bluuebunny/crossref_metadata_2025_split huggingface dataset:
Characterizing Downhole Fluid Analysis Sensors As Digital Twins: Lessons of the Machine Learning Approach, The Physics Approach and the Integrated Hybrid Approach
Authors: Price Jimmy , Jones Chris , Dai Bin , Gascooke Darren , Myrick Michael 
Published: September 2021

Abstract
Digital fluid sampling is a technique utilizing downhole sensors to measure formation fluid properties without collecting a physical sample. Unfortunately, sensors are prone to drift over time due to the harsh downhole environmental conditions. Therefore, constant sensor evaluation and calibration is required to ensure the quality of analysis. A new technique utilizes a virtual sensor as a digital twin which provides a calibration that can be utilized by the physical twin. Digital twin technology enables the end-user to operate and collaborate remotely, rapidly simulate different scenarios, and provide improved accuracy via enhanced up-to-date calibrations. With respect to downhole fluid identification, the contribution of harsh environmental conditions and sensor drift can also be mitigated by realizing a virtual implementation of the fluid behavior and the individual sensor components. Historically, the virtual behavior of a digital twin has been constructed by a combination of complex multi-physics and empirical modeling. More recently, access to large datasets and historical results has enabled the use of machine learning neural networks to successfully create digital twin sensors. In this paper, we explore the efficacy of constructing a digital twin on a single downhole optical fluid identification sensor using both the machine learning nonlinear neural network and the complex, multi-physics' based modeling approaches. Advantages and lessons to be learned from each individual method will be discussed in detail. In doing so, we have found a hybrid approach to be most effective in constraining the problem and preventing over-fitting while also yielding a more accurate calibration. In addition, the new hybrid digital twin evaluation and calibration method is extended to encompass an entire fleet of similar downhole sensors simultaneously. The introduction of digital twin technology is not new to the petroleum industry. Yet there is significant room for improvement in order to identify how the technology can be implemented best in order to decrease costs and improve reliability. This paper looks at two separate methods that scientists and engineers employ to enable digital twin technology and ultimately identify that a hybrid approach between machine learning and empirical physics'-based modeling prevails.
Glycine for Enhanced Water Imbibition in Carbonate Reservoirs – What is the Role of Amino Group?
Authors: Baghishov Ilgar , Abeykoon Gayan A. , Wang Mingyuan , Argüelles Vivas Francisco J. , Okuno Ryosuke 
Published: September 2021

Abstract
Previous studies indicated the efficacy of the simplest amino acid, glycine, as an aqueous additive for enhanced water imbibition in carbonate reservoirs. The objective of this research was to investigate the importance of the amino group of glycine in its enhanced water imbibition. To this end, glycine was compared with two carboxylates (acetate and formate) with/without adding hydrogen chloride (HCl) for adjusting the solution pH. Note that the amino group is the only difference between glycine and acetate.
Contact-angle experiments on calcite were carried out at 347 K and atmospheric pressure with 68000-ppm reservoir brine (RB), and 4 different concentrations of glycine, acetate, and formate solutions in RB. To test the hypothesis that calcite dissolution is one of the main mechanisms in wettability alteration by glycine, we performed another set of contact angle experiments by adding HCl to brine, acetate, and formate solutions. HCl was added to match the pH of the glycine solution at the same concentration. We also performed imbibition tests with Texas Cream Limestone cores at 347 K with brine, glycine, acetate, and formate solutions (with and without HCl) in RB at 5.0 wt%.
Contact-angle results indicated that glycine changed calcite's wettability from oil-wet to water-wet (45°). However, acetate solution was not able to change the wettability to water-wet; and formate moderately decreased the contact angle to 80°. The pH level increased from 6.1 to 7.6 after the contact angle experiment in glycine solution, indicating the consumption of hydrogen ions due to calcite dissolution. The levels of pH in formate and acetate solutions, however, decreased from 8.4 to 7.8. The acidity of glycine above its isoelectric point arises from the deprotonation of the carboxyl group.
Imbibition tests with carbonate cores supported the observations from the contact-angle experiments. The oil recovery was 31% for glycine solution, 20% for RB, 21% for formate solution, and 19% for acetate solution. This re-confirmed the effectiveness of glycine as an additive to improve the oil recovery from carbonates. An additional set of imbibition tests revealed that acetate at the pH reduced to the same level as glycine was still not able to recover as much oil as glycine. This showed that glycine recovered oil not only because of the calcite dissolution and the carboxyl group, but also because of the amino group. It is hypothesized that the amino group with its electron donor ability creates a chelation effect that makes glycine entropically more favorable to get attached to the calcite surface than acetate.
Another important result is that the formate solution at an adjusted pH resulted in a greater oil recovery than RB or RB at the same pH. This indicates that there is an optimal pH for the carboxyl group to be effective in wettability alteration as also indicated by the pH change during the contact-angle experiment.
Advanced Gas While Drilling GWD Comparison with Pressure Volume Temperature PVT Analysis to Obtain Information About the Reservoir Fluid Composition, a Case Study from East Kuwait Jurassic Reservoir
Authors: Ahsan Mohammad J. , Al-Turkey Shaikha , Rane Nitin M. , Snasiri Fatemah A. , Moustafa Ahmed , Benyounes Hakim 
Published: September 2021

Abstract

Objectives/Scope
The acquisition of mud gas data for well control and gathering of geological information is a common practice in oil and gas drilling. However, these data are scarcely used for reservoir evaluation as they are presumably considered as unreliable and non-representative of the formation content.
Recent development in gas extraction from drilling mud and analyzing equipment has greatly improved the data quality. Combined with proper analysis and interpretation, these new datasets give valuable information in real-time lithological changes, hydrocarbons content, water contacts and vertical changes in fluid over a pay interval.

Methods, Procedures, Process
Post completion, Mud logging data have been compared with PVT results and they have shown excellent correlation on the C1-C5 composition, confirming the consistency between gas readings and reservoir fluid composition. Having such information in real time has given the oil company the opportunity to optimize its operations regarding formation evaluation, e.g downhole sampling, wireline logging or testing programs.
Formation fluid is usually obtained during well tests, either by running downhole tools into the well or by collecting the fluid at surface. Therefore, its composition remains unknown until the arrival of the PVT well test results. This case intends to use mud gas information collected while drilling to predict information about the reservoir fluid composition in near real time. To achieve this goal we compared mud gas data collected while drilling with reservoir fluid compositional results.
Pressure volume temperature (PVT) analysis is the process of determining the fluid behaviors and properties of oil and gas samples from existing wells.

Results, Observations, Conclusions
The reason any oil and gas company decides to drill a well is to turn the project into an oil-producing asset. But the value of the oil extracted from a single well is not the same as the value of the oil produced from another. The makeup of the oil, which can be determined from the compositional analysis, is an important piece of the equation that determines how profitable the play will be. The compositional analysis will determine just how much of each type of petroleum product can be produced from a single barrel of oil from that wells.

Novel/Additive information
Formation samples were obtained from offset wells in the Marrat Formation. These datasets gave valuable indications on fluid properties and phase behavior in the reservoir and provided strong base for reservoir engineering analysis, simulation and surface facilities design.
The comparison of the gas data to PVT results gives a good match for reservoir fluid finger print, early acquisition of this data will help for decision enhancement for field development.
Suppression Performance of an Unmodified Bio-Extract for Simulated Offshore Gas Hydrate Mitigation
Authors: Wachikwu-Elechi Virtue Urunwo , Ikiensikimama Sunday Sunday , Ajienka Joseph Atubokiki , Akaranta Onyewuchi Emmanuel , Okon Okon Efiong 
Published: September 2021

Abstract
Gas hydrate inhibition through the use of chemicals has been ongoing over the years and these chemicals are toxic, synthetic and expensive, adding to the cost of doing oil and gas business, and also leads to environmental degradation. The call for greener environment has necessitated the search for more eco-friendly gas hydrate inhibitors. This paper takes a look at the use of a bio-extract in its unmodified state to inhibit gas hydrate using a locally made mini flow loop for gas hydrate studies. The bio extract was compared to a conventional gas hydrate inhibitor 2-Di(methylaminoethyl)methacrylate (2-DMAEM). For all the weight percentages considered (0.01-0.05wt%), the bio-extract had better pressure profiles. At the end of the experiment which lasted for 120 minutes, this is attributed to the fact that the pressures in the system were more regulated which prevented rapid gas dissolution in water. The Bio-extract is plant based, locally available in the commercial quantity and is eco-friendly so it should be harnessed as gas hydrate inhibitors in lieu of the expensive and imported conventional hydrate inhibitor 2-DMAEM which non-eco-friendly.
ESP and Completion Deployment using Dual Derrick Drill Ship Rigs
Authors: Lemos Daniel , Marins Jean , De Lima Raone 
Published: September 2021

Abstract
This paper presents an innovative concept to run Electrical Submersible Pumps (ESP) and upper completion utilizing dual derrick drillship rigs in deep water wells. The availability of a second deck to assemble, test and rack long assemblies brings the possibility to conduct a safer, efficient and reliable operation. The experience in Brazil running complex completions and high horsepower ESPs shows how important is to implement initiatives to reduce rig time. The main objective of the new process is to have every completion tool readily available in the drilling deck, requiring minimum time to connect it to the completion string. In the standard process, the tool sits in the pipe deck until completion string reaches its set position and only then the equipment is brought into the rig floor to be serviced and made up to the completion string. The methodology to assemble ESP and completion tools offline in the auxiliary derrick was developed in partnership with the operator, the service company, and the drilling rig contractor.
The offline preparation concept was considered as part of the completion design phase analyzing every step of the upper completion run, looking for efficiency improvement and reduced total rig time.
The modern automated pipe handling system was used to manipulate the long and heavy assemblies from the auxiliary deck to the racking system and from the racking system to the main deck without any safety concern, and with minimal human intervention.
Eight deep-water operations were completed in Brazil using the new concept and the results brought important rig time reduction in the upper completion running time. The tools that were part of the completion included DHSV, permanent downhole gauges, chemical injection valves, 1600 HP ESP system and tubing test valves. The new process allows the team to service equipment without the usual operation rush reducing installation related failure therefore increasing equipment reliability.
The methodology presented on this paper contributes to oil industry as a field-proven reference for offshore ESP and completion deployment technique reducing HSE exposure and total well construction cost. This is particularly important for deep and ultra-deepwater projects which are associated with high intervention costs. Dual derrick rigs were designed with focus to improve drilling operations and after the new process development, the modern robotized machinery empowers ESP and completion activities with improved efficiencies.
Fluid Cool Down vs. Heat Back - An Analysis of Bottomhole Gauge Temperature Responses to Optimize Stimulation Fluid Clean Up and Thereof Testing, Offshore Black Sea
Authors: Grubac Gabrijel , Patrascu Radu , Precupanu Laura 
Published: September 2021

Abstract
In an effort of maximizing the production from low permeability reservoirs in mature fields, operators often strive to implement innovative technologies and engineering approaches that can help achieve that goal. This paper presents an analysis of the temperature responses from bottom hole gauges of several horizontal wells that have been stimulated offshore Black Sea. The analysis covers the fluid cool down and heat back profile during stimulation and production. Ultimately, the analysis’ goal being to better understand the rheological properties of the stimulation fluid and enhance well clean-up by avoiding miss-allocation of temperature ranges during fluid testing for when the well is brought on production. Based on available data from bottom hole gauges implemented in the horizontal wells stimulated in the Black Sea, an analysis of the temperature gauge responses has been performed. The analysis includes a workflow of temperature change validation per well, considering fluid pumped per port in stimulation phase and fluids produced per port in production phases. The fluid production allocation per port was done utilizing chemical tracer technology results.
Stimulation treatments in the same reservoir offshore Black Sea, Romania have been analyzed in terms of bottom hole gauge readings of temperature during the stimulation fluid pumping and during the early production period of each well. A workflow was implemented on each well to correlate fluid per stimulation stage pumped to temperature changes during the treatments. Similar approach was used to correlate the temperature heat back profile during the shut in of wells in the initial 48 hours for proppant curing to the production phase clean-up of the wells. The observed cool down during pumping was of no surprise, but the heat back indicated a slower process of warm back that affects the stimulation fluid testing approach and the understanding of possible near wellbore pressure differentials caused by misallocation of temperature range testing of pre job rheology tests. A combination of temperature data with diagnostic tools and the pertaining analysis will provide a better description of wells’ performance.
In conclusion, misinterpretation of modelled cool down and reservoir heat back can lead to erroneous understanding of fluid clean up, ultimately affecting reservoir fluid inflow. Understanding the areal temperature response helped optimize fluid testing approach and plan for better clean up.
The approach and the sensitivity analysis results are beneficial in understanding the temperature behavior during treatment pumping and production of stimulated wells. This process can enhance an engineer's approach in scrutinizing stimulation fluid testing for improved post stimulation clean up.
Photoacoustic Nanotracers for Subsurface Applications: Opportunities and Challenges
Authors: Felix Servin Jesus Manuel , Al-Sadeg Hala A. , Abdel-Fattah Amr 
Published: September 2021

Abstract
Tracers are practical tools to gather information about the subsurface fluid flow in hydrocarbon reservoirs. Typical interwell tracer tests involve injecting and producing tracers from multiple wells to evaluate important parameters such as connectivity, flow paths, fluid-fluid and fluid-rock interactions, and reservoir heterogeneity, among others. The upcoming of nanotechnology enables the development of novel nanoparticle-based tracers to overcome many of the challenges faced by conventional tracers. Among the advantages of nanoparticle-based tracers is the capability to functionalize their surface to yield stability and transportability through the subsurface. In addition, nanoparticles can be engineered to respond to a wide variety of stimuli, including light.
The photoacoustic effect is the formation of sound waves following light absorption in a material sample. The medical community has successfully employed photoacoustic nanotracers as contrast agents for photoacoustic tomography imaging. We propose that properly engineered photoacoustic nanoparticles can be used as tracers in oil reservoirs. Our analysis begins by investigating the parameters controlling the conversion of light to acoustic waves, and strategies to optimize such parameters. Next, we analyze different kind of nanoparticles that we deem potential candidates for our subsurface operations. Then, we briefly discuss the excitation sources and make a comparison between continuous wave and pulsed sources. We finish by discussing the research gaps and challenges that must be addressed to incorporate these agents into our operations.
At the time of this writing, no other study investigating the feasibility of using photoacoustic nanoparticles for tracer applications was found. Our work paves the way for a new class of passive tracers for oil reservoirs. Photoacoustic nanotracers are easy to detect and quantify and are therefore suitable for continuous in-line monitoring, contributing to the ongoing real-time data efforts in the oil and gas industry.
Preventing Asphaltene Deposition by Inhibitor Squeeze Injection: Case Studies from Giant Carbonate Abu Dhabi Fields
Authors: Punnapala Sameer , Abdullah Dalia Salim , Grutters Mark , Cristea Zaharia , El Naggar Hossam El Din Mohamed , Bahamish Fatima Jamal , Senaad Rabah , Bakri Hasan Jamil , Abbas Zafar 
Published: September 2021

Abstract
Asphaltene deposition is a notorious flow assurance problem faced by oil companies that causes production loss and large expenses for operators. The complex nature of asphaltenes and limited data available makes it challenging to develop a full field implementation strategy that is economically viable as well. Conducting asphaltene clean-up operations whenever wells get plugged up are the reactive approach to deal with asphaltene issues. However these approaches often result in prolonged well downtime, production losses and high well intervention costs. As part of proactive measures, chemical inhibitors were screened for formation squeeze and field trials conducted to assess their performance. Results from these trials helped to frame the full-field implementation strategy that is promising from a technical-economic standpoint. This paper describes the asphaltene mitigation journey of a major Abu Dhabi oil operator that resulted in multi-million dollar savings.
Surfactant-Polymer Formulations for EOR in High Temperature High Salinity Carbonate Reservoirs
Authors: Sotomayor Mauricio , Alshaer Hassan , Chen Xiongyu , Panthi Krishna , Balhoff Matthew , Mohanty Kishore 
Published: September 2021

Abstract
Harsh conditions, such as high temperature (&gt;100 oC) and high salinity (&gt;50,000 ppm TDS), can make the application of chemical enhanced oil recovery (EOR) challenging by causing many surfactants and polymers to degrade. Carbonate reservoirs also tend to have higher concentrations of divalent cations as well as positive surface charges that contribute to chemical degradation and surfactant adsorption. The objective of this work is to develop a surfactant-polymer (SP) formulation that can be injected with available hard brine, achieve ultra-low IFT in these harsh conditions, and yield low surfactant retention. Phase behavior experiments were performed to identify effective SP formulations. A combination of anionic and zwitterionic surfactants, cosolvents, brine, and oil was implemented in these tests. High molecular weight polymer was used in conjunction with the surfactant to provide a high viscosity and stable displacement during the chemical flood. Effective surfactant formulations were determined and five chemical floods were performed to test the oil recovery potential. The first two floods were performed using sandpacks from ground Indiana limestone while the other three floods used Indiana limestone cores. The sandpack experiments showed high oil recovery proving the effectiveness of the formulations, but the oil recovery was lower in the cores due to complex pore structure. The surfactant retention was high in the sandpacks, but it was lower in Indiana Limestone cores (0.29-0.39 mg/gm of rock). About 0.4 PV of surfactant slug was enough to achieve the oil recovery. A preflush of sodium polyacrylate improved the oil recovery.