bluuebunny/crossref_metadata_2025 huggingface dataset:
A Reconstructed Core-Scale Model of the Lower Eagle Ford Shale Through FIB-SEM, SEM-EDS, and Microscopy for Gas Huff-n-Puff Simulation
Authors: Cudjoe Sherifa , Fu Qinwen , Tsau Jyung-Syung , Barati Reza , Goldstein Robert , Nicoud Brian , Baldwin Amanda , Zaghloul Jose , Mohrbacher David
Published: August 2020

Simulation of gas huff-n-puff (HnP) in core models is often simplified by assuming homogenous, isotropic models, which are not representative of fine-grained multi-component shales with multiple types of pore space and anisotropic permeability. According to the previous literaturte, history matching of a 6-cycle HnP process and tuning of cross-phase effective diffusion coefficients using a homogeneous model presented a need for a detailed core-scale geomodel to capture variations in effective diffusion coefficients as a result of heterogeneity experienced during each diffusion cycle. A workflow for reconstructing a corescale volume of Lower Eagle Ford (LEF) shale is presented that combines rock characterization using high-resolution digital images at the micrometer/nanometer scale and transmitted light microscopy to provide models for detailed heterogeneity of the LEF shale for gas huff-n-puff simulation.

Core-scale models form LEF are reconstructed using high-resolution SEM-EDS and FIB-SEM images. SEM-EDS and FIB-SEM images were coupled with transmitted light microsocpy and micro-computed tomography (CT) to constrain facies distribution, discrete fracture networks and to distribute petrophysical properties. The reconstruction method produced a more representative core model of the LEF and can be used for simulation of core-scale huff-n-puff experiments conducted in a diffusion cell.

Common grain types observed in the SEM-EDS images at different resolutions include detrital quartz, calcite, microfossils and fragments, microfractures, clay minerals, traces of dolomite, and albite. Also common is diagenetic calcite, pyrite, kaolinite, and secondary organic matter (OM) infilling the chambers of foraminifer tests ("forams") and other mineral pores. FIB-SEM analysis provided organic bulk transport properties including tortuosity and permeability within the generated pore network models of the LEF shale. Transmitted light microscopy provided the lamina-scale variation of samples from the LEF shale to be incorporated in the core model.

A detailed workflow is presented for reconstructtion of a LEF shale core-scale model using high- resolution images and photomicrographs. The model detailed the original core morphology, multiple pore space, and multicomponent mineral distributions for gas huff-n-puff simulation. Several realizations of the geomodel were prepared by varying mineral distributions within the layers as well as the range of petrophysical properties in order to present different gas huff-n-puff simulation scenarios. This provided the compositional model using a sophisticated heterogeneous component of tortuosity/permeability instead of a homogenous and isotropic model.
Chemical EOR While Fracturing: An Experimental Study for Evaluating Nanoparticle Additives
Authors: Yuan Lin , Zhang Yanze , Ahmad Yusra Khan , Dehghanpour Hassan
Published: August 2020

In this paper, we evaluate the idea of adding nanoparticles (NPs) in fracturing water to enhance its wetting affinity to oil-wet pores and to mobilize part of the oil during the extended shut-in periods. We analyzed the performance of two different nanoparticle additives (NP1 and NP2) on core plugs collected from the Montney Formation. Additive 1 is a colloidal dispersion with highly surface-modified NPs and additive 2 is a micellar dispersion with highly surface-modified silicon dioxide NPs, solvents and surfactants. The proposed methodology consists of the following steps: 1) Characterizing wettability of the candidate rock samples under different conditions of brine salinity and NP concentrations through dynamic contact-angle measurements, 2) Evaluating NP-assisted imbibition oil recovery during the shut-in period by conducting systematic counter-current imbibition tests, and 3) Evaluating pore accessibility by comparing the mean size of the particles formed in the NP solutions measured by dynamic light scattering (DLS) method with pore-throat size distribution of the core plugs obtained from scanning electron microscopy (SEM) and mercury injection capillary pressure (MICP) analyses.

The dynamic contact-angle results show that the core plugs are oil-wet in the presence of reservoir brine and fresh water as base fluids, and water-wet in the presence of the NP solutions. Consistently, the measured oil recovery factor (RF) by the NP solutions is 5% to 10% higher than that by the base fluids, which can be explained by the wettability alteration by NPs. Comparing the mean particle size of the NP solutions with the pore-throat size distribution of the plugs evaluates pore accessibility of core plugs. From MICP and SEM analyses, most pores of the rock samples have pore-throat radius in the range of 4 to 100 nm. The mean particle size of NP1 in low-salinity water is less than 30 nm while that of NP2 in low-salinity water is around 40 nm. The NPs can pass through most of the pore throats under low-salinity conditions. This is supported by fast and spontaneous imbibition of the NP solutions into the oil-saturated core plugs, compared with the base cases without the NPs solutions. When salinity increases, the particle size for NP solutions increases to more than 200 nm. Therefore, fewer pores may be accessed by NPs under high-salinity conditions if the NP solutions are not optimized for such conditions.
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

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

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

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

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

We 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

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

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

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

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.
A Novel Huff-n-Puff Technology for Chemically Shrinking Swelling Clays to Increase Matrix Permeability and Oil Production
Authors: Trost Paul , Wright John
Published: August 2020

A single cycle Huff-n-Puff wellbore remediation of a formation-damaged shallow turbidite sandstone, containing 4-5% illite/montmorillonite, was conducted to 1) chemically shrink the water-damaged swelling clays to increase matrix permeability, and 2) increase production. Chemical reduction of ferric oxides/hydroxides to ferrous oxide in, and on, the surface of swelling clays by a gaseous reducing agent (carbon monoxide-CO) was utilized. Extensive bench-scale and core flood testing have previously demonstrated CO’s ability to chemically increase matrix permeability. Slim tube studies have also demonstrated a mixture of CO2/CO can recover 80-90% of OOIP under immiscible conditions and at less cost than CO2.

Treating depth of the well was 700-820’, having a 146 psi SIP, and a production rate of 0.4 BOPD. Treatment consisted of 1) injecting 70 mcf of CO over 3 day period at an average of 380 psi; 2) shut-in 4 days to allow the CO to react with the ferric ions; 3) injection of 18 Mcf of gaseous CO2 at 400 psi, 4) switch to liquid CO2 injection. After a 48-day shut-in, reservoir pressures again were 146 psi. Pressure transient analysis (PTA) was conducted on the data collected during the injection and falloff of CO and the injection of CO2 gases. During the flowback period, with both gases present, the oil rate was monitored and compared to pre-treatment rates.

PTA showed a 400% increase in gaseous CO2 injectivity compared to the CO rates. Oil production increased 10-fold from 0.4 up to an average of 4 BOPD during the production cycle when CO2/CO was flowing back. After all the CO2/CO was recovered, production dropped to a sustained 1.2 BOPD versus the original 0.4 BOPD for a 300% increase in oil with minor volumes of gas.

Permitting was not an issue. Operational safety was ensured safety meetings and training of personnel combined with CO monitors, flare lines for the CO2/CO, and self-rescuer gas masks. A leak of CO at the wellhead occurred, was safely mitigated, and no safety problems were encountered during subsequent injection and flowback periods.
Measurement of Minimum Miscibility Pressure: A State of the Art Review
Authors: Dindoruk Birol , Johns Russell , Orr Franklin M.
Published: August 2020

This paper gives a critical review of miscibility measurement techniques published in the open literature along with recommendations and lessons learned. Many of these suggested methods violate the assumptions for multicontact miscibility (MCM). The confusion often arises from a failure to distinguish between the first-contact miscibility (FCM), in which two fluids can be mixed in all proportions without forming two phases, and MCM, in which fluid compositions that arise during the flow of two phases in a porous medium approach a specific critical point within the constraints of the MCM definition.

There are many analytical, numerical, correlational, and experimental methods available to estimate the minimum miscibility pressure (MMP) for MCM flow. The numerous available methods, some of which are quite inexpensive, have caused significant confusion in the literature and in practice regarding their ability to estimate MMP. Our experience has shown that the best methods are those that honor the multi-contact process (MCM), in which flow interacts with phase behavior in a prescribed way. Good methods that achieve this are slim-tube experiments, detailed slim-tube smulations, multiple mixing cell calculation methods, and the method-of-characteristics (MOC). Techniques such as the rising bubble apparatus (RBA) and vanishing interfacial tension (VIT) experiments are subject to significant uncertainties, though they may still provide quite useful information. Numerous MMP correlations have been developed. They should be used with caution for systems similarto those used to develop the correlation. Use for other systems can lead to significant errors. We discuss the advantages and disadvantages of most current methods and show that various combinations of methods can reduce uncertainty.
Feasibility Study of Gas Injection in Low Permeability Reservoirs of Changqing Oilfield
Authors: Tian Ye , Uzun Ozan , Shen Yizi , Lei Zhengdong , Yuan Jiangru , Chen Jiaheng , Kazemi Hossein , Wu Yu-Shu
Published: August 2020

Changqing Oilfield is the largest petroleum-producing field in China and one-third of its oil production is attributed to the formations with permeability lower than 1 mD. The rapid oil rate decline and low recovery factor (RF) associated with those formations require additional IOR/EOR measures besides waterflood. Based on the promising results from recent gas injection pilots in North America, we investigated the feasibility of gas injection in the low permeability formation (Chang 63) of Changqing Oilfield.

An eight-component fluid characterization, which fits both the constant composition expansion (CCE) test and separator test, was used in a numerical dual-porosity compositional model. A typical well pattern, composed of six vertical injectors and one horizontal producer, is selected for the modeling study. The input parameters, including relative permeability, fracture permeability, etc., were adjusted to achieve an acceptable history match of the production data. Huff-n-Puff using several gases—lean gas (CH4), produced gas, rich gas (C2H6), and solvent (C3H8)— were investigated and the results were compared with the current waterflood.

The simulation results show that the richer the injected gas, the higher the oil production. C3H8 huff-n-puff achieved the best performance, increasing the cumulative oil production by a factor of 2.28 after 5 cycles, then followed by C2H6 as 1.34, produced gas as 1.08. CH4 alone demonstrated a lower recovery factor than waterflood, because its minimum miscibility pressure (MMP) is close to the maximum allowable injection pressure, i.e., the minimum horizontal stress. In addition, the horizontal producer was completed at the reservoir top and water injectors were placed at the bottom, which was originally designed to improve the waterflood by gravity segregation. Under such well placement design, the miscible oil bank, which forms at the injection front during vaporizing drive, will be displaced towards the reservoir bottom even out of the SRV, undermining the huff-n-puff performance. Injection with rich gas will be more compatible, as the miscible bank forms at the injection tail. Injecting produced gas enriched with C3H8 will hence achieve promising EOR performance. The simulation also shows that increasing injection pressure increases the recovery factor. The leaner composition of produced gas could be compensated by a higher injection pressure. The optimal injection duration and soaking time could also be obtained after sensitivity analysis. Another critical factor is the fracture network characterized by the dual-porosity model, as simulation with the single porosity model only shows minor improvement in RF even with C3H8.

Our work confirmed the technical feasibility of injecting rich gas in the low permeability Chang 63 by compositional simulation. We also determined the key parameters for the operator to consider in the next phase of the project.
Catalytic hydrolysis of Dichlorodifluoromethane over MoO3/ZrO2 -TiO2 solid acid
Authors: Li Zhiqian , Zhou Tong , Ren Guoqing , Tan Xiaofang , Jia Lijuan , Liu Tiancheng
Published: August 2020

The catalytic hydrolysis of Difluorodichloromethane(CFC-12) by solid acid of MoO3/ZrO2-TiO2 calcined at different temperature had been studied. The effects of catalytic hydrolysis temperature and water vapor concentration on catalytic hydrolysis of CFC-12were also studied. The results showed that catalytic hydrolysis rate of CFC-12 reached to 98.65 % at 400。C when the MoO3/ZrO2-TiO2 catalyst was calcined at 500℃ with a concentration of water vapor of 83.18% ,and the main hydrolysis products were CO, CO2, HF and HCl. After 30 hours’ continuous reaction, the hydrolysis rate of CFC-12 was 65.34%. The XRD result reveals that the main phase of solid MoO3/ZrO2-TiO2 catalyst is the tetragonal Zr(MoO4)2with dopedTiO2 of anatase.
Cancer treatment with hormone therapy and its relationship with xerostomia and hyposalivation
Authors: Medeiros Glaucia de , Fernandes Jheiniffer , Pompeo Daniela , Pereira Jefferson Ricardo
Published: August 2020

Background: The appearance of new drugs for cancer treatment has increased patient survival but it has also brought adverse effects, such as the sensation of dry mouth and hyposalivation. Objective: To assess the relationship of using hormone therapy in breast and prostate cancer patients and the occurrence of xerostomia and hyposalivation. Method: Cross-sectional study with 114 patients diagnosed with cancer and treated with hormone therapy (anastrozole or bicalutamide). Age, type of neoplasia, sex, presence of xerostomia (yes or no), and type of medication were obtained with a questionnaire. The researcher collected resting and stimulated salivary flows in the morning. The descriptive statistic analysis, chi-square test (p<0.005), and t-test (<0.005) were performed using the Statistical Package for Social Science™ (SSPS), version 21, for different variables of hyposalivation and hormone therapy. Results: The results showed that 67 (55.8%) patients using hormone therapy drugs presented hyposalivation and 73 (64%) patients presented xerostomia. Conclusion: According to the results of this study, there is a positive association between stimulated hyposalivation and the use of hormone therapy drugs (p = 0.015). There was also a positive association between hyposalivation and xerostomia and the use of hormone therapy drugs (p = 0.049 and p = 0.001).
C-Reactive Protein and Lymphocyte are important indicators of severe coronavirus disease and poor prognosis in elderly patients
Authors: He Qinglin , Hu Xiafen , Xiang Xiaochen , Chen Siyang , Liu Wanxin , Liu Xiaoliu , Wang Qiang , Guo Kaiwen , Wu Qingming
Published: August 2020

Objective：To explore the value of C-reactive protein (CRP) and lymphocyte (L) in the assessment of disease severity and prognosis of elderly COVID-19 patients.Methods: A total of 194 positive COVID-19 patients were collected from Tianyou Hospital and Puren Hospital, affiliated hospital of Wuhan University of Science and Technology. Their demographic characteristics were analyzed. The dynamic changes of CRP and L in peripheral blood were retrospectively studied.Results: (1) There were significant statistical differences in CRP, L in clinical typing and clinical outcome in patients over 60 years old compared with those under 60 years old. Survival analysis showed that the risk of death was greater in patients over 60 than in those under 60.（2）In 125 patients over 60 years old, the hospitalized patients with severe or critical types of disease had significantly higher CRP than those with moderate type (p<0.01). In the outcome of the elderly patients, the CRP of the patients with the outcomes of discharge, improvement, aggravation and death increased successively (p<0.01). According to the analysis of Logistic regression model, the increase of CRP constitutes a risk factor for death in elderly patients. (3) In the ROC curve analysis to distinguish the death outcome and non-death outcome of COVID-19 patients, the area under the curve (AUC) of CRP and L was 0.751 and 0.720 respectively. CRP and L had good diagnostic accuracy for the death outcome of patients. (4) Changes in CRP were correlated with changes in CT imaging and were consistent with changes in the course of the disease.Conclusions: (1) The data collected in this research showed that the cumulative survival rate of patients over 60 years old was lower than that of patients under 60 years old. With the increase of age, the CRP of patients showed an increasing trend, and the L of patients showed a characteristic lower than the normal reference interval. (2) CRP and L are important monitoring indicators of COVID-19 in elderly patients. Combined with CT examination and observation of their dynamic changes, CRP and L are of important clinical guiding value for the judgment of disease severity and the evaluation of prognosis.
Evaluation and Identification of Morphological Characters Suitable for Delimitation of Taraxacum Species Distributed in Northeastern China
Authors: WU Jie , Liu Qun , Ning Wei , Cao Wei , Xing Yanping , Li Ran , Li Yuefei
Published: August 2020

The authors have withdrawn this preprint due to author disagreement.
Comparative study for the treatment of domestic wastewater using Chlorella Vulgaris
Authors: Moondra Nandini , Jariwala Namrata , Christian Robin A
Published: August 2020

Tertiary treatment using chemicals frequently prompts secondary contamination of sludge, making additional issues of safe disposal. Thus, vitality and cost required for tertiary treatment of wastewater stay an issue for industries and municipalities. In this study, different microalgal concentrations 360 mL (20%), 450 mL (25%), 540 mL (30%), 630 mL (35%), 720 mL (40%) and 810 mL (45%) were studied to treat domestic wastewater for 11 hours of detention time for both filtered and non-filtered effluent. During the study, removal was observed in Total Solids (TS), Total Dissolved Solids (TDS), Total Suspended Solids (TSS), Electrical Conductivity (EC), phosphate, ammonia and Chemical Oxygen Demand (COD) for all the microalgal concentrations mentioned. 30% microalgal concentration showed maximum removal efficiency among different microalgal concentrations studied. Maximum removal efficiency found in non-filtered effluents when treated with 30% microalgal concentration was 96.60, 91.73 and 84.71% respectively for ammonia, phosphate and COD concentration. However, the removal efficiency increased to 97.62, 92.47 and 88.75% respectively for ammonia, phosphate and COD in the case of filtered effluents. In the case of TSS and EC, removal efficiency reached up to 30.87 and 24.31% respectively for non-filtered effluents while it was 48.00 and 25.88% respectively, for the filtered effluents. One-way ANOVA was also conducted to determine the statistical significance of the study. The study showed that an algae-based system could accomplish a more affordable and environment-friendly way to treat domestic wastewater without tertiary treatment to a desirable limit.
Treatment of ruptured tiny intracranial aneurysms by electrocoagulation with guidewire manipulation:12 cases report
Authors: Xia Lixia , Hao Zhongfei , Wang Hongjun , Feng Yan , Zhan Yongxuan , Chen Minghui , Xie Peng , Li Qingbin , Li Ruiyan , Liu Yang , Wang Feng , Fang Yuequn , Li Youxiang , Li Yongli
Published: August 2020

Background: Ruptured tiny intracranial aneurysm (RTIA) is particularly rare seen. Treatment of RTIA is more difficult and not under control.Methods: We hereby present twelve rare cases of RTIA that were diagnosed based on DSA. These patients were found due to spontaneous or traumatic SAH, 11 of whom were treated only by electrocoagulation, and one of whom was treated by stent-assisted coiling and electrocoagulation.Results: There were eight patients with aneurysms located in posterior circulation and four patients with aneurysms located in anterior circulation. 11 patients were cured only by electrocoagulation merely: ten patients’ RTIA disappeared completely and immediately and another patient’s RTIA was thrombosed two months later. The twelfth patient was carried out stent-assisted coiling and electrocoagulation. The twelve patients’ average follow-up time was 12.5 months and the outcomes were all surprisingly excellent. No revascularization of aneurysm was found. Conclusions: Electrocoagulation with guidewire manipulation is a suitable method to treat RTIA. While large-scale studies with long-term follow-up are required to validate these promising results.
Effects of Cytokine Blocking Agents on Hospital Mortality in Patients Admitted to ICU With Acute Respiratory Distress Syndrome by SARS-CoV2 Infection: An Observational Cohort Study
Authors: Coloretti Irene , Busani Stefano , Biagioni Emanuela , Venturelli Sophie , Munari Elena , Sita Marco , Dallara Lorenzo , Tosi Martina , Clini Enrico , Tonelli Roberto , Fantini Riccardo , Mussini Cristina , Meschiari Marianna , Guaraldi Giovanni , Cossarizza Andrea , Alfano Gaetano , Girardis Massimo
Published: August 2020

Background The use of cytokine-blocking agents has been proposed to modulate the inflammatory response in patients with COVID19. Tocilizumab and Anakinra were included in the local protocol as an optional treatment in critically ill patients with acute respiratory distress syndrome (ARDS) by SARS-CoV2 infection. This cohort study evaluated the effects of therapy with cytokine blocking agents on in-hospital mortality in COVID19 patients requiring mechanical ventilation and admitted to intensive care unit. Methods The association between therapy with Tocilizumab or Anakinra and in-hospital mortality was assessed in consecutive adult COVID19 patients admitted to our ICU with moderate to severe ARDS. The association was evaluated by comparing patients who receive to those who did not receive Tocilizumab or Anakinra and by using different multivariable Cox models adjusted for variables related to poor outcome, for the propensity to be treated with Tocilizumab or Anakinra and after patient matching. Results Sixty-six patients who received immunotherapy (49 Tocilizumab, 17 Anakinra) and 28 patients who did not receive immunotherapy were included. The in-hospital crude mortality was 30,3% in treated patients and 50% in non-treated (OR 0,77, 95% CI 0,56-1,05, p=0,069). The adjusted Cox model showed an association between therapy with immunotherapy and in-hospital mortality (HR 0,35, 95% CI 0,16-0,77, p=0,009). This protective effect was further confirmed in the analysis adjusted for propensity score, in the propensity-matched cohort and in the cohort of patients with invasive mechanical ventilation within 2 hours after ICU admission. Conclusions Although important limitations, our study showed that cytokine-blocking agents seem to be safe and to improve survival in COVID-19 patients admitted to ICU with ARDS and the need of mechanical ventilation.