bluuebunny/crossref_metadata_2025_split huggingface dataset:
Mobility Changes Evaluation of a Polymer Solution at Reservoir Conditions, Polymer Flood Pilot Test Performed in an Extra Heavy Oil Reservoir. Orinoco Oil Belt, Venezuela
Authors: Ramirez Andres , Quevedo Luis , Vasquez Edgar , Ulacio Ivon , Rojas Gonzalo 
Published: August 2020

Abstract
The objective of the study was to estimate which was the effective mobility of a polymer solution injected in an extra heavy oil reservoir, also try to stablish if there was a reduction on effective permeability as injection progressed, and finally estimate the mobility ratio between the reservoir fluid and the injected fluid.
Laboratory analyses were used to evaluate the behavior at surface conditions of the polymer solution before injection, and also the quality of the polymer solution prior injection. Tests were performed to estimate the effect of water reservoir salinity over the polymer solution viscosity, and the effect of Iron and Oxygen ion content present in the solvent used for preparation. After project start up, five fall off tests (pressure transient tests) at different stages of the injection process were performed in order to evaluate the mobility evolution over an extended period of time. The tests were executed every three months after the beginning of the injection of the polymer solution. Other diagnostics techniques were also studied, in order to gain insight of what other variables could affect the injection process, among them: Hall plot diagnostics, and fiber optic data.
The evolution mobility of the polymer solution at reservoir conditions was determined, and as injection progressed, the solution mobility decreased over time for the same concentration, according to results obtained from interpretation of well tests analysis, the mobility decreased from 342 mD/cP to 145 mD/cP. Given that the mobility of the oil was very low (between 0,8 mD/cP and 1 mD/cP), the mobility ratio evolution over time showed that a reduction in polymer effective permeability occurred as injection progressed, favoring the flooding process, also depending of the effective permeability, the mobility compared to water, was almost seven times lower. Laboratory analyses showed and important dependency between shear rate and polymer viscosity in the case of polymer solution prior injection, and also a possible risk of solution viscosity reduction due the high salinity of the reservoir water.
The injection data, fall off analysis, and Hall plot analysis, combined with the results of the laboratory analyses are of great importance for the topic of enhanced oil recovery process in the case of extra heavy oil reservoirs. The results obtained show also that it is necessary to evaluate the actual performance, besides of the core test and simulation results. Finally the knowledge accomplished in this work was used to obtain important information necessary to asset feasibility, in the case of a larger scale implementation of the process.
Fundamental Investigation of Auto-Emulsification of Water in Crude Oil: An Interfacial Phenomenon and its Pertinence for Low Salinity EOR
Authors: Jennifer Duboué , Maurice Bourrel , Théo Dusautoir , Enric Santanach Carreras , Alexandra Klimenko , Nicolas Agenet , Nicolas Passade-Boupat , François Lequeux 
Published: August 2020

Abstract
The phenomenon of auto-emulsification occurring when crude oil is gently contacted with water was investigated using various techniques. This spontaneous emulsification which creates a micro-droplet layer at the oil/brine interface is believed to be linked to the improved oil recovery during low salinity Enhanced Oil Recovery (EOR). Crude oils and a model system (asphaltenes solubilized in toluene) have been studied. Observations were facilitated when using the model system, this allowed to have a better insight into the underlying mechanism of micro-droplet formation. It was established that the water micro-droplets appear in the oil phase due to an osmotic phenomenon: molecular water diffuses from the bulk water which provokes the water micro-droplets swelling. The kinetics of the micro-droplet formation is directly linked to the brine salinity in contact with the crude oil: salt addition slows down the emulsification process. This was further confirmed by the evaluation of the water chemical activity in the oil phase from calorimetry measurements.
Micromodel experiments showed a higher oil recovery when water micro-droplets are present in the system, irrespective of the initial wettability imposed to the micromodel material. Dilatational rheology measurement did not show significant visco-elasticity arising from the water micro-droplet presence; hence, the visco-elasticity difference cannot completely explain the higher recovery. Manipulation of crude oil droplet during dilatational rheology experiments highlighted the impact of micro-droplets on the shape of the macroscopic oil droplet. The nucleation of micro-droplets at oil/brine or solid/oil interface suggests an explanation for the EOR effect. We have observed that micro-droplets organize at the oil/water interface, while others nucleate at the oil/solid interface or sediment on the solid surface. The interaction of asphaltenes with water molecules dissolved in the oil phase may promote wettability alteration. The micro-droplet formation indicates the magnitude of this interaction for a given asphaltenes/brine system.
Field Trial for Wettability Alteration Using Surfactants: Formulation Development In Laboratory to the Implementation and Production Monitoring in an Offshore Reservoir
Authors: Rohilla Neeraj , Katiyar Amit , Rozowski Pete M. , Gentilucci Adrianno , Patil Pramod D. , Pal Mayur , Saxena Prabhat 
Published: August 2020

Abstract
Wettability Alteration (WA) as an Enhanced Oil Recovery (EOR) technique is screened for an oil wet carbonate offshore reservoir in this study. Surfactants can be used to change the rock wettability from oil-wet to water-wet conditions and can lead to unlocking significant incremental oil from oil-wet tight pores. A thorough lab program was designed to develop a wettability altering surfactant formulation and was validated with corefloods and spontaneous imbibition tests at reservoir conditions. Surfactant injection trials at smaller scale were conducted first which were successful. Currently, an ongoing long term surfactant injection pilot is operating to evaluate incremental oil gains.
An optimal surfactant formulation is developed on the basis of favorable phase behavior at reservoir conditions, the ability to alter wettability to a more water-wet state and cause minimal chemical losses on reservoir minerals in the form of adsorption. Surfactant formulations designed in this work are unique and provide high temperature stability (above 70 °C and in some cases up to 120 °C) and high salinity tolerance (&gt; 12 % TDS and up to 22% TDS in some low temperature cases).
The field implementation was done in a systemetic step wise manner to mitigate the risk in implementing such a technology field wide. The first step was to de-risk the long term injection and see if there is any injectivity impairment due to surfactant injection. The current injection trial showed improvement in injectivity that is indicative of changes in wettability. More importantly, there has been no evidence of any injectivity impairment, which paves the way for long term surfactant injection in the field.
Production Optimization of the CO2 Huff-N-Puff Process in an Unconventional Reservoir Using a Machine Learning Based Proxy
Authors: Almasov Azad , Onur Mustafa , Reynolds Albert C. 
Published: August 2020

Abstract
The main objective of this work is to investigate efficient estimation of the optimal design variables that maximize net present value (NPV) for the life-cycle production optimization during a single-well CO2 huff-n-puff (HnP) process in unconventional oil reservoirs. During optimization, the NPV is calculated by a machine learning (ML) proxy model trained to accurately approximate the NPV that would be calculated from a reservoir simulator run. The ML proxy model can be obtained with either least-squares support vector regression (LS-SVR) or Gaussian process regression (GPR). Given forward simulation results with a commercial compositional simulator that simulates miscible CO2 HnP process in a simple hydraulically fractured unconventional reservoir model with a set of design variables, a proxy is built based on the ML method chosen. Then, the optimal design variables are found by maximizing the NPV based on using the proxy as a forward model to calculate NPV in an iterative optimization and training process. The sequential quadratic programming (SQP) method is used to optimize design variables. Design variables considered in this process are CO2 injection rate, production BHP, duration of injection time period, and duration of production time period for each cycle. We apply proxy-based optimization methods to and compare their performance on several synthetic single-well hydraulically fractured horizontal well models based on Bakken oil-shale fluid composition. Our results show that the LS-SVR and GPR based proxy models prove to be accurate and useful in approximating NPV in optimization of the CO2 HnP process. The results also indicate that both the GPR and LS-SVR methods exhibit very similar convergence rates and require similar computational time for optimization. Both ML based methods prove to be quite efficient in production optimization, saving significant computational times (at least 5 times more efficient) than using a stochastic gradient computed from a high fidelity compositional simulator directly in a gradient ascent algorithm. The novelty in this work is the use of optimization techniques to find optimum design variables, and to apply optimization process fast and efficient for the complex CO2 HnP EOR process which requires compositional flow simulation in hydraulically fractured unconventional oil reservoirs.
Economic Assessment of Strategies for CO2-EOR and Storage in Brownfield Residual Oil Zones: A Case Study from the Seminole San Andres Unit
Authors: Ren Bo , Duncan Ian , Male Frank , Baqués Vinyet , Lake Larry 
Published: August 2020

Abstract
Brownfield residual oil zones (ROZ) may benefit from specific strategies to maximize production. We evaluated several strategies for producing from the Seminole ROZ. This ROZ lies below the main pay zone (MPZ) of the field. Such brownfield ROZs occur in the Permian Basin and elsewhere, formed by the action of regional aquifers over geologic time. CO2 can be injected into these zones to enhance oil recovery and carbon storage. Since brownfield ROZs are hydraulically connected to the MPZs, development sequences and schemes should influence oil production, CO2 storage, and net present value (NPV).
We conducted economic assessments of various CO2 injection/production schemes in the Seminole stacked ROZ-MPZ reservoir based on flow simulations. First, we constructed a high-resolution geocellular model from a seismic survey, wireline logs and core data. To calibrate the geological model and constrain the interface between the ROZ and the MPZ, we performed a comprehensive production-pressure history matching of primary depletion and secondary waterflooding. After this, we conducted flow simulations of water alternating gas (WAG) injection into the reservoir while considering several injection/productions schemes (e.g., switching injection from the MPZ to the ROZ, commingled production). For each scheme, various WAG ratios (i.e., reservoir volume ratio between injected water and CO2) were tested to find the maximum oil production and maximum CO2 storage. We assessed the economic results for each WAG ratio case on NPV.
The results from simulating various injection/production schemes showed that simultaneous CO2 injection into the MPZ and ROZ favors oil production. If instead, CO2 is injected into the MPZ and ROZ, then into the ROZ alone, this leads to increased CO2 storage. Storage performance is influenced by the interplay between the crossflow from the MPZ to ROZ and WAG ratios. As the WAG ratio increases, the amount of CO2 stored decreases more for commingled injection cases than for separated ROZ injection cases. Also, the WAG ratio leading to maximum oil production does not necessarily yield the largest NPV, because of the complicated interactions among CO2 consumption, reservoir heterogeneity, and oil recovery.
Brownfield ROZs are common below San Andres reservoirs in the Permian Basin, and they can be exploited to increase oilfields’ NPV and carbon storage potential. Our case study on the Seminole MPZ-ROZ is an analog for other similar reservoirs. We demonstrate that development sequences and WAG ratios influence the performance of CO2 EOR and storage. Thus, this work provides valuable insights into the further optimization of brownfield ROZ development and helps operators to plan flexible storage goals for stacked ROZ-MPZ reservoirs.
QEMSCAN Assisted Interpretation of Imbibition Capillary Pressure for Multi-Porosity Carbonate Rocks
Authors: Alramadhan Aymen , Cinar Yildiray 
Published: August 2020

Abstract
This paper demonstrates the effect of pore systems and mineralogy on imbibition capillary pressure (Pci) of carbonate rocks. A systematic workflow is developed and followed to ensure the data quality of Pci, minimize uncertainty in deriving the Pci from centrifuge tests, and analyze the data together with pore-size distribution from mercury injection capillary pressure (MICP) and mineralogy from Quantitative Evaluation of Minerals by Scanning Electron Microscopy (QEMSCAN). The workflow starts with assessing the centrifuge production data for gravity-capillary equilibrium at each speed. Then the quality-checked data is used to produce six different Pci curves using the analytical and numerical models. The analytical and numerical solutions assess the variability in solutions for various rock types, and ultimately, lead to the selection of the most-representative Pci curve. Finally, the representative Pci curves of varying rock types are analyzed together with the MICP and QEMSCAN data to examine the change in Pci curves as a result of changes in the number and character of pore systems, dominant pore throat radii, and mineralogy.
Findings from this study present insights into the impact of mineralogy and pore systems on the behavior of the Pci curves. From the mineralogy perspective, the presence of dolomite, microporous calcite, or rutile and anatase (TiO2) within the rock composition has a strong influence on the Pci behavior of carbonate rock. The data reveals that the contrast between the micropore and macropore systems of bi-modal carbonates has the strongest influence on Pci. We find that Pci can be clustered based on mineral content for bi-modal carbonate rocks and the degree of communication between micropore and macropore systems. The novel approach presented in this study links the MICP and QEMSCAN data to the imbibition process making the way toward a better dynamic rock typing.
Polymer Flooding - Towards a Better Control of Polymer Mechanical Degradation at the Near Wellbore
Authors: Garrepally Sandeep , Jouenne Stephane , Leuqeux Franpois , D. Olmsted Peter 
Published: August 2020

Abstract
Polymer flooding with visco-elastic polymers is an EOR technique improving both macro and microscopic recovery of oil. Its efficiency can be greatly limited by mechanical and chemical degradation of polymers. When injected in the reservoir, the early few centimeters travelled through the rock are crucial for determining the degradation undergone (degradation being defined as the irreversible loss of viscosity). Our aim is is to establish predictive laws for the degradation of polymer solutions flowing through porous media and for the associated flow thickening which can mobility reduction curves of polymer solutions injected or re-injected through sintered ceramic cores of length varying between 1 and 8 mm, we develop a model for predicting mobility reduction and degradation at any length of porous medium, any flux. The model is built by considering that a single injection at flux J on a core having a length NL0 is equivalent to N successive injections at flux J on a piece of the core of length L0. In linear fow, it is found that degradation increases sharply for the first few millimeters and then tends toward a quasi steady state value after a critical length Lc which decreases for increasing fluxes. This model is then transposed to radial flow. Similarly, there exists a critical distance Dc at which degradation reaches a steady state value. Dc is an increasing function of the injection well radius Rw and tends towards Lc at high Rw since radial flow becomes nearly linear.
Results obtained with the model are then discussed for predicting precisely on which distance degradation will be experienced and for determining if degradation experiments performed in linear flow in the lab are representative of radial flow around a real polymer injector. This study is a first in injecting polymer solutions through cores as short as 1 mm and in predicting mobility reduction and degradation in both linear and radial flow profiles.
A Nanoparticle Assisted CO2 Huff-N-Puff Field Test in the Eagle Ford Shale
Authors: Zheng Shuang , Sharma Mukul , Watts Robin , Ahmad Yusra 
Published: August 2020

Abstract
The primary objective of this work was to investigate the results and the possible mechanisms of oil recovery in a huff-n-puff style improved oil recovery (IOR) field pilot using nanoparticle assisted CO2 injection. A secondary objective was to study the sensitivity of the process to injection volume of nanoparticles and gas, the type of injected gas, soaking period, and the timing of IOR to maximize net present value. An Eagle Ford shale well was produced for 526 days before 167-barrels of nanoparticle treatment and 160-tons of CO2 were injected in 11 cycles into the well, shut-in for 5 days and then put back on production. A simulation study was conducted using a fully coupled geomechanical compositional fracturing and reservoir simulator using data from the pilot well. The primary production was history matched for the fractured horizontal well and the huff-n-puff process with nanoparticle and CO2 injection was simulated followed by a shut-in period. The simulated production after shut-in and the incremental oil recovery was compared with field measured data. The pilot test results clearly show that there is a significant oil rate increase after the nanoparticle and CO2 are injected. Lab results show that nanoparticles can lower the interfacial tension between the water and oil and alter the rock wettability to a preferential water-wet state, which is beneficial for oil production. The simulation studies show that CO2 injection alone results in smaller improved oil recovery and predicts a smaller oil recovery than in the field. This suggests that both the nanoparticles and gas play an important role in increasing the relative permeability to oil and improving oil recovery. Results from the sensitivity study show that larger injection volumes of nanoparticles and gas result in higher oil recovery. Among different injection gases simulated, in this oily window of the Eagle Ford shale, ethane gives the highest oil recovery followed by CO2, methane, and nitrogen. A longer soaking period after the injection also helps to increase oil recovery. It is also shown that it may be better to perform IOR at an earlier stage of primary production to maximize the cumulative oil recovery. Our field and simulation results provide operators with significant new insights into the design of an IOR process that uses nanoparticles with CO2 injection. The integration of field pilot test data with realistic compositional geomechanical reservoir simulation for the first time provides a quantitative estimate of the improvement in oil recovery and insights into the possible mechanisms of oil recovery.
Catalytic Impact of Clays During In-Situ Combustion
Authors: Pope Connor , Ismail Norasyikin Bte , Hascakir Berna 
Published: August 2020

Abstract
Clays are known to act as a catalyst during the in-situ combustion (ISC) process. This work investigates the role of clay in reaction kinetics of a bitumen sample.
Several Thermogravimetric Analysis/Differential Scanning Calorimetry (TGA/DSC) experiments were conducted on a Canadian bitumen and its saturates, aromatics, resins, and asphaltenes (SARA) fractions in the presence and absence of a clay (kaolinite and illite) mixture. The role of each fraction in ISC reactions was investigated at low temperature oxidation (LTO) and high temperature oxidation (HTO) regions by calculating the total activation energy and the heat of combustion. The activation energy calculations were based on the Arrhenius approximation and the heat of reaction was estimated by a simple integration of the DSC curve below the standard zero heat generation line.
Accordingly, we have observed that saturates act like ignitors and their ignition characteristics are enhanced in the presence of clay. Bitumen oxidation in LTO region requires more heat for asphaltenes only in the absence of clay. In the presence of clays, bitumen oxidation in LTO region requires more heat for the mutual interaction of resins with asphaltenes. The required heat for the bitumen oxidation and combustion in HTO region is reduced due to contribution of mainly saturates fraction in the presence of clays. The generated heat (heat of combustion) is increased both in LTO and HTO regions for clay presence case. This is mainly due to the mutual interaction of aromatics fraction with resins fraction in LTO region and the mutual interaction of aromatics fraction with saturates fraction in HTO region. It has also been found that bitumen sample contains emulsified water, which reduces the combustion process performance.
Research and Application of Horizontal Well Infill SAGD Development Technology for Super Heavy Oil Reservoirs
Authors: Tao Liang , Li Geng , Li Lingduo , Shan Jiangtao 
Published: August 2020

Abstract
In order to find effective replacement technology for ultra-heavy oil reservoirs at the late stage of horizontal well cyclic steam injection, pilot test on infill steam-assisted gravity drainage (SAGD) development has been carried out in Xinjiang Oilfield, China. In this study, a fine reservoir geological model was built by combining numerical reservoir simulation with the pilot test to analyze the development mechanism of infill SAGD, and optimize the location of the infill SAGD well group, the infill timing, and the timing of horizontal well turning into production well, as well as the operational parameters of the infill SAGD during start-up phase and production phase. Also, the adjustment techniques at each stage have been worked out. The research results show that the reasonable development technical parameters of the infill SAGD are: the SAGD steam injection well is 5m above the original horizontal well, and the infilling time is after 7 to 8 cycles of steam injection of the original horizontal well; after infilling, the original horizontal well is converted into production well after 2 cycles of steam injection; the bottom hole dryness of steam is greater than 85%, and the production/injection ratio is 1.22 and 1.23. The new technology is expected to increase the ultimate recovery factor by 30%-35%, and will have great reference significance for the development of similar super heavy oil reservoirs.