bluuebunny/crossref_metadata_2025_split huggingface dataset:
Predict Reservoir Fluid Properties from Advanced Mud Gas Data
Authors: Yang Tao , Yerkinkyzy Gulnar , Uleberg Knut , Arief Ibnu Hafidz 
Published: October 2020

Abstract
In a recent paper, we published a machine learning method to quantitatively predict reservoir fluid gas oil ratio (GOR) from advanced mud gas (AMG) data. The significant increase of the model accuracy compared to traditional modeling approaches makes it possible to estimate reservoir fluid GOR based on AMG data while drilling, before the wireline operation. This approach has clear advantages due to early access, low cost, and a continuous reservoir fluid GOR for all reservoir zones. In this paper, we release further study results to predict other fluid properties besides GOR, which is essential for geo-operations, field development plans, and production optimization.
We use two approaches to predict other fluid properties. For the first approach, we develop machine learning models for reservoir fluid density, similar to the GOR prediction approach in the previous paper. Based on an extensive fluid database, we establish machine learning models to predict reservoir fluid density from C1 to C5 compositions (same format as AMG data). As the second approach, instead of developing a machine learning model for individual fluid property from C1 to C5 compositions, we investigate the most important properties for EOS fluid characterization: C6 and C7+ compositions, and molecular weight and density of C7+ fraction. Once these properties are in place, the entire spectrum of fluid properties can be calculated with the equation of state (EOS) model.
The results of fluid property prediction are satisfactory with both approaches. The reservoir oil density prediction has a mean average error (MAE) of 0.039 g/cm3. The accuracy is superior to typical density derived from the pressure gradient from wireline logging data. For the essential fluid properties required for EOS model prediction, the overall accuracy is acceptable compared with laboratory measurements. The reservoir fluid properties predicted from the EOS model are similar or better than the predictions from individual machine learning models. We applied the field measured AMG data into the fluid property models and achieved reasonable results, as illustrated by the reservoir fluid density example.
The paper completed the methodology to predict all fluid properties based on AMG data. This work paves the way to generate a complete reservoir fluid log for all relevant fluid properties. The method has a significant business impact due to the full coverage of reservoir fluid properties along the well path compared with the availability of discrete PVT samples. The advantage of providing fluid properties in all reservoir zones along the well path far outweighs the limitation of somewhat reduced fluid property accuracy.
The Effect Particle Size Distribution of Granular LCM on Fracture Sealing Capability
Authors: Lee Lu , Dahi Taleghani Arash 
Published: October 2020

Abstract
Lost-Circulation Materials (LCMs) are used to control and mitigate fluid loss problems by fracture sealing. Without a proper lost-circulation technique, an increase in non-productive time (NPT) and well control problems may occur. A good design in the LCMs to seal fractures and to successfully prevent the occurrence of a serious lost-circulation event can alleviate a heavy drilling budget. Various LCMs exist in the market, of which can be broadly categorized as fibrous, flaky, or granular. Granular LCMs are effective in sealing fractures and are of low cost. A successful bridging and sealing from the LCMs depend on their mechanical strengths, shapes, sizes, and particularly, the particle size distribution (PSD). In this paper, the computational fluid dynamics (CFD) and the discrete element method (DEM) are coupled to simulate the sealing capabilities of granular LCMs on different PSDs. A single smoothed fracture is created for the study of such phenomenon. The dynamic process of fracture sealing involves the initiation of bridging from large particles and the effective particle packing to form a seal, thereby reducing the fluid loss. It is found that the LCMs with bimodally distributed sizes can achieve effective fracture sealing. The coarse LCMs should be close to the average fracture size, where accurate measurement is required. The median of the fine to coarse LCM sizes should not exceed 0.67 for fracture sealing to occur. The LCM blend consists of coarse and fine LCMs, where the fine to coarse LCMs by volume is around one third.
Effectiveness of a Smart Hydrogel in Well Leakage Remediation
Authors: Welch Nathan , Gilbertson Robert , Boukhalfa Hakim , Roback Robert , Carey J. William , Goodman Harvey , Rösli Ursula , Gisiger Jocelyn , Espie Tony , Minnig Christian 
Published: October 2020

Abstract
Leakage in carbon storage and hydrocarbon wells continues to be an area of concern in the development and abandonment of reservoirs. Industry need for a leakage remediation sealant that can perform in systems beyond the capability of cement squeezes has driven the development of a CO2/pH activated "smart" gel. Exploratory laboratory tests and a mock field scale well test were performed to determine the effectiveness of the smart gel. Control of the smart gel particle size distribution was demonstrated through batch synthesis experiments. Microfluidic experiments show some of the mechanisms leading to the successful sealing of an engineered fracture system. Initial and subsequent testing of the deployed smart gel in a leaky mock well completion proves the effective scale up of the smart gel sealing capability and can further drive wider adoption of this unique technology.
Laboratory Visualization of Enhanced Gas Recovery in Shale
Authors: Elkady Youssef , Kovscek Anthony 
Published: October 2020

Abstract
In this work, we lay the experimental groundwork for measuring CO2 storage, and other industry-relevant gases, in shale on a core scale. This works emphasizes the role of adsorption on gas storage using two core samples (one Eagle Ford and one Wolfcamp). Mass balance and Computed Tomography (CT) methods are used independently to co-validate our results. The validation process allows for confidence in the accuracy of the CT visualizations. In addition, the CT method significantly reduces the characterization time needed for measuring gas storage before running any further investigations related to gas flow and recovery.
The pulse-decay technique is initially used to quantify apparent porosity, permeability, and adsorption for He, N2, Kr, CH4, and CO2 at room temperature (and 42 °C in some cases) up to 800 psia pore pressure. In the case of Kr, Eagle Ford core (EF1) is imaged at the end of each pressure pulse step to compare CT-derived to pulse decay derived results. At 650 psia, CO2 and Kr storativity (SCF of gas per ton of rock) in sample EF1 have roughly 4.5× and 2× the storativity of He, respectively. Absolute adsorption of CO2 (181 SCF/Ton) is significantly greater than N2 (5 SCF/Ton) and Kr (45 SCF/Ton) at 650 psia pore pressure. Furthermore, our proposed CT approach yields a good match to the mass balance characterization results for Kr as opposed to the conventional CT formulation.
Permeability results show negative correlation between adsorption affinity of gas and sample liquid-like permeability. In the case of Kr and N2 measurements on sample EF1, the greater compressibility of Kr is overcome by its larger adsorption affinity resulting in a greater than N2 permeability at lower pore pressures but lower permeability at higher pore pressures. The Wolfcamp sample (WC2) captures a potentially irreversible effect of CO2 on permeability attributed to either permanent matrix swelling or matrix softening.
This study bridges both CT and mass balance derived results to ensure accurate visualization of the physics during characterization. Both methods show a better displacement of in-situ Kr (proxy for CH4) with CO2 as compared to N2 injection. CT visualizations of both gas displacement experiments show two relatively permeable flow pathways emerge during early times.
Reservoir Implications of Measured Thermodynamic Equilibrium of Crude Oil Components: Gases, Liquids, the Solid Asphaltenes, and Biomarkers
Authors: Mullins Oliver C. , Johansen Yngve Bolstad , Achourov Vladislav , Chen Qing , Cañas Jesus Albert , Chen Li , Pomerantz Andrew E. , Forsythe Julia C. , Betancourt Soraya S. , Bayestehparvin Bita 
Published: October 2020

Abstract
The process of compositional equilibration of reservoir crude oil requires excellent reservoir connectivity. For example, the measured of asphaltene gradients for indications of connectivity is now commonplace. In addition, equilibrated fluids imply various other important fluid and reservoir properties. However, some measurements of distinguishing equilibration from disequilibrium have been ambiguous. Here, we provide measurement protocols which provide robust determination of equilibrium within a framework of reservoir fluid geodynamics. Thermodynamic modeling of measured asphaltene gradients vertically and laterally with considerations of solution gas provides a robust determination of equilibrium. In addition, two-dimensional gas chromatography with its high-resolution compositional evaluation especially within a geochemical context can corroborate conclusions from asphaltene gradient analysis. Outlier locations in the reservoir can often be found and aid considerably in delineating the important reservoir fluid geodynamic processes operative in the reservoir and validating the assessments regarding equilibrium. The evolution of lateral equilibration is shown in a reservoir with known initial (at time of charge) and present-day lateral gradients. Modeling clarifies the convection which has occurred over geologic time to minimize these lateral gradients. Different processes of mass transport in reservoirs are compared. Equilibration processes and corresponding asphaltene gradient measurements are analyzed for differing geologic times including a very young (Pleistocene and Pliocene) and very old (Cretaceous) reservoir charges in different reservoirs. The important role of convection is shown, with its critical requirement of a density inversion.
Using Production Data to Constrain Resource Volumes and Recovery Efficiency in the Marcellus Play of West Virginia
Authors: Boswell Ray , Carney B. J. , Pool Susan 
Published: October 2020

Abstract
Recovery efficiency (RE) is a poorly constrained parameter with respect to unconventional resource development. However, the increasing volume and quality of data related to Marcellus development in West Virginia provide an opportunity to assess this parameter. In this report, we develop a map of estimated ultimate recovery (EUR) per square mile (mi2) for the Marcellus Play in West Virginia and compare that map to published estimates of both technically recoverable resources (TRR) and original gas-in-place resources (GIP). These comparisons reveal that Marcellus wells appear capable of producing significantly more gas than previously estimated and, throughout large areas of the State, more gas than has been assessed to be in place. While explanations for this observation likely include both potential overestimation of EUR and underestimation of GIP, our review indicates that a primary source of the discrepancy is overly-conservative GIP calculations. New GIP calculations have been conducted for a range of wells that appear to account for the bulk of the "excess gas" by including GIP volumes from bounding formations determined likely to be part of the larger Marcellus Reservoir Unit (MRU). In northeastern West Virginia, the MRU includes both the Marcellus Formation and the lower 300 ft of the Mahantango Formation. In northwestern West Virginia, units up to the Cashaqua Shale Member of the Sonyea Formation are included in the MRU. These new GIP/mi2 values, when compared with our estimates of TRR/mi2, indicate that ultimate RE for ongoing development generally ranges between 20 to 60%.
Our approach to estimate TRR/mi2 is based on identification of 166 Marcellus "development sites" in northern West Virginia. Each development site was selected to consist of multiple horizontal wells that were drilled as a coordinated activity at a common spacing over a short period of time by a single operator. Sites and wells also were selected to maximize both the relevance (post 2012 vintage wells where possible) and reliability (more than 18 months production history) of the EUR forecasts. Site area was determined as the product of cumulative lateral length and well spacing. The cumulative EURs for all wells in each site were estimated (using two independent sources for EUR estimation) and those sums were divided by the area to obtain a single point estimate of TRR/mi2. Our review indicates that Marcellus Play resource assessments tend to be overly conservative. This analysis shows the value of focusing on the most relevant production data and using those data as a ground truth check on resource assessments.
A Numerically Optimized WAG Injection Strategy for Successful Implementation of Foam Assisted Gas EOR
Authors: Katiyar Amit , Nguyen Quoc 
Published: October 2020

Abstract
The objective of this paper is to numerically determine necessary constraints of a novel water-alternating-gas (WAG) foam injection strategy for conformance correction and improved oil recovery with gas-EOR applied in conventional reservoirs.
A 3D 5-spot reservoir simulation model is created that simplistically captures a severe vertical conformance problem in a CO2 WAG flood. This simulation model is run on a conservative WAG strategy to lead the model to a mature gas flood state. An empirical foam model is used to implement the foam assisted gas EOR in this simulation model and determine the necessary injection constraints for its successful production-enhancing field deployment.
The simulation results of the gaseous-foam EOR technology applied in 5-spot model show that the constant rate foam injection is ideal for conformance correction and improved oil recovery even if the baseline WAG operation is maintained. Typically, most of the current WAG fields operate at constant surface pressure. The simulation results show that with constant surface pressure and baseline WAG operation, foam generation results in loss of injected gas rate and volume and potentially limits the oil recovery even with improved conformance. To mitigate this productivity gap, foam WAG strategies with higher gas water ratios (GWR) were investigated. It is first confirmed that in a pattern with conformance issues, higher GWR makes the typical gas floods even worse. However with constant surface pressure foam injection, higher GWR allows ideal gas-water mixing ratios for stronger foam generation without impacting the target injection gas volume and reservoir pressure. In addition, during foam injection, higher injection pressure than baseline can further allow maintaining baseline gas injection rates and volumes that results in improved oil recovery with more uniform gas sweep.
Prior field tests of gaseous foam conformance solution have, at times, shown inconclusive results. This study is critical to identify the limitations of the gaseous foam-EOR technology applied under constant surface pressure constraints and to provide potential solutions through optimized GWR and/or injection pressure.
Improving ESP Run Lives on Aggressively Declining Wells: A Case Study in the Permian Basin
Authors: Escobar Katherine , Gibson Matthew , Watson Arthur , Duran Salvador , Andara Oswaldo 
Published: October 2020

Abstract
The current strategy for many operators of US land has moved to increase production during the early stages of new wells to maximize immediate cash flows and rate of return. Electric submersible pumps (ESPs) have long been an accepted and widely used artificial lift method capable of moving high volumes of fluid with relatively moderate efficiencies and run lives. Nevertheless, in some plays in the Permian Basin, the technical requirements for artificial lift systems has increased, especially for ESPs. For the specific case of this study based on almost 40 wells in the Spraberry field, rapidly declining flow rates starting around 5,000 bbl/d and declining to 2,000 bbl/d or less in only two to four months, have inevitably forced the current pump stages to work significantly outside of their recommended operating range (ROR).
Even though compression pumps were designed to extend operation outside of their ROR and onto the left side of the curve, the aggressive decline rates seen in this case study have shown how excessive downthrust can still be a concern on compression construction pumps. This paper comprises a case study of pulled equipment that was operating significantly below the ROR. This operating condition led to severe net down thrust force, axially deflecting the components downward.
After the production challenges were analyzed and the pulled ESPs showed evidence of excessive downthrust, a new pump stage and ESP design were proposed to increase the flexibility of the ROR and adapt to the rapidly declining flow rates. This new technology was initially developed for the Bakken, and due to its proven flexibility, its use has been extended to more unconventional and conventional plays across the US. Even when the production declines and the pump's operating point moves to the flat section of the head-rate curve, the data on this study has shown that the features of the new stage such as hydraulic improvements, increased axial stiffness and additional travel, have led to enhancements in downthrust management. Ultimately, this translated into 31% run life improvement for the operator. Finally, due to the improvements on the design with a reduced number of stages, power consumption has decreased and impacted the cost of barrel produced.
An End-to-End Deep Sequential Surrogate Model for High Performance Reservoir Modeling: Enabling New Workflows
Authors: Navratil Jiri , De Paola Giorgio , Kollias Georgos , Nadukandi Prashanth , Codas Andres , Ibanez-Llano Cristina 
Published: October 2020

Abstract
Despite considerable progress in the development of rapid evaluation methods for physics-based reservoir model simulators there still exists a significant gap in acceleration and accuracy needed to enable complex optimization methods, including Monte Carlo and Reinforcement Learning. The latter techniques bear a great potential to improve existing workflows and create new ones for a variety of applications, including field development planning. Building on latest developments in modern deep learning technology, this paper describes an end-to-end deep surrogate model capable of modeling field and individual-well production rates given arbitrary sequences of actions (schedules) including varying well lo-cations, controls and completions. We focus on generalization properties of the surrogate model which is trained given a certain number of simulations. We study its spatial and time interpolation and extrapolation properties using the SPE9 case, followed by a validation on a large-scale real field. Our results indicate that the surrogate model achieves acceleration rates of about 15000x and 40000x for the SPE9 and the real field, respectively, incurring relative error ranging between 2% and 4% in the interpolation case, and between 5% and 12% in the various spacial and time extrapolation cases. These results provide concrete measures of the efficacy of the deep surrogate model as an enabling technology for the development of optimization techniques previously out of reach due to computational complexity.
A Comprehensive Rheological Characterization of HPAM-Based Polymers for the Potential EOR Implementation
Authors: Karimov Damir 
Published: October 2020

Abstract
Polymer flooding is well-established and effective independent technique for improving oil recovery. However, this method is not considered viable due to the limitations such as retention at the unfavorable conditions, weak stability in the presence of divalent ions, high cost and its inability to work under high temperature-high salinity conditions. For that reason, this paper will evaluate the proper conditions and criteria for the successful implementation of polymer flooding.
Four different partially hydrolyzed polyacrylamide (HPAM) based polymers were prepared using standard API procedure for polymer preparation. The effect of concentration and temperature and concentration was evaluated through different rheological measurements. The experimental studies on evaluating the performance and stability of polymers were investigated by performing long-term thermal stability and mechanical degradation tests. Thus, comprehensive rheological studies with partially hydrolyzed polyacrylamide (HPAM) based polymer solutions were designed for defining suitable polymer solution.
The preliminary experimental work was carried out at 25-80 °C temperature range and at different concentrations (1000-3000ppm). All four HPAM based polymer solutions showed a typical non-Newtonian rheological characteristic with shear thinning behavior. The obtained results also showed the dependence of the polymer viscosity on the concentration and temperature. As a result, Flopaam 5115 retained and showed the maximum viscosity comparing to other polymer solutions under these conditions. Then, the performance and stability of polymers was tested through different sets of rheological experiments such as long-term thermal stability and mechanical stability tests. In this case, Flopaam 5115 also showed good thermal and mechanical resistance at 80 °C for more than one hundred days and at 23900rpm, respectively.
Through the series of different rheological experiments, we identified the most suitable polymer and the conditions that would not disturb the performance and effectiveness of the particular solution. A comprehensive study on the screening different HPAM solutions showed promising results for a future investigation in this direction. The research based on different screening parameters such as concentration, temperature, time, and mechanical exposure was found to be vital for the successful implementation of polymer flooding on a field.