bluuebunny/crossref_metadata_2025 huggingface dataset:
Combining Nanocatalyts with Solvent as a Strategy to Improve Steam-Based Hybrid Technology: Phase Behaviour Modelling and Thermal Simulation Approach
Authors: García-Duarte H. A. , Ruiz-Cañas M. C. , Perez-Romero R. A.
Published: April 2024

As a strategy to optimize the recovery and energy efficiency in cyclic steam stimulation (CSS) processes, the alternative of combining steam - nanosolvents has been under study in Colombian heavy oil reservoirs. The use of oil-based nanocatalysts (nanosolvents) in combination with steam allows extending the effectiveness of the catalyst, transporting it better within the reservoir due to the solubility of naphtha in the crude oil. The interaction phenomena associate with this hybrid technology must be evaluated under a robust phase behavior study which represent oil - solvent interaction analysis and, the effect on the oil density and oil viscosity at different temperatures.

This work shows a methodology to incorporate solvent/oil mixtures phase behavior into the field numerical model. Based on experimental PVT tests (such as compositional analysis and fluids characterization) a fluid model was developed. Using Peng Robinson Modified Equation experimental data were adjusted such as GOR and density. Additionally, the mixture viscosity were fitted with the modified Pedersen equation. Incorporate the effect of nanocatalysts in the numerical modeling required the grouping by pseudo-components of live oil according to the proposed kinetic model, obtaining a good adjustment and a better representation of the live oil. This allowed the inclusion of the component's properties such as asphaltenes and upgrading oil used in the kinetic model of the CSS + solvent enhanced with nanoparticles technology.

The experimental results indicate the high solubility of the solvent in crude oil, due that a linear mixture rules for naphtha - oil was developed. Additionally, a representative fluid model is mandatory to represent aquathermolysis catalytic reaction in the CSS. The modelling results show that the highest incremental recovery of the nanofluid was achieved in early stages of CSS with an increase of 23% concerning the baseline. Likewise, a sensitivity analysis was developed based on a fixed cumulative oil production in the presence of nanofluids, obtaining a 61% reduction in the steam injection rate, indicating that the hybrid technology not only generates positive impacts on recovery but also positively impacts on improving energy efficiency and reducing the carbon footprint.

A novel methodology to represent the fluid interaction in presence of nanocatalysts in the numerical modeling was developed as a strategy to incorporate oil compositional changes in thermal hybrid process.
Enhancing ASP Flood Design: Integrating Pilot Learnings, Lab Re-Optimization and Field Analogues Before Commercial Implementation - A Case Study of India
Authors: Hanotia A. , Biswas M. , Rana V. , Pandey V. , Mavoori R. , Rathi K. , Mitra S.
Published: April 2024

The ASP flooding is a complex technology as experienced from latest field implementations at western onshore basin in ONGC. Although, ASP pilot has been successfully executed in concerned reservoir, few challenges are still present. The present paper proposes to address these challenges before moving for the commercialization.

Encouraging laboratory and simulation results lead to ASP pilot with inverted five spot pattern. The pilot shows directional heterogeneity leading to early breakthrough which necessitated Profile Modification and Water Shut off jobs. Active aquifer and low polymer buffer viscosity lead to increase in water cut. Besides, the chemical quality monitoring, supply chain management were the challenges to be addressed before full field expansion. The re-optimization of chemical formulation is also performed in lab to mitigate the detrimental effect of alkali induced scaling and to reutilize the effluent water. Simulation was also revisited with envisaged incremental oil of 6.6% in thirteen years.

Lessons learnt during pilot implementation and the experience of a commercial ASP project in an analogous field helped in better formulating development strategy for the present project.

To prevent the ground water exploitation and better management of effluent water, the ASP formulation was modified without compromising its performance. The scaling problem as was encountered at surface and subsurface in analogous field lead to reduction in alkali concentration and incorporation of scale inhibitor. For better control of chemical supply chain and quality monitoring, the responsibility matrix was revisited. ASP expansion has been considered in the structurally top part where sand is well developed and well productivity is higher with reduced well spacing. Sensitivity runs showed that incremental oil recovery increases with higher slug size and higher polymer buffer concentration. The ASP injection comprises of 14 inverted 5 spot patterns. The surfactant induced tough emulsion formation is also proactively addressed in the upcoming ASP project.

Although ASP process is a complex technology but it has the potential to significantly enhance the field recovery. The technical and managerial challenges faced in pilot and in the running of commercial project helps to take necessary action beforehand. No matter how well prepared a plan may be it is inevitable that it will face challenges and obstacles along the way. However, being agile and timely midcourse correction is the key for success.
Co-Injection of Surfactant and Gas in Unconventional Reservoirs
Authors: Schechter D. S. , Moore B. , Sarmah A.
Published: April 2024

Enhanced oil recovery in unconventional reservoirs has established a track record in the past few years. It is an important technology to investigate and implement to pursue longevity in the thousands of horizontal laterals that are reaching their terminal decline towards abandonment. EOR techniques have been proven to be technically feasible and to a certain degree, economically attractive. The techniques described in this paper are 1) gas injection in the huff n' puff mode 2) surfactant injection in the huff n' puff mode and 3) co- injection of both miscible gas and surfactant. The objectives of this paper are to present laboratory evidence and field resu lts for the three techniques described.

This paper will present laboratory justification behind each of the three methods. Results from core data are presented for each of the three methods that include gas penetration, imbibition, and the use of both mechanisms for co-injection of gas and surfactant. Experiments using time-lapse CT scanning demonstrate the saturation changes as oil is displaced when core samples are exposed to gas, surfactant, or a combination of both.

Miscible gas experiments conducted using time-lapse CT scanning indicate gas penetration induces saturation changes on reasonable time scales. Wettability alteration by surfactants as determined by contact angle measurements will be presented. Ample contact angle and imbibition data demonstrate that wettability alteration is the key to application of surfactants in unconventional reservoirs. Both techniques have been applied in successful field projects.

A novel co-injection method with both miscible gas and surfactant is described. Application of co-injection using both gas and surfactant capitalizing on the synergy between the mechanisms is especially intriguing, both from a laboratory and field perspective. The technique utilizes both the diffusion/swelling mechanism of miscible gas along with the ability of surfactant to alter wettability resulting in gas sweeping the larger pore spaces and aqueous phase surfactants to displace oil in smaller pores via capillary pressure. Experiments are presented that show miscible gas displaces oil from larger pores and surfactant imbibition displaces oil from smaller pores during co- injection. Review of a co-injection project demonstrates key advantages over gas injection alone such as 1) prevention of rapid gas migration via fractures away from injection well 2) reduction of the necessity for high pressure compression to attain the Minimum Miscibility Pressure (MMP) by utilizing co-injection of surfactant and gas and 3) a superior gas utilization factor (GUF) as compared to gas-only projects showing the importance of surfactant during co-injection.
Numerical Studies of Unstable Fingering Flow in a Water-Oil System
Authors: Jia Cunqi , Hu Jinchuan , Sepehrnoori Kamy
Published: April 2024

Fingering behavior is a crucial phenomenon in the improved oil recovery process and significantly influences oil recovery, including heterogeneity channeling and viscous fingering. This study modeled the fingering behavior during the water flooding process and enhanced the simulation method to represent these two phenomena simultaneously. In this study, we employ the Corey correlations to preserve laboratory-measured data on the relative permeability and incorporate the impact of capillary pressure. The Leverett J-function is additionally used to integrate formation heterogeneity and saturation influence on capillary pressure. The method is validated through a comparison with lab-based flat-plate displacement experiments, with authentic measured relative permeability data. our improved model can accurately capture the results of the fingering phenomenon, obtaining similar fingering patterns and quantitatively matching the BHP, water cut, and oil recovery factor. Based on it, we explored the influence of injection rate, water and oil viscosities, and viscosity ratio. The results indicate that increasing the injected water viscosity delays the breakthrough, thus improving the oil recovery. It is worth noting that the same value of viscosity ratio does not obtain the same results. For instance, when the water and oil viscosities are 100m and 1000 mPa·s, 1PV water injection results in a final recovery factor of 54.79%, while 38.02% with viscosities of 1mPa·s and 10 mPa·s respectively. Water injection rates also affect the final oil recovery. These two typical findings cannot be captured in most of previous simulations. By considering the impact of capillary pressure heterogeneity, such physical phenomena are well reproduced in this work. Compared to visualization experiments and micro-scale direct simulation, macro-scale fingering simulation has always been challenging. While some studies can obtain fingering images similar to those observed in laboratory experiments, the relative permeability used deviates significantly from actual conventional laboratory measurements. However, our improved model can simultaneously reproduce both heterogeneity channeling and viscous fingering phenomena with authentic laboratory-measured data.
Hot Oil Now a Successful Optimization Acceleration Project, Safer, Faster and Hotter: A Case Study of Optimization Challenges in a Thermal Steam Flood Field, South of Sultanate of Oman
Authors: AL-Shuaibi Hasna A. , AL-Shaqsi Khadija. A. , Al-Mawali Shaikha. N. , AL-Sheibani Hamdan. S. , Bhavsra Chetan. D. , Maabady Islam. A.
Published: April 2024

This paper covers the optimization challenges in a thermal Steam Flood field located south of Oman. Focusing on the A Field, which is a deep reservoir characterized by high-temperature and high-pressure conditions, making it one of the most challenging fields in Oman. The research methodology encompasses a comprehensive analysis of optimization challenges in A Field, classifying them into three primary categories: subsurface challenges, surface challenges, and process challenges. This classification sets the stage for a detailed examination of mitigation plans and strategies tailored to each challenge. To maximizing oil recovery, ensuring reservoir balance, preventing loss of containment, and ensuring Health, Safety, and Environment (HSE) practices. Implementation of Practical Problem-Solving sessions (PPS) and Continuous Improvement (CI) initiatives, specifically tailored to improve process challenges, has resulted in significant improvements. This includes a notable 70% reduction in the total surface optimization cycle time, liberating resources for approximately 51 days to address other workovers and enhance resource deployment efficiency. Furthermore, the paper showcases substantial cost savings equivalent to a full-time Petroleum Engineer position, coupled with an accelerated enhanced oil recovery in 2023 of around 35 % net oil gain of the average field production compared to 4 % net oil production gain of the average field production in 2021. The establishment of a standardized process flow as a Standard Operating Procedure (SOP) and the creation of a visual management system, coupled with tracked Key Performance Indicators (KPIs), ensure the sustainability of these improvements. This paper presents novel insights into the optimization challenges faced in a thermal steam flood field and provides a case paper of the A Field in Oman. The research emphasizes the significance of aligning optimization criteria, introducing visual tracking tools, and following agreed-upon surface and subsurface optimization processes. The paper also highlights the potential benefits of automation, standardization, and visualization in planning and executing optimization activities. By leveraging automation and lean methodologies, the field can overcome challenges more efficiently, leading to increased operational efficiency and higher oil recovery rates. The findings contribute to the understanding of optimizing thermal fields and offer valuable lessons for similar projects worldwide.
Self-Granulated Thermoplastic Elastic Particles for Fracture Conformance Control of Harsh Reservoirs
Authors: Xue Yan , Yin Qiulu , Zhang Chunquan , Wei Bing , Lu Jun , Wang Yiwen
Published: April 2024

To address the challenges associated with the complex preparation process of polymer particles for conformance control and the difficulties in combining injection and conformance control performance, a study was conducted on a thermoplastic elastic particle conformance control agent using polyvinyl alcohol (PVA) as the particle skeleton. The millimeter-scale elastic particles can be prepared in-situ by incorporating a hydrophobic modifier (HM) and a cross-linking agent glutaraldehyde into the aqueous phase. By adjusting the content of HM and stirring speed, the particle size can be regulated. The texture profile analysis indicated that the self-granulated thermoplastic elastic particles exhibit excellent elasticity and high resilience. Furthermore, they can undergo thermoplasticization in highly mineralized water (21×104 mg/L, Ca2+ + Mg2+ = 1.2×104 mg/L) and crude oil at 130 °C, while maintaining exceptional mechanical properties. Physical model experiments demonstrated that the particle system exhibits good migration ability and plugging performance. The particles’ breakthrough pressure significantly increased after high-temperature treatment, reaching 1860 kPa, highlighting the practical potential of these particles for oil reservoir applications. With a simple dropwise stirring "one-pot" synthesis method, the thermoplastic elastic particles offer advantages including straightforward synthesis, environmental friendliness, excellent mechanical performance, thermal stability and salt resistance. These thermoplastic elastic particles show great potential for future industrial production and have promising prospects as a fracture conformance control agent.
The Effect of Small Molecule Gas-Soluble Polymers on Minimum Miscibility Pressure During CO2 Injection
Authors: Torabi Farshid , Gandomkar Asghar
Published: April 2024

The minimum miscibility pressure is the main technical challenges during CO2 flooding. Therefore, the purpose of this work is to explore the effect of small molecule CO2-soluble polymers including PDMS, PFA, P-1-D, and PVEE on minimum miscibility pressure during gas flooding. The dilute concentrations of polymers (1000 to 50000 ppm) were considered to dissolve in CO2 at 60 and 80 °C. According to the cloud point pressure results, the small molecule CO2-soluble polymers dissolved in carbon dioxide at pressures consistent with gas-based EOR methods (less than 2500 psi) at both 60 and 80 °C. Also, (CO2/polymers)-oil interfacial tensions were decreased extremely via the dissolution of dilute concentrations of polymers in CO2. Moreover, the small molecule CO2-soluble polymers decreased significantly the MMPs by 19.4% for CO2/PFA, 17% for CO2/PDMs, 13.6% for CO2/PVEE, and 10% for CO2/P-1-D scenarios in comparison with pure carbon dioxide injection. Moreover, the 26.5% additional oil was recovered during miscible CO2/PDMS injection in comparison with miscible pure CO2 scenario. Therefore, the small molecule CO2-soluble polymers containing functional groups with oxygen can be one of the best candidates for miscible CO2 displacement in the field-scale.
Enhancing Condensate Production by 29%, Through Thermal Gas Injection from a Retrograde Gas Condensate Reservoir - With an Operational Case Study in the Western Desert of Egypt
Authors: Taha Maged Alaa , Shokier Eissa , Attia Attia , Yahia Aamer , Mansour Khaled , Abdelkhalek Dina Medhat
Published: April 2024

In retrograde gas condensate reservoirs, the accumulation of liquid from natural gas below the dew-point pressure leads to condensate blockage, a significant issue in reservoir damage. Although most of this liquid doesn't reach the level required for production, it hinders the flow of natural gas, affecting its production.

This study focuses on the impact of gas injection methods (like methane, carbon dioxide, and nitrogen) and high-temperature steam on an Egyptian retrograde gas condensate reservoir. Various scenarios were tested, involving different temperatures, enthalpy levels, types of injection gases (CO2, N2, CH4), and injection rates.

The findings revealed that neither conventional nor thermal gas injection methods significantly increased cumulative gas production compared to simply depleting the reservoir. However, non-thermal gas injection methods boosted cumulative condensate production by 8.6%. Notably, thermal CO2 injection showed a substantial increase, enhancing condensate production by 28.9%. The study found that thermal gas injection does not vaporize condensate more effectively than conventional injection methods under similar reservoir pressure trends. Instead, the primary benefit of thermal injection is in enhancing condensate mobility. Therefore, thermal injection is most suitable for depleted retrograde reservoirs, where a significant amount of non-producible liquid has already accumulated. The research also explored the operational aspects of implementing thermal gas injection in retrograde gas condensate reservoirs. This includes considerations for carbon dioxide recovery units, compressors, storage tanks, corrosion-resistant pipelines and tubing strings, as well as corrosion inhibitors and downhole gas heaters.
Synergistic Effects Between Supercritical CO2 and Diluted Microemulsion on Enhanced Oil Recovery in Shale Oil Reservoirs
Authors: Yuan Shuai , Wang Bin , Yang Maoqin , Zheng Leyi , Liu Hao , Li Yuan , Zhou Fujian , Liang Tianbo
Published: April 2024

The development of unconventional liquid-rich reservoirs, supercritical carbon dioxide (scCO2) considers a promising fluid to further improve oil recovery of shale oil reservoirs in and after hydraulic fracturing. However, the scCO2 has some disadvantages to limit its application in hydraulic fracturing, such as ultra-low viscosity, asphaltene deposition and high miscible pressure. Diluted microemulsion (DME) shows great potential as the additive of fracturing fluid to improve the well productivity through strengthening the spontaneous imbibition during the shut-in period after hydraulic fracturing. Therefore, it is essential to further understand the synergic effects between scCO2 and DME at the pore scale. In this study, three soaking sequences are designed and compared, which include only scCO2 soaking, water-scCO2-DME soaking sequence, and DME-scCO2-DME soaking sequence using shale cores from the Lucaogou Formation. Low-field nuclear-magnetic-resonance (NMR) technique are utilized to quantify the oil distribution among different pores in each soaking stage. Furthermore, component change of the produced oil is characterized by the gas chromatography (GC). Notably, T1-T2 spectra are introduced to verify the results of T2 spectra and GC. Results show that DME can replace the oil from small pores into large pores and thus improve the extraction effects of scCO2. The solid-liquid and oil-water/scCO2 interactions determine the adhesion work of heavy components. DME can enhance the heavy component (C17+) mobilization through interfacial tension (IFT) reduction and wettability alteration. Combing scCO2 and DME can effectively improve the mobilization of both light and heavy components of crude oil, and thus achieve a better ultimate oil recovery rate.
Chemical Enhanced Oil Recovery Experiences in Colombia: Field Pilots Review
Authors: Gutierrez M. , Castro R. H. , Corredor L. M. , Fernández F. R. , Zapata J. , Jimenez J. A. , Reyes J. D. , Rojas D. M. , Jimenez R , Acosta T. , Dueñas D. E. , Solorzano P. L. , Mayorga H. , Llanos S. , Quintero H. I. , Garcia H. A.
Published: April 2024

Polymer injection is a technique that has been applied worldwide to improve oil reservoir volumetric sweep efficiency and increase the recovery factor. Different applications using partially hydrolyzed polyacrylamide (HPAM) polymers have been carried out in some Colombian fields since 2011. Several pilots have been implemented to test both technical and economic feasibility. This article summarizes the pilot's results and the lessons learned. The different polymer technologies evaluated for chemical Enhanced Oil Recovery (CEOR) are i) Colloidal dispersion gels (CDG) for mobility control and deep divergence executed in Dina Cretáceo and Tello fields, ii) Polymer flooding for mobility control executed in Yariguí- Cantagallo, Casabe, Palogrande-Cebu, Chichimene, and La Cira- Infantas, iii) Alkaline-Surfactant Polymer (ASP) flooding to increase recovery executed in San Francisco, and Caracara Sur fields.

The results of pilots have caused a positive impact, such as an increase in oil production and a decrease in water production, improving the recovery factor in the influenced reservoir volume. The advances in the last decade have increased the interest in applying polymer injection technologies in different Colombian fields. This article reviews Colombian references and our experience in the first designs and polymer applications in the field. From their view, a short state-of-the-art description of the characteristics of each polymer technology was structured, as well as the objectives and results of each pilot implemented factors such as design, operating conditions during its execution, and process efficiency.
Application of Koval's Theory to Low Salinity Waterflooding and the Hybrid of Low Salinity Waterflooding and Polymer Flooding
Authors: Jerauld Gary R.
Published: April 2024

While fractional flow theory is a useful first step in modeling enhanced oil recovery, viscous instabilities and channeling often have a large impact the timing and efficiency of oil recovery, as they do in low salinity waterflooding. Jain and Lake (2013) developed an analytical method the combines fractional flow theory with Koval's method to account for these instabilities for situations when two fronts are form, and solved the resulting equations for miscible floods using the method of characteristics. We apply this method for low salinity waterflooding and the combination of polymer flooding and low salinity waterflooding. To make the method fit for the purpose of screening, we extended the theory to approximate the spreading wave of the chase flood and explain conditions for the new set of shocks that form in this application which have not been described previously. For the combination of low salinity and polymer flooding the theory is extended to add a third front. The resulting approach provides an effective screening tool for low salinity waterflooding and the combination of low salinity waterflooding and polymer flooding EOR projects which accounts for the impact of heterogeneity/mobility ratio on these floods. Application of this model to secondary corefloods gives a simple explanation for why the two fronts predicted by fractional flow theory are typically not observed. Application to tertiary corefloods demonstrates why there is often early breakthrough and a broad range of slopes in the oil recovery versus throughput. Application to Low Salinity/polymer flooding hybrid process demonstrates the full value of mobility control in overcoming unfavorable mobilities between the oil bank and chase low salinity waterflood.
Designing an In-Depth Conformance Gel System for Carbonate Reservoirs
Authors: Hernando L. , Alotaibi M. , Salehi N. , Zaitoun A. , Fahmi M. , Wang J. , Alfakeer T. , Mirzayev K.
Published: April 2024

Many fields worldwide are facing conformance problems increasing with time, due to heterogeneity of the reservoir rock (fractures, features, vugs). During water injection, channeling occurs through the high-permeability streaks, causing early water breakthrough and poor waterflood efficiency. The objective of this paper is the design of an efficient and performing gel system for in-depth fluid diversion in reservoir conditions.

A laboratory and simulation study was undertaken to design a gel system that can suit high-salinity high-temperature conditions. The temperature is around 99°C. Formation water salinity is very high while water injection salinity can reach up to 57,000 ppm. Vuggy intervals create a thief zone between injection well and production well.

The gelation has to be delayed for at least one week to be injectable at a large distance from the well. To achieve this goal, four gel systems were investigated. The influence of three parameters has been evaluated, namely polymer concentration, crosslinker concentration and aging temperature. Aging tests were performed at reservoir temperature and gelation tests at slightly lower temperature, representative of near-well conditions (85°C). Three main criteria have been taken into account to select the best system, i.e., gel quality, gelation time and gel stability over time. From bulk tests, two gel systems were qualified. Then, coreflood experiments were performed in low-permeability matrix cores and in high-permeability vuggy cores. Injectivity of polymer and crosslinker solutions (gelant) before gelation was evaluated. After gel formation in the vuggy core, gel stability tests by water injection under increasing differential pressure aimed at determining gel parting pressure and permeability reduction after gel breakthrough.

Many parameters influenced gelation time. Gelation time can be increased by decreasing polymer and/ or crosslinker concentration but a minimum concentration is needed to obtain a strong gel. Coreflood experiments in matrix rock type showed that the gelant will not invade the matrix deep in the reservoir. Corefloods in vuggy zone indicated that mobility reduction of the viscous gelant drops when flow rate increases, thus showing the ability of the gel to invade deeply the high-permeability streaks. For the best gel formulation, gelation time was 12 days. After aging, the gel generates a permeability reduction as high as 20000 and strongly reduces accessible pore volume of the vuggy core.

The novelty of the lab work is the design of an optimum gel treatment to improve the water injection profile, especially in extended lateral and horizontal wells. This study also gave parameters like blend adsorption, mobility reduction during polymer injection, permeability reduction and gelation time. These parameters can be utilized in simulation work to evaluate gel treatment efficiency in a pilot.
Integrated Asset Modeling of a Coupled Reservoir for Production Optimization
Authors: Eastwood-Anaba A. A. , Ampomah W.
Published: April 2024

This thesis presents an approach for coupled subsurface and surface network facility optimization of oil production and CO2 sequestration, utilizing CO2 in enhanced oil recovery. A field-scale integrated asset model of the mature Farnsworth field is developed with a surface-coupled history-matched compositional numerical reservoir simulation model and operating conditions optimized.

The reservoir flow model was constructed based on extensive geophysical, geological, and engineering data from the Farnsworth Field Unit. Peng-Robinson equation of state parameters were tuned to field laboratory measured fluid properties. The model was calibrated to the primary and secondary recovery phases and subsequently to the tertiary recovery phase.

Once a good match was achieved for the tertiary phase, an optimization model was designed with the goal of maximizing oil recovery and CO2 storage. A sensitivity analysis was conducted to determine the most impactful parameters among recycled and purchased CO2, Water-Alternating-Gas (WAG) cycle and ratio, Tubing Head Pressure (THP) of injectors and producers, separator pressure and gas compressor injection rate. A Radial Basis Function Neural Network was used to create the proxy from training data obtained from numerous simulations. A Particle Swarm Optimubizer was used to find the optimum operating conditions of the surface facility network and maximize oil recovery and CO2 storage.

The optimized values provide a more efficient use of CO2 in incremental oil recovery. This results in higher cumulative oil recovery while the CO2 remained trapped in the reservoir and/or in closed loop. The conversion of water injectors to CO2-WAG injectors based on optimized development strategy improved oil production by increasing the sweep efficiency of the water in the region. The inclusion of surface facilities is necessary in this study to optimize oil production with an increased accuracy of life cycle assessments for CO2-EOR processes.

Integrated Asset Modeling gives access to operating conditions and surface facility constraints that would otherwise be left to assumptions or ignored. This paper presents a robust framework for optimizing surface operating conditions for maximizing oil recovery based on existing field capacity.
Improved Capillary Desaturation Model for Carbonate Reservoirs
Authors: Lashgari Hamid , Tawfik Miral , Jackson Adam C. , Dwarakanath Varadarajan , Alexis Dennis , Thach Sophany , Shi Xundan , Slaughter Will , Mathis Lee , Pope Gary
Published: April 2024

This paper presents a modified Capillary Desaturation Curve (CDC) model to capture the effect of the capillary number (Nc) on residual oil saturation (Sor) for carbonate reservoirs during water- and polymer flooding. The proposed model is implemented in a multicomponent, multiphase chemical reservoir simulator. Several simulation test cases are presented to illustrate the impact of the modified CDC model. Experimental and literature data for CDC were used to show that the modified model was needed to make accurate forecasts of a proposed polymer flood in a carbonate reservoir. The simulation results and experimental CDC data show that the decrease in Sor at relatively lower capillary numbers (10 -7<Nc<10 -5) often makes polymer flooding more attractive for carbonate reservoirs. Simulation results also show that the original CDC model underestimates the incremental recovery during water- and polymer flooding. Also, a sensitivity study shows the proposed model yields better forecasts of the oil recovery at various trapping-number exponent, injection rate, and permeability.
An Experimental Evaluation of a Hybrid EOR Method Combining Low-Tension-Gas and Polymer-Gel
Authors: Niu Fangya , Panthi Krishna , Zhou Nancy C. , Lu Meng , Zhang Danhua Leslie , Delshad Mojdeh , Mohanty Kishore K.
Published: April 2024

Heterogeneous sandstone reservoirs pose many challenges to oil recovery, one of them being recovering oil from the low permeability zones. Low-tension-gas (LTG) flooding has been proven to be effective in mobilizing oil trapped in low permeability reservoirs. Meanwhile, polymeric gel systems have been used successfully for conformance control in heterogeneous reservoirs. The objective of this study is to maximize oil recovery in a high-temperature, high salinity, and heterogeneous sandstone reservoir by LTG flooding with the assistance of a polymeric gel for conformance control. In this study, a dual parallel core flood was designed by setting up a high permeability core and a low permeability core in parallel and conducting simultaneous injections. The LTG flood and polymer gel placement were investigated separately first to confirm the efficacy. All experiments were conducted at 92°C. Bulk foam tests were performed to evaluate the stability and injectivity of ultralow-IFT foam and foam drive. The LTG core floods were completed in outcrop sandstone cores and composite reservoir cores to test the designed injection scheme. The plugging efficiency of formulated polymer gel was studied by a core flood in an outcrop sandstone core. It decreased the permeability from 1.4 Darcy to 0.4 mD after 1 week of incubation period. In the dual core flood test, we carried out waterflood and LTG flood before and after the gel application. The recovery analysis showed that before introducing the gel system LTG itself could provide a certain degree of profile control. The formulated polymer gel could provide stronger profile control and the following waterflood and LTG greatly improved oil recovery from the low permeability region by 41% and 37% respectively. The result of dual core flood demonstrates the effectiveness of a novel hybrid EOR process in the high temperature-high salinity heterogeneous reservoirs.
Effect of Pressure, Initial Water Saturation, Rock Type and Injection Rate on Oil Recovery and Displacement Efficiency of CO2 Injection in Carbonate Reservoirs
Authors: Masalmeh S. K. , Farzaneh S. A. , Sohrabi M. , AlHammadi M.
Published: April 2024

Miscible gas injection is the most widely applied enhanced oil recovery (EOR) method in light oil carbonate reservoirs, both as tertiary and secondary method. Miscible gas has high displacement efficiency and usually results in a low residual oil saturation (Sorm) in the part of the reservoirs that is contacted with gas. Accurate determination of Sorm and understanding the parameters that affect displacement efficiency are crucial for successful miscible gas EOR projects.

This paper presents a comprehensive experimental program designed to investigate the effect of experimental pressure, pore volume injected, injection rate, rock type and initial water saturation on the displacement efficiency, Sorm and recovery factor of miscible/near-miscible CO2 injection. The CO2 injection experiments were performed using live crude oil at pressures above the minimum miscibility pressure (MMP) using reservoir core samples of up to 1 ft long and 2 in. diameter. All CO2 injection experiments were performed using vertically oriented cores, with gas injection from the top unless stated otherwise.

The experimental results show that: 1-Oil recovery decreases as pressure decreases with Sorm increases by more than 20 saturation units as the pressure decrease from 4250 psi to 2700 psi; 2-CO2 breakthrough was much earlier at lower pressure which leads to more CO2 recycling, 3-The recovery factor is strongly affected by pore volume injected, however, the effect of the CO2 injection volume is much more significant at lower pressure; 4-The injection rate has insignificant effect on oil recovery and Sorm for miscible or near miscible CO2, due to the low IFT between oil and CO2, 5-Rock heterogeneity had little effect on ultimate oil recovery of miscible CO2 injection, however, the ultimate recovery for the heterogenous rock was obtained at much higher pore volume injected, and 6-The presence of mobile water at the beginning of CO2 injection resulted in lower displacement efficiency and increased Sorm. However, this water blocking effect should be determined experimentally for a given reservoir rock/fluid system. The results of this study cannot be generalized for other reservoirs.

The results of this study have important implications for the design and performance predictions of CO2 gas injection. Starting CO2 injection at higher reservoir pressure is recommended due to its superior displacement efficiency and less CO2 recycling due to later breakthrough. However, higher pressure may negatively impact the required CO2 volume, the compression cost and project economics.
Lessons Learned from the Implementation of Two Thermally Active Polymer Campaigns as an In-Depth Conformance Technology: Yariguí Field, Colombia
Authors: Gutierrez M. , Corredor L. M. , Castro R. H. , Barbosa C. , Quintero H. I. , Garcia J. S. , Kazempour M. , Peñuela G. , Pachon Y. F. , Cabezas A. J. , Rojas J. , Manrique E. J.
Published: April 2024

The Yariguí-Cantagallo oil field, located in Colombia's western flank of the Middle Magdalena Valley basin, is a well-established and mature oil-producing field. Oil extraction operations started in 1941 and have been accompanied with water injection since 2008. However, due to the challenge of water channeling, certain wells have experienced a significant increase in water cuts, exceeding 90%. For this reason, ECOPETROL S.A. initiated its first in-depth conformance treatment endeavor in Colombia in 2020, targeting two wells. It was followed by a second campaign in 2022, which included five wells. The chosen solution for these conformance projects is known as Thermally Active Polymer (TAP). This technology is employed in reservoirs undergoing waterflooding and facing complications such as thief zones and preferential flow channels. TAP relies on the deployment of expandable submicron particles that are injected downhole using a surfactant as dispersant, with the injection water as the carrier fluid. The selection of injection patterns and the estimation of treatment volume were carried out through the analysis of diagnostic plots and analytical pattern simulations.

The injection process for the first pattern started on December 14, 2020, entailing a cumulative injection of 6,344 barrels of water containing TAP at an injection rate of 700 barrels per day. The TAP concentration gradually increased from 3,500 ppm to 12,000 ppm. Subsequently, the second injection pattern was executed on December 23, 2020. In this case, 9,152 barrels of water containing TAP were injected at an injection rate of 700 barrels per day, with TAP concentrations ranging from 3,500 ppm to 8,000 ppm. The five injectors of the second campaign were intervened with slightly different strategies. Some of the wells were treated with two grades of TAP with different activation kinetics. This paper provides a comprehensive overview of the implementation of TAP technology as a pilot project in Colombia. It outlines the methodology employed and offers insights into the project's QAQC monitoring and injection-production results. The two years monitoring of the first campaign have showed water cuts reduction by up to 5%, resulting in a remarkable increase in oil recovery of 39KBO (Barrels of oil). As for the second campaign, the additional oil recovery is up to now of 26KBO.
Comprehensive Enthalpy-Based Phase Behavior for EOS-Based Compositional Thermal Simulation
Authors: Barrios-Molano H. E. , Sepehrnoori K.
Published: April 2024

This work presents the selection of the most adequate isenthalpic flash method for EOS-based compositional thermal simulation. Five multi-component isenthalpic flash methods were studied. We consider water as a component and the mutual solubility of water and hydrocarbons. A novel isenthalpic flash method is presented. We present a new single-component isenthalpic flash. Finally, we propose a new phase identification algorithm for application into thermal EOR processes.

Five multi-component isenthalpic flash methods were studied: direct substitution, full Newton, partial Newton, Q-function maximization, and a novel bisection-like isenthalpic flash. Modifications to Q-function maximization are proposed to account for cases in which isothermal flash could fail. We compared these methods for robustness and computational performance to select the most adequate for compositional thermal simulation. A new isenthalpic flash for single-component fluids is proposed and compared with more traditional solutions such as steam tables. Finally, we present a new method for phase identification for thermal EOR processes based on fluid enthalpy and mass density.

We compare five multi-component isenthalpic flash methods using two different initial conditions. We perform a series of flash calculations over a pressure and enthalpy range. More than 179000 flash calculations were performed for each method. Also, we compare the combined use of the methods studied. The methods were evaluated in terms of robustness and performance. From the individual method comparison, we conclude that none of the methods studied by themselves is adequate for thermal reservoir simulation. However, the combined use of these methods shows better results. We found when we use both Newton methods and call Q-function maximization with bisection when Newton fails to be robust enough for its application to compositional thermal reservoir simulation. We show a case of the single-component isenthalpic flash method using water and comparing it with steam tables. The results are in good agreement. The method proposed in this work has the advantage that could be applied to any component described by an equation of state. The results of the phase-identification algorithm are shown, demonstrating its usability for compositional thermal reservoir simulation.
Recent Advances in Modeling Polymer Flooding
Authors: Li Z. , Dean R. M. , Lashgari H. , Luo H. , Driver J. W. , Winoto W. , Pope G. A. , Thach S. , Dwarakanath V. , Mathis L. , Wood L. , Nurmi L. , Hanski S. , Pin E.
Published: April 2024

New and improved physical property models have been added to the UTCHEM reservoir simulator to accommodate a broader range of polymer flooding applications and to improve its predictive capabilities. Accurate simulations of the chemistry and physics of polymer flooding are needed to design and optimize a polymer flood including the selection of the best polymer to use for specific reservoir conditions. The new polymer viscosity model implemented in UTCHEM can be used to calculate polymer viscosity more accurately as a function of polymer concentration, shear rate, salinity and hardness, temperature, and intrinsic viscosity. The new model is based on extensive polymer viscosity and rheological measurements. The improved polymer rheology is important for more reliable predictions of polymer injectivity and reservoir sweep. A hydrolysis model has been added to UTCHEM to aid in the selection of polymers as a function of temperature, brine composition and pH. A new cation exchange model that includes hydrolyzed polyacrylamide has been implemented to account for the effect of different cations in the brine on the polymer properties as a function of the degree of hydrolysis. The inaccessible pore volume model has been modified to include the exclusion of large polymer molecules from pores below a certain size in addition to the effect of polymer size on the velocity of the polymer molecules within the pores that are large enough for the polymer to enter. The new inaccessible pore volume model serves as a useful tool for selecting reservoir- compatible polymers and improving the accuracy of the simulations. Extensive high-quality lab data were used to validate the new models. Simulation cases were built to illustrate how the models can be used to upscale lab results to field scale.
Improve Waterflood Vertical Conformance for a Heavy Oil Multi-Layer Sandstone Reservoir. A Case Study from South of Oman Field
Authors: Al Sawafi M. M. , Shammakhy Al , Al-hinai S. M.
Published: April 2024

One of the challenging Waterflood field in south of Oman was suffering significantly from poor waterflood vertical conformance. The field lost 60% of its oil production rate within 4 years, despite drilling 40 additional oil producers at the same time, which is corresponding to 50% increase in number of wells. The field is a heavy oil, multi-layer sandstone oil reservoir. Each layer has its own depositional environment, oil viscosity and static properties. Moreover, the extensive faulting of the field leading to compartmentalization adds more complexity to the field remedy plans. The original development strategy was based on commingled production/Injection from all layers. It was found that one layer (L4) has heavily dominated production and injection in the field, which only has 25% of the total STOIIP, leaving the remaining 75% oil unswept. This paper will highlight and showcase the mitigation plans that were implemented that lead to significant improvement to the WF vertical conformance which led to stable field production recently.

The first and the most important step toward fixing the production crisis was to improve the understanding of the communication paths in the reservoirs by integrating production data, pressure data, and an improved understanding of the sand distribution in the reservoirs. The key surveillance data that helped was the Production Logging Tools (PLTs), tracers and the Reservoir Pressure.

Considering all limitations and risks, it was found that the best development scenario was implementing a double inverted five spot waterflood pattern in the field (Fig 5). These two patterns are called: the A-pattern and the B-pattern. The aim of this development is to establish dedicated production from remaining layers units other than the L4, as the L4 is interpreted to have heavily dominated production and injection in the field. The B-pattern will first be completed on the L5 & L6 units (both deeper than the L4). The A-pattern wells will be gradually converted to dedicated wells on the L3 and L1&2 (if present). Check Fig 2

In 2023, 95% of the recovery plan has already been implemented which led to a sustainable oil production with 0% decline rate in the last 5 years. Also, it is clear from the PLTs that the vertical conformance has improved significantly. There are clear evidences that all others units are now contributing to both production and injection. In some patters, it was observed that the WF vertical conformance has improved up to 50%.

Also, from economic point of view, the project has achieved its promised NPV with very attractive UTC of less than 15 $/bbl and more than 20 mln bbl of additional reserve.