bluuebunny/crossref_metadata_2025_split huggingface dataset:
Application of Tracer Based Workflow for Calibrating Reservoir Heterogeneity
Authors: Doorwar Shashvat , Purswani Prakash , Ambastha Anil , Jain Lokendra , Thach Sophany 
Published: August 2020

Abstract
Capturing the correct reservoir heterogeneity in a geological model is critical for designing and accurately forecasting expected production benefits from improved/enhanced oil recovery (IOR/EOR) processes. In simple terms, reservoir heterogeneity is often considered as a measure of statistical variation of static properties, such as porosity and permeability. Lorenz coefficient and Dykstra-Parsons coefficient are two such measures of reservoir heterogeneity that account for these static effects. These measures are considered simplistic because the spatial distribution and arrangement of these properties is more critical for reservoir characterization than its statistical variation. Dynamic Lorenz coefficient is one such measure that accounts for the spatial distribution and arrangement of porosity and permeability. Dynamic Lorenz coefficient cannot be directly measured in the field but can be implicitly inferred from tracer data. This inferred heterogeneity will be influenced by the spatial distribution of static properties and can also be significantly influenced by multiphase flow effects, such as, viscous fingering and gravity over/under-ride which often arise from the differences in the viscosities and densities of the different phases involved. Dynamic Lorenz coefficient interpreted from a tracer test response lumps both static and multiphase (dynamic) effects into one measure of heterogeneity. During geological model construction, dynamic Lorenz coefficient is also used to rank the model in terms of heterogeneity to select the most representative model. However, the geological models are ranked using fast single-phase/streamline simulations and are devoid of complications caused by adverse mobility or density effects. This creates a disconnect between the heterogeneity measures used to characterize a geological model and those available to characterize a reservoir. Thus, calibrating a geological model to field data is a laborious task.
In this paper, we present a workflow that bridges this gap by decoupling the effect of adverse mobility to obtain an approximate measure of heterogeneity that can be cross-checked against the geological realizations to select the most representative model. The workflow developed in this paper is for inverted, seven-spot patterns and is mainly focused on water-wet reservoirs.
EOR Screening Including Technical, Operational, Environmental and Economic Factors Reveals Practical EOR Potential Offshore on the Norwegian Continental Shelf
Authors: Smalley P. Craig , Muggeridge Ann H. , Amundrud Sølvi S. , Dalland Mariann , Helvig Ole S. , Høgnesen Eli J. , Valvatne Per , Østhus Arvid 
Published: August 2020

Abstract
We present a novel advanced EOR screening approach, adding to an existing technical screening toolkit powerful new practical discriminators based on: (1) Operational complexity of converting existing offshore fields to new EOR processes; (2) Environmental acceptability of each EOR process, given current field configuration; (3) Commercial attractiveness and competitiveness. We apply the new approach to 14 EOR processes across 85 reservoirs from 46 oilfields and discoveries on the offshore Norwegian Continental Shelf (NCS).
When the operational, environmental and economic thresholds were included, 45% of the technical opportunities were screened out, and the overall potential recovery increment was ~280 MSm3 (million standard cubic metres), the top processes being HC miscible, low salinity/polymer, low salinity, CO2 miscible, gels. Excluding environmental factors (i.e., assuming environmental issues could be solved by new technologies), the increment is ~340 MSm3, indicating a ~60 MSm3 prize for research into environmentally benign EOR methods. The economic thresholds used here were intentionally set low enough to eliminate only severely commercially challenged opportunities; using higher commercially competitive thresholds would reduce the overall volumes by a further ~40 MSm3.
The extension of EOR screening to include operational, environmental and economic criteria is not intended as a substitute for in-depth studies of these factors, but it should help stakeholders make earlier and better-informed decisions about selection of individual EOR opportunities for deeper study, leading to piloting and eventual field-scale deployment. Revealing the sensitivity of each EOR process to operational, environmental and economic factors will also help focus R&D onto the practical, as well as technical, barriers to EOR implementation.
Successful Foams EOR Field Pilot in a Naturally Fractured Reservoir by the Injection of the Foaming Agent Dispersed in the Gas Stream
Authors: Ocampo Alonso , Restrepo Alejandro , Clavijo Julian , Mejía Juan M. 
Published: August 2020

Abstract
This work presents the concept, progression, execution and results for a successful field implementation for a new technique to create insitu blocking foams in a gas condensate naturally fractured reservoir by the injection of the foaming agent dispersed in the hydrocarbon gas stream. This new technique aims at simplifying the operation and reducing the footprint and costs for the deployment of EOR foams in gas injection based projects. It also helps to overcome the disadvantage of limited reservoir volume of influence obtained by the SAG technique.
The selected field area for the pilot was confirmed to be naturally fractured dominated both by the production and gas injection performance. The field area had only one oil producer and one gas injector, so monitoring the results of the pilot was simplified. The operation was carefully planned so that a ramp up in foamer solution concentration could be implemented at the field, and the response of the gas injector well could be monitored in real time. Additionally, a gas tracer program was implemented to track the fly times of the gas prior and after the dispersed foam treatment.
About 1000 Bbls of foaming solution were dispersed in the hydrocarbon gas stream in one gas injector of a gas condensate Piedemonte field, whose injectivity performance was confirmed to be highly influenced by the natural fractures. Base gas injection conditions were about 30 MM scfd at 3800 psi WHIP. Once the dispersed foamer injection started, the gas injectivity in the well was progressively reduced to the point of increasing the WHIP to ~5000 psi, and the final gas rate was half of the base. The oil production well influenced by this injector changed its performance showing an increasing ramp in oil production and a reduction of the gas oil ratio (GOR) after the dispersed chemical injection period. The tracking of the gas tracers evidenced a delay in the gas fly times between the injector and the producer wells of two fold (63 days Vs 28 days), as a consequence of the dispersed foam treatment.
This is the first time a successful foam EOR field pilot is done in a naturally fractured reservoir by the injection of the foaming agent dispersed in a hydrocarbon gas stream. It is believed this new foams technique could also be extended to other non-condensable gases at field operating conditions like CO2, Nitrogen, Air, and Flue Gas.
Numerical Simulation of Crossed-Linked Polymer Injection in Dina Cretaceous Field: A Real Field Case Study
Authors: Izadi Mehdi , Jimenez Jaime Alberto , Zapata Jose Francisco , Felipe Castillo Andres , Pinto John , Vicente Sebastian 
Published: August 2020

Abstract
The main objective of this work is to shed light on the mechanism of modeling crossed-linked polymer (CLP) technology, by incorporating real field pilot injection and production data in the Dina Cretaceous field located in the Upper Magdalena Valley (UMV) Basin in Colombia. The paper will highlight why original simulation model predictions differ from the actual observed field data and the predictability of numerical simulation of CEOR process would be discussed and presented. Despite successful application and positive field results in the literature, the propagation of CLP system in porous media has been challenged with conflicting opinions and reports and still remains debatable and uncertain.
This paper will use recent experimental laboratory data in conjunction with actual field data to properly explain the possible mechanism of CLP and offer practical modeling techniques to capture experimental and field data. Therefore a modeling methodology was developed and used to model the field data, this method is based on previous modeling mechanisms with incorporating a new grid-based residual resistance factor (RRF) and pore throat sizes. The model requires a proper understanding of rock typing and populate the permeability distribution based on pore throat sizes. The new modeling mechanism was able to reasonably predict the pilot performance in some of the offset producers.
To model delayed viscosification and adsorption of the CLP process, two approaches has been evaluated and used in the original simulation model, the use of multiple regions and chemical reaction. The chemical reaction rate is tuned to calibrate laboratory data and to model the delayed viscosification and RRF. However recent laboratory experiments explained the possible mechanisms of CLP formation through intra-molecular crosslinking and intra-inter-molecular crosslinking.
In conclusion, because of extensive and numerous laboratory experiments and the conduct of field pilot results, proposed numerical modeling demonstrate the complexity of modeling the CLP system and offers a practical solution to the field applications.
An Investigation into Fluid-Fluid Interaction Phenomenon During Low Salinity Waterflooding using a Reservoir-on-a-Chip Microfluidics Model
Authors: Tetteh Joel T. , Aryana Saman A. , Barati Ghahfaorkhi Reza 
Published: August 2020

Abstract
Injection of modified salinity brines modified salinity brines (MSB), i.e. brine with seawater-like salinity (SWS) and low salinity water (LSW) in oil-wet carbonate rocks is relevant to improved oil recovery operations. Many reports in the literature relate the underlying mechanisms to rock-fluid interactions such as ionic exchange and electrical double layer expansions, which cause wettability alterations at the rock surface. Little attention seems to have been placed on fluid-fluid interactions as a potential mechanism in displacement processes.
In this work, we investigate the role of fluid-fluid interactions in improved oil recovery using MSBs. Interfacial tension and surface elasticity calculations are correlated to visual observations of displacement processes to investigate the role of crude oil snap-off. A series of microfluidic chips featuring pore throats that are 50μm in diameter are used to observe snap-off as a function of salinity in the displacing fluid. The flow experiments suggest that, in a water-wet constricted pore throat, SWS brines suppress crude oil snap-off as compared to FWS brine. This behavior is correlated to the higher surface elasticity of oil-SWS interface than that of oil-FWS interface. Higher surface elasticity suppresses the expansion of the thin water film coating pore throat walls and hence increases the capillary number at which snap-off of the crude oil phase is expected to occur.
Moreover, water interacts with the polar components to form reverse micelles called microdispersions. These microdispersions are observed in the aged chip near the oil-brine interface in the pore-network of a microfluidic device. Similarly, in a vial test performed by Tetteh and Barati, (2019), microdispersion formation was only observed very close to the oil-brine interface, caused by the transport of water molecules into the oil phase. These microdispersions remobilize and redistribute the oil, and along with a slight change in wettability in the medium, they improve the observed recovery. In the pore-network flow experiments, the use of SWS brines resulted in the formation of relatively larger oil droplets, which is attributable to the suppression of crude oil snap-off and enhanced oil coalescence resulting from changes in oil-brine interfaces. The integrated experimental study presented in this work demonstrates the importance of fluid-fluid interactions in improved oil recovery using MSBs.
Pulser Model: Updated Framework and Lessons Learned from Applications in Forecasting CO2 Flood Performance
Authors: Kumar Deepanshu , Bandyopadhyay Parag 
Published: August 2020

Abstract
Reservoir management of Carbon Dioxide-Enhanced Oil Recovery (CO2-EOR) floods is essentially an optimization problem-maximizing the oil recovery while simultaneously minimizing the CO2 injection volumes. Liu et al. (2014) proposed a parametric model of recovery factor as a function of miscible CO2 injected in dimensionless form. Incorporating the lessons learned from application of the model for production forecasting of multiple CO2 floods across the Permian basin, the updated model has better predictive power over the life of the flood. Results from applications to actual field data are also presented.
The Pulser Model is linearized, which allows for faster solution and robust convergence. Algorithmic nuances for regression are described. A physical interpretation of the model parameters is explored so as to facilitate physics-constrained optimization. This allows calibration of parameters to data such as heterogeneity (from core) and CO2 storage capacity of the rock. Sensitivity analysis of model parameters is conducted on field data sets to evaluate relative and physical significance of the model parameters.
Development of Surfactant Formulation for Harsh Environment
Authors: Pinnawala Gayani , Nizamidin Nabijan , Spilker Kerry , Linnemeyer Harold , Malik Taimur , Dwarakanath Varadarajan 
Published: August 2020

Abstract
Good phase behavior is critical for identifying high performance surfactant formulations for coreflood recovery. For conventional CEOR projects, good phase behavior entails high solubilization parameters, rapid equilibration to low viscosity microemulsions and aqueous stability of aqueous surfactant mixtures. For reservoirs with harsh conditions, i.e high temperature (&gt; 90°C), high salinity (&gt;50,000 ppm TDS), high divalent ions (&gt; 1500 ppm TDS), high GOR (&gt;150) and presence of H2S, developing formulations with good phase behavior is challenging. Several carbonate reservoirs have conditions as outlined above and the scarcity of formulations that are stable in the above-described conditions makes surfactant applications challenging. We present results that show the development of surfactant formulations that show good behavior under harsh conditions. We validate the performance with a combination of phase behavior, thermal stability, and coreflood experiments and show that high-performance surfactants can be developed for harsh reservoir conditions.
Improving CO2 Vertical Sweep Efficiency in Tinsley Field with Dedicated Injectors
Authors: Sheikha Hussain , Blackmer Scott Mitchell , Sharaf Essam , Marks Dustin 
Published: August 2020

Abstract
Lower oil production rate, conformance, and poor sweep efficiency are major concerns in an enhanced oil recovery (EOR) flood when implemented across multiple intervals. Oil recovery and flood performance in reservoirs with multiple lobes characterized by heterogeneous rock properties suffer greatly when the lobes are commingled. Tinsley Field is a reservoir with two distinct lobes. Initial development of the EOR flood commenced by commingling injection in the same wellbore and production from the two lobes to decrease the capital cost and boost oil production. Reservoir management of the CO2 flood indicated good sweep was taking place in one lobe. Concerns about the possibility of early breakthrough of CO2 in the dominate lobe, leaving stranded oil in the other lobe, prompted the initiation of a dedicated injection program. Early breakthrough could lead to filling up our compressors more quickly than anticipated, which could increase our capital requirements. Dedicated injection into individual lobes was initiated to improve the sweep efficiency.
The team devised a methodology to select prospective wells and quantify the feasibility of adding new dedicated injectors in some of the existing patterns at Tinsley field. The methodology utilized a combination of geological cross sections to identify areas that are characterized by two lobes separated by a shale barrier or baffle, injection profiles to identify the current CO2 allocation, and an estimation of remaining oil in place. A sector model was constructed to simulate the recovery process and aid in understanding the impact of dedicated injection on oil production rate and recovery from individual lobes.
The study revealed that only two of the three fault blocks can be characterized with an upper and lower lobe. Within those two fault blocks, several producers were identified as having poor conformance with a high remaining oil in place. Numerical results of the simulation model show that without dedicated injectors, the two lobes will be flooded at two different injection rates leaving substantial oil unrecovered because of the different injectivity of each zone. Candidate dedicated injectors were selected and ranked for execution based on our methodology. The early results from the dedicated injection program indicate it will lead to a higher recovery factor in the lower lobe because of dedicated injection into the lower lobe resulting in higher processing rate of CO2.
The methodology presented in this paper provides a logical workflow that can identify areas with stranded oil in a reservoir with multiple zones. Following this process could lead to opportunities to drill dedicated injectors to improve oil production rate, conformance, and recovery factor.
Containment of Water-Injection-Induced Fractures: The Role of Heat Conduction and Thermal Stresses
Authors: Hwang Jongsoo , Zheng Shuang , Sharma Mukul , Chiotoroiu Maria-Magdalena , Clemens Torsten 
Published: August 2020

Abstract
Reservoir cooling by water or waste-water injection can significantly alter the reservoir stress. The out- of-zone fracture growth is substantially affected by this poro-thermo-elastic stress changes occurring in heterogeneous rock layers. No previous study, however, systematically investgated the influence of heat conduction and convection on the associated stress alteration and fracture height growth during the long- term water injection in multiple layers. Without understanding this coupled effect, which occurs over a long-term fracture propagation, it is difficult to capture the conditions for the fractures to breach into the bounding shale layers.
In this paper, we present that the thermal conduction between the injection sand and bounding shale is crucial in predicting the fracture containment during water injection. We developed a fully coupled compositional reservoir/fracturing simulator that solves poro-thermo-elasticity. We used it to simulate 3- dimensional fracture propagation induced by cold water injection and, at the same time, calculate the stress field influenced by the thermo-poro-elastic effect in heterogeneous reservoir layers. Effective stress in the bounding layer is dynamically updated to capture the poro-thermo-elastic effect and associated fracture height growth. We first validate our model with existing analytical solutions and studied a field case. We identify the effects of fluid properties, rock properties, and injection temperature on stress changes and the fracture containment for the first time.
Transport of Biopolymer Scleroglucan in Cores at HTHS Conditions
Authors: Song Haofeng , Mohanty Kishore K. 
Published: August 2020

Abstract
Polymers are extensively used in chemical EOR processes to provide mobility control. Both synthetic polymers (e.g., HPAM) and biopolymers (e.g. Xanthan, Scleroglucan) are used. HPAM and Xanthan, do not show high temperature and high salinity (HTHS) tolerance. The purpose of this study is to evaluate temperature and salinity tolerance of an EOR grade biopolymer, Scleroglucan at HTHS conditions (100 °C and sea water salinity) and study its transport through medium permeability rocks (200-500 mD). In the absence of oxygen and glutaraldehyde, the Scleroglucan solution prepared in synthetic seawater, maintained its viscosity at 100 °C for at least two months. In the presence of a biocide, glutaraldehyde, the biopolymer degraded at 100 °C. Transport of this biopolymer was studied in both Indiana limestone (200~500 mD) and Berea sandstone (~300 mD) cores at 100 °C. The results suggest transport in porous media (~200 mD) without inducing any face plugging.
Bhagyam ASP Pilot: Successful Formulation Development to Pilot Design and Planning
Authors: Jain Shakti , Prasad Dhruva , Pandey Amitabh , Koduru Nitish , Raj Rahul 
Published: August 2020

Abstract
The paper discusses the alkaline surfactant polymer (ASP) flood pilot design including formulation development, pilot area selection, well and pattern type, slug size and sequence, slug viscosity etc for the Bhagyam field. It also discusses the various lab, well and reservoir surveillance techniques planned for the baseline, ASP flood monitoring, residual oil saturation and incremental recovery estimates from the pilot.
The Bhagyam is an onshore field in the Rajasthan state of western India and is part of Mangala-Bhagya m- Aishwariya (MBA) development in the Barmer basin. The main producing unit is Fatehgarh multi -storied fluvial sand stone. Reservoir quality is excellent with permeability in the range of 1 to 10 Darcy and porosity in the range of 25-30%. The crude oil is moderately viscous (15 to 500 cP) and highly active with TAN (total acid number) value of ~2 mgKOH/gm. All the reservoir and fluid properties together with low salinity (5000 ppm) and moderate temperature (54 degC) makes it an ideal candidate for polymer and ASP EOR methods. The field has been developed with downdip water injection and post successful evaluation of long term polymer injectivity test, it is currently under full-field polymer flood implementation. The details of polymer flood injectivity and full-field expansion plans are discussed by Sharma et. al. 2016 and Shankar et. al. 2018.
EOR assessment has been part of the field development planning process from start. Multiple phase behaviour studies and corefloods have been conducted to screen the surfactant and generate necessary parameters for the simulation studies. The formulation consists of combination of sulfate and sulfonate based surfactants. The focus of the pilot area selection has been to utilize the existing well s to maximum possible extent, reduce the geological uncertainty and minimize the interference from ongoing activity in the field. A normal 4 spot pilot with ~150m spacing has been selected together with two observation well for time lapse saturation monitoring and one coring well towards end of pilot for saturation determination.
Dynamic models have been used to design slug size, sequence, viscosity and estimate incremental oil potential. Multiple tracer surveys together with distributed pressure measurements and interference tests are planned to establish connectivity and calibrate model. Initial estimates of pilot incremental oil recovery is in the range of 15-25% of stock tank oil intial in-place (STOIIP) over the polymer flood. Overall pilot design aims at collecting all the necessary data for reducing uncertainty for full-field expansion in a short time frame.