bluuebunny/crossref_metadata_2025_split huggingface dataset:
Carbon Footprint and Energy Intensity Assessment for Enhanced Oil Recovery (EOR) Based on Polymer Injection: A Colombian Case Study
Authors: Quintero H. I. , Solorzano P. L. , Barbosa C. , Corredor L. M. , Martinez A. , Feriz E. F. , HernÁNdez R. , Vega S. M. , Carrasca L K. J. , Zapata J. F. , Guerrero C. M. , DueÑAs D. , Rojas C. 
Published: April 2024

Abstract
Chichimene is an oil field located in the Colombian eastern basin. Since 2014, enhanced oil recovery (EOR) through the water injection process has been carried out successfully in part of this field. A polymer injection pilot was carried out over five injection patterns to optimize this process as a promising strategy for polymer-based EOR in challenging reservoir conditions with high temperatures and heavy oil. Polymer injection started in 2015 in the first injection pattern, and it was extended between 2018 and 2019 to five injector wells covering different areas of the oil field. 21.65 MSTB of polymer-augmented water were injected (approximately 7,000 t of polymer). At the end of 2022, the incremental oil production had reached around 4.9 MBbls (Million barrels of oil), and it is expected to increase up to 6.9 MBbls, resulting in a 9.84% incremental oil recovery factor by the end of the water displacement period.
Considerable incremental oil recovery concerning the pilot patterns’ production baseline and notable carbon and energy intensity improvements were observed. Life cycle GHG (Green House Gas) emissions and energy consumptions associated with the crude oil production chain were estimated. Moreover, a suitable calculation tool of carbon footprint and energy intensity related to each stage of crude oil recovery by polymer injection processes was performed. The main contributions of GHG emission and energy consumption for the polymer-based EOR process analyzed were linked to lifting, oil dehydration, water clarification treatment, and Injection systems. The contribution of each stage in the total carbon footprint of crude oil production was calculated for the polymer flooding and compared with oil baseline production.
The carbon footprint of implementing the oil recovery project was calculated for eight years. The results show that the carbon intensity of the crude oil baseline production in the five patterns is close to 20 kg CO2-eq/BO (barrels of oil) on average. Nevertheless, EOR by polymer injection decreases to 19.3 kg CO2-eq/BO. Regarding the energy intensity, the oil baseline production of the five patterns achieved 8.5 kWh/BO; however, the specific energy consumption in the EOR process by polymer injection decreased to 6.7 kWh/BO. The reduction is attributed mainly to energy use optimization in crude oil lifting and enhanced water re-injection with polymer. Furthermore, the carbon intensity reduction could lead to more than 3,200 t of CO2-eq avoided and improve the energy performance of polymer-based EOR by more than 21% concerning the baseline case. Nevertheless, a significant potential GHG emissions reduction of more than 4,000 t CO2-eq could be expected for the whole impact of this pilot project in the Chichimene field.
Experimental Evaluation of Using Treated Produced Water for IOR/EOR: A New Sustainability Frontier
Authors: Ayirala S. C. , AlSaleh S. H. , Al-Yousef Z. , Boqmi A. , Satrawi M. , Wang J. , AlYousef A. A. 
Published: April 2024

Abstract
Huge volumes of produced water are being generated from oil & gas fields worldwide. If this produced water can be treated for reuse as low salinity injection water, it becomes a real game changer to promote sustainability in IOR/EOR projects. In this study, the low salinity treated produced water obtained from zero liquid discharge (ZLD) technology has been used to evaluate the potential of recycled produced water in polymer flooding, gel- and foam-based mobility control processes.
Both static and dynamic tests were conducted at ambient and elevated temperatures using high salinity injection water (HSIW) and treated produced water (TPW). Rheometer was used to determine the viscosity characteristics of sulfonated polyacrylamide polymer solutions at 25oC and 75oC. Static glass bottles tests were conducted with gel solutions formulated using 3,000 ppm sulfonated polyacrylamide and 150 ppm Cr(III) crosslinker at 95oC to determine the gel strength. Foam half-life times were measured to assess the foam stability. Finally, a core flood was conducted to evaluate the incremental oil recovery potential of using treated produced water in polymer flooding.
The results demonstrated that the polymer concentrations are reduced by about 8-times (from 2000 ppm to 250 ppm) to achieve the same viscosity in TPW as HSIW to significantly lower the polymer consumption requirements. The gelation times of the gel in HSIW was one to two hours, while that of the gel in TPW was one to two days. Such considerable elongation of gelation time obtained with treated produced water would favorably deliver the gel deep into reservoir to achieve more efficient conformance improvement. The foam generated using the treated produced water showed at least 10-times longer foam half-life than that produced using the high salinity injection water. The core flood results conducted using 250 ppm polymer in treated produced water showed about 18% total incremental oil recovery after high salinity water injection. These findings clearly demonstrate the promising potential of treated produced water in different IOR/EOR processes to lower chemical concentrations and achieve better mobility control/conformance improvement for higher oil recovery.
This work, for the first time, evaluates the beneficial impact of treated produced water in different mobility control processes involving polymer, gels, and foams. The promising experimental results obtained suggest that the proposed method of using low salinity treated produced water not only increases oil recovery due to synergistic effects, but also establishes a new sustainability frontier in IOR/EOR projects due to produced water recycle/reuse.
Maximizing Steam Distribution Performance to Prevent Forced Steam Release in a Steam-flooded Oil Field
Authors: Reza Muhammad , Johan _ , Riyanto Achmad , Muzammir _ 
Published: April 2024

Abstract
The significant decline of steam generation and distribution demand from 1.3 million barrels of steam per day (BSPD) down to 300-400 MB SPD has reduced steam velocity that triggered the condensation at the end of steam corridors that potentially caused facility integrity issue, mainly corrosion in steam-flooded Duri Field, Indonesia. Starting 2014, this issue has become a concern, and it was addressed by maintaining steam flow at the end of the corridors. The solution was to maintain the injector located the end of corridor (EOC) active, at least injecting steam at 45 barrels steam per day (BSPD), or if there was no active injector at the end of the corridor then the steam must be blown down to atmosphere, which resulted in significant steam waste while the steam constitutes of 40% total operational expenses in steam flood recovery.
A total of 137 steam blowdown sites were identified with a total estimated continuous steam waste of 35,000 BSPD. In average, each site releases steam rate of 260 (BSPD). The strategy to eliminate this steam waste involved integrated evaluation of steam line configuration and active steam injector location. Based on this condition, the resolution to stop steam blowdown would require either reactivating idle or broken steam injector or installing isolation valve. Out of these 137 sites, 47 sites should be resolved by injector reactivation while the remaining 90 sites should be resolved by isolation valve installation.
The steam injector reactivation was started in February 2021 and completed in October 2022. It resulted in steam saving of 12.5 MB SPD. Steam saving has been used to fund the 2022-2023 steam redeployment program that resulted in an increase of 10% oil production in 2022 and 25% in 2023 in the targeted patterns. Meanwhile, the installation of isolation valve is currently in progress. Eighty of the 90 blowdown sites were already closed after installation of isolation valve from October 2021 that resulted in steam saving of 19 MB SPD. This steam saving will play an important role in supporting the steam optimization program where fuel gas supply remained a constraint at that time.
The efforts to eliminate steam blowdown described above have become a standard for steam flood operation especially in Duri Field. Steam corridors would need to either maintain the last injector downstream of the line with injection rate at least 45 BSPD or have an isolation valve installed if it has extension downstream of that injector. This operational design has contributed to conservation of energy safely and preservation of the surface facilities integrity.
Selected Recommended Practices for Increasing the Efficiency and Accuracy of CO2 Sequestration Models
Authors: Benavides J. , Dindoruk B. , Cherry A. , Shukla S. 
Published: April 2024

Abstract
Computer simulation has become widely used to predict the life of CO2 plumes resulting from planned subsurface sequestration schemes. The process is very similar to what has been done in the oil and gas industry for decades, however, while reservoir simulations can be "history matched" to real-world performance, analog data is mostly missing in order to calibrate proposed CO2 project models. Therefore, it is critical to attempt to understand the impact of the various "default" input parameters that are often used in CO2 sequestration models. This paper attempts to highlight potential enhancements in the modeling process that can lead to improved accuracy of predictions.
Many CO2 screening investigations use simple homogeneous block models in place of utilizing more complex realistic geologic models. Comparisons between homogeneous models of porosity and permeability with simple stochastically generated porosity and permeability (having the equivalent average values), could make significant differences. The use of Black Oil models instead of Compositional models will be investigated as a method to improve time efficiency allowing the investigation of more "what-if" scenarios. Guidelines for simple calibration of a black oil model to a compositional model are also presented.
The importance of residual phase trapping as a potential primary trapping mechanism in addition to structural and stratigraphic trapping will be investigated. While including parameters for residual trapping, too often default values in simulation tools are used without recognizing the high variability of these parameters, especially considering the laboratory-based observations for some of them. Several scenarios are presented highlighting the importance of these uncertainties.
End-point values of relative permeability curves can have significant effects on plume geometry and are modeled in various scenarios. Critical Gas Saturation is often overlooked in the modeling process. This value is often defaulted to an unrealistically low value that can lead to "runaway" low saturation plumes when models are run for extended periods (as required by government regulations). Critical gas trapping at the edge of plumes can be an often-overlooked additional trapping mechanism.
Effect of Nano-Silica Synthesized from Rice Husk on Low Salinity Water Flooding
Authors: Wanli Mariam , Suda Shinya , Murata Sumihiko 
Published: April 2024

Abstract
Water flooding is acknowledged as an environmentally friendly and economically feasible approach in Enhanced Oil Recovery (EOR) and remains a subject of fascination for researchers due to its intricate microscopic mechanisms and challenges. This research explores the microscopic effects of rice husk-derived nano-silica on oil recovery in both low salinity water flooding (LSWF) and high salinity water flooding (HSWF) methods. These methods are considered environmentally sustainable and economically viable in Enhanced Oil Recovery (EOR). Initial investigations involved zeta potential and contact angle measurements to assess surface wettability under varying pH and saline concentrations in n-decane environments. The nano-silica, synthesized through thermal and chemical treatments of rice husk, exhibited an amorphous structure with height and width dimensions of 50 nm. Contact angle measurements on muscovite surfaces treated with stearic acid showed that nano-silica positively influences EOR efficiency in both LSWF and HSWF scenarios. Particularly, nano-silica significantly reduced the final contact angle, with the most notable effect observed at pH 6. In LSWF with nano-silica at this pH, the final contact angle decreased by 42% in n-decane, while in HSWF, it decreased by 55%. Moreover, a lower pH resulted in a faster rate of contact angle change, with pH 2 exhibiting the highest rate. These findings contribute valuable insights for advancing water flooding, offering practical implications for the industry by improving oil recovery efficiency and minimizing environmental impact.
Aqueous Ketone Solution for Wettability Alteration in High-Salinity-High-Temperature Carbonate Reservoirs
Authors: Lawal Tesleem , Mirzaei-Paiaman Abouzar , Okuno Ryosuke 
Published: April 2024

Abstract
Enhanced oil recovery (EOR) has been studied for high-salinity high-temperature (HSHT) carbonate reservoirs, but their thermodynamic conditions, brine chemistry, and petrophysical properties tend to pose various technical challenges for both gas- and chemical-based EOR. This paper presents an experimental study of aqueous solution of 3-pentanone for EOR in a carbonate reservoir with a brine salinity of 224,358 ppm at a reservoir temperature of 99°C. The short dialkyl ketone was previously studied as a sole additive to injection brine for rapid wettability alteration in oil-wet carbonate rocks without affecting the water/oil interfacial tension; however, it had not been tested under HSHT conditions. The main objective of this research was to investigate the impact of 3-pentanone on convective oil displacement in oil-wet carbonate rocks under HSHT conditions.
First, aqueous stability was confirmed for mixtures of 3-pentanone and two brines: formation brine (FB) with a salinity of 224,358 ppm and injection brine (IB) with a salinity of 54,471 ppm at reservoir temperature. Quantitative proton nuclear magnetic resonance (1H NMR) analysis was used to determine the solubility of 3-pentanone in FB and IB. Spontaneous and forced imbibition experiments were conducted to assess imbibition enhancement in oil-aged Texas Cream carbonate cores by a solution of 3-pentanone in IB (3pIB) and compared with IB. Afterward, corefloods with oil-aged carbonate cores were performed by injecting IB followed by 3pIB as a tertiary flooding scenario and also by injecting only 3pIB as a secondary flooding scenario. Analysis of the spontaneous imbibition and coreflooding results was assisted by history-matched numerical models where capillary pressure and relative permeability curves were obtained. These data were further used to infer wettability alteration potential of 3-pentanone solution. Because of the markedly different solubilities of 3-pentanone in injection brine (1.1 wt%), formation brine (0.3 wt%), and oil (first-contact miscible), material balance analysis of corefloods was performed to understand the transport of 3-pentanone through varying salinities from injection brine (54,471 ppm) and resident brine (224,358 ppm) while being mixed with in-situ oil.
Spontaneous and forced imbibition tests confirmed the wettability alteration of oil-aged carbonate rocks by 1.1-wt% 3pIB. This was further supported by the slope analysis of temporal recovery data as well as analyzing history-matched capillary pressure and relative permeability data. Coreflooding results showed increased oil production rate and reduced residual oil saturation by 3pIB. Relative permeability data, through Lak and modified Lak wettability indices, also indicated a wettability alteration toward more water-wetness by 3-pentanone solution.
Techno-Economic-Environmental Analysis of CO2 Storage and EOR in an Underdeveloped Field
Authors: Mirzaei-Paiaman A. , Okuno R. , Lawal T. , Sheng K. , Chen C. , Lai I. , Chen S. , Hu L. 
Published: April 2024

Abstract
Geological sequestration of carbon dioxide (CO2) is considered an important technology for mitigating the increasing level of atmospheric CO2. One of the most common methods for CO2 geological sequestration is to inject CO2 into depleted oil reservoirs, which recovers part of the remaining oil that has been unrecovered by simpler methods of oil recovery (e.g., water injection). Previous studies have shown that such CO2-enhanced oil recovery (CO2-EOR) effectively serves as a CO2 sequestration method because a successful CO2-EOR typically results from efficient displacement of resident fluids (water and oil) at thermodynamic conditions such that CO2 of a large density (e.g., 15 mol/L as supercritical CO2) can develop multicontact miscibility with the reservoir oil. Unlike previous studies, this research investigates practical opportunities of CO2 sequestration and CO2-EOR in underdeveloped oil fields, which are not fully depleted with only a few wells.
A realistic compositional simulation model was constructed to represent a carbonate oil reservoir in the Gulf of Mexico Basin. Based on the history-matched simulation model, a series of CO2 water-alternating-gas (WAG) injection strategies was studied by varying operational conditions (i.e., CO2 and water injection rates, production rate, and WAG cycle) and analyzed for oil recovery and carbon storage. A comprehensive economic model was developed to evaluate the net present value (NPV) and used for varying scenarios with, for example, 45Q tax credit and oil price.
Results indicated an inverse relationship between oil recovery and CO2 storage. That is, a displacement pressure above the minimum miscibility pressure (MMP) yielded maximal CO2 storage, but a suboptimal level of oil recovery. This contrasts with the widely known observations for CO2-EOR/sequestration in developed oil fields, where operating above MMP maximizes both oil recovery and CO2 storage. Analysis showed that pressure management using a small number of wells in an underdeveloped oil field can play an important role in optimizing CO2-EOR/storage because oil recovery comes not only from CO2-EOR mechanisms, but also from oil flow potentials induced by the limited number of wells. Under the current economic conditions, NPVs were positive even without factoring in the 45Q tax credit accrual for the case studied. However, the CO2-WAG scenarios with the greatest NPVs were associated with the smallest amounts of CO2 storage, which was not desirable from the environmental viewpoint. A synergistic scenario was possible to increase CO2 storage and NPV together by proper adjustments in carbon tax credit according to oil price.
Machine Learning-Enhanced Forecasting for Efficient Water-Flooded Reservoir Management
Authors: Sinha Utkarsh , Gautam Sandarbh , Dindoruk Birol , Abdulwarith Abdulrahman 
Published: April 2024

Abstract
This study focuses on the crucial aspect of inter-well connectivity (IWC) in waterflooding operations, acting as a key indicator of the efficiency of connections between production and injection wells. Accurately evaluating the effectiveness, the flooding process, and predicting the future production rates heavily rely on understanding IWC. While reservoir simulation is comprehensive, it demands extensive input data. Forecasting production rates with only injection and production rates as inputs presents a formidable challenge. To address this, the Capacitance-Resistance Method (CRM) emerges as a prominent reduced-physics model. Despite its utility, basic CRM may produce inaccurate forecasts due to assumptions like a constant Productivity Index and pseudo-steady state flow.
In this research, we performed a comparative analysis of various models aimed at predicting liquid production rates solely based on water injection rates. Our investigation involved scrutinizing assumptions and identifying deficiencies in each approach, offering a comprehensive understanding of the strengths and limitations associated with modeling waterflood production scenarios. We utilized pure data-driven methods and modern deep learning time series techniques, specifically Recurrent Neural Networks (RNN). Furthermore, physics-informed data-driven methods, namely Augmented Sparse Identification of Non-Linear Dynamics (SINDy) and Augmented Physics Informed Neural Networks (PINNs) method (which were modified from their actual forms to suit specific problems and niche applications) are also utilized. These modern data-driven regression methods are trained under physics-based constraints to limit the degree of freedom during optimization.
Our observations indicated that Augmented PINNs is the best-performing method in terms of accuracy, leading to its selection as our final solution. Our proposed solution demonstrated superior accuracy compared to the established approaches like conventional CRM, offering simplicity, computational efficiency, and scalability for handling large field datasets. Furthermore, we established an algorithm to conduct a health-check for injection and production rates by screening out outliers during training and creating the regression model. This research significantly contributes to enhancing the understanding of IWC and improving the precision of liquid production rate forecasts in waterflooding scenarios.
Milne Point Field Polymer Flood Update and Further Expansion
Authors: Aitkulov Almas , Edwards Reid , Redwine Connor , Cunha K 
Published: April 2024

Abstract
Milne Point Field initiated the first polymer injection pilots on the North Slope of Alaska starting in 2018 and has rapidly progressed to full-field polymer injection within four years. The two initial pilot projects injected at an initial total rate of 6,000 barrels of water per day (bwpd) utilizing five horizontal injection wells. Expansion activities began two years later, in 2020, with the addition of three more polymer injection units. By the end of 2021, two more polymer injection units were added, followed by one in 2022 and another in 2023. Currently, Milne Point operates nine active polymer skids, and the field's polymer injection rate has reached 60,000 bwpd via 50 horizontal injection wells. Targeted reservoirs have average permeabilities ranging from 100 to 1000 md and in-situ oil viscosities ranging from 13 cp to 1300 cp. Both secondary and tertiary floods are being conducted in both greenfield and brownfield development areas, each with varying, yet all promising, results. The highest observed recovery is in a secondary polymer flood pattern at 34% of OOIP with an oil viscosity of 850 cp and water breakthrough after 5 years or 0.2 PV injection. Responses in injection well injectivities have ranged from as low as 0% up to a 50% loss to date and are observed to be correlated with well spacing and total reservoir mobility. The intent of this paper is to: a) provide an update on previously published results from 2022; b) highlight what has been done to date regarding moving from polymer flood concept to near full-field expansion; and c) present observed results with the hope that they can help set expectations for future polymer flood projects.