bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experimental Measurements and Molecular Simulation of Carbon Dioxide Adsorption on Carbon Surface
Authors: Gomaa Ibrahim , Guerrero Javier , Heidari Zoya , Espinoza D. Nicolas 
Published: September 2022

Abstract
Geological storage of carbon dioxide (CO2) in depleted gas reservoirs represents a cost-effective solution to mitigate global carbon emissions. The surface chemistry of the reservoir rock, pressure, temperature, and moisture content are critical factors that determine the CO2 adsorption capacity and storage mechanisms. Shale-gas reservoirs are good candidates for this application. However, the interactions of CO2 and organic content still need further investigation. The objectives of this paper are to (i) experimentally investigate the effect of pressure and temperature on the CO2 adsorption capacity of activated carbon, (ii) quantify the nanoscale interfacial interactions between CO2 and the activated carbon surface using Monte Carlo molecular modeling, and (iii) quantify the correlation between the adsorption isotherms of activated carbon-CO2 system and the actual carbon dioxide adsorption on shale-gas rock at different temperatures and geochemical conditions. Activated carbon is used as a proxy for kerogen. The objectives aim at obtaining a better understanding of the behavior of CO2 injection and storage into shale-gas formations.
We performed experimental measurements and Grand Canonical Monte Carlo (GCMC) simulations of CO2 adsorption onto activated carbon. The experimental work involved measurements of the high-pressure adsorption capacity of activated carbon using pure CO2 gas. Subsequently, we performed a series of GCMC simulations to calculate CO2 adsorption capacity on activated carbon to validate the experimental results. The simulated activated carbon structure consists of graphite sheets with a distance between the sheets equal to the average actual pore size of the activated carbon sample. Adsorption isotherms were calculated and modeled for each temperature value at various pressures.
The adsorption of CO2 on activated carbon is favorable from the energy and kinetic point of view. This is due to the presence of a wide micro to meso pore sizes that can accommodate a large amount of CO2 particles. The results of the experimental work show that excess adsorption results for gas mixtures lie in between the results for pure components. The simulation results agree with the experimental measurements. The strength of CO2 adsorption depends on both surface chemistry and pore size of activated carbon. Once strong adsorption sites within nanoscale network are established, gas adsorption even at very low pressure is governed by pore width rather than chemical composition. The outcomes of this paper provides new insights about the parameters affecting CO2 adsorption and storage in shale-gas reservoirs, which is critical for developing standalone representative models for CO2 adsorption on pure organic carbon.
Novel Method to Detect Fracture Closure Event Using Continuous Wavelet Transform
Authors: Adel Gabry Mohamed , Eltaleb Ibrahim , Soliman M. Y. , Farouq Ali S. M. 
Published: September 2022

Abstract
The Diagnostic Fracture Injection Test (DFIT) is widely used to get the fracture closure pressure, reservoir permeability, and reservoir pressure. Conventional methods for analyzing DFIT are based on the assumption of a vertical well but fail for horizontal wells drilled in ultra-low permeability reservoirs with potential multiple closures. There is still a significant debate about the rigorousness and validity of these techniques due to the complexity of the hydraulic fracture opening and closure process and assumptions of conventional fracture detection methods.
In this study, a new signal processing approach was proposed by M.Y. Soliman, U. Ebru, F. Siddiqi, A.Rezaei, and I. Eltaleb (2019) and (2020) was extended to use the continuous wavelet transform to identify the closure time and pressure. The new method was applied to synthetic and actual field data. The synthetic data were produced using commercial fracture simulators based on fracture propagation and closure simulation principles with predefined fracture closure. To determine this closure instant, we decompose the pressure fall-off signal as the output of the fracture system into multiple levels with different frequencies using the continuous wavelet transform. This "short wavy" function is stretched or compressed and placed at many positions along the signal to be analyzed. The wavelet is then multiplied term-by-term by the signal, and each product yields a wavelet coefficient value. The signal energy is observed during the fracture closure process (pressure fall-off) and the fracture closure event is identified when the signal energy stabilizes to a minimum level.
Because of the uncertainty of the real field fracture closure, a predefined simple synthetic fracture simulation with known fracture closure was used to validate the new methodology. The new continuous wavelet transform technique showed clear success without any prior assumptions or the need for additional reservoir data. The new methodology is also extended to actual field cases and showed the same success as conventional classical methods.
Typical Curve and Diagnosis Method for Identifying Fracture Closure Points of Fractured Wells in Flowback and Early-Time Production Period for Tight Oil Reservoir – A Field Example from Ordos Basin in China
Authors: Sun Zhaole , Cheng Linsong , Du Xulin , Jia Pin , Cao Renyi , Xue Yongchao 
Published: September 2022

Abstract
Fracturing fluids will carry an amount of proppant flowing back to the wellbore due to the inappropriate flowback schedule, which causes some parts of fractures to be closed without support. The appearance of closed fracture sections without support (pinch point) has a serious negative effect on well performance and is also a potential signal of refracturing. A four-region model considering fracture closure is developed to detect pinch points by analyzing production data in material equilibrium time.
Therefore, a novel four-region flow model is proposed to study the influence of pinch points on well dynamics performance in the initial stage of production and to diagnose the pinch point. In this model, the fluid flow to the wellbore is regarded as three parts: matrix, fracture, and pinch points. The position of the pinch point on the fracture (near wellbore) is considered. The existence of pinch points makes the fracture conductivity segmented, and the partial closure of fracture can be simulated by setting different fracture lengths, widths, and permeability. The flow in each region is treated as the linear flow and is coupled through boundary conditions and flux supply. Thereby, the mathematical model of flow containing pinch points is established.
This paper analyzes the production data of oil well, draws the logarithmic curve of RNP and its derivative RNP’ versus the material balance time (MBT), and conducts rate transient analysis to determine the occurrence of pinch points. In the case of the near-wellbore pinch point, the slope of the first half of RNP curves is relatively small, while the slope of the back section is about 1/2. Compared with RNP curves, the early slope of RNP’ curves is relatively large and gradually changes into the linear flow stage with a slope of 1/2. Different properties of pinch points mainly affect the slope of the left and right ends of RNP and RNP’ curves. The new analysis method can be used to analyze the influence of fracture closure position and degree of fracture closure on well productivity. Finally, the novel four-region flow analysis model was applied to the analysis of oil production data from a typical well in Ordos Basin. The length, width, and permeability of the near-wellbore fracture closure section can be obtained by fitting the proposed chart.
The novel four-region flow model method and its curve characteristics provided in this article can be used as an important reference for judging whether there is a pinch point in fracture. It has a certain guiding significance for the formulation of fracturing schemes for new wells and whether old wells need refracturing in actual production.
Effective Use of Surveillance to Optimize the Development Plan for a Deep-Water Reservoir
Authors: Satik Cengiz , Burgess Matthew , Carter Matthew , Evans Frank 
Published: September 2022

Abstract
A three-phase strategy was adopted for a deep-water reservoir development due to large uncertainties associated with fault compartmentalization and aquifer support. First phase started with primary production from several wells while water injection was implemented a few years later as second phase. Finally, the third phase involved infills. Data collected during drilling was utilized to improve reservoir characterization. This paper describes how a Surveillance, Analysis and Optimization (SA&O) plan was utilized to resolve key subsurface uncertainties and optimize the development plan, along with lessons learned and best practices.
The development plan included adding five infill wells during the infill campaign. Two of those infills, Well1 and Well2, delineated the reservoir south of a major fault. Early reservoir characterization placed two sealing faults between the Well1 and Well2 wells, creating a separate fault compartment with a future infill well in the development plan. Steeply dipping beds below a thick salt canopy make seismic imaging a challenge and fault delineation uncertain. Although a future infill well was planned to recover the reserves from this compartment, the length and transmissibility of the faults, as well as reservoir heterogeneity between the Well1 and Well2 wells were highly uncertain. Prior to start-up of Well2, a pulse test and multiple pressure build-up tests were conducted as part of the SA&O plan to resolve fault uncertainties. The pulse test involved creating pressure pulses by shutting-in and starting-up the Well1 and monitoring at Well2 for pulse arrival. Test design was developed using Intersect and Saphir numerical simulations sensitizing on the fault extent and transmissibility uncertainties.
The test was planned and executed successfully as a result of multi-functional collaboration between the asset development, reservoir management support, and operations teams. Analysis of all transient pressure data indicated very strong pressure communication without any detectable barrier between the Well1 and Well2 wells. Increased confidence in recent seismic imaging enhancements have since corroborated these results. Reservoir simulations without these compartmental faults, indicated that Well1 & Well2 can effectively drain most of the recoverable oil, with limited improvement from an additional well. Consequently, the development plan was optimized by removing the future infill well, translating to a significant capital cost saving.
Oil and Gas: Innovation, Patents, and the Future of an Industry
Authors: Brewer Peter L. 
Published: September 2022

Overview
This article is written in support of the Society of Petroleum Engineers’ Annual Technical Conference and Exhibition. As of the time of this writing, the event is scheduled to take place in Houston, Texas, during the week of October 3, 2022. The ATCE is the SPE's flagship international event. The host facility will provide over 90,000 square feet of exhibition space along with numerous presentation rooms. It is an honor to be a part of this program.
The author has been tasked with preparing an article that discusses the role that patents have played in the development of the oil and gas industry. As someone who has written hundreds of patent applications in various energy generation fields over the last 22 years, and as a degreed petroleum engineer himself, the author believes that he is uniquely suited for the task.
A number of years ago, the author wrote an article for the Society of Petroleum Engineers entitled Intellectual Property for the Oilfield The article was written in connection with a presentation at an International Association of Drilling Contractors (IADC) Drilling Conference held in Dallas, Texas. A reciprocal article was published by a patent attorney in Canada the same year. See R.B. Caldwell, Patent Monopoly-Protecting Your Ideas (in Canada). The two articles focused much more on the patent process itself than the development of oil and gas technology and the role that the patent process has played.
The author is unaware of any attempts that have been made, scholarly or otherwise since 2002 to discuss the role that patents play in the oil and gas industry. This paper is a humble attempt to fill that void.
Technology Development Framework: Moving From Qualitative to Quantitative Decision-Making
Authors: Clark Hamish P , Castellanos Diaz Orlando 
Published: September 2022

Abstract
Technology development in the energy sector typically suffers from an ad hoc approach to making decisions about the key questions of "What is the next de-risking step?" and "At what scale?". This lack of structure in decision making occurs despite the technology development process usually being within a stage gated protocol. This often leads to significant waste of time and resources and plenty of "surprises" about the extent of additional testing required.
The approach proposed in this manuscript is relatively simple to use, scalable, and transferable across industry sectors. Consistent application of the methodology has the potential to bring a quantitative rigor that can lead to more effective and efficient technology development and improve both intellectual and monetary capital allocation. Additionally, the framework provided facilitates a more structured and faster learning curve for people moving into technology development roles. Starting with a high-level understanding of the technology and business case, the methodology identifies possible commercial deployments and associates key technical and commercial risks that can be barriers to commercialization. Then, using a "Risk Burndown" approach based around an initial assessment of Probability of Success (POS), different Paths to Deployment (PTD) are developed. A Value of Information (VOI) approach is used to evaluate key metrics. This leads to a diverse set of de-risking options with associated trade-offs for informed decision making.
The methodology has been developed and deployed since 2017 across a portfolio of both incremental improvement and game-changing subsurface technologies at Suncor Energy, a large integrated Canadian energy company. Over 25 technologies have been progressed using elements of this workflow with 7 of the more complex and expensive projects employing the full quantitative VOI approach. These analyses have been used to inform decision making on over CAD 400 million of proposed de-risking activity spend.
Pseudo-Aquifer Index: A New Concept for Estimating Transient Water Influx using Kumar-Ramey Average Pressure Equation
Authors: Kumar A. , Banerjee D. 
Published: September 2022

Abstract
This paper presents a new concept of Pseudo-Aquifer Index and a major departure from classical methods to estimate transient water influx using Kumar-Ramey equation employing reservoir average pressure obtained from transient tests for a central well in a constant pressure reservoir. The new method overcomes the two limitations of the conventional methods of van Everdingen-Hurst (1949), Carter-Tracy (1960), Fetkovich (1971), and similar other studies. These methods require apriori knowledge of (1) pressure history at the reservoir-aquifer boundary (oil-water contact or OWC) with time, and (2) aquifer characterization in terms of rock and fluid properties, depth, and geometric configuration. Such data for aquifer and OWC pressure history carry a high degree of uncertainty at the beginning of a newly discovered complex offshore or onshore reservoir development.
Kumar-Ramey (1974) presented dimensionless water-influx (WeD) as a function of dimensionless average pressure and producing time which yields cumulative water-influx volumes as a fraction of cumulative reservoir withdrawal. Kumar (1977) also provided the dimensionless pressure at the reservoir aquifer boundary with time. Plots of dimensionless average pressure, dimensionless boundary pressures at the OWC, and cumulative water influx function (WeD) are presented as a function of producing times for the three cases of pseudo-aquifer-index of 0.25, 0.50, and 1.0. Some of this data is obtained from Kumar (1977) and is transformed into polynomial equations. Two examples show the applications, and compare transient water-influx results with those obtained from van Everdingen-Hurst method.
A log-log type curve of dimensionless average pressure and time is included for determination of reservoir properties when average pressure is known A considerable advantage of the new method is its simplicity, generality, ease in use, and implementation in reservoir engineering software and simulation when compared to conventional methods. This study is also the first to provide a systemic characterization of transient boundary (OWC) pressures in closed and partial water drive reservoirs.
A Deep Learning Optimization Framework for Geothermal Energy Production Based on Carbon Dioxide
Authors: Katterbauer Klemens , Qasim Abdulaziz , Al Shehri Abdallah , Al Sofi Abdulkareem 
Published: September 2022

Abstract
CO2 plume geothermal technology (CPG) has been developed in recent years by several companies. The technology aims to utilize CO2 stored in saline aquifers to produce geothermal energy. CPG is different from conventional geothermal concepts. Here, the feedstock utilizes CO2 as a carrier fluid through which heat is extracted from the subsurface reservoir. Furthermore, the system does not necessarily rely on shallow natural hydrothermal locations but can utilize a conventional sedimentary basis. At last, CPG can still harvest energy in low-temperature environments that are currently not suitable for conventional geothermal extraction.
We present a new deep learning optimization framework for the maximization of power generation from a CPG system. The framework utilizes an adapted N-BEATS approach. The approach is based on a stack of ensembled feedforward networks that are also stacked by interconnecting backcast and forecast links. The advantages of the framework are its flexibility with respect to different input parameters and various forecastable time series. This is particularly important for CPG to easily capture variations in the temporal dynamics and temperature responses across the various CO2 injection and production wells.
We evaluated the framework on a simulated CO2 storage reservoir based in the Taranaki basin in New Zealand. The Taranaki basin has been well studied for CO2 storage, given the presence of a large saline aquifer that may be well suitable for both CO2 storage and CPG energy production. We simulated 3.5 years of CO2 injection and production for geothermal energy production as input to the N-BEATS framework. The training performance of the network was strong, and the model's performance was then evaluated on subsequent two years of energy production. The deep learning framework is then integrated into a global optimization framework to optimize energy production while adapting CO2 injection.
The new deep learning N-BEATS optimization framework for CPG power generation represents an innovative way to enhance energy generation from CO2 storage reservoirs providing a sustainable way to minimize carbon footprint while delivering energy.
A Subsea Multilateral Oil Producer, Completed with AICD Sand Screens and Selective Inflow Valves is Evaluated by Combined Acoustic and PL Tools, Identifying the Sand Producing Branch and a Tubing Leak in a Single Operation
Authors: Troup Duncan , Griffin Tim , Pham Minh , Primarolo Andrew , Brighton James 
Published: September 2022

Abstract
Subsea completions offer a number of advantages, but intervention operations can be complex and expensive. A horizontally completed multilateral well exhibited unexpected sand production and a tubing leak leading to the well being shut in. This paper discusses the novel tools and techniques deployed to localise the tubing leak, identify the bore responsible for sand production and to provide relative sand quantification at differing flowrates
The evaluation methodology was essentially the same as a comprehensive production logging intervention, with the addition of a novel acoustic tool to quantify sand impacts. Data was recorded with the tools stationary while the well was flowed in a variety of different states by means of hydraulically actuated inflow control valves. This enabled well behaviour during transition from one state to another to be monitored in real-time and recorded, giving unprecedented insight into sand production dynamics, as well as sustained production from stabilised flowrates. Logging at different flowrates at different depths allowed quantification of minimum sand transport flowrates.
With the well shut-in, a leak detection survey was conducted while running in hole and a faulty GLV identified. With the well flowing comingled from both mainbore and lateral 2, data indicated a mixture of oil and water being produced, along with significant quantities of sand. Choking back both bores to 50% resulted in continued water and sand production. When the ICV was cycled to close lateral 2, water cut and sand production both increased with slug flow evident indicating the mainbore was producing sand associated with water production. Lateral 2 was then reopened and the mainbore closed. Sand production declined to zero and the water cut dropped, showing that lateral 2 was not producing either sand or meaningful amounts of water. The time-based data was recorded at depths, one in 3-1/2" tubing above the ICV and the other in 5-1/2" tubing higher up. For a given flow rate, it was possible to compare relative sand rates at the 2 points and infer the fluid velocities needed for sand transport to occur. The data identified the source of the sanding, the source of the water and the minimum flow needed to prevent sand settling in the well.
Robust and reliable detection of the presence of sand in 3-phase production flow is a powerful tool in itself to allow diagnosis of failures of sand control, in this case the positive identification of the bore responsible for sand production. The addition of a quantifiable fourth phase to traditional production logging elevates the understanding of downhole sand production by enabling the correlation of sand rate with variable parameters such as holdup and local fluid velocities.