bluuebunny/crossref_metadata_2025_split huggingface dataset:
Field Test of Nitrogen Injectivity as a Method to Reduce the Uncertainties for the Miscible WAG Project
Authors: Mukhametzyanov Iskander , Glavnov Nikolay , Akchurin Ruslan , Penigin Artem , Vershinina Maya 
Published: August 2020

Abstract
One of the key uncertainties associated with miscible water-alternating-gas (WAG) projects is the well injectivity. The underestimation of productivity indexes of the injectors always results in the loss of additional oil production. This paper describes the current solutions and approaches to the design and implementation of nitrogen injection pilot into the injection well on the remote oil field in order to adjust the technical and economic indicators of miscible WAG process.
First of all, according to the probability distribution of permeability on the field, the well selection process was carried out. At the second stage, due to the high capital costs of pipeline construction, a gaseous agent(nitrogen) that may be transported in the liquid form was selected. Then, for each well, based on the simulation models, the required nitrogen resources were estimated to ensure that the steady-state flow was achieved. The final stage of pilot works design includes the selection of the measuring instruments to record injection rates, pressures (BHP, THP), temperatures in the well and production logging.
The main result of the pilot injection of the nitrogen into the reservoir was the confirmation of the key success criteria: productivity indexes and gas injectivities, tightness of the cement in the wells and the possibility of displacing the water from the wellbore to the reservoir at the current tubing head pressure. During the analysis of the results, the simulation model which were designed to calculate the predicted effects of the implementation of the miscible WAG on the field were adjusted to match pilot tests results. Application of the results of pilot injection allowed to increase a duration of the water injection cycles without loss of the gas injection volumes and gas utilization levels. The duration change in the operating cycles of the WAG, in turn, makes it possible to increase the displacement efficiency, which leads to an increase of the cumulative oil production by 10%.
Based on the key uncertainty management studies: laboratory studies to study the processes of oil and gas interaction (slim-tube test, asphaltenes precipitation test), special core analysis, pilot gas injection and economical evaluation, a decision was made to launch a miscible WAG project in the oil field.
In this paper, it is shown that the implementation of a nitrogen injection pilot allows us to reduce the uncertainties in injectivity for wells originally constructed not for gas injection. Correct analysis of the results gives a deeper understanding of the processes occurring in the injection wells during the transition period from water to gas injection. This field test of nitrogen injectivity gives a good opportunity for the full filed WAG project implementation.
Optimizing Tight Oil Assets on Water Flood Utilizing Polymer Gel Technology; A Cost-Effective Approach with High Rate of Success
Authors: Roostapour Alireza , Qaid Mohammed , Tudor Eric , Lantz Mike 
Published: August 2020

Abstract
Thanks to the advancements in and convergent of the two technologies of horizontal well drilling and hydraulic fracturing, the oil production from tight formations has become possible and economic. While hydraulically fractured horizontals wells (HFHW) have increased the productivity of these reservoirs, these wells typically see a sharp decline in hydrocarbon rate due to tight nature of these reservoirs.
Operators have improved oil recovery methods in these formations with the successful application of the secondary recovery method of waterflooding. This combination of HFHW and waterflooding has primarily been implemented in Canadian tight oil formations such as the Canadian Bakken Shale, lower Shaunavon, Viking, Belly River and Cardium. With the application of waterflooding on these HFHW, the one issue that operators are facing is the management of quick water breakthrough due to well to well communication through the network of induced or natural fractures resulting in poor sweep efficiency of waterfloods.
Conformance improvement using polymer gel technology, a polymer and a polymer specific cross-linker, has been a common practice in conventional assets for 30 years. The polymer solution is mixed with the crosslinker on the surface and the mixture becomes more viscous (due to the reaction between polymer and crosslinker) as it is pumped downhole and into the reservoir. The application of polymer gel technology in unconventional tight oil water floods requires a new approach and is most successful when approached in a systematic way starting with proper diagnosis and candidate selection followed by engineering design and field execution. After candidate selection and diagnosis of communication between wells, a treatment design is put together based on the level of communication as measured by the transit time between the two wells. The conformance treatment is implemented by bull heading the mixture of polymer and crosslinker and sequentially increasing the gel strength by increasing polymer concentration at fixed polymer to crosslinker ratio. The idea is to build pressure continuously throughout the treatment, an indication of polymer gel filling up the path of communication.
A new application for gel conformance technology, in tight oil waterfloods, as a cost-effective solution, to address the well to well communication and improve sweep efficiency is discussed in this article. Relatively smaller size and lower strength of gel, compared to the typical applications, makes the application of polymer gel in HFHWs unique and very effective. This paper will review multiple campaigns in Canadian Bakken from 2016 to 2018 and discuss the rate of success, incremental oil produced and longevity of these treatment. Opportunities to further optimize these treatments and the pitfalls have been recognized and discussed.
Two-Phase Flash for Tight Porous Media by Minimization of the Helmholtz Free Energy
Authors: Achour Sofiane H. , Okuno Ryosuke 
Published: August 2020

Abstract
Thermodynamic modeling of phase behavior is one of the most fundamental components in the study of enhanced oil recovery by gas injection. Robust algorithms exist for multiphase equilibrium problems with no capillary pressure as commonly used in compositional reservoir simulation. However, various convergence problems have been reported even for simple two-phase split problems in the presence of capillary pressure by using the traditional algorithm based on minimization of the Gibbs free energy.
In this research, the phase-split problem with capillary pressure is formulated by using the Helmholtz free energy for a given temperature and total volume. The algorithm is based on the successive substitution (SS) for updating K values, which is coupled with the volume update by using the pressure constraint equation. The robustness of the SS algorithm is improved by using the convexity information of the Helmholtz free energy.
Case studies present phase-split problems with capillary pressure by using the developed algorithm and highlight several advantages of using the Helmholtz free energy over the Gibbs free energy. The improved robustness comes mainly from the involvement of a single energy surface regardless of the number of phases. The pressure variability that occurs during the phase-split calculation with capillary pressure is inherent in the Helmholtz free energy in volume space.
A Critical Review of Capillary Number and its Application in Enhanced Oil Recovery
Authors: Guo Hu , Song Kaoping , Hilfer Rudolf 
Published: August 2020

Abstract
Capillary number (Ca), defined as dimensionless ratio of viscous force to capillary force, is one of the most important parameters in enhanced oil recovery (EOR). The ratio of viscous and capillary force is scale-dependent. At least 33 different Cas have been proposed, indicating inconsistencies between various applications and publications. The most concise definition containing velocity, interfacial tension and viscosity is most widely used in EOR. Many chemical EOR applications are thus based on the correlation between residual oil saturation (ROS) and Ca, which is also known as capillary desaturation curve (CDC). Various CDCs lead to a basic conclusion of using surfactant to reduce interfacial to ultra-low to get a minimum ROS and maximum displacement efficiency. However, after a deep analysis of Ca and recent new experimental observations, the traditional definition of Ca was found to have many limitations and based on misunderstandings. First, the basic object in EOR is a capillary-trapped oil ganglia thus Darcy's law is only valid under certain conditions. Further, many recent tests reported results contradicting previous ones. It seems most Cas cannot account for mixed-wet CDC. The influence of wettability on two-phase flow is important but not reflected in the definition of the Ca. Then, it is certainly very peculiar that, when the viscous and capillary forces acting on a blob are equal, the current most widely used classic Ca is equal to 2.2* 10−3. Ideally, the condition Ca ∼ 1 marks the transition from capillary dominated to viscous-dominated flow, but most Cas cannot fulfill this expectation. These problems are caused by scale dependent flow characterization. It has been proved that the traditional Ca is of microscopic nature. Based on the dynamic characterization of the change of capillary force and viscous force in macroscopic scale, a macroscopic Ca can well explain these complex results. The requirement of ultra-low IFT from microscopic Ca for surfactant flood is not supported by macroscopic Ca. The effect of increasing water viscosity to EOR is much higher than reducing IFT. Realizing the microscopic nature of the traditional Ca and using CDCs based on the more reasonable macroscopic Ca helps to update screening criteria for chemical flooding.
Improving Recovery in the Yates Field Using Dynamic Feedback Loop based on Physics-Informed Artificial Intelligence
Authors: De Bruyker Dirk , Kosut Robert , Valdez Raul , Haymes Seth , Schoeling Lanny , Petro Miroslav , Weiner Douglas , Joseph Alfred , Lee Jun Kyu , Emami-Naeini Abbas , Ebert Jon , Ghosal Sarbajit 
Published: August 2020

AbstractWe present a robust control system and methodology for physics-informed artificial intelligence (PAI) used to optimize and improve oil recovery, demonstrated in the Yates Field operated by the Kinder Morgan CO2 company. The system consists of a robust control system (referred to as Dynamic Feedback Loop, or DFL) equipped with novel hydrocarbon sensors that measure oil concentration and other parameters continuously and simultaneously on a set of producing wells. The goal of this system is to optimize operational parameters (e.g. choke valve settings, injection rates) to reach specific target metrics of production (e.g. maximizing produced oil while minimizing produced gas).The key element of our approach is the use of a multi-layer artificial neural network (deep neural network, or DNN, to be specific) that extracts physics-based parameters from the real-time measurements and predicts relevant parameters of the DFL control system. DNNs are prone to overfitting in training, making them ineffective in unfamiliar or challenging situations outside the training dataset. To overcome this problem, we have developed a physics-informed robust neural network technique, where the reservoir physics and sensor data are used to train DNN representations of the key physical parameters. Typically, only simplified physical models are developed using available geostatic or historical production data. Also, due to the dynamic nature of these systems, the accuracy of the models often changes over time. To improve predictive capability of the model, we combine the DNN with the system-theoretic robust control concepts based on physics with a model uncertainty formulation. The concept was first validated using a combination of simulations, isolated sensor data and analyses based on sets of historic production data.A study using historic production data on Kinder Morgan's Yates Field Unit (YFU) 4045 Pilot (3 producing wells) indicates application of the DFL system results in an increase in cumulative production of up to 35% per year, compared to what is obtained through a traditional (fixed-point) control system. Currently, the DFL is being field-tested on a different set of wells in the Yates Field, instrumented with the novel hydrocarbon sensors that generate continuous and simultaneous production data.
Comprehensive Experimental Study of Huff-n-Puff Enhanced Oil Recovey in Eagle Ford: Key Parameters and Recovery Mechanism
Authors: Min Byeungju , Mamoudou Sidi , Dang Son , Tinni Ali , Sondergeld Carl , Rai Chandra 
Published: August 2020

Abstract
Huff-n-puff gas injection enhanced oil recovery has received increased attention especially in the unconventional plays like the Eagle Ford, where oil recovery is as low as 5 - 10%. An increase in 1% of recovery could realize a potential of 2.3 billion barrels of oil, which has an enormous economic value. Through a laboratory investigation of huff-n-puff conducted on preserved Eagle Ford samples; we evaluate different factors that can affect the recovery performance such as minimum miscibility pressure (MMP), surface area, soaking time, injection pressure, composition of injection gas and injection gas rate. In addition, different recovery mechanisms such as a vaporization (concentration gradient) and a miscible flowback (pressure gradient) were also investigated.
Two sets of experiments were conducted utilizing a high-pressure chamber: one with Eagle Ford oil, providing MMP values using a VIT technique and vaporization test with different soaking times (2 days, 4 days, and 6 days). Another set of experiment were performed with preserved Eagle Ford samples. Different types of gas: carbon dioxide (CO2,) methane (C1), ethane (C2), C1:C2 (72:28) mixture, C1:C2 (95:5) mixture, and field gas were injected at various pressures from 1000 psi below MMP, MMP to 1000 psi above MMP with various soaking time of (1 hr, 3 hr and 6 hr). Nuclear Magnetic Resonance (NMR), HAWK pyrolysis, isothermal nitrogen adsorption tests (BET), Mercury Injection Capillary Pressure (MICP) and Gas Chromatography (GC), were performed to qualitatively and quantitively monitor the changes in Eagle Ford hydrocarbons recovered from shale samples.
The experimental results demonstrated that: 1) as methane concentration in gas is increased, MMP also increased, 2) residence time (soaking time + production time) controls the recovery, 3) injection pressure determines the fraction of hydrocarbons mobilized, 4) surface area variation studies showed that the samples with higher surface area have greater recoveries, 5) ethane showed the best performance of all the gases tested (40% recovery). CO2 performed the second best (32%). C1:C2(72:28) mixture and field gas exhibit the similar efficacy in recovery (24% and 21%). C1:C2(95:5) mixture showed the worst recovery (11%). 6) high injection rate yielded better recovery (37%) than low injection rate (24%), 6) Increase in pore surface area by factor of 2.5 was observed from the opening of small pores and pore- throat on post huff-n-puff sample. In addition, recovery mechanism study shows that miscible flow back mobilized hydrocarbon up to C30, vaporization at 1000psi above MMP mobilized hydrocarbon up to C23 and vaporization 1000psi below MMP mobilized hydrocarbon up to C15. The results also indicated that longer soaking times increased diffused oil concentration in vapor phase.
Planning for Large Scale ASP Flood Implementation in Mangala Oil Field
Authors: Pandey Amitabh , Jain Shakti , Prasad Dhruva , Koduru Nitish , Raj Rahul 
Published: August 2020

Abstract
A highly successful ASP flood pilot has been conducted in the Mangala oil field in the Barmer basin located in the Rajasthan state of western India. The field which contains paraffinic oil with ~15cP oil viscosity is currently under full field polymer flood. The field has a STOIIP of ~1300 mmbbls and has already achieved more than 30% recovery factor in 10 years of production since coming online in 2009. The ongoing polymer flood is performing satisfactorily and the objective of large scale ASP implementation is to arrest the projected production decline and improve the ultimate recovery from the field.
A normal 5-spot ASP pilot was conducted in the topmost reservoir of the field during the year 2014-15. The ASP formulation contained surfactant combination of high molecular weight TSP-EO-PO-sulfate and high carbon number ABS. The pilot was highly successful with estimated incremental recovery by ASP injection of more than 20% of the pilot STOIIP over polymer flood. The water-cut in the pilot dropped from more than 90% to levels of 20-30%. Comprehensive modeling of the corefloods and the pilot performance helped to calibrate the chemical flood simulator which was used for the development of large scale implementation concept. Various produced fluid related studies helped to design the surface facility concept. Given that large volumes of chemicals will be used, work is ongoing to define the chemical procurement strategy.
The sector level modeling studies indicated that closer spacing improves the response time and helps to maximize the reserves in a given time frame. The study identified that infill drilling to convert the existing 5-spot polymer flood pattern into a direct line drive pattern is an optimal concept. The modeling study in combination with the surface facility considerations helped to design the expansion approach. The slug size sensitivity suggested to use slightly bigger pore volume of ASP slug in the range of 0.4-0.6 PV taking into consideration heterogeneity uncertainties attached with flooding multiple sands in fluvial deposition. The facility studies using the pilot information and additional lab studies helped to design the surface facilities concept. Requirement of produced water reinjection and water softening of the water for ASP injection in combination with anticipated scaling and produced fluid separation issues posed significant challenges.
The paper will present the development journey of a very large scale ASP implementation concept in the Mangala field with focus on modeling at core/pilot/sector/full-field scale. The uncertainties associated with modeling of complex mechanism of the process will also be discussed. A high level surface facility concept and chemical procurement strategy will also be presented. This would be one of the few case history of a very large scale ASP implementation planning project.
Phase Behavior and Minimum Miscibility Pressure of Confined Fluids in Organic Nanopores
Authors: Song Yilei , Song Zhaojie , Liu Yueliang , Guo Jia , Bai Baojun , Hou Jirui , Bai Mingxing , Song Kaoping 
Published: August 2020

Abstract
Phase equilibrium of shale fluid is highly disturbed due to liquid adsorption and capillary pressure in densely-developed organic nanopores. And the miscibility phenomenon between gas and oil is also changed during gas injection for enhanced oil recovery (EOR). Therefore, it is imperative to develop a general framework of theoretical models and algorithm to investigate the effect of pore proximity on phase behavior and miscibility of confined fluids in shale formations.
In this study, first, an improved vapor/liquid equilibrium (VLE) calculation model is presented to calculate the phase behavior of confined fluids based on our modified Peng-Robinson equation of state (A-PR-EOS) which can reflect the effect of adsorption. The capillary pressure across the interface and the critical property shift of pure component are also taken into account. An improved Young-Laplace equation is utilized to simulate capillarity and the shifted critical properties can be obtained using the A-PR-EOS. Then, a prediction process for the phase behavior of a quaternary mixture (CO2, CH4, n-C4H10, n-C10H22) is performed, and the results are compared against the experimental data from previous literature, yielding an average error of 1.29%. Results indicate that the presence of nanopore confinement could decrease the density difference between the liquid and vapor phase of the quaternary mixture, and thus induce the reduction of interfacial tension (IFT). As pore size becomes smaller, the IFT decreases rapidly, especially when the pore radius (Rp) is less than 20 nm. Furthermore, the vanishing interfacial tension (VIT) algorithm and the modified VLE procedure are applied to determine the minimum miscibility pressure (MMP) of Bakken shale oil with CO2. The MMP is reduced from 20.2 MPa at 50 nm pores to 17.5 MPa at 20 nm pores. Hence, the reduction of pore size leads to a decrease in MMP, i.e. the CO2 and the reservoir fluid could reach miscibility at a lower pressure, which is beneficial for CO2-EOR.
The proposed model could provide a consistent description of fluid phase behavior over the whole range of pore sizes in the Bakken, and could be applied to guide the development of shale hydrocarbon reservoirs, such as reserves and production estimates.
CO2 Foam Field Pilot Design and Initial Results
Authors: Alcorn Zachary Paul , Føyen Tore , Zhang Leilei , Karakas Metin , Biswal Sibani Lisa , Hirasaki George , Graue Arne 
Published: August 2020

Abstract
This paper presents the field design, monitoring program, and initial results from a CO2 foam pilot in East Seminole Field, Permian Basin, USA. Tertiary miscible CO2 injection has suffered from poor areal sweep efficiency due to reservoir heterogeneity and an unfavorable mobility ratio between CO2 and reservoir fluids. A surfactant-stabilized foam was selected to reduce CO2 mobility for increasing oil recovery and CO2 storage potential in an inverted 40-acre five spot well pattern. The foam system was designed to maximize the success of foam generation through surfactant screening and optimizing surfactant concentration and foam strength. Previous work identified a water-soluble, non-ionic surfactant at a concentration of 0.5 weight percent (wt%) and 70% foam quality for the pilot. A surfactant-alternating-gas (SAG) injection strategy, consisting of 10 days of surfactant solution injection followed by 20 days of CO2, began in May 2019.
Baseline CO2 injection profiles, tracer tests, injection bottom hole pressures, and flow rates were collected for comparison to pilot surveys. The pilot monitoring program included repeat injection profiles, tracer tests, three-phase production monitoring, and collection of downhole pressure data for evaluation of reservoir response to foam injection. Produced fluids were also collected for chemical analysis to determine surfactant breakthrough time. A field injection unit was designed to meet the requirements of surfactant delivery, mixing, and storing. A methodology was also established to effectively validate foam formulation consistency in the field.
Initial results revealed that pilot CO2 injectivity was reduced by 70%, compared to baseline CO2 injection, indicating reduced CO2 mobility after each surfactant slug. Baseline and pilot injection profiles show increased flow into the reservoir interval and potential blockage of a high permeability streak. The baseline CO2 tracer test measured CO2 breakthrough in 22 days, in one of the pattern producers. Expected breakthrough, based upon simulation, is 66 days during the pilot, which will be verified by a repeat tracer test at the end of the pilot. Production response is not expected for another six to nine months due to the volumes injected during the pilot. However, the early signs of sustained oil production despite less volume injected during the pilot indicate an initial positive response to foam.