogy and physicochemistry of different reservoirs, the current data base is not yet sufficient to conclusively determine the alterations of geochemical prosperities when CO2 is injected especially for tight reservoirs. The attention of this work was given to a tight sandstone reservoir in Lucaogou formation of Jimsar sag (China). The interactions of reservoir rocks, formation brine and supercritical CO2 were extensively investigated under reservoir conditions (75 °C and 32 MPa) aiming to reveal possible mechanisms behind. The results showed that the dissolution of supercritical CO2 in the brine created an acidic environment (solubility = 0.94 mol/Kg), which induced the dissolution of minerals into the brine and their subsequent precipitation. The primary precipitants in this work were found to be iron minerals and kaolinite, as evidenced by Scanning Electron Microscopy and Energy Dispersion Spectrum (SEM-EDS) analyses. Moreover, the SEM-EDS observations have shown clear signs of mineralogical changes of the rocks with the preferred dissolution of K-feldspar, albite and ankerite. Kaolinitation due to the corrosion of K-feldspar and albite occurred during the CO2-exposure experiments. The mineral surface after exposure to CO2 was altered to be more water-wet as a result of mineral dissolution, kaolinite formation and surface corrosion.

Direct gas thickening is a conventional mobility control method to improve volumetric sweep efficiency for miscible gas injection (MGI) projects. However, the viability of this approach with technically feasible thickeners has not been verified at the field-scale due to a combination of high costs and/or environmental issues. One approach to make this technique economically more attractive is the implementation of an alternating injection scheme (similar to water-alternating-gas (WAG)) that would require less of the thickened gas compared with a continuous injection scheme. In this study, the effectiveness of this approach where a miscible alternating injection of thickened associated gas (TAG) or thickened CO2 (TCO2) with unthickened AG is explored in both nonfractured and fractured composite carbonate cores. Twelve core-flooding experiments were conducted using different injection schemes (i.e., continuous unthickened, continuous thickened, and alternating thickened–unthickened). These tests demonstrate...

A High Pressure Differential Scanning Calorimeter (HP-µDSC) was used to characterize the kinetic inhibition performance of several kinetic hydrate inhibitors (KHIs) up to 390 bar (39 MPa) of model natural gas. A novel protocol was devised to increase the spread between effective KHIs to obtain their performance ranking. The natural gas used in the study was a mixture of 90 mol% methane and 10 mol% propane. Linear cooling ramps at a constant cooling rate of 0.5 K/min were used under isobaric conditions. Both the formation temperature of natural gas hydrate during a linear cooling ramp and the amount of hydrate formed were used for comprehensive analysis. The second method was based on the growth inhibition of natural gas hydrates and opened a new possibility that only several repeat measurements may be sufficient for fast screening of good KHIs. The results showed that HP-µDSC is a promising tool for the evaluation of kinetic inhibition performance of KHIs that can only be obtained in minute quantities.

Carbon dioxide (CO2) hydrate-based cold thermal energy storage (CTES) is a promising method for load shifting and demand management of cooling systems and for CO2 utilisation. A challenge of CO2 hydrate-based CTES is to find a compatible CO2 gas storage, the CO2 regeneration and absorption conditions of which can be coupled with the charging and discharging conditions of the CTES, respectively. Amine diethanolamine infused hydrogels (DEAIHs) can be an effective CO2 absorber as the gas–DEA surface contact area is greatly enlarged by infusing the solution into a hydrogel. However, the influencing factors of the CO2 absorption and regeneration performance of DEAIHs are unknown. This paper investigates the performance of DEAIHs and explores the possibility of applying them in cyclic CO2 gas storage for CTES. The effects of pressure, temperature, DEAIH sample mass and amine diethanolamine (DEA) mass fraction on CO2 absorption and absorption rate are investigated. It was found that a higher pressure prompted CO2 absorption while a temperature of 12℃ resulted in the highest CO2 absorption rate. The average CO2 absorption rates in the first 100 min were 0.250, 0.228, 0.155 and 0.033 mmol min–1 for 20-g DEAIH sample with 30-wt% DEA and 60-g DEAIH sample with 30, 47 and 89-wt% DEA, respectively. CO2 regeneration from DEAIH under zero and non-zero gauge pressures are studied. Under non-zero gauge pressures, a pressure rise followed by a pressure drop caused by CO2 re-absorption appeared in the CO2 regeneration from DEAIH. It was found for the first time that the system passed through a meta-equilibrium state before it reached an equilibrium pressure. Cyclic absorption and regeneration at 110℃ under zero gauge pressure showed that the CO2 absorption decreased dramatically after the third cycle due to the volatility of amine. Operating a coupled CO2 hydrate-based CTES and CO2 gas storage system demonstrated the possibility of DEAIH material for CO2 gas storage in CTES systems.

In situ combustion (ISC) is advantageous for (ultra)heavy reserves due to its high heating efficiency and small surface footprint compared to steam injection. Herein, the focus of this work was given to the key factor in sustaining the continuity of the combustion front, the asphaltene fraction. Structure–property alterations of Tahe asphaltenes caused by low temperature oxidation (LTO) were thoroughly examined. Particular attention was placed on its combustion and pyrolysis kinetics. The results showed that after LTO 10.35 wt % coke was formed. Scanning electron microscopic observations indicated that the surfaces of the oxidative products were fairly rough as a result of air attack and the caused reactions on site, and these alterations promoted the subsequent combustion. The textures of the products were observed to be further compacted and condensed after LTO. As anticipated, distinguished reaction regions were clearly identified on the thermogravimetric (TG)/differential scanning calorimetric curves ...

The low salinity effect (LSE) in enhanced oil recovery (EOR) is widely accepted. However, its underlying mechanisms remain unclear due in part to the complex interactions at the oil/brine/rock interface. The chemistry of brine largely depends on the ionic composition. Thus, in this work, attention was placed on the roles of individual ions and salinity in LSE through direct measurements of oil/brine/rock interfacial behaviors, oil displacement efficiencies, and oil–water relative permeability in sandstone porous media. The results showed that the oil/water interfacial tensions (IFTs) were weakly dependent on ion and the lowest IFTs were generated at the salinities of 0.2–0.5 wt %. In contrast, the interfacial dilational modulus varied significantly with ion types and salinities due to the adsorption of polar components at the oil/water interface. Moreover, wettability alteration of the sandstone surface was found to be associated with the divalent ions in our work. As a result of the viscoelastic interfac...

Multi-functional polymers were designed and synthesized that contain both kinetic hydrate inhibitor and corrosion inhibitor groups. This was achieved by modifying a co-polymer of vinyl caprolactam and acrylic acid (PVCap-co-AA) where the acid groups were converted to known corrosion inhibitor groups including imidazole (APIM) and quaternary ammonium (ATCH) moieties. Therefore, all of the resulting polymers had the same molecular weight, end groups and overall composition which allowed for accurate determination of the performance of these inhibitors. Their performance as kinetic hydrate inhibitors were evaluated by determining the hydrate onset time, growth rate, and resistance to flow using a high pressure autoclave. The experimental results show that both PVCap-co-APIM and PVCap-co-ATCH were able to delay hydrate nucleation, however PVCap-co-APIM was better than PVCap-co-ATCH. The performance of new KHICIs were evaluated and compared with a commercial KHI, Luvicap, with three different cooling rates: fo...

Hydrate shell growth on hydrogel particles incorporating monoethylene glycol (MEG) was investigated using Raman spectroscopy and a high pressure autoclave apparatus. Surface images of hydrogel particles covered by a hydrate shell are presented and the obtained Raman spectra indicate MEG molecules were excluded from the formation of the hydrate shell. The Raman spectra and surface imaging of the particles demonstrate that the particles remain intact after the dissociation of the shell. In subsequent hydrate formation cycles, the hydrate fraction in the liquid phase was determined from gas consumption measurements in a high pressure autoclave. The hydrate fraction reached only 0.11 for hydrogels containing MEG while a high hydrate fraction of 0.41 was observed for a control system consisting of bulk water and decane mixture. The growth rate in the presence of hydrogel particles was suppressed in the early stages of hydrate formation, suggesting that the increasing MEG concentration inside the hydrogel core may limit the further inward hydrate growth. After hydrate formation the hydrogel particles were analyzed by thermogravimetric analysis (TGA), suggesting the possibility of recovering hydrogel polymer through conventional heating methodologies. These results demonstrate that injecting hydrogel particles containing high concentration of MEG may be feasible to manage the risk of hydrate plug formation as they will absorb the free water resulting in the dispersed hydrogel particles among the hydrocarbon liquid phase.

Hydrocarbon-miscible gas flooding typically involves injection of an associated gas (AG) mixture containing mainly methane (CH4) enriched with light hydrocarbon fractions and possibly acid gases. The AG mixture has been recognized as an excellent candidate for miscible gas injection (MGI). However, in general, the viscosity of the AG at reservoir conditions is significantly lower than that of crude oil leading to an unfavorable mobility ratio and low volumetric sweep efficiency during flooding. This study assesses the suitability of a library of commercially available polymers to thicken AG as a means of mobility control. The focus of the study is on the Field A located in the Harweel cluster in southern Oman. First, soluble polymeric thickeners for an AG mixture (CH4 60%, C2H6 9%, C3H8 6%, and CO2 25%) were identified using a parallel gravimetric extraction technique combined with cloud point measurements. Then, the viscosity of the identified soluble polymeric candidates in AG mixture was measured in a ...

When crude oil is extracted out of a subterranean reservoir at high temperature and pressure, it is usually transported via a pipeline, where the crude oil experiences radical changes in its physical and chemical properties, instigating numerous complications. Among the various flow assurance problems, wax deposition and build up are among the most commonly found. However, the accurate mechanism of wax deposition is still unclear and is widely debated among researchers. The mechanism under multiphase conditions is also an ambiguity. This review covers the six wax deposition mechanisms, the challenges in multiphase flow conditions, the latest types of chemical inhibitor, and a summary of factors governing chemical inhibitor performance.

Excessive water production is becoming common in many gas reservoirs. Polymers have been used as relative permeability modifiers (RPM) to selectively reduce water production with minimum effect on the hydrocarbon phase. This manuscript reports the results of an experimental study where we examined the effect of initial rock permeability on the outcome of an RPM treatment for a gas/water system. The results show that in high-permeability rocks, the treatment may have no significant effect on either the water and gas relative permeabilities. In a moderate-permeability case, the treatment was found to reduce water relative permeability significantly but improve gas relative permeability, while in low-permeability rocks, it resulted in greater reduction in gas relative permeability than that of water. This research reveals that, in an RPM treatment, more important than thickness of the adsorbed polymer layer ( e ) is the ratio of this thickness on rock pore radius ( e r ).

As a low carbon fuel, natural gas is leading the transition to a cleaner energy system. However, water blockage is seen to reduce gas deliverability significantly in many gas producing wells. We have developed an environmentally friendly and cost-effective non-fluorinated chemical treatment using a new benzoxazine monomer as a wettability modifier to combat water blockage. This chemical would adhere to silicate surfaces through a silane moiety followed by the application of a thermally accelerated ring-opening polymerization of the benzoxazine moiety. The performance of the treatment has been evaluated using contact angle measurements, spontaneous imbibition tests, and core-flooding experiments at 60 °C and 10.35 MPa. After chemical treatment, the contact angle shifts from almost 0° to 90°, implying that the treatment alters the wettability from strongly water-wet to an intermediate gas-wetting state. Spontaneous imbibition measurements show about 65% reduction in the volume of water imbibed into the rock sample after chemical treatment, suggesting a substantial increase in hydrophobicity of rock pore surfaces. Core-flooding experiments indicate that the chemical treatment increases gas relative permeability (by up to 22%) whilst decreasing residual water saturation (by up to 10%). Taken together, we demonstrate that this novel non-fluorinated benzoxazine monomer can successfully shift wettability of sandstone rocks from a strongly water-wet to an intermediate-wet state and thus aid to mitigate water blockage at relatively low cost and in an environmentally friendly manner. Furthermore, this chemical can withstand extra high temperatures encountered in many deep low permeability gas reservoirs where water blockage may be highly pronounced.

Libraries of kinetic hydrate inhibitors (KHIs) based on poly(N-isopropylacrylamide) (PNIPAM) were synthesized by post-synthetic modification of an existing PNIPAM copolymer. Unlike other synthetic routes this generates accurately controlled libraries of KHIs with similar molecular weight (M‾w), molecular weight distribution, end groups and composition. This allows for accurate interpretation of the effect of each of these components and highlights key functional groups that can improve performance. This was assessed using a high throughput KHI ranking method based on its inhibition performance of Structure II (sII) forming cyclopentane (c-C5) hydrate under atmospheric pressure. Hydrate inhibition tests showed that performance of PNIPAM-based KHIs can be improved by careful inclusion of select groups. In addition, cloud point data demonstrates that polymers with higher deposition points could be generated using this method. The presence of side products has a pronounced effect on cloud point but minimal effect on hydrate inhibition performance. These data provide valuable insights into polymers that can improve the performance of KHIs. The method can also be applied to a number of structural motifs to develop chemicals to overcome issues associated with natural gas transport.

The formation of clathrate hydrates is considered to be a major flow assurance problem in offshore oil and gas lines. Kinetic hydrate inhibitors (KHIs) are used for hydrate prevention, with their efficiency assessed by techniques that are a bottleneck for new materials development in this area. Efficient design of high-performance advanced materials requires a thorough understanding of the structure–property relationships that is currently hindered by conventional evaluation protocols. A cost-effective method for the rapid, parallel screening of potential KHIs is desirable, which preferably does not involve handling of highly pressurized and potentially flammable/explosive fuel gases. We have developed a novel high-throughput KHI ranking method based on its inhibition performance of Structure II (sII)-forming cyclopentane (c-C5) hydrate under atmospheric pressure. Ice seeding was used to induce the nucleation of c-C5 hydrate to save time, so the method focuses on the growth inhibition performance (as oppo...

Miscible gas injection is an important enhanced oil recovery technique due to favourable displacement efficiency by eliminating interfacial tension (IFT) between the injected gas and oil phases. Miscible displacement often results in far higher recovery compared to immiscible displacement. However, miscibility can be difficult to achieve in high temperature reservoirs due to high minimum miscibility pressure (MMP) with increasing reservoir temperature and in shallow reservoirs where MMP would be higher than fracture pressure. Limited studies have been performed to explore the potential of reducing MMP in CO2-oil system using chemical additives. These additives work by collecting at the boundary between the two phases thereby reducing the interfacial tension. Specifically, none have investigated potential chemical additives to reduce the MMP in methane-oil systems, which limits the potential of methane injection. We thus investigated the effect of promising chemicals (surfactant based & alcohol based) for reducing the MMP in the methane-oil system at different temperatures (333 & 373 K) for an oil with a high acidity (4.0 mg KOH/g). Results using the vanishing interfacial tension (VIT) technique show that the tested surfactant-based chemicals reduce the MMP (methane-crude oil) by up to 9% at 373 K, whereas the tested alcohol-based chemicals have little effect on the MMP. Moreover, the results show that increasing temperature improves chemical performance and yields a higher MMP reduction, suggesting that these additives are more effective in high temperature reservoirs. The outlined research likely expands the application envelop of miscible natural gas injection in shallow and high-temperature reservoirs, in addition to the environmental benefits of reducing the associated gas flaring.

This proof-of-concept study demonstrates a promising approach to enhance the CO2 capture capacity of liquid amines, in which the amines were infused into microgel particles. A diverse range of amine infused microgels (AIMGs) were readily prepared within 5 min by adding microgel particles into different amine solutions. The AIMGs absorb CO2 based on the infused amines. Due to the solid particle structure, the space among the AIMG particles provided diffusion channels for the CO2 molecule and enhanced the contact efficiency of the amines and CO2. As a result, the absorption efficiency of the amines was significantly increased resulting in higher CO2 uptake and faster absorption kinetics for the AIMGs compared to the conventional bulk amine solutions. Furthermore, by ‘locking’ the amine solutions in the microgel particles, the corrosion and foaming issues of amine solutions could be substantially mitigated. Therefore, the amine solutions which have higher concentrations than the commercial counterparts could be used in the preparation of AIMGs. Due to the thermally stable network structure, the AIMGs which were prepared by the amines with low volatility exhibited favorable cyclic capacity during the temperature-swing regeneration process.

Field A, located within the Harweel cluster in southern Oman, has been recognised as a viable miscible gas injection candidate. However, the mobility ratio of such a flood is unfavourable due to the low viscosity of the injected gas (0.01 to 0.04 cP) as compared to that of the in-situ oil (0.24 cP). One approach to overcome this issue is to thicken the injected gas to effectively control the gas mobility and increase the sweep efficiency. This study will present the details of a numerical reservoir simulation study, which assesses the potential benefits of adding polymers to the injected gas to increase the viscosity. Considering the composition of the AG in Field A, we have examined a number of different AG compositions to include different levels of hydrocarbon gas and CO2. We have also evaluated the direct effect of the different gas compositions on the oil properties during the flood. The simulation was carried out using CMG-GEM and the associated PVT module CMG-WinProp. A full-field 3D geological model has been built based on the typical geological characteristics and the light oil fluid properties in Field A. The simulation model takes into account the reservoir heterogeneities and future design considerations of the enhanced oil recovery (EOR) project to be implemented in the field. The results confirm that increasing the injected gas viscosity close to that of the oil has a significant effect on the gas mobility, time of breakthrough and the ultimate recovery in Field A. It has also been observed that the oil viscosity reduction with natural gas dissolution is much more pronounced than that achieved with the pure CO2. Such an effect resulted in 4% higher oil recovery by the injection of thickened natural gas (76%) than the thickened pure CO2 (72%). Furthermore, bacause gas breakthrough is delayed, a low gas-oil ratio can be maintained during the injection. These results demonstrate the real advantages of thickening the natural gas over CO2 for improving the gas flood efficiency in a light oil reservoir such as Field A. The contribution of this study is significant considering the fact that to date there have been limited studies evaluating the effect of thickened natural gas for EOR. Most of the previously completed research work in this area have mainly focused on the identification of thickener polymers for CO2 injection processes.

A solidified natural gas (SNG) technology was investigated to transport natural gas in a hydrate slurry. A Vitamin E derivative (D-alpha tocopherol succinate, Vitamin E-TS), which is naturally derived and readily available, was used to disperse water in the decane phase under the turbulent mixing condition. Compared to other non-ionic or cationic surfactants, Vitamin E-TS induced fast hydrate formation and a high conversion rate with an advantage of maintaining flowability during hydrate formation. For example, when using sorbitan monostearate (Span-60), hydrates grew to form a thick layer at the decane/water interface. Due to the strong cohesion of hydrate in the layer, a high relative torque was observed on mixing and the impeller was stopped. Moreover, dodecyltrimethylammonium bromide (DTAB) showed increased relative torque in the early stage of hydrate formation. From the experimental results under both steady and dynamic operating conditions, Vitamin E-TS showed the optimal performance in quickly producing hydrate slurries and high conversion while maintaining fluid flowability. Accordingly, a continuous process was proposed to use water and decane as feed to produce the hydrate slurry in the presence of Vitamin E-TS.

The solubility of an oligomer in a supercritical gas solvent (e.g. CO2 or associated gas (AG) mixture) and the subsequent effects on the phase behaviour, interfacial tension (IFT) and miscibility pressure of the in-situ oil/oligomer-thickened gas system at a molecular level are crucial to understanding and designing a thickened miscible gas injection (MGI) process. We have conducted cloud point pressure measurements, which revealed that the phase behaviour of P-1-D-thickened CO2 would follow a UCST (upper critical solution temperature) trend while P-1-D-thickened AG mixture would lie close to a LCST (lower critical solution temperature) behaviour. Moreover, our measured equilibrium IFTs of crude oil/P-1-D-thickened CO2 system and crude oil/PVEE-thickened CO2 system were found to be slightly lower than those of the crude oil/CO2 system. This results in a slight reduction in the MMP (minimum miscibility pressure) and considerable reduction in the first contact miscibility pressure (Pmax). We found the dissolution of P-1-D in the AG mixture to cause an increase in the equilibrium IFT for the crude oil/P-1-D-thickened AG mixture system, resulting in an increase in both of the MMP and Pmax. This indicates that the dissolution of an oligomer may have a considerable effect on the crude oil/thickened gas IFT behaviour at a pressure close to the cloud point pressure.