bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experimental Evaluation of Lactic Acid for Matrix Acidizing of Carbonates
Authors: Bettencourt Greyson Soares , Zhu Ding , Hill A. D. , Kamman Chad 
Published: October 2023

Abstract
To improve efficiency of standard HCl stimulation treatments, many alternative acid systems have been developed to mitigate corrosion, increase wormhole efficiency, and divert fluids for better acid coverage. However, these alternative systems come at a price compared to HCl which is cheaper and sufficient in most applications.
Lactic acid is an organic acid that is less corrosive and has reduced reactivity compared to HCl. The advantage and application of lactic acid has not been studied extensively like other alternative acids. To evaluate lactic acid as a viable alternative acid system, we conducted a series of linear core flood matrix acidizing experiments using 40 weight percent lactic acid at two temperatures over a range of injection rates. The goal was to characterize the wormholes created by lactic acid and identify the appropriate condition that lactic acid can outperform HCl. Core flood tests were also conducted at high temperature and lower concentrations to observe change in behavior and performance.
Lactic acid performance was analyzed by comparing pore volumes to breakthrough (PVbt) with previous HCl experiments. Lactic acid was found to be more efficient than HCl at injection rates below optimum for 40 %. At the lower temperature of 150 °F, lactic acid maintained similar PVbt over the range of injection rates.
Wormhole geometry from CT imagery and pressure response data was studied to identify unique characteristics or behavior lactic acid may have. CT images of lactic acid generated wormholes reveal a geometry versus injection rate relationship that is contrary to the conventional understanding of wormhole growth patterns. Images show extensive branching in most low injection rate tests. The results are characterized as appearing to have self-diverting behavior. Pressure differential data across the core shows pressure drop increases in nearly every experiment. For the lower concentration tests, pressure differential increase was not observed for 10 % and 20 % and only occurred at 30 % lactic acid. Precipitation occurred during and immediately after most high temperature experiments and after the 30 % test which is suspected to be plugging permeable channels. Further investigation may provide more insight into the unique capabilities of a simple yet overlooked acid system.
Proppant Flowback Prevention and Control by Analysis of Early Time Well Production Data
Authors: Pandey Vibhas J. 
Published: October 2023

Abstract
Proppant flowback during the post-stimulation well clean up and production is a common occurrence in most hydraulically fractured wells. Whilst some proppant is expected to be produced during the well cleanup operations that typically follow the treatment execution, the long-term production of proppant can be problematic from an economic viewpoint. A thorough analysis of early time production data can be used to develop guidelines that can aid in minimizing the proppant flowback and associated issues.
It is a well-known fact that the production of the proppant from a propped fracture is related to the forces acting on the proppant pack during the well that is actively producing fluids. Some of these, e.g., increase of effective stresses on the proppant, are stabilizing in nature, whereas others related to inertial flow from fluid velocity, viscosity and others can destabilize the pack. Most proppant flow back related studies associate the proppant production with critical flow velocities that are prevalent for given flowing conditions. This important parameter is thus a key to predicting proppant production during the well's producing life. In this study, flow rate and pressure data collected during the post-treatment flowback activity is used in simulating bottomhole (BH) production rates with the help of calculations. Using Gaussian solution scheme, the BH rate is distributed amongst the various perforation clusters while incorporating the effects of key hydraulic fracture characteristics in presence of simulated effective bottomhole flowing pressures across each fluid entry point into the wellbore. The solution is updated at each time step during the simulation. The production allocation is then used for calculation of effective flow velocities which are then compared with critical velocities to determine if proppant production can occur. Steps to mitigate or reduce the flowback, if present, are then recommended based on the analysis.
In the flowback model developed during the study, flowing bottomhole pressures at each sleeve depth was generated with the help of hydrostatic and frictional pressures, and used in forward calculation of total flow rate at downhole conditions. The bottomhole flowrate was then allocated across various sleeves and finally, the associated production fluid velocities were calculated. These were compared with critical velocities corresponding to the fracture associated with each of the sleeves (or perforation set) to determine if there was potential of proppant flowback under the prevailing conditions.
The procedure developed in the study can help in diagnosing conditions that may lead to proppant flowback and thus aid in preventing it by adjusting the controllable parameters during the treatment design and production phase. This technique can be easily implemented on similar completions worldwide.
Horizontal Well Design to Optimize CO2 Sequestration and Oil Recovery in the Permian
Authors: Gang T. , Jones A. , Bandyopadhyay P. , Tovar F. , Bealessio B. 
Published: October 2023

Abstract
This paper presents a reservoir modeling study about positioning horizontal wells to optimize carbon sequestration and oil recovery simultaneously in the Wasson field, which is one of the largest reservoirs in the Permian Basin with 6 billion barrels of original oil in place. A significant portion of this field has been under CO2 injection for enhanced oil recovery for decades, so the CO2 gathering, processing, and distribution network in the area makes the Wasson area extremely cost-competitive as a CO2 storage site. Transitioning the source of CO2 injected in the Wasson area from natural to anthropogenic has the potential to sequester hundreds of millions of metric tons of carbon in the coming decades. Although the traditional development strategy has achieved attractive economic returns in the better-quality rock, novel well configurations are needed to be economically successful as development is expanded to areas with lower rock quality.
We used a compositional, history-matched reservoir model to perform a sensitivity study of lateral section length, horizontal orientation, spacing, and vertical placement for both production and injection wells. We also studied the vertical placement of the wells with respect to the main oil column (MOC) and the residual oil zone (ROZ), a distinctive characteristic of the Permian Basin. In all the scenarios, the MOC is to be co-developed with the ROZ. Since our focus was on the lower-quality rock areas, we selected horizontal wells due to their success in the cost-effective development of tight reservoir rocks. The significant remaining greenfield potential in the Wasson area offers an opportunity for a complete revolution of the development strategy from vertical to horizontal wells.
The most important finding of this study is that the vertical placement of the horizontal injector has a significant effect on oil recovery and lifecycle CO2 retention. Placing the injector close to the bottom of the ROZ and the producers in the MOC resulted in the highest carbon sequestration. The optimized case improved CO2 sequestration by 40% over the base case. The absence of significant vertical flow barriers in the area, along with our prior understanding of the reservoir heterogeneity and CO2 phase behavior, enabled us to optimize well placement to take advantage of gravity drainage. This configuration exposed a larger section of the reservoir volume to the injectant, resulting in a higher sweep efficiency.
Our work provides relevant guidance on the design of future developments using horizontal wells to optimize carbon sequestration and incremental oil recovery simultaneously during CO2 EOR and carbon capture, use, and storage (CCUS) projects. These findings are likely to lead to technical and economic success, even in the poor rock quality areas in the Wasson reservoir, significantly increasing the sequestration and oil recovery potential of this field.
Machine Learning Assisted Petrophysical and Geochemical Reservoir Description Integrating Multi-Scale Well Data
Authors: Xu Chicheng , Jin Yuchen , Lin Tao , Li Weichang , Alzayer Yaser , Ibrahim Zainab 
Published: October 2023

Abstract
Qualitative visual observations of depositional and diagenetic features in core are routinely recorded by geoscientists for geological environment interpretation and reservoir characterization. Quantitative core plug measurements that are typically acquired from laboratory often results in spatially discrete data points. This work applies image analysis and machine learning (ML) workflow to develop continuous reservoir property profiles along the cored interval capitalizing on both discrete core measurements and core visual characteristics.
We introduce a ML assisted workflow that converts core photos into continuous quantitative features that can be integrated with routine core analysis and well logs for integrated reservoir characterization. Visual rock types (VRT) and their associated properties can be predicted based on the quantitative attributes of core photos such as color, brightness, and texture variations by using ML algorithms such as k-means clustering and support vector machine.
We applied the workflow to characterize unconventional reservoirs based on multi-scale well data from the Eagle Ford Shale USA including core photos, core gamma ray, core plug measurements of petrophysical and geochemical properties, and well logs. Inclusion of quantitative, continuous, and high-resolution image attributes significantly enhanced the accuracy of both facies classification and total organic carbon (TOC) prediction. The accuracy of both classification and regression outperformed the benchmark that only used well log data which proves its practical value in reservoir characterization. Successful prediction of reservoir properties from core photos can lead to increased data coverage and resolution to enhance reservoir characterization and reduce the cost associated with destructive tests.
A Novel Approach to Predict Hydrodynamic Forces Using a Mechanistic Model for Pseudo-Slug Flow
Authors: Garcia C. , Sondermann C. Nogueira , Pereyra E. , Sarica C. 
Published: October 2023

Abstract
Pseudo-slug flow is a flow pattern for flow-induced vibration (FIV) applications owing to high force amplitude, which could cause fatigue on pipes and fittings subject to gas-liquid conditions. FIV prediction requires understanding the unsteady nature of the two-phase flow, particularly the structure velocity. A comprehensive analysis of datasets published in the literature with a wide range of diameters, inclinations, fluids, and flow conditions was conducted. Based on the data collected and previous studies in the literature, it was identified that the structure velocity of pseudo-slug flow is often found to vary between the linear velocity of slug flow and the wave celerity in segregated flow. Dimensionless parameters are proposed to calculate the structure velocity, while the flow behavior is modeled with Zhang et al. (2003) unified model and used as input for the new model. The proposed approach predicts structure velocity for pseudo-slug and churn flow, considering slug pressure contribution and dimensionless velocity. With a more accurate calculation of the structure velocity, improving the prediction of hydrodynamic forces for fatigue analysis is possible.
New Technology Reduces Carbon Emissions from Natural Gas Compression and Production Facilities
Authors: Guoynes John , Stiles David , Vail Cory , Stiles Robert , Kreuz Terry , Pritchard Gary , Nolen Craig , Schmitt Joshua 
Published: October 2023

Abstract
Natural gas compression contributes significantly to greenhouse gas (GHG) emissions, emitting nearly 10% of the total carbon dioxide equivalent per year from the Oil & Gas industry sub-sector1. The most common method of reducing GHG emissions from compression currently involves converting to electric drive2. Electric drive is not a preferred fuel source with most compressor operators because it can be expensive, difficult to acquire at field sites, and it can place new demands on existing power supply grids. A new chemical-free process has been developed with a small footprint to capture exhaust from natural gas drive compressors and supporting gas-fueled production equipment. The process separates carbon dioxide (CO2) and nitrogen from exhaust allowing the CO2 to be discharged at high pressure for transport, sequestration, or enhanced oil recovery (EOR). GHG emissions are significantly lowered from compression while permitting operators to maintain their preferred natural gas fuel source.
The patented process3 treats high volumes of exhaust, up to 70 million scf/D, containing CO2, nitrogen, and water. It incorporates innovative technology for carbon capture including a unique rotary separator design to remove water and centrifugally separate CO2 from exhaust gas. Advanced moving wall compressors and moving wall expanders have been developed to regulate system pressures and temperatures to values necessary for separation and discharge of supercritical CO2. The system is mounted on a small skid allowing for easy placement at typical production and midstream sites.
Technical and economic results of the system are presented, demonstrating that high-quality carbon dioxide is captured, separated, and pressurized for disposal or commercial use without the use of large equipment. This paper presents details of the process with initial test results and how it can be used on thousands of oil and gas production, midstream, and transmission sites. The exhaust gas stream is processed after lowering the temperature, then water is removed, and CO2 is separated from nitrogen without chemicals. The design lowers GHG emissions from all internal combustion engines, turbines. and supporting production equipment. The CO2 produced from this technology can be greater than 99% pure and meets IRS guidelines using 45Q tax credits for carbon sequestration.4
The oil and gas industry has a long history removing CO2 from gas streams.5 The novel technology presented incorporates new and practical solutions for oil and gas operators to reduce their GHG Scope 1 and Scope 2 emissions while maintaining their preferred natural gas fuel source at their midstream, transport, and production sites.
Flare Reduction Through Aquathermolysis Process Control in Heavy Crude Oil Field
Authors: Al Fazari M. , Hinai A. , Ghefeili H. , Rashdi A. , Mahrezi D. 
Published: October 2023

Abstract
Petroleum Development Oman LLC (PDO) is Oman's premier oil producer and operates several fields at "A". "A" East and "A" West are located on the eastern flank of the South Oman Salt Basin. As "A" Thermal fields contain heavy oil, PDO plans to significantly increase oil recovery by increasing the steam injection which is having high energy intensity.
The objective of this paper is to demonstrate the improvement in Flared Gas reduction resulted in reduction in Green House Gases (GHG) emissions.
This work had been initiated after noticeable increase in Associate gas flaring in AP Flare system. High GOR wells has been surveyed and closed to control the flare resulted in oil deferment, however the flaring was still increasing. Many challenges faced including casing vent, PCV passing, increasing in steam injection (Aquathermolysis Process) and flare gas metering.
In this project, lean practices were used to define the opportunities including A SIPOC (suppliers, inputs, process, outputs, customers) diagram, Process Mapping, Cause & Effect Diagram, Root causes analysis, and development of Visual Management Boards (VMB), standard operating procedures (SOP) to sustain Improvements.
Practical Problem Solving (PPS) and Kaizen approaches were used, and several countermeasures had been completed leading to reduce in Associate gas flaring by an average of 50%, equivalent to (∼ 2 million USD/annum).
This project had been completed with minimum spend on capex. By doing these modifications, it resulted in below benefits (confirmed):
GHG Reduction of 30K TCo2e/yr due to reduction of Flared gas in and utilization for Boiler Fuel Gas. An oil secure of 10% of total "A" production due to maintaining the processing Gas in /out of the Facility. A cost saving of more than 2 mln$ / annum due to the utilization of gas for other process.
Effect of Quick Salinity Variations in Virtual Meter Applied on Water Injection Wells
Authors: Parisi S. , Ursini F. , Vignati E. , Quattrocchi S. 
Published: October 2023

Abstract
Real Time Virtual Flowmeter (RTVFM) is a key digital technology for real time monitoring of well performances, for both production and injection wells. The main advantage of this tool is to provide estimations of well flow rates, based on wellbore pressure drop, using real-time (RT) pressure and temperature data measured by gauges installed in the well. This paper focuses on the effects of water properties on RTVFM application to water injection by evaluating their impact on the dynamic gradient and its implication in the rate estimation.
Injected water can be a mix of different sources: sea water, fresh water, formation water and produced water. As a result of these different contributions, it is common to observe variations of salinity even on an hourly basis. A variation of water salinity impacts on density and viscosity, therefore changing the dynamic gradient. Salinity in injected water is commonly measured by sampling analysis, thus providing data with a much lower frequency than RT gauges. As a result, it is not usually possible to integrate salinity variation into the standard RTVFM workflow, leading to significant errors in the rate estimation. The innovative workflow presented in this paper, named Virtual Salinity, calculates water salinity in real time in wells equipped with reliable flowmeters. It regresses the dynamic gradient equation on salinity values. The results of this workflow improve the quality of RTVFM application to other wells injecting the same water mix. At each timestep, virtual salinity values are used to evaluate the correct pressure gradient for RTVFM calculation.
The workflow has been successfully tested on a deepwater offshore asset, to prove its reliability. The Virtual Salinity has been applied on an offshore injection network: three wells injecting a mix of produced and sea water. The workflow, applied to all injectors, generated consistent salinity profiles. A reference virtual salinity profile has been used as an input for RTVFM simulations. For all of the injectors, RTVFM reproduced the independent flowmeter measurement with enough accuracy.
The innovative methodology here presented provides a key tool to monitor salinity of injected water and can be used in field where injected salinity is not measured, providing a valuable information at minimal costs. Water salinity is one of the main inputs of production data analysis, that allows to maximize reservoir knowledge and consequently final recovery. Moreover, the greater accuracy of Virtual Meter rates significantly improves the injection monitoring, thus supporting an effective reservoir management.
Combined Experimental and Well Log Study of Anisotropic Strength of Shale
Authors: Zheng Danzhu , Miska Stefan , Ozbayoglu Evren , Zhang Jianguo 
Published: October 2023

Abstract
Organic-rich shales have been contributing significantly to gas production in the US, led by new developments in horizontal drilling and hydraulic fracturing techniques. Shales have been known to be the source of wellbore instability problems in drilling processes. In the past practice, shales were treated as isotropic for mud window calculation and trajectory design. However, organic-rich shales are anisotropic due to their laminated structure and chemical properties. Thus, it is vital to theoretically and experimentally investigate the anisotropic strength of shale.
This study aims to evaluate the anisotropic mechanical properties of shale by tri-axial tests and predict anisotropic shale properties by well-logging data interpretation. Shale mechanical properties (Young's Modulus, Shear Modulus, and Poisson's Ratio) of different bedding plane orientations (0/ 45 / 90 degrees) were studied. Both compressive strength and tensile strength were investigated in different directions. A simple Plane of Weakness and Modified Cam Clay failure criteria were applied to describe the shear failure mechanism.
Well logging data were used to connect experimental data and actual field data. Compressional wave velocity was predicted with different inclination angles by stiffness parameters. The predicted compressional wave velocity for a 45-degree inclination angle perfectly fits the field logging data. Experimental data indicated the mud window for a particular shale formation.
This study provides an understanding of shale anisotropic strength of different bedding orientations and instructions on safety mud window calculation for directional drilling through shale formations.
A Recurrent Neural Network-Based Solvent Chamber Estimation Framework During Warm Solvent Injection in Heterogeneous Reservoirs
Authors: Ma Z. , Yuan Q. , Xu Z. , Leung J. Y. 
Published: October 2023

Abstract
Warm solvent injection (WSI), injecting low-temperature solvent into formations to reduce the viscosity of heavy oil, is a clean technology for heavy oil production while reducing greenhouse gas emissions and water usage. The success of WSI operation depends on the uniform development of solvent chambers in reservoirs. However, reservoir heterogeneity stemming from shale barriers plays a detrimental role in the conformance of solvent chamber development and oil production rate. In this work, we develop a novel recurrent neural network (RNN)-based framework with the capability of efficiently tracking and estimating the solvent chamber positions in heterogeneous reservoirs based on only production time-series data. The developed estimation model utilizes the "sequence-to-sequence" mapping methodology to correlate observed production time-series sequence and solvent chamber edge sequence via a long short-term memory (LSTM) algorithm. The developed RNN-based workflow is tested via several cases, and the results are promising. The predicted dynamic solvent chamber locations match the corresponding true locations with a high coefficient of determination and a low mean squared error. The major benefits of this workflow include reducing time for numerical simulations and saving overall monitoring and tracking costs for conventional techniques. The present work would provide a good illustration of the capability of practical integration of machine learning methods in solving engineering problems.