bluuebunny/crossref_metadata_2025_split huggingface dataset:
Deployment of Self-Healing CO2 Resistant Cement for Carbon Capture and Storage Wells in Eastern Australia
Authors: Azwar C. , Alsaman M. , Veisi M. , Vang G. , Boggon P. , Narainasamy H. , Nguyen K. T. 
Published: November 2024

Abstract
Carbon capture and storage (CCS) is a vital technology in the fight against climate change. Eastern Australia is an important site for CCS activities where one of the operators is starting a CCS project with target to store 1.7 million metric tons (MMT) of CO2 per year, ensuring enhanced safety and permanence in the same reservoirs that have securely held oil and gas for millions of years. This paper explores the benefits of deploying novel cementing technology in CCS wells in Eastern Australia.
CO2 injection leads to a corrosive environment, which can cause cement sheath degradation. This paper presents the decision-making process used in selecting a suitable cementing system for the CO2-rich environment post-injection, and the first-time application of a self-healing and CO2-resistant cementing system in Australia. The operator is committed to safer operations throughout the life of the well by providing long-term well integrity for the CCS wells. The failure of cement sheaths due to the degradation of conventional Portland cement in a CO2 corrosive environment can lead to significant environmental risks.
The newly developed, self-healing CO2-resistant cement can withstand the effects of carbonation, making it superior compared to conventional cement systems in a CO2 environment. The deployment of this self-healing CO2-resistant cement system technology for the CCS wells in Eastern Australia has the potential to significantly improve wellbore integrity. This technology offers several benefits, including improved resistance to mechanical stresses and vibrations, resistance to chemical attack, and low permeability. In case of loss of the integrity, when the cement sheath is exposed to CO2 leaking fluids, it has the capability to self-heal and restore the long-term well integrity. Several crucial challenges were addressed for successful delivery, including the remoteness of Eastern Australia, limited accessibility to the location, job frequency, and handling at the third-party uniquely equipped blending facility. All challenges were addressed through rigorous quality control processes developed from extensive laboratory testing and comprehensive blend lifecycle management. Post-job result analysis included running wireline logs to confirm the annular barrier. Cement evaluation logs outcomes were excellent and exceeded expectations. Overall, the deployment of novel self-healing CO2-resistant cement system technology for the CCS wells in Eastern Australia ensures safer, more environmentally responsible CCS operations.
Experimental Study on Carbonated Water Flooding Enhanced Volatile Reservoirs Recovery Based on NMR Technology
Authors: Pan Yue , Liu Huiqing , Tang Jiawei , Zhou Song , Luo Chen , Wang Zuochen , Liu Renjie , Chen Pengyi 
Published: November 2024

Abstract
Volatile reservoirs possess intricate pore-permeability structures and high connate water saturation. Water flooding development is impeded by a strong water-lock effect, while gas injection development faces challenges with significant gas channeling, resulting in a low recovery rate. To address these issues and capitalize on the synergies between water and gas flooding, this study explores the utilization of carbonated water (CW) flooding to enhance the recovery factor in volatile reservoirs.
This study investigates the feasibility of CW flooding in a practical volatile reservoir in Kazakhstan. Employing online nuclear magnetic resonance (NMR) displacement technology, we systematically explore the impact of different displacement media (formation water, surfactant, and CW) on the recovery factor in volatile oil reservoirs. Additionally, through the integration of high-pressure mercury data with NMR T2 spectra, we ascertain the lower limit of pore diameter under different displacement methods. Finally, NMR imaging is applied to analyze the oil recovery and core microscopic pore throat producing characteristics within the rock cores.
Analysis of converted NMR T2 spectra reveals that conventional water flooding and surfactant flooding are more effective in producing crude oil in microscale micropores and microscale macropores, facing challenges in nanopores and submicron pores. CW flooding compensates for the limitations of water and surfactant flooding in producing crude oil from nanopores and submicron pores. Further data processing allows for the calculation of recovery rates and lower limits of pore diameter for different displacement methods. The pore diameter lower limits for conventional water flooding and surfactant flooding are approximately 0.1 |-im. with CW flooding exhibiting a lower limit of about 0.08 ^m. The recovery rate for CW flooding is approximately 5% higher than the other two displacement methods. Moreover. an unexpected observation from core imaging reveals that. for fractured cores. regardless of the displacement method. primary producing predominantly occurs around the fractures. As displacement progresses. crude oil in the matrix migrates towards the fracture ends. resulting in the producing of matrix oil.
Through a series of online NMR displacement imaging experiments. we investigated the impact of conventional water flooding. surfactant flooding. and CW flooding on the oil recovery and core microscopic pore throat producing characteristics in volatile reservoirs. The study determined the feasibility of CW flooding to improve the recovery efficiency of volatile reservoirs. presenting promising application prospects. Moreover. it is considered an environmentally friendly method for reducing greenhouse gas emissions.
Simulation of the Triple Completion-Gas Downhole Water Sink-Assisted Gravity Drainage Process through the Re-Injection of Petroleum Associated Gas (PAG)
Authors: Sadkhan Rawaa A. , Almansor Alzahraa M. , Al-Mudhafar Watheq J. , Javid Khalid , Rao Dandina N. 
Published: November 2024

Abstract
The ongoing production of oil results in a gradual depletion of reservoir pressure over time. This decline in pressure persists until it reaches a threshold at which the reservoir can no longer yield hydrocarbons through primary recovery methods. Therefore, the implementation of secondary recovery techniques is necessary to streamline pressure maintenance operations. This intervention mitigates the pressure decline for a limited period, repeating the process until the reservoir no longer generates hydrocarbons through secondary recovery techniques. Therefore, we employ tertiary recovery strategies as the last resort to enhance oil recovery from the reservoir. In this paper, we reconstructed a compositional reservoir simulation model to simulate the use of Petroleum Associated Gas (PAG) for re-injection in clastic reservoirs, surrounded by strong water aquifers, with the aim of maximizing oil production and minimizing water cut to the greatest extent possible. We specifically employed the Triple Completion Gas Downhole Water Sink Assisted Gravity Drainage (TC-GDWS-AGD) process on the Upper Sandstone member to improve cumulative oil production and reduce water cut. The TC-GDWS-AGD process places a 7-inch casing diameter and two horizontal completions, one for water production beneath the water-oil contact and the other for oil production within the high oil saturation oil zone. A packer isolates both completions from each other. Additionally, a packer perforates the top vertical annulus for gas injection at the reservoir's top, forming a gas cap and mitigating pressure depletion.
The results showed that the DC-GAGD had a significant increase in the cumulative oil (24.5 MMbbl), while the TC-GDWS-AGD achieved similar results by an amount of 23.4 MMbbl, which is nearly 5 MMbbl more than the primary scenario of 18 MMbbl. As for the water cut, DC-GAGD showed a decrease in the first days, reaching 70%, but after a short period, the water cut would rise again as a result of the continued gas injection, while TC-GDWS-AGD showed better results and for a relatively longer period of time compared to DC-GAGD, although the water cut decrease in it was 80%. It was evident that the reservoir could not sustain production for 10 years at a rate of 10,000 barrels per day. Therefore, we investigated if the TC-GDWS-AGD process could significantly mitigate the tendency of water cresting and reduce the water cut in oil production wells to low levels, especially when we reduced the strength of the maximum oil production to the appropriate levels of the current reservoir capacity, which is 2000 STB/day However, oil recovery is lower than in other cases with higher constraint values. Therefore, we should conduct an optimization to determine the optimal levels of constraints that yield the maximum oil production and the minimum water cut.
Evaluation of Residual Oil Zone Development in a Mature West Texas Carbonate Reservoir
Authors: Alobeidli A. A. , Alqallabi S. A. , Khan S. A. , Hixon E. S. , Hameed A. , Jackson J. , Nandi A. 
Published: November 2024

Abstract
West Texas has long been known as a showcase for successful post-waterflood (tertiary) recovery by CO2 flooding of mature waterfloods in conventional oil reservoirs. However, a large oil resource exists in the form of Residual Oil Zones (ROZs) that have been more economically challenging to develop compared to the familiar Main Pay Zone (MPZ). The conventional MPZs are producible at a feasible cost. As these CO2 floods are becoming very mature and the production is continuously declining, ROZ is becoming attractive enough to be considered and evaluated as a development opportunity.
The subject field (Means) has been producing for the last several decades with nearly half of Original Oil in Place (OOIP) residing in the untapped ROZ. This is a light oil for which CO2 has already been shown to be an effective miscible displacement injectant. Oil production from the MPZ has been in steady decline and therefore, a decade ago, several wells were drilled through the ROZ layers to gather additional data. Since the production was commingled with the MPZ and given the vertical heterogeneity, the ROZ performance was less than expected with the recovery being less than 1% after 10 years of CO2 injection. Hence the idea of utilizing dedicated wells in ROZ was evaluated by conducting this simulation study.
This study was commenced by gathering all the recent log, core, and injection/production data and construction of a rigorous ROZ geologic model. Special consideration was given to the location and extent of vertical barriers as well as location of high-perm layers to adequately capture their effect. A section of the reservoir comprising of nine 5-spot sectors was selected for a scoping simulation study. Both vertical and horizontal wells (dedicated to ROZ only) were evaluated with various well spacings. Sensitivities were also conducted with different Water Alternating Gas (WAG) cycles, continuous initial gas injection followed by WAG cycles, and with gas injection only.
Advanced Lightweight Thixotropic Cement Slurry (ALWTC) First Time Worldwide Application in a Primary Cementing Across Natural Fractured Limestones
Authors: Ramadan A. , Salazar J. , Sajid M. 
Published: November 2024

Abstract
Lost circulation while cementing intermediate sections across the Umm er Radhuma (UER) Formation, a naturally fractured limestone formation in UAE, is technically challenging and has financial impacts, including nonproductive time and remedial operational expenses. All fields in UAE encounter severe lost circulation while drilling UER Formation and cementing this section using lightweight slurries to isolate the zone and mitigate losses is a paramount task which requires several post-top jobs to provide zonal isolation of the casing.
ALWTC technology was developed in the UAE as a lost circulation solution to reduce and mitigate losses across vugular and naturally fractured formations during drilling. But wells having the same or more complex loss scenarios during primary cementing where standard lost circulation materials and conventional lightweight slurries are used, have limitations. The ALWTC solution was evaluated and modified to be applied with the same lightweight technology currently used in primary cementing but enhanced with a specific thixotropic agent. An identified risk is the fast gel development (thixotropic behavior), a high risk that can compromise the cement placement in primary cementing, especially in jobs where large volumes are used.
Smooth execution with well-coordinated events and best practices were deployed to ensure excellent execution without any health, safety, and environment or service quality incidents. During the first job, partial to full returns were observed, achieving cement to surface, which was our target. On one top job, only 5 to 6 bbl. of slurry were pumped, compared to 300 to 400 bbl. before. This saved 3 days of rig time and USD 25,000 of additional cost and services for the operator; additional jobs performed with similar performance. It was concluded that ALWTC is possible and suitable for primary cementing jobs across vugular and naturally fractured limestone formations. Cement evaluations also showed remarkable results across the UER and Simsima formations, compared to the normal slurry design that was being used before.
ALWTC is a technology developed locally in the UAE for UAE cementing challenges across vugular and/or naturally fractured limestone formations. This technology has immense potential in the Middle East where losses across limestone formations are some of the biggest challenges and cementing to provide the required zonal isolation is a must.
Multiphase Fluids Performance Ratio Analysis of ICD/AICV to Analyse the Multiphase Mixture Behaviour of Oil-Water Mixture and Oil-Gas Mixture During Production in Carbonate or Sandstone Reservoirs
Authors: Bjerke A. , Ismail I. Mohd , Mathiesen V. 
Published: November 2024

Abstract
In today's engineer's toolbox, a variety of inflow control technologies exist that can help to achieve the targets to enhanced oil recovery. Characterizing difference type of inflow control technology especially that performed during the well lifetime are challenging due to the fluids phase change during the well life. The nature of porous media, and complex interaction of fluid and rock in the reservoir often lead to mixture flow during most of the well life during production phase. Early water and gas breakthrough increase the challenge of understanding the mixture behavior flow from the reservoir to the well. Different inflow control technologies are used to enhanced oil recovery and choke the unwanted fluids (water/gas) compared to oil. It is essential to understand the performance of inflow control technology during the multiphase mixture production. The Fluid Performance Ratio (FPR) analysis for single phase flow has been presented in a paper previously. In this paper the multiphase mixture fluid methodology and workflow have been developed to compared different type of inflow control technology completion to understand the capability to reduce unwanted water and gas production in multiphase flow along the wellbore in the reservoir. Different inflow control technology and its flow performance are a function of both density and viscosity. The fluid composition affects the multiphase flow behavior differently for various devices, i.e., the pressure drop for mixture oil, water, and gas. Different designs have been tested in laboratory with single phase and multiphase flow that replicates downhole operating conditions. The multiphase fluid performance ratio will compare the performance difference in choking of multiphase fluids mixture for oil/water and oil/gas and express the multiphase fluid performance ratio in percentage. Experimental flow loop results illustrate a significant difference in multiphase behavior of oil/water and oil/gas between conventional ICDs and AICVs. AICV with dynamic flow area shows more effective control of mixed fluid during breakthrough resulting in improved oil recovery and limiting the unwanted water and gas more effectively. Case studies shown and demonstrating the mixture production behavior. Comprehensive guidelines on the multiphase fluid performance ratio analysis have been developed to compare different type of inflow control technology completion to understand the capability in multiphase fluid mixture to reduce unwanted water and gas production along the wellbore in the reservoir. The continued development of a new characterization method for multiphase flow performance ratio has helped to unveil the benefits of characterizing and differentiating between inflow control technologies.
Analyzing the Levelized Cost of Hydrogen: Leveraging Machine Learning for Evaluating Production Pathways
Authors: Ezechi C. G. , Sekar L. K , Okoroafor E. R. 
Published: November 2024

Abstract
This study examines the economic viability of producing hydrogen by various routes, paying attention to the hydrogen colors that are less prominent in literature. The analysis was done by comparing the levelized cost of hydrogen (LCOH) for eleven hydrogen production pathways. Predictive analysis for hydrogen production rates was also carried out using an artificial neural network (ANN) model. The data was collected using a literature-based methodology which considered several factors, such as feedstock costs, operating expenses, and capital expenditures. The study showed that the LCOH varies greatly depending on the production pathways. Due to its more modern technology, hydrogen obtained from fossil fuels (black/brown, gray, and blue) is usually less expensive than hydrogen derived from renewable energy sources (green, yellow). On the other hand, blue hydrogen requires carbon capture technology, which makes the operating costs associated with it higher. Aqua hydrogen stands out with the lowest levelized cost of $0.23/kg hydrogen produced, but environmental concerns from oil sand extraction and emerging technologies like orange hydrogen need further consideration. The ANN model was developed based on key hydrogen production parameters, and its performance was evaluated using metrics such as the proportion of variance (R-squared), mean square error and root mean square error. The R-squared result for the test data set was 92% (R2=0.92), showing the model's high predictive accuracy. This study is unique in two ways: first, it shows significant differences in LCOH across several hydrogen colors, with aqua hydrogen becoming the most economical choice. Second, it shows how machine learning can be used to find cost-cutting measures and optimize hydrogen production processes through various methods. Further research is required to address the lack of real-time production data, investigate the environmental effects of these production processes, and improve the accuracy of developed models.
Enhancing CO2 Dissolution Storage and Analyzing Leakage Risks in CCUS Using Microfluidic Technology
Authors: Chen Zheng , Li Lei , Su Yuliang , Hao Yongmao , Wang Wendong 
Published: November 2024

Abstract
In the process of CCUS, it is crucial to improve the efficiency of CO2 sequestration and analyze related leakage risks. This study aims to design experiments and evaluation methods using microfluidic and SEM technologies to investigate the effects of different agents on enhancing CO2 solubility storage under varying pore size conditions and to analyze the microscopic impacts of CO2 dissolution on rock minerals. The experimental results show that the addition of solubilizing agents reduces CO2 erosion, making dissolution less evident, and the resulting mineral precipitates fill some of the pores, reducing CO2 leakage paths. Triethanolamine exhibits a more significant solubilizing effect at higher pressures, while the effectiveness of solubilizing agents decreases with smaller pore diameters. Isopropyl citrate shows optimal solubilizing effects under low-pressure gaseous conditions. Under high-pressure supercritical conditions, smaller pores enhance the solubilizing effect, reaching up to 201.9%.
Distributed Temperature Sensing Using Tapered Monobore Completion for Extended Reach Wells
Authors: Barragan E. , Varma E. , Wibowo S. , Jimenez A. , Al Wahedi O. , Zafar O. , Khaled M. , Aljasmi S. A. 
Published: November 2024

Abstract
The oil industry faces several challenges when performing Lower Completions in Extended Reach Wells (ERW), such as increased friction factor, higher tortuosity, and so on. The introduction of Tapered Monobore Completion (TMC) for Extended Reach Wells (ERW) marks a significant advancement in the field of reservoir development. This paper explores the process of design and benefits of TMC, particularly in conjunction with Distributed Temperature Sensing (DTS) technologies and Limited Entry Liner (LEL) stimulation technique, to enhance production rates, reduce operational costs, and improve reservoir management.
A new method was devised after several trials of running Distributed Temperature Sensing (DTS) Completions in longer horizontal wells with conventional 3-1/2″ completion in horizontal hole section. The Monobore Completion was adjusted to a tapered 4-1/2″ + 3-1/2″ in horizontal hole and the number of swell packers was reduced. DTS completion with carrier using Limited Entry Liner (LEL) was deployed with a length of more than 6350 ft in a carbonate reservoir in the Middle East. Various simulations of torque and drag analysis were performed to determine the optimal configuration of the Tapered Monobore Completion.
After the first successful design and deployment of a well in the long horizontal hole, two more wells have been finished and more are planned in other reservoirs of the Field. Also, the Tapered Monobore Completion design is being considered for other Fields in the same area. The successful deployment sets a standard for best practices and improvements in well completion. It shows that TMC can work in ERW and can greatly affect operational efficiency and cost-effectiveness. The results and methods from this project are expected to shape future designs and operations, helping the oil and gas industry's skills in reservoir use and management. Combining Tapered Monobore Completion with DTS systems gives operators real-time reservoir monitoring abilities. This combination helps operators make informed choices for reservoir management, possibly increasing hydrocarbon recovery through accurate and timely actions.
TMC has a streamlined design that needs fewer parts and less time to install, making it more affordable than conventional completion methods. This lower cost is helpful not only in the immediate term but also for the long-term profitability of well operations. The Monobore design is simple and allows for easier access for well interventions and maintenance. This access is crucial for reducing the time and costs of these operations, and improving operational efficiency.