bluuebunny/crossref_metadata_2025_split huggingface dataset:
Geochemical Modeling of Wormhole Propagation During Carbonate Acidizing with Consideration of Fractures
Authors: Wei Wan , Yu Wei , Chen Youguang , Sepehrnoori Kamy 
Published: August 2020

Abstract
Matrix acidizing is a widely-used stimulation treatment performed below the fracture pressure of the formation. The purpose of acidizing is to improve or restore the formation permeability through rock dissolution. Natural fractures exist in approximately 50% of carbonate reservoirs worldwide (Jo Garland et al. 2018). In this paper, a two-scale continuum model is implemented in UTCOMP (a 3D compositional reservoir simulator) with consideration of fractures using EDFM (Embedded Discrete Fracture Model). The model is also coupled with IPhreeqc (an open- source geochemical program) to calculate reactions occurring among minerals and geochemical species in the aqueous phase. In the coupled model, the two-scale continuum model describes convection and dispersion while IPhreeqc is responsible for the dissolution calculation both in the matrix and on the fracture surface. We validated the simulation model by comparing with the analytical solution. We used two methods for reaction calculation; in the first method we assumed a simple first-order reaction between acid and mineral; in the second method the UTCOMP-IPhreeqc coupled model is used to calculate complex reactions among geochemical species and different mineral compositions. Consistent results were obtained between the simple-reaction model and the UTCOMP- IPhreeqc coupled model by tuning the reaction calculation in the IPhreeqc database. On this basis, we investigated the effects of fractures on acidizing efficiency and wormhole propagation. It is found that for homogeneous matrix with existence of fractures, wormhole in the matrix is generated along the fracture. For heterogeneous matrix, the initiation of the wormhole is dependent on the permeability distribution in the matrix, but wormhole propagation after the initiation is dependent on the position of the nearest fracture tip and the fracture orientation. As a high- conductivity flow path, fracture retards wormhole propagation in the matrix by attracting most acid. As acid dissolves the minerals on the fracture surface, the fracture conductivity is increased and the fluid leak-off into the matrix is reduced. For a vertical fracture with a smaller height compared with the matrix thickness, wormhole propagation is slowed down for the entire matrix. For the first time, it is possible to simulate formations with hydraulic fractures or natural fractures during acidizing, with consideration of geochemical reactions among aqueous phase and different rock compositions. The presented model improves our understanding in acidizing optimization.
In-Situ Generation and Propagation of a Nanocellulose Reinforced CO2 Foam in Tight Formation Fractures for Conformance Control
Authors: Wei Bing , Chen Shengen , Tian Qingtao , Xu Xingguang , Li Xinyuan , Lu Jun 
Published: August 2020

Abstract
EOR projects implemented in Bakken and Changqing tight formations demonstrated that the fractures could cause early breakthrough of the injected CO2 and finally led to undesirable oil recovery. Therefore, conformance control technologies should be developed for the outstanding EOR performance in fractured tight formations. Given this, a nanocellulose (NCF) reinforced CO2 foam was rationally designed in the present work and the flow behaviors in tight formation fractures including generation, propagation and permeability reduction were investigated. The bulk properties of NCF-CO2 foam in gas and supercritical states including foam stability and texture were thoroughly evaluated in a high-pressure-high-temperature (HP-HT) windowed cell. A series of model fractures with certain apertures in tight rocks were designed and assembled for coreflooding experiments. The differential pressure (ΔP) across the core sample during foam flow was continuously monitored. At the end of the experiments, the produced ΔP as a function of gas and water injection rate was mapped. The results showed that the addition of NCF into CO2 foam considerably retarded foam film drainage and bubble coalescence thereby improving the stability of the induced foam. The NCF-CO2 foam had finer bubbles and more robust lamella film than conventional CO2 foam. As a consequence, the half-life of NCF-scCO2 (supercritical state) foam was found to be two times longer than the counterpart conventional scCO2 foam. It was also observed that NCF-CO2 foam could rapidly generate in-situ in fractures and propagate throughout the models. Small fractured aperture led to high ΔP under identical experimental conditions. In addition, NCF-scCO2 foam exhibited noticeably higher ΔP compared to conventional scCO2 and NCF-CO2 foams, validating the effectiveness of the conformance control strategy. Furthermore, the flow of NCF-CO2 foam in fractures significantly decrease the fracture permeability and the most noticeable reduction occurred at fg=0.67 (foam quality). This work, for the first time, demonstrates that the nanocellulose can be applied to effectively boost the scCO2 foam stability. In addition, the flow characteristics of this foam in fractures are investigated, which provides insights into conformance control for tight formations.
Sizing Gelant Treatment for Conformance Control in Hydraulically-Fractured Horizontal Wells
Authors: Liang Bin , Jiang Hanqiao , Li Junjian , Li Min , Lan Yuzheng , Seright Randall 
Published: August 2020

Abstract
Horizontal wells are subject to water breakthrough problems caused by natural or hydraulic fracture connections. Treatment with gelant normally is an effective choice. However, at present, no methods can provide quantitative guidance for designing gelant treatment in fractured horizontal wells. In this paper, we proposed a fracture-conductivity-based analytical model to guide sizing gelant treatment in hydraulically fractured horizontal wells. It includes the evaluation of fracture number intersected with the horizontal well, calculation of gelant leakoff distance according to the desired water productivity reduction, and the method to determine optimal gelant volume. The principle for controlling gelant injection and the method for forecasting water shutoff performance are also included. The successful application is based on two requirements: (1) gelant can penetrate a short distance from fracture surface into adjacent matrices; and (2) gelant or gel can reduce permeability to water more than to hydrocarbon. Finally, we summarize a 9-step procedure for sizing gelant treatment in fractured horizontal wells. This work provides quantitative guidance for water shutoff treatment using cross-linked polymer gels that create disproportionate permeability reduction.
Insights into Field Application of EOR Techniques from Modeling of Tight Reservoirs with Complex High-Density Fracture Network
Authors: Niu Geng , Schechter David 
Published: August 2020

Abstract
Pilot tests of surfactant additives in completion fluid and gas huff n' puff in depleted wells have proven the possibility of production enhancement in unconventional liquid reservoirs (ULR). However, numerical simulation studies regarding EOR techniques neglect two important features of the ULR: extensive fracture discontinuity and high fracture density. This work explores how these two features effect depletion forecasts and EOR evaluation in ULR by applying discrete fracture network (DFN) modeling and optimized unstructured gridding.
In this study, grid generation algorithms for Perpendicular Bisection (PEBI) gridding are improved to handle reservoirs with complex fracture geometry and high fracture intensity. The depletion behavior of the dual-porosity methods and the DFN method are compared based on the "sugar-cube" conceptual model. Data including outcrop maps and FMI log are used to characterize fracture network geometry and build DFN models to represent realistic stimulated tight reservoirs. Dynamic fluid flow models are calibrated through history matching of depletion. To properly model EOR processes at the field scale, results from publications of lab experiments regarding surfactant imbibition and CO2 huff n' puff are used to generate simulation parameters. A series of surfactant spontaneous imbibition and gas huff n' puff simulations are performed on those calibrated DFN models to study the impact of fracture geometry on EOR performance.
Simulation results indicate that dual-porosity methods are not correct if the transient period of fracture-matrix flow lasts for extaned periods or the continuity of fractures is poor, both of which are very common in ULR. By tuning parameters within a reasonable range, DFN dynamic fluid flow models match the production data and can represent the realistic stimulated ULR. Surfactant assisted spontaneous imbibition (SASI) in the matrix domain results in a marginal production increase compared to water imbibition. It is found that wettability alteration incurred in the fracture system may play a more important role in production enhancement. Simulation results of gas huff n' puff indicate the main recovery mechanisms are re-pressurization and viscosity reduction characteristic of multicontact miscibility. And for reservoirs below the bubble-point, another recovery mechanism is the increase of heavy components' flux. However, either increasing the soak period or increasing the portion of the production period in each cycle has a minor effect on recovery enhancement.
This study reveals the significance of using DFN with the unstructured grid to study the EOR processes in ULR. This approach can capture the rapid and extreme change in phase saturation and component fraction within the stimulated reservoir volume (SRV). Our results demonstrate the important factors that affect the field-scale EOR performance in ULR.
Wettability Altering Surfactants for High Temperature Tight Carbonate Reservoirs
Authors: Alammari Faisal G. , Miller Chammi S. , Mohanty Kishore K. 
Published: August 2020

Abstract
Most tight carbonate reservoirs have low oil recovery factors after the primary and secondary recovery stages. High-temperature carbonate reservoirs tend to be oil-wet/mixed-wet due to positively charged minerals and negatively charged oil molecules, hence reducing oil relative permeability. This study aims to enhance oil recovery from tight carbonates by virtue of wettability alteration using surfactants. Twenty different surfactants of different classes and different functional groups are systematically evaluated by first testing their aqueous stability at reservoir conditions. The aqueous stable surfactants were tested for contact angles on the mineral surface. Seven surfactant candidates were selected for spontaneous imbibition experiments, where oil recovery was monitored as a function of time. Wettability-altering surfactants increase the oil recovery by spontaneous imbibition. Up to 190% increase in oil recovery from outcrop core plugs was observed compared to the control sample with sea water.
Visualization the Surfactant Imbibition at Pore Scale by Using of Fractured Micromodels
Authors: Yu Fuwei , Jiang Hanqiao , Ma Mengqi , Xu Fei , Su Hang , Jia Junjian 
Published: August 2020

Abstract
Recovery in low permeability oil reservoirs is challenging because they are often high fractured and oil-wet. Microemulsion-forming surfactant solutions, which can replace oil from tight matrix by imbibition, have been verified as effective enhanced oil recovery fluids for tight reservoirs. To better understand the mechanisms of oil recovery from oil-wet, fractured rocks using microemulsion-forming surfactants, microfluidic experiments including single channel micromodel tests and fractured micromodel imbibition tests which could visualize the in-situ phase changes were conducted in this work. Through on our study, the priority of wettability alteration and phase change with a function salinity was clarified. Besides, the imbibition dynamics of microemulsion-forming surfactants at different salinities were provided, and further understanding about the equilibrium process of microemulsion during imbibition was obtained. Based our studies, we suggest a moderate salinity for microemulsion-forming surfactants enhanced imbibition recovery.
Offshore Polymer EOR Injection Philosophies, Constrains and Solutions
Authors: Flavien Gathier , Christophe Rivas , Lionel Lauber , Antoine Thomas 
Published: August 2020

Abstract
In the past decade, the number of polymer injection projects has greatly increased worldwide, with more and more full field implementations. More recently, the focus has shifted toward the deployment of such technologies offshore which presents very specific constraints in terms of facilities, logistics and produced water treatment.
One restraint is related to the surface facilities and the footprint available to install the required equipment. This can have a great impact on the choice of the chemical form; two forms are usually considered (powder or emulsion) which dictate the type of equipment necessary and the complexity of the injection process.
Other factors come into play when choosing the product form, including weather conditions, available storage, logistics and the existing infrastructure. Many projects are being constrained by the presence of subsea chokes, which can degrade the polymer solution and compromise the economics if not dealt with adequately.
In this paper we will review the existing projects and discuss the offshore deployment philosophies for polymer injection. Then, the focus will be on brown fields and the differences between polymer emulsion and powder forms and how both can be processed in the field. Specific highlights will be on polymer design and selection, equipment and logistics for a real field case.
Recent developments will be presented in relation to viscosity preservation during injection even in the presence of subsea chokes. Different approaches will be proposed including the deployment of non-degrading chokes or the use of Delayed Viscosity Polymer.
Use of In-Situ CO2 Generation in Liquid-Rich Shale
Authors: Ogbonnaya Onyekachi , Wang Shuoshi , Shiau Benjamin , Harwell Jeffrey 
Published: August 2020

Abstract
Modified in situ CO2 generation was explored as an improved tool to deliver CO2 indirectly to the target liquid rich shale formations. Once injected, the special CO2- generating compound, urea, decomposes deep in fractures at the elevated temperature conditions, and releases significant amounts of CO2. For field implementation, the minimum surface facility is required other than simple water injection equipment. Injection of urea solution may be easier and cheaper than most gas injection approaches.
In this effort, in situ CO2 treatment and designs were carried out on a group of Woodford shale core samples. The oil saturated shale cores were soaked in different urea solutions kept in pressurized (1500 and 4000 psi) and heated extraction vessels at temperature of 250 °F. The adopted treatment step closely simulates the huff-and-puff technique. A series of experiments were run with various ingredients, including brine only, brine plus surfactant, brine plus urea and ternary mixture of brine/surfactant/urea. In addition, the extraction experiments were tested at below and above MMP conditions to decipher the principal recovery mechanism.
Based on our preliminary observations, the sample cores did not lose their stability after an extended period of oil extraction with in situ CO2 treatment. The urea only case could recover up to 24% of the OOIP compared to about 6% for the brine only case and 21% for the surfactant only case. Also adding a pre-selected surfactant to the urea slug did not have any benefit. There was no significant difference in oil recovery when the test pressure was below or above MMP. The main recovery mechanisms were oil swelling, viscosity reduction, low interfacial tension and wettability alteration in this effort.
Multiple researchers reported successful lab scale CO2 gas extraction EOR experiments for liquid rich shale like upper, middle and lower Bakken reservoir. The best scenario could recover 90% of the OOIP from the shale core samples. The evidences of this effort offer a strong proof of concept of in situ CO2 generation potential for liquid rich shale reservoirs.
Practical Chemical Formulation Design – Time to Break Away from Micellar Polymer Floods, Again
Authors: Dean Elio , Pitts Malcolm , Wyatt Kon , James Dean , Mills Kathryn , Al-Murayri Mohammed , Al-Kharji Anfal 
Published: August 2020

Abstract
With a resurgence of chemical EOR opportunities throughout the world, high concentration surfactant design has re-emerged its uneconomic face. High concentration surfactant formulation is the micellar polymer design from the past that produced high oil recoveries in the lab but were uneconomic in the field. Formulation designs must consider factors beyond simply oil recovery for economic success and to minimize production issues in the field.
Analysis and comparison of micellar polymer design projects from the 1970-1980s to current SP/ASP formulation designs are discussed. A simple formulation cost calculator is showcased, costs of all formulations are presented, and price per incremental barrel produced (chemical cost only) are shown assuming a 0.1 PV of incremental recovery.
Analysis concludes the following:
Micellar polymer floods were phased out because they were uneconomic. Key reasons are high cost of surfactant and emulsion problems faced when produced surfactant concentration exceed a certain threshold resulting in either greater production cost or disposal of produced oil in the form an unbreakable emulsion. Alkali can improve economics as a low-cost commodity product that can be used to reduce surfactant concentration required to attain high oil recoveries. Alkali is an order of magnitude lower cost per pound than the typical surfactant and can be used as an enhancing agent to improve the performance of other injected chemicals. Alkali is not a "silver bullet" that will save economics, and adds challenges and cost for water softening, which can be economically detrimental to field projects. Many high concentration surfactant formulation floods are being re-introduced to the industry. Not only are these designs un-economic but include multiple chemicals that add complexity and cost to the facilities and difficulty for facility personnel. A formulation that requires more than $20 of chemical per barrel of incremental oil is unlikely to be economic with $50/bbl oil. Key differences between laboratory results and field implementation results are discussed. Geologic uncertainty is addressed since it is the greatest challenge to field economic success.
The industry is taking steps back to an uneconomic time of chemical EOR by obscuring the difference between designs meant to increase reserves (economic oil) versus those that serve an academic or research purpose. Operators are unwittingly paying the price to advance the science of chemical EOR when service companies provide formulations that are not economic. This paper is meant to remind the industry that high concentration surfactant formulations never were economic and certainly will not be economic in today's price environment.
Improving Polymerflood Performance Via Streamline-Based Rate Optimization: Mangala Field, India
Authors: Chen Hongquan , Park Jaeyoung , Datta-Gupta Akhil , Shekhar Sunit , Grover Kavish , Das Joyjit , Shankar Vivek , Suresh Kumar M. , Chitale Ashish 
Published: August 2020

Abstract
This paper describes a novel streamline-based rate allocation approach to maximize oil recovery from polymerfloods and its application to an ongoing polymerflood in the Mangala field, India which is one of the largest polymerfloods in the world. With over 130 injectors and producers, the field-scale optimization is challenging because of the long simulation times, operational constraints at the well, group and field level and changing field conditions.
The FM-1 unit which is the main producing zone of the Mangala field comprises of multi-layered single storied fluvial channel sands of thickness ranging 3-10m with excellent flow characteristics. The gross thickness of FM-1 is about 90m. The sand is under a five-spot pattern polymerflood with a well spacing of aproximately 200m. A finite difference simulator is used for modeling the polymerflood performance with all relevant physics (mobility control, adsorption, residual resistance factor, polymer rheology/shear thinning, inaccessible pore volume and time-dependent degradation). Streamlines are generated from the flux field extracted from the finite difference simulation and are used to calculate pair-wise efficiency for each injector-producer streamline bundle. The pair-wise efficiency quantifies how much oil is recovered given a barrel of water injection. The streamline-based optimizer iteratively reallocates the fluids to injectors and producers by diverting the injected fluid to high efficiency pairs located in unswept oil regions. After optimization, injection efficiency plots as well as streamline/time of flight plots are used to examine and visualize the flow pattern changes leading to the improved flood performance.
The reservoir model is first calibrated with 10 years of waterflood history. The polymer injection concentration and tapering schemes are determined based on extensive laboratory experiments. The optimization focuses on reallocating the well rates while maintaining the well, group and field level constraints. Two optimization scenarios were studied to examine the potential benefits of rate allocation: (1) optimization of rate allocation for both injectors and producers, (2) optimization of rate allocation for injectors only. Both the scenarios yield improved oil recovery (~5 MMSTB), accelerated production and reduced polymer usage (utility factor). The streamline and injection efficiency plots clearly reveal regions of improved sweep efficiencies, providing an intuitive explanation of the enhanced performance.
A 1D Analytical Solution to Determine Residual Oil Saturations from Single-well Chemical Tracer Test
Authors: Doorwar Shashvat , Tagavifar Mohsen , Dwarakanath Varadarajan 
Published: August 2020

Abstract
Single well chemical tracer tests (SWCTT) have been extensively used in the field to estimate residual oil saturation in a reservoir for more than 50 years. They are often used as characterization methods to gauge EOR potential/performance. Therefore, an accurate estimation of Sor from SWCTT's is critical. Current approaches for SWCTT interpretation use a combination of history matching with numerical modeling tools or use of an approximate analytical technique developed for partitioning interwell tracers. History matching is more accurate, requires multiple assumptions and can be potentially time consuming. The basic analytical solution for partitioning inter-well tracer neglects tracer hydrolysis and provides approximate estimations of Sor. We solve for the exact solution of the 1-D convection-reaction solution using the modified method of moments. No additional simplifying assumptions such as slow reaction rate, fast flowback etc. were made while solving the flow equation. We tested the resulting exact solution against synthetic numerical simulations and 50+ published field cases and compared actual versus calculated oil saturations. The synthetic tracer data was generated for different heterogeneities, tracer reaction rate, partition coefficients and tracer soak time. Analysis of the synthetic SWCTT result shows that our analytical approach correctly estimates oil saturation. The calculated residual oil from our analytical model was consistently within ±0.02 saturation units while the original analytical model consistently underpredicts oil saturation.
Novelty of this model is in its simplicity in calculating residual oil saturation from SWCTT's. The model requires only tracer concentration histories as an input to be able to calculate the near-wellbore residual oil saturation. The developed method can be solved directly in Microsoft excel without requiring any advanced computation/simulation tools.