Oklahoma is known for having ample sources of CO 2 , pipelines and sinks where for many decades, oil and gas operators were injecting CO 2 into geological formations for EOR purposes. We utilized SimCCS, an economic-engineering software tool (DOE-NETL), to integrate infrastructure related to CO 2 sources, pipeline, and geological formations. The approved tax incentive program by IRS (45Q) has motivated many oil and gas operators to participate in reducing CO 2 concentration and minimizing global warming effect by collecting CO 2 from various sources, select the best pipeline route and the safest location to inject into geological formation for EOR purpose or deep saline aquifer for sequestration. This paper presents an economic evaluation of CO 2 capture, utilization, storage (CCUS) into geological formation in the state of Oklahoma. Under this comprehensive approach, the process of capturing, transporting, and storing CO 2 into geological or saline formations has been economically evaluated for different sites and routes utilizing an ad hoc simulation software (SimCCS) for integrated modeling of CCUS. The outcome of this paper determines the most optimal scenario using optimization algorithms embedded in SimCCS. This case study will mitigate the CO 2 sequestration approval process when operator apply for tax credit under 45Q program. Our work will assist oil and gas operators by comparing different scenarios based on utilizing existing infrastructure, making decision in building new transportation system or new injection well to benefit the approved tax incentive program at its maximum capacity. Moreover, the outcome of this work will shed lights into future legislation demands (locally and nation-wide) to maintain CCUS momentum after its initial implementation phase is concluded.

The paper describes the in-situ polymer sampling in Mangala which helped explain the performance of a large polymer flood in Mangala field in India. The Mangala field contains medium-gravity viscous crude oil. Notably, it is the largest polymer flood in India and 34% of the STOIIP has been produced in 11 years of production. Mangala was put on full field polymer flood in 2015, six years after the start of field production on water flood in 2009. Polymer flood added 93 million barrels above the anticipated water flood recovery in 6 years. Reservoir simulation models could replicate the initial Mangala polymer flood performance. However, the performance of the lower layers of Mangala (FM-3 and FM-4) continued to progressively deviate from modeling estimates. Equally importantly, the prediction of polymer breakthrough deviated significantly from modeling estimates. After 6 years and 0.7 pore volumes of polymer injection, it is apparent that field performance is equivalent to only 50-60% of the viscosity of the polymer injected at the surface. To better understand and quantify the nature and extent of polymer degradation it is necessary to gather representative down hole samples of polymer which has stayed in the reservoir conditions for a considerable length of time. Accelerated ageing studies in the lab showed HPAM can lose viscosity and precipitate after prolonged exposure to Mangala reservoir conditions with an increase in the degree of hydrolysis as the primary reason for the degradation. The concept of transfer function based on first order kinetics was used to extrapolate the laboratory results to Mangala reservoir temperatures. To test the hypothesis, a multi-disciplinary team implemented a plan to gather a representative polymer sample from the reservoir. The polymer sample had been in the reservoir for nearly 120 days and was captured in low shear and anaerobic conditions to minimize shear and oxidative degradation. The sample was tested for degree of hydrolysis by NMR method. The results confirmed that the level of hydrolysis of the injected HPAM did increase in the reservoir leading to lower viscosity and reduced lower amide concentration. Preliminary simulation studies using the concept of viscosity half-life were used to mimic the polymer degradation with time in the reservoir. The method is quite a simplistic representation of the thermal degradation, but it significantly improved the model's water cut predictions for lower layers and the full field polymer breakthrough predictions. The impact of polymer precipitation in the reservoir on the permeability is under study and it will drive the next phase of more detailed modeling.

Improved oil recovery in carbonate rocks through modified injection brine has been investigated extensively in recent years. Examples include low salinity waterflooding and surfactant injection for the purpose of residual oil reduction. Polymer addition to injection water for improvement of sweep efficiency enjoys field success. The effect of low salinity waterflooding is often marginal and it may even decrease recovery compared to seawater flooding. Polymer and surfactant injection are often effective (except at very high salinities and temperatures) but concentrations in the range of 5000 to 10000 ppm may make the processes expensive. We have recently suggested the idea of ultra-low concentration of surfactants at 100 ppm to decrease residual oil saturation from increased brine-oil interfacial elasticity. In this work, we investigate the synergistic effects of polymer injection for sweep efficiency and the surfactant for interfacial elasticity modification. The combined formulation achieves both sweep efficiency and residual oil reduction. A series of coreflood tests is performed on a carbonate rock using three crude oils and various injection brines: seawater and formation water with added surfactant and polymer. Both the surfactant and polymer are found to improve recovery at breakthrough via increase in oil-brine interfacial elasticity and injection brine viscosification, respectively. The synergy of surfactant and polymer mixed with seawater leads to higher viscosity and higher oil recovery. The overall oil recovery is found to be a strong function of oil-brine interfacial viscoelasticity with and without the surfactant and polymer in sea water and connate water injection.

Pressurized Mud Cap Drilling (PMCD) technique is typically applied for drilling formations with natural fractures and large vugs that result in severe or total losses. The density of the drilling fluid used in PMCD is slightly below reservoir pore pressure. In the case of very low reservoir pressures below base oil densities (~6.7 ppg), foam can be an option. This paper presents a methodology to develop an oil-based foam system for a PMCD application. The scope includes the descriptions of a foam PMCD application, functional requirements of foam, the development workflow, testing procedures, and modeling that are necessary to qualify a foam for PMCD application. The development methodology first involves identifying the constraints and well conditions of a given PMCD application; these include wellpath, hole and casing sections, reservoir pressure and temperature, surface pumping pressure limits (typically a rotating control device limit), foam stability requirements, etc. The above constraints drive the performance requirements for the foam. Next comes the design of the foam formulation and evaluating its performance against these requirements through various lab tests and modeling efforts, which can include ambient pressure half-life tests for initial screening, static and rotational stability tests at in-situ well conditions, rheology tests, solubility tests, pressure transmission estimates, gas migration estimates, and hydraulics modeling. Example results from the lab tests and modeling are shown to provide more insights into the development process. The proposed methodology may be used as a guide to design a foam drilling fluid for a PMCD application. The iterative nature of the development method is shown and is driven by the functional requirements that are coupled to each other. For example, a more viscous foam may be more stable but it may not be pumpable. Likewise, a less viscous foam may be pumpable but may not be sufficiently stable. Similarly, a highly compressible foam may not be good at pressure transmission to monitor downhole pressure variations as compared to a less compressible foam. In summary, the methodology described in this paper explains the development of an oil-based foam for a PMCD application that satisfies a set of operational constraints and functional requirements while highlighting the major factors that could impact foam performance. The application of foam to PMCD is a new concept and to our knowledge has not been applied in the field; in significantly depleted reservoirs this may become a viable option.

Unconvnetional reservoirs are predominantly consisted of nanoscale pores. The strong confinement effect within nanopores imposes significant deviations to the confined fluid phase behavior. Minimum miscibility pressure (MMP) in unconventional reservoirs, as a parameter highly related to the phase behavior of confined fluids, is inevitably affected by the nanoscale confinement. The objective of this work is to investigate the impact of nanoscale confinement on MMP of unconventional reservoir fluids and to recognize a reliable theoretical approach to determine the MMP values in unconventional reservoirs. A modified Peng-Robinson equation of state (PR EOS) applicable for confined fluid characterization is applied to perform the EOS simulation of the vanishing interfacial tension (VIT) experiments. The MMP of a binary mixture at bulk and 50 nm are obtained via the VIT simulation. Meanwhile, the multiple mixing cell (MMC) algorithm coupled with the modified PR EOS is applied to compute the MMP for the same binary system. Comparison of the calculated results to the experimental values recognize that the MMC approach has higher accuracy in determining the MMP of confined fluid systems. Moreover, this approach is then applied to predict the MMP values of both Bakken and Eagle Ford oil at different pore sizes with various injected gases. Results demonstrate that the nanoscale confinement causes drastic suppression to the MMP of unconventional reservoir fluids and the suppression rate increases with decreasing pore size. The drastic suppression of MMP is highly favorable for the miscible gas injection EOR in unconventional reservoirs.

Although polymer flooding technology has been widely applied and achieved remarkable effect of increasing oil. Yet the "entry profile inversion" phenomenon occurs inevitably in its later stage, which seriously affects the development effect. In recent years, the soft microgel particle dispersion is a novel developed flooding system. Due to its excellent performance and advanced mechanism, it can slow down the process of profile inversion, and achieve the goal of deep fluid diversion and expanding swept volume. The soft microgel particle dispersion consists of microgel particles and its carrier fluid. After coming into porous media, it shows the properties of "plugging large pore and leave the small one open" and the motion feature of "trapping, deformation, migration". In this paper, reservoir adaptability evaluation, plugging and deformation characteristics of soft microgel particle dispersion in pore throat is explored by using the microfluidic technology and 3D Printing technology. On this basis, by adopting the NMR and CT tomography technology, the research on its oil displacement mechanism is further carried out. Furthermore, the typical field application case is analyzed. Results show that, soft microgel particles have good performance and transport ability in porous media. According to the reservoir adaptability evaluation, the size relationships between particles and core pore throat is obtained, to provide basis for field application scheme design. Through microfluidic experiments, the temporary plugging and deformation characteristics of particles in the pore throat are explored. Also, when injecting soft microgel particle into the core, the particle phase separation happens, which makes the particles enter and plug the large pore in the high permeability layer. Therefore, their carrier fluid displace oil in the small pore, which works in cooperation and causes no damage to the low permeability layer. Furthermore, by using NMR and CT techniques, its micro percolation law in porous media and remaining oil distribution during displacement process is analyzed. During the experiment, microgels presents the motion feature of "migration, trapping, and deformation" in the core pore, which can realize deep fluid diversion and expand swept volume. From 3D macro experiment, microgels can realize the goal of enhance oil recovery. Finally, the soft microgel particle dispersion flooding technology has been applied in different oilfields, such as Oman, Bohai and other oilfields, which all obtained great success. Through interdisciplinary innovative research methods, the oil displacement mechanism and field application of soft microgel particle dispersion is researched, which proves its progressiveness and superiority. The research results provide theoretical basis and technical support for the enhancing oil recovery significantly.

Carbonate reservoirs are challenging for chemical EOR, particularly in selecting fine-tuned chemical formulations which combine high performance, stable behavior, and trouble-free operations. The design of suitable formulations requires substantial laboratory work and a solid methodology. In this paper, a systematic all-inclusive laboratory workflow to design a surfactant-polymer (SP) formulation for a carbonate reservoir is presented. In this work, a complete process for development and evaluation of an SP formulation for high-salinity high-temperature conditions is proposed and adopted. For which, a high throughput robotic platform is used for efficient and robust formulation design. The process is illustrated on an actual case with harsh reservoir conditions (i.e. a high temperature of 100℃ and high connate salinity of 213,000 mg/L). The SP design methodology consisted of five steps: surfactant design, polymer selection, surfactant/polymer verification, topside assessment, and oil-displacement evaluation. The surfactant formulation design consisted of four substeps: solubility scans, phase-behavior scans (salinity scans), IFT measurements, and static adsorption tests. The sourced polymers were screened based on three key performance indicators: viscosity, filter ratio, and thermal stability. The selected surfactant formulations and polymers were then assessed as sloppy slugs in terms of compatibility and injectivity. Then, the unique topside assessment was conducted where it consisted of two components focusing on: separation kinetics and separated water quality. Finally, an oil displacement study was performed using a preserved composite plug, in which the SP formulation developed through the outlined process was used. The results demonstrate the potential of a mixture of Olefin Sulfonate (OS) and Alkyl Glyceryl Ether Sulfonate (AGES). The results also illustrate couple of polymers with stabilities suitable for high temperature conditions: an associative polymer, and an AM/AMPS copolymer. In addition, injectivity corefloods supported the SP slug transportability across the porous media. Corefloods also demonstrated the SP slug capacity to recover around 62% ROIC (remaining oil in core). Finally, SP in produced brines improved the separation kinetics but lead to a slight deterioration in separated water quality. A key novelty of the adopted workflow is the integration of topside assessment. In addition, the experimental steps were clearly delineated including the preparation of representative oils. Beside a clear layout of the methodology, the work demonstrates that a surfactant-polymer formulation can successfully be designed for high temperature carbonate reservoirs and provide encouraging guidelines with respect to SP impact on topside facilities.

Complex surfactant formulations have been applied to generate an ultra-low interfacial tension (IFT) (e.g., 10 -3 dyne/cm) between the displacing water phase and the displaced oil phase in chemical enhanced oil recovery (CEOR), where the residual oil after waterflooding can be largely recovered as an oil bank. This paper is concerned with a simpler, lower-cost CEOR, in which a sole additive of surface active solvent (SAS) makes low-tension displacement fronts in polymer flooding (e.g., 10 -2 dyne/cm) without involving ultra-low IFT microemulsion phase behavior. The main objective of this research is to technically verify such low-tension polymer (LTP) flooding for a secondary-mode oil displacement through a sandpack of 9.5 Darcy. Previous research found that 2-ethylhexanol-7PO-15EO (2-EH-7PO-15EO, or "7-15") as SAS was able to reduce the IFT between polymer solution and the reservoir oil from 15.8 dyne/cm to 0.025 dyne/cm. In this research, the effect of SAS partition coefficient on LTP flooding was studied as an additional factor for SAS optimization. In particular, the comparison between two SAS species, 2-EH-4PO-15EO (4-15) and 2-EH-7PO-25EO (7-25), was important, because they had similar IFT values, but markedly different partition coefficients. The IFT was 0.18 dyne/cm with 4-15 and 0.20 dynes/cm with 7-25; and the partition coefficients were 1.61 with 4-15 and 0.68 with 7-25 at the experimental temperature, 61°C. These two SAS species were compared in secondary-mode LTP flooding with a slug of 0.5 wt% SAS for 0.5 pore-volumes injected (PVI). The oil recovery factor at 1.0 PVI was 65% with 4-15 and 67% with 7-25. At 5.0 PVI, it was 74% with 4-15 and 84% with 7-25. Although these two SAS species gave comparable IFT values, their oil-displacement efficiencies were quite different because 7-25 propagated more efficiently in the sandpack with the smaller partition coefficient. The smaller partition coefficient helped the SAS flow more efficiently in the aqueous phase with less retention in the remaining oil. Optimization of SAS likely requires taking a balance between lowering the partition coefficient and lowering the IFT. The SAS recovery at the effluent was 61% for the 4-15 SAS and 78% for the 7-25 SAS. The propagation of the 4-15 SAS was retarded approximately by 1.0 PVI in comparison to that of the 7-25 SAS. The adsorption of the 4-15 and 7-25 SAS were 0.019 mg/g sandpack and 0.020 mg/g sandpack. With a similar IFT reduction, the SAS with a smaller partition coefficient (i.e., 7-25) resulted in less retention, less retardation, and more oil production for a given amount of injection.

Recently, spherical nanoparticles have been studied to enhance oil recovery (EOR) worldwide due to their remarkable properties. However, there is a lack of studies of nanosheets on EOR. In this work, we synthesize the amphiphilic molybdenum disulfide nanosheets through a straightforward hydrothermal method. The octadecyl amine (ODA) molecules were grafted onto the surfaces of molybdenum disulfide nanosheets due to the presence of active sites over the surfaces of MoS 2 nanosheets. The synthesized amphiphilic molybdenum disulfide nanosheets (ODA-MoS 2 nanosheets) are approximate 67 nm in width and 1.4 nm in thickness. The effects of ultralow concentration ODA-MoS 2 nanosheets on the dynamic wettability change of solid surfaces and emulsion stability were also studied and discussed. Besides, the core flooding experiments were also conducted to reveal the adsorption rules and the oil displacement effects of ultralow concentration ODA-MoS 2 nanosheets. Experimental results indicate that the oil-wet solid surface (a contact angle of 130°) can transform into the neutral-wet solid surface (a contact angle of 90°) within 120 hrs after 50 mg/L ODA-MoS 2 nanosheets treatment. In addition, micro-scale emulsions in size of 2 µm can be formed after the addition of ODA-MoS 2 nanosheets by adsorbing onto the oil-water interfaces. The desorption energy of a single ODA-MoS 2 nanosheet from the oil-water interface to the bulk phase is proposed. When the concentration of ODA-MoS 2 nanosheets is 50 mg/L, the emulsions are the most stable. Core flooding results demonstrate that the ultimate residue of ODA-MoS 2 nanosheets in porous media is less than 11%, and the highest increased oil recovery of around 16.26% is achieved. Finally, the production performance of ultralow concentration of ODA-MoS 2 nanofluid (50 mg/L) in the application of Daqing Oilfield is summarized and discussed.

Even though the influence of wettability alteration on imbibition is well-documented, its synergy with Interfacial-Tension (IFT) for Alkali/Nanoparticles/Polymer flooding requires additional investigation. Particularly, when the oil Total Acid Number (TAN) may determine the wetting-state of the reservoir and influences IFT. Therefore, a laboratory evaluation workflow is presented that combines complementary assessments such as spontaneous imbibition tests, IFT and contact angles measurements. This workflow aims at evaluating wettability alteration and IFT changes when injecting Alkali, Nanoparticles and Polymers or a combination of them. Dynamics and mechanism of imbibition was tracked by analyzing the recovery change with the inverse Bond number. Three sandstone types (outcrops) were used that mainly differ in clay content and permeability. Oils with low and high-TAN were used, the latter from the potential field pilot 16TH reservoir in the Matzen field (Austria). We have identified the conditions leading to an increase of recovery rates as well as ultimate recovery by imbibition of Alkali/Nanoparticles/Polymer aqueous phases. Data obtained demonstrate how oil TAN number (low and high), chemical agent and reservoir mineralogy influence fluid-fluid and rock-fluid interactions. Application of alkali with high-TAN oil resulted in a low-equilibrium IFT. Alkali-alone fall short to mobilize trapped low-TAN oil. Alkali-polymer is efficient in wettability alteration of oil-wet core plugs towards water-wet state for high-TAN oil. The investigated nanofluids manage to restore a water-wet state in cores with high clay content along with improving gravity driven flow. IFT reduction between oil and surface-modified nanoparticles is unaffected by the acidity of the oil. Furthermore, contact angle in high-TAN oil remained similar even after 1000 min of observation for 2.5% clay cores in synthetic brine, but increases significantly when in contact with alkali/polymer. Comparing porosity and permeability before and after imbibition, a slight reduction was observed after imbibition with brine and nanofluids. We preliminary conclude that permeability reduction is not associated to the tested nanoparticles present in solution. We observed evidence of change in the imbibition mechanism from counter-current (capillary driven/high inverse Bond number) to co-current (gravity driven/low inverse Bond number) for nanoparticles/alkali. The calculated inverse Bond number correlates with the ultimate recovery, larger inverse Bond number leading to lower ultimate recovery. This work presents novel data on the synergy of IFT, contact angles and Amott imbibition for the chemical processes studied. We leverage from complementary laboratory techniques to define a comprehensive workflow that allows understanding wettability-alteration when injecting Alkali, Nanoparticles and Polymers or a combination of them. Obtained results show that the workflow can be used as an efficient screening tool to determine the effectiveness of various substances to increase oil recovery rate and ultimate recovery.

The first-ever polymer flood pilot to enhance heavy oil recovery on Alaska North Slope (ANS) is ongoing. After more than 2.5 years of polymer injection, significant benefit has been observed from the decrease in water cut from 65% to less than 15% in the project producers. The primary objective of this study is to develop a robust history-matched reservoir simulation model capable of predicting future polymer flood performance. In this work, the reservoir simulation model has been developed based on the geological model and available reservoir and fluid data. In particular, four high transmissibility strips were introduced to connect the injector-producer well pairs, simulating short-circuiting flow behavior that can be explained by viscous fingering and reproducing the water cut history. The strip transmissibilities were manually tuned to improve the history matching results during the waterflooding and polymer flooding periods, respectively. It has been found that higher strip transmissibilities match the sharp water cut increase very well in the waterflooding period. Then the strip transmissibilities need to be reduced with time to match the significant water cut reduction. The viscous fingering effect in the reservoir during waterflooding and the restoration of injection conformance during polymer flooding have been effectively represented. Based on the validated simulation model, numerical simulation tests have been conducted to investigate the oil recovery performance under different development strategies, with consideration for sensitivity to polymer parameter uncertainties. The oil recovery factor with polymer flooding can reach about 39% in 30 years, twice as much as forecasted with continued waterflooding. Besides, the updated reservoir model has been successfully employed to forecast polymer utilization, a valuable parameter to evaluate the pilot test’s economic efficiency. All the investigated development strategies indicate polymer utilization lower than 3.5 lbs/bbl in 30 years, which is economically attractive.

Geologic CO 2 sequestration and CO 2 enhanced oil recovery (EOR) have received significant attention from the scientific community as a response to climate change from greenhouse gases. Safe and efficient management of a CO 2 injection site requires spatio-temporal tracking of the CO 2 plume in the reservoir during geologic sequestration. The goal of this paper is to develop robust modeling and monitoring technologies for imaging and visualization of the CO 2 plume using routine pressure/temperature measurements. The streamline-based technology has proven to be effective and efficient for reconciling geologic models to various types of reservoir dynamic response. In this paper, we first extend the streamline-based data integration approach to incorporate distributed temperature sensor (DTS) data using the concept of thermal tracer travel time. Then, a hierarchical workflow composed of evolutionary and streamline methods is employed to jointly history match the DTS and pressure data. Finally, CO 2 saturation and streamline maps are used to visualize the CO 2 plume movement during the sequestration process. The power and utility of our approach are demonstrated using both synthetic and field applications. We first validate the streamline-based DTS data inversion using a synthetic example. Next, the hierarchical workflow is applied to a carbon sequestration project in a carbonate reef reservoir within the Northern Niagaran Pinnacle Reef Trend in Michigan, USA. The monitoring data set consists of distributed temperature sensing (DTS) data acquired at the injection well and a monitoring well, flowing bottom-hole pressure data at the injection well, and time-lapse pressure measurements at several locations along the monitoring well. The history matching results indicate that the CO 2 movement is mostly restricted to the intended zones of injection which is consistent with an independent warmback analysis of the temperature data. The novelty of this work is the streamline-based history matching method for the DTS data and its field application to the Department of Engergy regional carbon sequestration project in Michigan.

Solvent flooding is a well-established method of enhanced oil recovery (EOR), with carbon dioxide (CO 2 ) being the most-often used solvent. As CO 2 is both less viscous and less dense than the fluids it displaces, the displacement suffers from poor sweep efficiency caused by an unfavorable mobility ratio and unfavorable gravity number. Creating in-situ CO 2 foam improves the sweep efficiency of CO 2 floods. Another application is the injection of CO 2 foam into saline aquifers for carbon capture and storage (CCS). The goal of the core flood experiments in this paper was to study the effectiveness of surface coated silica nanoparticles as an in-situ CO 2 foaming agent. In each experiment, the pressure drop was measured across five separate sections in the core, as well as along the whole core. In addition, the saturation distribution in the core was calculated periodically using computed tomography (CT) scanning measurements. The experiments consisted of vertical core floods where liquid CO 2 displaced brine from the top to the bottom of the core. A flood with surface coated silica nanoparticles suspended in the brine is performed in the same core and at the same conditions to a flood with no nanoparticles, and results from these floods are compared. In these experiments, breakthrough occurred 45% later with foamed CO 2 , and the final CO 2 saturation was also 45% greater than with the unfoamed CO 2 . The study shows how nanoparticles stabilize the CO 2 front. The results provide quantitative information on, as well as a graphical representation of, the behavior of the CO 2 foam front as it advances through the core. This data can be used to upscale the behavior observed and properties calculated from the core-scale to the reservoir-scale to improve field applications of CO2 flooding.

Previous efforts to promote hydrogen as an energy carrier described a Utopian world in which renewable resources provided all energy for heating, electricity, transportation, and industrial needs. The elegance of this vision overlooked the cost and the footprint represented by the renewable energy resources required to generate so much electricity, and the additional cost required to employ electrolysis to generate hydrogen for energy storage not possible for electricity. Today an abundance of natural gas offers an option for hydrogen generation from methane that can include capturing and storing CO2 produced from the generation process. This results in blue hydrogen, effectively as ecologically attractive as the green hydrogen from electrolysis, and considerably less expensive. This paper evaluates a New Hydrogen Economy employing blue hydrogen as a bridge to net zero greenhouse gas emissions. Of particular interest is the observation that depleted natural gas reservoirs offer pore space sufficient to store about 1.5 times the CO2 coming from hydrogen generation from the produced natural gas. The implication of this observation is that blue hydrogen generation need not rely on saline aquifer storage or on CO2 Enhanced Oil Recovery. We find that blue hydrogen cost is comparable to the cost of current crude oil-based transportation fuels. Further, electricity generated using blue hydrogen is less expensive than decarbonized electricity generated from natural gas with post combustion CO2 capture and storage. The infrastructure required for this energy transition can leverage existing natural gas transport and storage and existing petroleum industry skills. Energy companies committed to net zero emissions need not rely only on renewable energy sources or nuclear power. Further, switching to blue hydrogen reduces or eliminates combustion related pollution including nitrogen and sulfur oxides. Finally, the Blue Hydrogen Economy makes efficient and cost effective use of petroleum engineering core skills, as well as the core skills championed by the petroleum industry.

The success of supercritical CO 2 Enhanced Oil Recovery (EOR) cannot be duplicated if the cost of CO 2 transposition and processing becomes prohibitive. Research results of the in-situ CO 2 EOR (ICE) approach offered a potential technology for many waterflooded stripper wells that lack access to affordable CO 2 sources. Previously the ICE synergetic mechanisms were only qualitatively attributed to oil swelling and viscosity reduction due to the preferential partition of CO 2 into the oleic phase. This study aims to quantify the contributions to recovery factors from several plausible mechanisms with numerical modeling and simulation. First, the urea reaction was modeled as the CO 2 generating chemical decomposing to CO2 and ammonia in the reservoir conditions. The CO 2 partitions into oil, which leads to the reaction continuation to generate more CO 2 . The resulting ammonia largely left in water may further react with certain crudes to generate surfactants, thus, decrease the oil/water interfacial tension (IFT). It is expected that the oil containing CO 2 also has a lower IFT with water. The reaction kinetics under different temperatures were incorporated into the numerical model. A numerical model featuring the synergetic mechanisms was built including stoichiometry and kinetics of urea reaction, oil swelling effect, oil viscosity reduction, and IFT reduction effect on the relative permeabilities. The laboratory experiments, pore volume injection versus oil saturation were history matched for three different oils including Dodecane, Earlsboro oil, and DeepStar oil. The phase behavior was modeled with the equation of state (EOS) under different mole fractions of CO 2 . The reaction kinetics were also modified to history match the laboratory experiment. The estimated reduction of oil viscosity was calculated, 76% for Earlsboro oil, 91% in DeepStar oil, and 75% in dodecane oil. The oil swelling factors ranged from 1.60% to 19% in the three lab models, which translates to the recovery factor of oil. The endpoints of relative permeability were modified to account for the recovery contribution to the IFT and viscosity reduction. The impact of reaction kinetics on oil swelling and recovery factor was also determined, and they are not numerically close to reaction kinetics used in the lab cases. The matched reaction kinetics, activation energy and reaction frequency factor for the dodecane laboratory experiment were 91.80 kJ/gmol and 6.5E+09 min −1 . The study concluded that the incremental recovery due to oil swelling ranges between 3.16% and 18.30%, and then from 12.91% to 41.59% is due to IFT reduction for all the cases. The relative permeability and urea reaction kinetics remained the most uncertain parameters during history matching and modeling the ICE synergetic mechanisms.

Viscoelastic surfactant (VES)-based fracturing fluids can reduce the risk of formation damage when compared with conventional polymer-based fracturing systems. However, many VES systems lose viscoelasticity rapidly under high-temperature conditions, leading to high fluid leakoff and problems in proppant placement. A gemini cationic VES-based system offering thermal stability above 250°F and its efficiency in friction reduction is presented in this paper. Rheology measurements were conducted on viscoelastic cationic gemini surfactant fluids as a function of temperature (70 – 300°F) and surfactant concentration. The length of surfactant alkyl chain was varied to investigate the impact of surfactant chain length on VES fluid viscosity at elevated temperatures. The effect of flow rate on friction reduction capability of the surfactant fluid was measured on a friction flow loop. Foam rheology measurements were conducted to evaluate the VES fluid's ability to maintain high temperature viscosity with reduced surfactant concentration. A gemini cationic surfactant was used to prepare a viscoelastic surfactant system that could maintain viscosity over 50 cP at a shear rate of 100 s −1 up to at least 250°F. With this system, viscoelastic gel viscosity was maintained without degradation for over 18 hours at 250°F, and the fluid showed rapid shear recovery throughout. Decreasing the average alkyl chain length on the surfactant reduced the maximum working temperature of the resulting viscoelastic gel and showed the critical influence of surfactant structure on the resulting fluid performance. The presence of elongated, worm-like micelles in the fluid provided polymer-like friction reduction even at low surfactant concentrations, with friction reduction of over 70% observed during pumping (relative to fresh water) up to a critical Reynolds number. Energized fluids could also be formulated with the gemini surfactant to give foam fluids suitable for hydraulic fracturing or wellbore cleanouts. The resulting viscoelastic surfactant foams had viscosities over 50 cP up to at least 300°F with both nitrogen and carbon dioxide as the gas phase. The information presented in this paper is important for various field applications where thermal stability of the treatment fluid is essential. This will hopefully expand the use of VES-based systems as an alternative to conventional polymer systems in oilfield applications where a less damaging viscosified fluid system is required.

CO 2 foam holds promising potential for conformance improvement and mobility reduction of CO 2 injection in fractured systems. However, there still exists two main issues hampering its wide application and development, 1. Instability of CO 2 foam lamellae under reservoir conditions, and 2. Uncertainties of foam flow in fracture systems. To address these two issues, we previously developed a series of functional nanocellulose materials to stabilize the CO 2 foam (referred to NCF-st-CO 2 foam), while the primary goal of this paper is to thoroughly elucidate foam generation, propagation and sweep of NCF-st-CO 2 foam in fractured systems by using a self-designed visual heterogeneous fracture network. We found that NCF-st-CO 2 foam produced noticeably greater pressure drop (Δ P ) than CO 2 foam during either co-injection (COI) or surfactant solution-alternating-gas (SAG) injection, and the threshold foam quality ( f g *) was approximately 0.67. Foam generation was increased with total flow rate for CO 2 foam and stayed constant for NCF-st-CO 2 foam in fracture during COI. CO 2 breakthrough occurred at high flow rates (>8 cm 3 /min). For SAG, large surfactant slug could prevent CO 2 from early breakthrough and facilitate foaming in-situ . The increase in sweep efficiency by NCF-st-CO 2 foam was observed near the producer for both COI and WAG, which was attributed to its better foaming capacity. Film division and behind mainly led to foam generation in the fracture model. Gravity segregation and override was insignificant during COI but became noticeable during SAG, which caused the sweep efficiency decreased by 3~9% at 1.0 fracture volume (FV) injected. Due to the enhanced foam film, the NCF-st-CO 2 foam was able to mitigate gravitational effect, especially in the vicinity of producer.

Polymer flooding is one of the most commonly used chemical EOR methods. Conventionally, this technique was believed to improve macroscopic sweep efficiency by sweeping only bypassed oil. Nevertheless, recently it has been found that polymers exhibiting viscoelastic behavior in the porous medium can also improve microscopic displacement efficiency resulting in higher additional oil recovery. Therefore, an accurate prediction of the complex rheological response of polymers is crucial to obtain a proper estimation of incremental oil to polymer flooding. In this paper, a novel viscoelastic model is proposed to comprehensively analyze the polymer rheological behavior in porous media. The proposed viscoelastic model is considered an extension of the unified apparent viscosity model provided in the literature and is termed as extended unified viscosity model (E-UVM). The main advantage of the proposed model is its ability to capture the polymer mechanical degradation at ultimate shear rates primarily observed near wellbores. Furthermore, the fitting parameters used in the model were correlated to rock and polymer properties, significantly reducing the need for time-consuming coreflooding tests for future polymer screening works. Moreover, the extended viscoelastic model was implemented in MATLAB Reservoir Simulation Toolbox (MRST) and verified against the original shear model existing in the simulator. It was found that implementing the viscosity model in MRST might be more accurate and practical than the original method. In addition, the comparison between various viscosity models proposed earlier and E-UVM in the reservoir simulator revealed that the latter model could yield more reliable oil recovery predictions since it accommodates the mechanical degradation of polymers. This study presents a novel viscoelastic model that is more comprehensive and representative as opposed to other models in the literature.

This paper studies the effect of trapped, emulsified oil on the requirement for the geometrical Roof snap-off for foam generation in a porous medium. We extend an existing hydrodynamic pore-level model to describe the liquid accumulation in an appropriately-sized pore in the presence of oil. The effect of oil is simulated by adjusting the pore shape to be asymmetrical as observed in microfluidic experiments with residual oil. We alter the boundary and initial conditions of the problem to test various scenarios. Specifically, four cases are presented. The liquid accumulation is presented when the amount of wetting liquid volume connected to the pore is altered through changing the boundary conditions (cases 1 and 2). Moreover, the effect of drier surrounding medium and/or drier pores is also tested by increasing either the capillary pressure surrounding the pore or the capillary pressure of the pore itself (cases 3 and 4). We find that the presence of residual oil affects the liquid accumulation times when there is no external liquid pressure gradient applied. Additionally, residual oil presence makes the Roof snap-off criterion for liquid accumulation stricter. To augment our pore-level study, we use a statistical pore network to observe the effect of the microscopic changes observed in our pore-level model macroscopically. Our results indicate that a stricter Roof snap-off criterion leads to fewer germination sites for lamellae generation. Our pore network analysis computes the generation rate constant to be as much as four times larger in the absence of oil than in its presence. Results suggest that changes to the shape of pore constrictions by emulsified oil reduce the effectiveness of foam generation.

Several gas Enhanced Oil Recovery (EOR) pilots enhanced with aqueous-foam based conformance solutions have been implemented in the last 30 years. While these pilots were technically successful, there were economic challenges limiting their commercial viability. Many of these pilots were implemented with water-soluble foaming surfactants that can get adversely affected by near wellbore gas-water gravity segregation and adsorption loss up to 90% of the injected surfactant. Novel, gas-soluble surfactants can be injected with the gas phase where these surfactants are carried with the gas to thief zones faster and deeper with relatively lower adsorption to the rock surface. However, the conventional foam modeling approach relied only on the surfactant concentration in brine to determine foam strength, which adversely predicted the performance of gas soluble surfactants. With proven laboratory evaluations and multiple successful field implementations, the advantages of low adsorbing and gas soluble surfactants cannot be ignored. In this paper, the advantages of surfactant partitioning to the gas phase are confirmed by correcting the conventional foam modeling approach while simulating 1D transport of CO 2 -foam displacing brine in porous media. An empirical foam model was developed from the lab scale core flooding work of CO 2 foam transport through porous media using a novel gas-soluble foaming surfactant. While investigating the performance of gas soluble surfactants, global surfactant concentration was used to determine foam strength as the surfactant can transport to the gas-water interface from both the phases. Lab experiments and simulations with an improved foam modeling approach confirmed that a higher gas phase partitioning surfactant generated robust foam and deeper foam propagation while injecting surfactant with CO 2 in a water saturated core. In addition, comparing three partition coefficient scenarios around 1 on mass basis, the higher gas phase partitioning surfactant showed the larger delay in gas breakthrough. Overall, the simulation results with our better modeling approach do support the advantages of the higher gas phase surfactant partitioning in deeper foam transport and conformance enhancement for the gas-EOR technology.