bluuebunny/crossref_metadata_2025_split huggingface dataset:
Geomechanical Assessment of Potential CO2 Storage Sites in the US Shallow Water Gulf Coast
Authors: Haghi A. , Otto S. , Duval G. 
Published: October 2023

Abstract
Carbon capture and storage (CCS) is an essential technology that will play a major role in transitioning toward net-zero carbon emissions. CCS is the only group of technologies that reduces emissions in key energy and industrial sectors directly but also reduces CO2 to balance emissions in sectors difficult to abate. Offshore CCS offers most of the CO2 storage opportunities to achieve the growth required in storage capacity beyond the feasible onshore storage. Geomechanical screening of potential CCS sites for safe and efficient CO2 injection in deep geological formations is still a substantial challenge, especially over large areas with hundreds of drilled structures and fields, such as the shallow water Gulf of Mexico (GOM). In this study, we collect existing geophysical and petrophysical logs, drilling data (e.g., mud weight, leak-off test), pore pressure (MDT) and temperature data from 123 wells to evaluate potential CO2 leakage via the caprock due to gas injection-induced fault reactivation or fracturing. For this, we develop pore pressure and 1D mechanical Earth models for six wells, strategically distributed throughout the study area with all the required data, and map Shear Stress Levels (SSL) and Pressure Rooms (PR) for all potential storage formations. We further develop stress polygons based on friction equilibrium and poroelastic failure criteria for gas injection-induced shear failure. We characterize the contemporary state of stress in GOM by normal faulting (NF) stress, which is consistent with the predominantly extensional regime in the western intraplate North America. Using the World Stress Map (WSM) database, we find a mean SH orientation of N98° (±47°) based on 79 borehole breakouts with an overall length of 1241 m in 23 offshore wells in GOM. Stress orientations are locally affected by salt bodies and faults. We observe a pore pressure transition from hydrostatic at a shallow depth (i.e., wide PR) to an extreme overpressure zone (i.e., narrow PR), which makes deep reservoirs more sensitive to tensile fracturing during CO2 injection. We show that SSL is less than 0.4 in all reservoirs and seals in the GOM area, and PR decreases northwest of the study area. Furthermore, we reveal that the critical pressure and temperature limits for shear failure are far beyond the PR limit. Hence, following the PR limit, gas injection-induced reservoir failure and fault reactivation is unlikely in the study area, providing confidence that caprock mechanical leakage is a low-risk issue for long-term CO2 storage.
Unraveling the Role of Water in Microwave/Electromagnetic-Assisted Catalytic Heating for Hydrogen Production from Gas Reservoirs
Authors: Yan K. , An B. , Yuan Q. 
Published: October 2023

Abstract
To cope with the increasing pressures of decarbonization that the petroleum industry is facing, a novel approach, entitled in-situ microwave/electromagnetic-assisted catalytic heating technology, is recently proposed for hydrogen (H2) production directly from petroleum reservoirs. This work investigates H2 generation from methane (CH4) cracking in the presence of sandstone rock powders under microwave irradiation through a purpose-designed lab-scale microwave reactor system. The role of water and rock minerals during reactions is also examined. The real-time variations of measured temperature of rock samples, gas flow rate, and concentration of hydrogen and other generated gases are monitored. Deuterium oxide, or the so-called heavy water (D2O), is used to track the sources of hydrogen from methene and water. A rapid temperature increase is identified for the sandstone samples during microwave heating, which is referred to as the "temperature soaring" (TS) phenomenon. The TS phenomenon happens at 560-590 ℃ under microwave irradiation at a relatively higher power. Once TS phenomenon occurs, the sample can be easily re-heated up to 700 ℃ using a low microwave power at less than 0.3 kW. The experimental results show that Fe-based and other metal minerals in the sandstone rocks have an evident natural catalytic effect for promoting CH4 conversion to H2. The H2 production with 1.0 mol.% concentration starts at a measured temperature of 392 ℃, followed by a maximum H2 concentration and CH4 conversion at 91 mol.% and 79% respectively as the temperature reaches 668 ℃. Furthermore, in the presence of D2O, a peak concentration of 4.9 mol.% D2 gas and 18.2 mol.% HD gas are generated during methane conversion to hydrogen experiments. Further, water can enhance H2 generation via coke gasification in a temperature range from 330-580 ℃. Additionally, negligible CO2 and minor CO are generated in the experiments when methane continuously flows through the sandstone samples and converted to hydrogen under microwave irradiation. The proposed technology potentially opens a new pathway for clean H2 production directly from natural gas reservoirs.
Answering Natural Language Questions with OpenAI's GPT in the Petroleum Industry
Authors: Eckroth J. , Gipson M. , Boden J. , Hough L. , Elliott J. , Quintana J. 
Published: October 2023

Abstract
This work documents two experiments that make use of OpenAI's ChatGPT and GPT-4 for question answering in the petroleum industry. First, we describe PetroQA, a prototype tool that can answer natural language questions. It uses PetroWiki content to inform ChatGPT about facts specific to this industry. We are able to convince ChatGPT to avoid hallucinations and cite its sources. We asked nearly 200 SPE members to volunteer to test PetroQA and discuss results from that test. Second, we are developing and testing a tool, known as GraphQA, that allows users to ask questions and receive answers from a large graph knowledge base consisting of facts and relations between concepts such as wells, fields, basins, formations, geography, geologic age, rock type, operators, and more. A knowledge base like this is difficult for users to explore, so we use GPT-4 to automatically generate accurate graph queries from their natural language questions. We explore several novel techniques for prompting GPT-4 to produce the right queries and have developed an advanced caching mechanism to reduce interactions with the cloud model, thus reducing time to answer and cost.
Characterization of a New Litho-Density Logging-While-Drilling Tool to Ensure High-Confidence Reservoir Data
Authors: Vogt Andreas , Haeussler Andre , Banzarov Bair V. , Ritzmann Nicklas 
Published: October 2023

Nuclear logging-while-drilling (LWD) tools delivering gamma-gamma density, photoelectric factor (Pe) and neutron-porosity measurements are essential services for the oil and gas industry to calculate accurate asset NPV (Net Present Value). As a part of the triple-combo bottom-hole assembly, neutron and formation density measurements enable accurate quantification of porosity, hydrocarbons volume and type, and through 360° coverage density imaging, bed boundary and structural measurements, and real-time reservoir navigation (Ellis & Singer, 2007), (Wahl, Tittman, & Johnstone, 1964). One of the crucial steps in tool development is the precise characterization and correction of any wellbore induced effects, in order to ensure accurate and reliable true formation properties to be evaluated, leading to a high confidence in formation properties calculated from them.
In this paper we describe how stringent radiation-transport simulations of the instrument response are utilized during the characterization process for the case of a high-temperature 4.75-in combined neutron-porosity and litho-density tool, designed to be utilized for demanding rotary-steerable drilling applications. The tool covers application ranges of temperature up to 175°C, pressures of up to 30,000 psi and dogleg severities of 15°/100 ft during rotation and corrosion resistance in demanding oil and gas drilling applications (Reckmann, et al., 2022). The nuclear measurements are improved by integral stabilizers and fluid displacers. Moreover, the tool determines borehole size shape orientation using multi-axis acoustic azimuthal caliper coupled with an in-situ measurement of mud sound speed and mud density. All nuclear and acoustic measurements are implemented with digital data acquisition chains and correction algorithms utilizing model-based design.
While neutron-porosity tools are characterized by nuclear simulation techniques since several decades, gamma-gamma density logging-while drilling tools, typically employing a 137Cs logging source and two scintillation gamma-ray detectors, are often characterized experimentally in a formation laboratory. The caveat of this procedure is that only a limited variety of formations, tool standoffs and drilling fluids can be covered. Another approach is the application of nuclear Monte-Carlo simulations, either to aid an experimental characterization with additional datapoints, or to derive a complete characterization that is scaled to reality in a later experimental test.
Locating, Quantifying, and Remediating Downhole Sand Infiltration to Minimize Equipment Failures and Increase Oil Production: A Case Study in Kuwait
Authors: Elias M. , Tagarieva L. , Alaryan A. , Tirkey N. , Prosvirkin S. , Vishnu R. 
Published: October 2023

Abstract
Sand infiltration requires immediate action to avoid costly downhole and surface equipment erosion. Additionally, sand particles may reduce hydrocarbon production by blocking downhole fluid flow. This study demonstrates the advantage of integrating multiple reservoir monitoring logs to identify the sand contribution zones, quantify the sand production, and plan the well remediation work required, while minimizing operation downtime.
A focused logging program and analysis method was developed to identify the sand infiltration location. Integration of passive acoustic and array-based production logs acquired the critical data to find the sand infiltration zones. The passive acoustic tool captured the count of inflowing sand strikes on the tool body generating a definitive acoustic signature. The array production logging tools mapped the fluid rates, flow delays, and fluid transport in the well. Post-processing of the passive acoustic data counted the unique sand strike events resulting in a quantitative sand infiltration assessment for a high deviation well penetrating Burgan and Wara reservoirs.
Sand and hydrocarbon production occurred in the Burgan reservoir, while the Wara formation was initially not producing any type of fluids due to Burgan sand infiltration. Within the Burgan formation large quantities of sand were detected inside the wellbore and approximately 100 feet below the inflow location. While some sand particles circulate up-hole with the flow others settle on the bottom. Acoustic logging analysis indicated that sand infiltration was generated from the middle Burgan perforations between 5737 ft and 5742 ft. According to the production logging analysis, less than 250 STB/D Burgan oil production was only flowing from the upper-most perforations between 5714 ft and 5718 ft due to sand fill below. Remediation action focused on a cement squeeze in the middle Burgan to close the sand infiltration perforations then a subsequent re-perforation of the Wara formation to resume production in that section. The Wara formation was relogged after perforation confirming reduced sand infiltration and an oil gain of 1530 STB/D with 170 STB/D of water production. Therefore, the sand infiltration information resulted in improved remediation outcomes. The integrated measurements clearly established the impact of sand infiltration on fluid inflow and created a road map for future well monitoring improvements.
This case study illustrates the successful integration of passive acoustic and array-based production logging to detect the sand infiltration zones and the high value fluid inflow zones. Well remediation activities were further optimized, re-establishing oil flow of 1530 STB/D from a set of non-producing perforations of the Wara formation.
Impact of Pressure-Dependent Interfacial Tension and Contact Angle on Capillary Trapping and Storage of CO2 in Saline Aquifers
Authors: Ren Bo , Littlefield James , Jia Cunqi , Duncan Ian 
Published: October 2023

Abstract
CO2 capillary trapping increases the total amount of CO2 that can be effectively immobilized in storage aquifers. This trapping, manifesting itself as accumulated CO2 columns at a continuum scale, is because of capillary threshold effects that occur below low-permeability barriers. Considering that capillary pressure is dictated by heterogeneous pore throat size, the trapped CO2 column height and associated CO2 saturation will vary spatially within a storage aquifer. This variation will be influenced by two pressure-dependent interfacial parameters: CO2-brine interfacial tension and CO2-brine-rock contact angle. Our objective is to understand how the pressure-dependence of these two parameters affects the heterogeneity of capillarity-trapped CO2 at a continuum scale.
Our conceptual model is a one-dimensional two-zone system with the upper zone being a flow barrier (low permeability) and the lower zone being a flow path (high permeability). The inputs to this model include microfacies-dependent capillary pressure versus saturation curves and permeability values. The input capillary pressure curves were collected in literature that represents carbonate microfacies (dolomudstone, dolowackstone, dolopackstone, and dolograinstone) in a prevalent formation in the Permian Basin.
We then employed the Leverett j-function to scale the capillary pressure curve for the two zones that are assigned with the same or different microfacies. During scaling, we considered the influence of pressure on both the interfacial tension and contact angle of CO2/brine/dolomite systems. We varied the zone permeability contrast ratio from 2 to 50. We then assumed capillary-gravity equilibriums and calculated the CO2 saturation buildup corresponding to various trapped CO2 column heights. The CO2 saturation buildup is defined as the CO2 saturation in the lower layer minus that in the upper one.
We found that the saturation buildup can be doubled when varying pressure in a storage aquifer, after considering pressure-dependent interfacial tension and contact angles. Thus, assuming these two parameters to be constant across such aquifers would cause large errors in the quantification of capillary trapping of CO2. The whole study demonstrates the importance of considering pressure-dependent interfacial properties in predicting the vertical distribution of capillary-trapped CO2. It has important implications in developing a better understanding of leakage risks and consequent storage safety.
Shunted Gravel Pack Failures – And How to Prevent Them
Authors: Latini Carolina , Govinathan Kesavan , Wassouf Philip , Jain Samyak , Tibbles Raymond 
Published: October 2023

Abstract
The success of any gravel pack treatment implies effective gravel coverage of the screens. Shunt tubes are used in both open and cased hole completions to overcome some of the challenges present for conventional gravel placement techniques by allowing slurry to bypass any premature bridges and continue packing downstream. Shunted gravel packs are therefore viewed as the most forgiving gravel placement technique, which has generated a myth that the use of a shunt tubes "guarantees" a successful gravel pack. However, failures of shunted pack placement are being experienced, resulting in wells that are incompletely packed. A better understanding of the limitations of shunt tube systems and an appropriate engineering design can effectively reduce the risk of shunted gravel pack failures.
Case histories are used to present a variety of shunt tube gravel placement failures. Surface and bottom hole gauge data combined with an industry standard sand control simulation software has enabled more detailed evaluation and identification of the different failure mechanisms. These include incomplete packs due to shallow zone fracturing, the blockage of shunt entry due to fluid quality issues and shunts erosion failures, among others.
This paper consolidates the various shunted gravel pack failure mechanisms that have been experienced in field operations and makes recommendations on how improved treatment designs can prevent them.
Critical Evaluation of Chemical Additives in Reducing the Minimum Miscibility Pressure for Gas Injection Process
Authors: Qi Zhenbang , Jiang Li , Emakpor Maroghoke , Stewart Suzanne , Abbott Jonathan , Abedini Ali 
Published: October 2023

Abstract
It is highly desirable to achieve minimum miscibility pressure (MMP) between injection gas and reservoir crude oil phase under the reservoir pressure in the gas injection (Huff-n-Puff) process, despite the obvious challenges, in order to gain more productive sweep efficiency and hence higher oil recovery yield. Here, we report on the evaluation of the performance of five discrete chemical additives in lowering the MMP of a hydrocarbon gas mixture with a representative crude oil through utilization of a microfluidic MMP measurement device. In the current study, a microfluidic platform was developed to accurately measure the MMP of a hydrocarbon gas and crude oil system in the presence and absence of chemical additives at 77°F and 150 °F, respectively. The gas stream consists of 70 mol% methane and 30 mol% propane, representing a typical hydrocarbon gas used for gas injection operations. A group of selected chemical additives were individually premixed with the oil phase at 1 wt% loading prior to the microfluidic testing to quantify the reduction in the MMP. The highly sensitive fluorescent microscopy was also employed to provide real-time insight into the porescale of the oil displacement during the gas injection process. The MMP of the gas and oil system was measured to be 3060 Psia at 77 °F. All the chemical additives demonstrated an effective reduction in the MMP within in a range of 9–21% with one of the additives outperformed the best, lowering the MMP to 2410 Psia. The direct fluorescent optical access into the microfluidic porous structure, however, showed considerable deposition occurred during injection for some of these chemical additives, a potential concern for formation damage. The top two chemical additives were then tested at 150 °F and compared with the gas–oil MMP with no chemical additive (3785 Psia at 150 °F). The selected two chemical additives lowered the MMP to 3425 Psia (10% reduction) and 3495 Psia (8% reduction) with no depositions observed in the porous media. The use of selected chemical additives to lower the MMP can make a significant contribution to the gas injection EOR processes in depleted reservoirs that can in turn potentially improve the performance of the reservoir-scale productions. This work reveals critical insight in chemical additive selection, plus dosages, for effective MMP reduction. Although the extent of MMP reduction was decreased at higher temperature, 10% reduction is nevertheless remarkable, given its low dosage, and can be improved further by adjusting the chemical loadings for high pressure operations. The microfluidic MMP testing platform is advantageous over the conventional slim tube method in significantly shortened turnaround time and minimized fluid consumption.
Measurement of the Static Proppant-Settling Velocity in Fracturing Fluids Through Digital Image Analysis
Authors: Huang Jiangshui , Lin Lijun , Lin Genyao , Richardi Bryant , Liu Fuchen , Li Jianshen , Yang Zhenzhou 
Published: October 2023

Abstract
This paper presents a novel method for quantitatively measuring the static proppant-settling velocity in hydraulic fracturing fluids through digital image analysis. The method developed is reliable and efficient for measuring the static proppant settling velocity (Sv) when there is no clear settling interface, which is useful for comparing the proppant carrying capability of different friction reducers (FRs), optimizing the concentration of friction reducers in the fracturing fluids for field operations, and improving the proppant carrying capability of friction reducers through the synthesis process.
The experimental procedure involves pouring a fracturing fluid with proppants into a transparent glass cylinder, taking images of the proppants settling using a camera, transferring the images into a computer, and analyzing the images using macro programs prepared to measure the static proppant settling velocity. The settling velocity is determined by measuring the position (height) change of a proppant concentration selected with time, which is realized through using image saturation to determine the position of the proppant concentration in the image analysis. The results obtained from this method show that the proppant size, friction reducer concentration, salinity of the friction reducer fracturing fluids, and friction reducer molecule weight and chemical structure have an impact on the static proppant settling velocity. Also, the method developed in this study can be helpful for selecting proper fracturing fluids for field applications and the optimization of friction reducers in the synthesis process through quantitatively measuring the settling velocity.
To the best of our knowledge, except for determining the settling velocity of a single particle in the fluids, this is the first study to quantitatively measure the static proppant-settling velocity in fracturing fluids through digital image analysis. The method developed offers several benefits including the ability to measure the settling velocity in real-time, low cost, and ease of implementation even when there is no clear settling interface. The results obtained from this method provide valuable insights into the transport behavior of proppants in fracturing fluids, enabling better design of hydraulic fracturing treatments to improve the recovery of oil and gas.