bluuebunny/crossref_metadata_2025 huggingface dataset:
Chemical EOR Field Support Including Surfactant Blending Studies and Quality Control for Shale and Tight Assets
Authors: Pinnawala Gayani W. , West Scott , Nizamidin Nabi , Alexis Dennis A. , Dwarakanath Varadarajan
Published: April 2024

One of the key components of surfactant related chemical EOR is the surfactant formulation package. After developing a surfactant formulation, delivering it to a target field and assuring similar or better performance is challenging. Since most surfactant formulations contain multiple components, delivering these surfactants as a blend rather than as individual components helps to maintain the correct ratio of components in the surfactant formulation and reduces potential for error during mixing and injection. Thorough quality assurance and quality control (QA/QC) processes support the surfactant blend product performing as designed in field applications. These fundamental steps were applied when deploying surfactant technology which optimizes fracturing fluids for stimulation of shale and tight formations. This paper describes two surfactant formulations developed by Chevron Upstream Labs and successfully deployed in the field. We discuss blending methods, laboratory QA/QC experiments results, field compatibility and aqueous stability test results of mainly two surfactant blends. The paper also describes critical assurance activities that were used to ensure execution excellence.
Modeling Phase Behaviour of Solvents/Water/Heavy Oil Systems Under Reservoir Conditions with the PC-SAFT Equation of State
Authors: Li Yunlong , Huang Desheng , Dong Xiaomeng , Yang Daoyong
Published: April 2024

As for conventional cubic equations of state (CEOSs), they find their limits in precisely predicting phase behaviour in systems featuring a broad spectrum of molecular sizes, especially liquid densities. Based on the perturbation theory, the statistical associating fluid theory (SAFT) has been used as a standard approach to describe how complex fluids and fluid mixtures with a substantial disparity in molecular sizes behave; however, its application is still limited in heavy oil-associated mixtures due to fundamental and technical challenges. In this work, a perturbed-chain (PC) SAFT equation of state (EOS) has been developed to characterize heavy oil-associated systems containing polar components (e.g., dimethyl ether (DME) and water) and non-polar components (e.g., CO2 and N2) with respect to their phase behaviour and physical properties. Experimentally, constant composition expansion (CCE) tests were meticulously conducted to measure saturation pressure (Psat), phase volume, and phase compositions for CO2/heavy oil, N2/heavy oil, and DME/heavy oil systems in the absence and presence of water, spanning a range of pressure up to 20 MPa and temperature up to 433.2 K. Theoretically, a PC-SAFT EOS model together with temperature-independent binary interaction parameters (BIPs) is integrated to reproduce the measured Psat and other physical properties of the aforementioned systems. It is experimentally found that addition of water into each of the aforementioned systems will increase its Psat compared to that without water. By characterizing heavy oils as four pseudocomponents (PCs), the density (ρ) of the aforementioned systems can be accurately predicted with the root-mean-squared relative error (RMSRE) of 1.84%. Then, the BIPs for each binary pair of the aforementioned systems are obtained by minimizing the discrepancy between the measured Psat and the calculated ones. The proposed model shows its superior performance over the widely used CEOS (i.e., Peng-Robinson EOS) with an RMSRE of 2.93% for the predicted Psat of the aforementioned systems. The theoretical model proposed in this study excels to reproduce the experimentally measured phase behaviour and physical properties under reservoir conditions, allowing us to accurately evaluate and optimize the hybrid steam-solvent processes in a heavy oil reservoir.
Establishing Target Oil in a Major Oil Field Under Gas Assisted Gravity Drainage
Authors: Valdez R. , Pennell S. P.
Published: April 2024

Technical analysis and data gathering methods are presented for establishing the lowest depth of development in a shallow, highly fractured San Andres dolomite field currently being developed under Gas Assisted Gravity Drainage (GAGD). Expanding development deeper is critical for extending the field life and managing long term drilling and CO2 injection. The field underwent a first phase of GAGD from 1992 through 2000 restoring the oil-water contact down to the discovery depth of +1050 feet above sea level (ASL).

Several steps were taken to quantify the transition zone target for expansion including field wide data gathering, areal performance analysis, and a dedicated pilot or demonstration project. Data gathering included saturation logging of several existing open-hole observation wells. Pilot hole drilling and logging prior to horizontal well re-drills was also utilized. Dimensionless performance analysis and modeling were used to compare both areal and vertical variations in development. Finally, an extensive pilot project was initiated in 2021 which included a de-watering test, sponge coring and & laboratory analysis, horizontal drilling and repeat saturation logging to demonstrate the feasibility and commerciality of deeper development.

Logging showed oil saturations as high as 50% down to a range of depths from +1000 to +990 feet ASL and rapid declining saturation to the imbibition free water level of +960 ASL. Deeper rock properties also showed similar reservoir porosity, permeability and fracture intensity as the shallower horizons. Performance analysis showed varied oil response closely tied to fracture intensity and oil column thickness (OCT). The demonstration pilot had several key findings: 1) de-watering of the reservoir to expand the GAGD process and gas cap could be established within several months, 2) the lowest depth of mobile (or target) oil is +990 feet ASL, 3) horizontal wells drilled to a depth of +990 feet ASL showed two distinct oil responses: a) oil production from reconnecting the oil column plus additional drained oil from contact lowering and b) 100% water production for several months prior to oiling in from contact lowering. The two distinct responses also coincided with OCT in the fractures and oil-water contact level prior to deepening. The combined response was observed in the Eastern part of the pilot with 20 foot OCT and OWC at +985 feet ASL versus the Western part of the pilot at 5 foot OCT and OWC varying from +1005 to +990 feet ASL.

Prior to field testing development deeper into the transition zone, GAGD core laboratory experiments showed remaining oil saturation as low as 15% could be achieved. The intensive data gathering and field demonstration showed incremental reserves could be achieved. This has resulted in extending the drilling program several more years, lowering of the contacts further and additional oil recovery.
The Effect of Polyethylene Oxide on Residual Oil Saturation of Low Permeability Carbonates
Authors: Laudon S. , Balhoff M. , Mohanty K.
Published: April 2024

The objective of this paper is to investigate the transport and incremental oil recovery associated with Polyethylene Oxide (PEO) compared to Hydrolyzed Polyacrylamide (HPAM) through a series of corefloods in low permeability carbonate cores for use in enhanced oil recovery (EOR). Recent studies have brought attention to PEO's improved injectivity in low permeability carbonate reservoirs compared to acrylamide-based polymers offering a promising alternative (Mejia et al., 2022a; Mejia et al., 2022b; Trine et al., 2022). Five two-phase experiments were conducted in Indiana limestone cores (permeability <100 mD) with PEO and HPAM of similar molecular weights (4 MM Dalton) and viscosity; they were designed to measure incremental oil recovery for both polymers. Tracer tests were completed to determine heterogeneity. Brine was displaced by a 50-cP oil, and initial oil saturations averaged 55.8%. The oil was displaced initially with a waterflood for 3-5 pore volumes. The waterflood, on average, recovered 60.7% of original oil in place (OOIP). Oil cut was consistently zero at the conclusion of the waterflood suggesting the cores were at or near residual oil saturation. The polymer flood followed the waterflood for three pore volumes or until oil cut was zero. HPAM was injected in the first two experiments, and PEO was injected in the final three. When HPAM was injected, oil production in terms of OOIP from the polymer flood was minimal (average 2.2%) which was expected since oil saturation was presumed near residual. However, in the experiments when PEO was injected, oil production from the polymer flood averaged 13.5%, suggesting that residual oil saturation was decreased by the polymer. PEO was consistently shown to produce more oil compared to HPAM. This work suggests that PEO may result in higher oil recoveries and reduced residual oil saturation under certain conditions.
Investigating Imbibition Rate and Oil Recovery Mechanisms from Fractured Formations by Hybrid EOR Approaches
Authors: Kashiri Razieh , Bukayev Azamat , Pourafshary Peyman
Published: April 2024

Enhanced Oil Recovery (EOR) methods play a crucial role in producing significant volumes of trapped hydrocarbons within fractured oil-wet reservoirs. These methods aim to modify the fluid-rock interactions, reduce interfacial tension, and alter the wettability of the reservoir to increase the total oil recovery. Imbibition is the fundamental mechanism for fluid transport between matrix and fracture within fractured formations. Different EOR mechanisms affect the imbibition by altering capillary-related parameters such as wettability and interfacial tension. The rate of spontaneous imbibition is different during different EOR techniques, such as surfactant flooding, low salinity water injection, and hybrid methods. The effect of the type of capillary modifications on the imbibition rate was studied in this work.

This study delves into a series of spontaneous imbibition tests aimed at scrutinizing imbibition rates across diverse EOR strategies: low salinity water flooding, surfactant flooding, and hybrid EOR approaches for fractured reservoirs. The effect of parameters such as pH was also investigated. The oil recovery due to the alteration in capillary force during the spontaneous imbibition was recorded, and the imbibition rate was analyzed based on recovery/square root of time data. Furthermore, an array of parameters, including interfacial tension, ion composition, and pH, were measured and studied to investigate the mechanisms behind varied imbibition rates. The impact of imbibition rates on the forced imbibition process was also assessed, striving for a comprehensive understanding of imbibition dynamics during EOR strategies.

The results showed a significant difference in imbibition rates between standalone low salinity water flooding imbibition and surfactant solutions. Our studies demonstrated that the rate of capillary pressure alteration due to changes in interfacial tension surpasses the rate of alteration caused by shifts in the wettability state. Application of the hybrid method enhances the imbibition rate, which affects the oil recovery from a fractured formation. Under high pH conditions, the imbibition rate exhibited a low initial rate, followed by substantial increases by the injected water dilution. Conversely, under acidic conditions, the trend was reversed due to the activation of different low salinity water-related recovery mechanisms.

The significance of this investigation goes beyond the laboratory setting, extending its impact to the practical realm of designing processes within fractured reservoirs. By illuminating the complicated interplay between pH, water salinity, capillary, and imbibition rates, this study serves as a vital base for designing hybrid approaches that optimize EOR techniques tailored to fractured reservoirs’ complexities.
Evaluation of Electroassisted Carbonated Water Injection (ECWI) in a Tight Reservoir: Outstanding Performance of Enhancing Oil Recovery and CO2 Storage Capacity
Authors: Jia Zejiang , Ning Zhengfu , Lyu Fangtao , Yang Daoyong
Published: April 2024

Traditionally, carbonated water injection (CWI) finds its low injectivity in a tight reservoir with a low efficiency and slow effectiveness. By combining a direct current (DC) electric field with the CWI, i.e., the electroassisted CWI (ECWI), we conducted a series of experiments to evaluate the ECWI performance in a tight reservoir and identify the key underlying recovery mechanisms. Experimental results show that early adopting the ECWI in a tight sandstone reservoir results in the highest oil recovery up to 61.9%, compared to those of 51.2% for the CWI and 41.3% for the conventional waterflooding. During an ECWI process, a voltage of 10 V achieves the highest oil recovery, but that of 15 V has the best water injectivity and CO2 storage capacity. It is found that the underlying recovery mechanisms result from both electroosmosis and enhancement of carbonized water-rock reactions induced by a DC electric field. For a tight reservoir, the ECWI has the advantages of significantly increasing water injectivity, oil production rate, and CO2 storage capacity. By introducing two new indicators to respectively evaluate the water injection performance and energy consumption, the ECWI is found to perform moderately well at a low voltage in an energy-saving and financially viable manner.
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

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

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

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

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

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

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

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

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

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.
A Holistic EOS Model for Characterization of Northern Kuwait Extra-Heavy Oil Mixed with Liquid Solvents
Authors: Al-Murayri M. T. , AlFadhli A. , Baroon B. , Soltani A. , Garifullin R. , Rousseau D. , Bekri S. , Delamaide E.
Published: April 2024

Liquid solvent injection is envisaged for extra-heavy oil extraction from the Lower Burgan Abdali (ADBG) reservoir in North Kuwait. This is a deep reservoir (9000 ft) where steam-assisted EOR methods are associated with a wide array of tehno-ecnomic challenges. This paper presents a methodology for creating a holistic Equation of State (EOS) describing the thermophysical properties of the selected solvents, extra-heavy oil, and their blend at different conditions. Such a model is essential for studying subsurface-to-surface variations in the mixture properties to assess the viability of solvent-assisted production.

Representative extra-heavy downhole oil samples and two multi-component liquid solvents were investigated by performing high-pressure laboratory testing. Fluid density and viscosity were measured under varying conditions. A cubic EOS model was built to reproduce the extra-heavy oil lab-based PVT data. Simultaneously, another EOS model was developed for the two solvents. These EOS models were merged into a unified model to ensure pseudo-component overlap representation and lumping of the components for a correct extra-heavy oil and solvent mixture prediction. The viscosity modelling challenges and solutions for extra heavy-oil (with and without minor dissolved gas) and solvent mixtures were also investigated in detail.

Lab evaluation using representative downhole oil samples (with minor dissolved gas) showed significant differences in the molecular weight of C36+ and the measured viscosity. A single EOS model was created using multi-fluid regression. The heaviest fraction had to be split into two pseudo-components coexisting in both samples but at different molar fractions. The components existing in both extra-heavy oil and solvent were lumped to avoid overlapping. It was demonstrated that the resulting EOS model can accurately reproduce the phase and volumetric behaviour of extra-heavy oil, solvent and their blend at different pressures and the reservoir temperature. Furthermore, it was noticed that the modified Lohrenz-Bray-Clark (LBC Heavy Oil) can predict the viscosities at isothermal conditions. For non-isothermal conditions, the viscosity of each pseudo-component is to be calculated at different temperatures in a tabulated format.
Quantitative Characterization Method for Remaining Oil Distribution in Heavy Oil After Multi-Cycle Steam Huff and Puff Based on CT Scanning
Authors: Zheng Haoyu , Hou Jian , Du Qingjun
Published: April 2024

Steam huff and puff is an important development method for heavy oil reservoirs. An accurate description of the remaining oil distribution after steam huff and puff is crucial for reservoir development. In this study, an experimental setup is used to simulate the multi-cycle steam huff and puff process more realistically. The occurrence state and distribution of remaining oil after different cycles of steam huff and puff are investigated. CT scanning is conducted after the first, fourth, and seventh cycles. Based on characterization parameters such as shape factor, contact ratio, and Euler number, the microscopic remaining oil is classified into network remaining oil, cluster remaining oil, film remaining oil, and isolated droplet remaining oil. The volume proportions of different types of remaining oil of different cycles of steam huff and puff are compared. The viscosity of the heavy oil used in the experiment is 560 mPa·s (25°C). The results indicate that as the number of cycles increases, the volume proportion of network remaining oil decreases, while the volume proportions of cluster, film, and isolated droplet remaining oil increase. From the first to the seventh cycle, the volume proportion of network remaining oil decreases by 34.11%, while the volume proportions of cluster, film, and isolated droplet remaining oil increase by 12.87%, 14.48%, and 6.76% respectively. The oil phase transitions from a continuous distribution to a discontinuous distribution. With an increase in the number of cycles, the water saturation increases, and the distribution of remaining oil becomes more dispersed. The results of this research guide the subsequent production of heavy oil.
Evaluation of Production and Injection Profiles by a Combination of Thermal Anemometry Technology, Spectral Noise Logging, and Numerical Temperature Modeling in Horizontal Oil Producers and Water Injectors
Authors: Dolgikh A. , Shubenok D. , Chinchayan G. , Al Bahri B.
Published: April 2024

The limitations of conventional spinner-based methods of production logging in horizontal wells, such as low rate, oil viscosity, wellbore trajectory, and debris, have driven the development of non-mechanical technologies over the past two decades. The paper illustrates an innovative combination of several spinnerless methods as a comprehensive approach for reservoir performance evaluation based on recent field cases. The ability of a simultaneous evaluation of the fluid flow rate inside the wellbore as well as through the formation allows a complete assessment of well-reservoir performance.

For the wellbore fluid flow evaluation, the thermal anemometry method was proposed. The technique allows the detection of the fluid flow zones and the calculation of fluid velocity based on temperature changes of the permanently heated thermal anemometer sensor. The successful field tests and cases of the technique application were published in several technical papers [1, 2], where the consistency of thermal anemometry data with spinner results was proved. The current technical paper provides the fluid flow velocity calculation methodology based on the laboratory and field calibrations of the thermal anemometry tool.

Spectral noise logging (SNL) and numerical temperature modeling were proposed for the reservoir fluid flow evaluation. The mentioned methods were also successfully implemented over the last decade and confirmed by the number of published technical papers [3, 4]. For the spectral noise logging the new-generation split-channels tool was used. For the numerical temperature modeling the high-resolution temperature data acquisition was used to derive the quantitative production/injection profiles related to reservoir flow.

The paper demonstrates the results of several case studies where the combination of the spinnerless methods was applied: one oil producer and two water injectors. For oil producers, the cause of the high water cut was determined by the localization of water inflow zones. For water injectors, the evaluation of the water injection conformance across the reservoir section was resolved by calculating the detailed injection profiles.

The complex results of reviewed case studies emphasizing the wellbore-oriented and reservoir-oriented flow profiles give a broader understanding of the production/injection processes. The paper also discusses the limitations of each technique, as well as the advantages and complementarity of the comprehensive approach in general. One of the advantages discussed in the paper is a lack of mechanical elements in tools, making the combination of spinner-less methods a reliable alternative to conventional spinner-based methods for production logging in horizontal water injectors and oil producers.
The Effect of Different Miscible Degrees on the Migration of Diversified Phase Zones in the Tight Reservoir
Authors: Liu Xiliang , Chen Hao , Cheng Weiming , Xu Chenghao , Zuo Mingsheng , Gao Shuaiqiang , Wu Yi , Liu Haipeng , Qi Xinyu , Brahim Mahaman Sidi
Published: April 2024

Both laboratory tests and pilot wells have demonstrated the significant potential of CO2 as an EOR medium. Due to the weak pressure conduction and mass transfer of the CO2-oil system, multiple zones between the injection well and production well are generated in the ultra-low permeability reservoirs. This work aims to explore the characteristics of multiple zones and mechanisms of CO2-EOR, combining the experimental results, core-scale, and field-scale simulation.

Long core displacement experiments were conducted under different miscibility pressures with production gas assayed using gas chromatography. When the core-scale simulation matched with the experimental results, the four CO2 fronts, which were used to distinguish different zones, were defined based on pressure, interfacial tension, and CO2 concentration along the long core. The distribution of five zones was upscaled to the field-scale model after the history matching of pilot wells. The final step was to evaluate the value of the miscible zone range, utilization factor of CO2 injection, oil recovery, and CO2 storage efficiency during the CO2 injection process.

Results show that the boundary between the original oil zone and the oil transition zone exists at the CO2 component front, where the CO2 concentration is zero. Additionally, the location of the CO2 component front does not overlap with the contact interface of CO2-crude oil, meaning that the dissolution effect of CO2 in the oil transition zone results in the CO2 component front moving farther. Besides, when the formation pressure is higher than the minimum miscibility pressure (MMP), the distance between the CO2-effective phase front and the CO2-effective component front further expands as the pressure increases, enlarging the miscible zone range. The pressure accumulates around the injection well because of slow pressure conduction. When the average formation pressure reaches 1.1 MMP, the miscible zone range is enlarged by 2.7% higher than that of the near miscible flooding (0.92 MMP), leading to a higher rate of oil recovery by 8.6% and a utilization factor of CO2 by 0.14t/t.

It is for the first time that the range of five zones and the characteristics of four CO2 fronts migration is assessed, furnishing an in-depth understanding of the complicated mechanisms and phase behavior in CO2 EOR in the ultra-low permeability oil reservoir. This work contributes to providing significant information for designing an economic and environmental CO2 flooding strategy and is significant in the improvement of oil recovery and the reduction of CO2 emission.