bluuebunny/crossref_metadata_2025_split huggingface dataset:
Subsurface and Operational Challenges in a Successful Microfrac Operation and Remedial Solutions – Observations from Recent Experiences in Tight Unconventional Reservoirs
Authors: Sen Souvik , Chakrabarti Prajit , Franquet Javier A. 
Published: May 2024

Abstract
In this study, we discuss the subsurface and operational challenges and effective remedial solutions for the wireline straddle packer microfrac operations to achieve successful breakdown and conclusive closure pressure, based on our recent experiences from the recently concluded microfrac campaign in the challenging Triassic and Cambrian unconventional reservoirs of Northern Africa. We share our experiences from the deeper clastic and carbonate targets which are tight, extremely strong, and exhibit a very high breakdown pressure gradient of up to 1.16 psi/ft. In case of breakdown pressure elevated by external factors (effect of mud filtrates etc.), the pump-out method facilitated the formation breakdown. The majority of the microfrac tests in these tight formations showed the proven benefit of multiple rapid loading and unloading cycles by injection (hole pressurization) and pump-out (hole depressurization) in inducing near-wellbore fatigue to effectively weaken the formation before achieving successful breakdown. The effect of near-wellbore poroelasticity was also observed, resulting in increasing fracture reopening and closure pressures in the consecutive microfrac test cycles; the pump-out technique was also effective in eliminating such effects. The tight unconventional reservoirs exhibited a low leak-off coefficient resulting in poor natural fall-off pressure decline response resulting in an overestimation of closure gradient. Therefore, controlled flowback by a small volume pump was adopted to achieve induced closure and conclusive Shmin estimates.
Scaling Field and Experimental Data Using Machine Learning Approaches to Evaluate Oilwell Cement Degradation, Stability and Integrity for CCUS Applications
Authors: Abraham J. J. , Devers C. , Teodoriu C. , Amani M. 
Published: May 2024

Abstract
Carbon Capture, Utilization and Storage (CCUS) processes are increasingly being utilized as a viable solution for carbon removal and meet the goal of net-zero carbon emissions by 2050. Captured carbon dioxide (CO2) is stored deep underground – typically in depleted oil or gas (O&G) wells - utilizing technologies and methods currently employed by the energy industry. However, there are certain ongoing well integrity challenges that would need to be addressed – especially those relating to the cement layer. Cement present in wells used for CCUS applications – including old or abandoned wells - need to ensure zonal isolation, be resistant to deterioration, corrosion, or gas migration, as well as be suited for adverse downhole conditions.
Oilwell cement present in existing or abandoned O&G assets have been exposed to a wide range of downhole conditions throughout their lifecycle. It is generally very difficult to determine the mechanical properties and physical condition of the cement downhole and a decline in these properties is expected over time. Experimental evaluations have shown that temperature plays a role in the setting and maturity of the cement, and in CCUS wells, corrosive factors are a major concern due to the acidic environment produced at the CO2 injection zone. These can significantly affect cement mechanical properties such as the Uniaxial Compressive Strength (UCS). Evaluations have shown Temperature or Acoustic Logs can be used to determine downhole properties which can then be correlated to the behavior of cements and the change in their mechanical properties over time using machine learning algorithms.
Laboratory evaluations showed varying mechanical properties for oilwell cement at different temperatures and degradation over time. Overall, Class G cements developed the highest stress failure resistance, followed by Class H cements. Higher temperatures accelerated the setting time of all cement samples due to rapid dehydration. However, this in turn reduced the peak UCS developed, indicating a lower stress failure criterion. UCS also showed a direct relationship to acoustic data which can be utilized to evaluate mature and abandoned wells for their integrity. When modeled using supervised machine learning algorithms, field temperature data and acoustic data can reliably predict the mechanical properties of cements over time. An artificial neural network model, and two tree based models were developed, which showed good correlation in predicting compressive strength of downhole cements.
Properly understanding the behavior of oilwell cement and the evolution of their mechanical properties is critical to ensure safe storage. Data driven algorithms which can correlate the dynamic mechanical properties of cement to the temperature gradient and acoustic logs can help reliability predict the integrity of the cement layer over time especially for CCUS applications.
Vibroacoustic Technology: Revolutionizing Pipeline Integrity Monitoring for Enhanced Performance
Authors: Gomes A. P. , Marino M. , del Giudice S. 
Published: May 2024

Abstract
The aim of this work is to present a versatile and robust vibroacoustic pipeline integrity monitoring technology, easily retrofittable to existing assets, capable of real-time detection and localization of leaks and Third-Party Interference (TPI). Additionally, the technology can offer features such as PIG tracking, assessment of valve-sealing quality, pressure tests, and more.
Top-class vibroacoustic sensor blocks are strategically positioned several kilometers apart along the pipeline. They effectively capture vibroacoustic waves generated by leaks and TPI events as they propagate through the pipeline and the surrounding fluid, taking advantage of the pipeline’s efficient waveguide properties. The acquired data is then transmitted to dedicated processing servers, triggering alarms as necessary. For leak detection, the system relies on an Advanced-Negative Pressure Wave, while the localization of both leaks and TPI events employs the TDOA method (Time Difference of Arrival). Sophisticated and patented algorithms are implemented to address noise removal, detection, and localization, resulting in a substantial reduction in the false alarm rate.
The Vibroacoustic Technology outlined in this work is presently deployed and operational on numerous pipelines globally, actively surveilling thousands of pipeline kilometers. The system has demonstrated its effectiveness in rapidly detecting and precisely localizing both spillage and impact events. Moreover, the system can identify and localize any internal events interacting with the pipeline, opening possibilities for various applications to monitor the asset. The sensor blocks are installed in hydraulic derivations along the pipeline tens of kilometers apart. These blocks transmit real-time data to a processing server, requiring less than 20 kbit/s and consuming less than 20 W of power. After a brief installation campaign, the detection system is calibrated, and the versatility of Vibroacoustic Technology is evident in its integration for diverse integrity management requirements. This work displays real use cases where the technology has excelled, detecting leaks, excavations, PIG tracking (in real time or after the PIG is lost inside the pipe), assessing inline valve sealing quality, identifying corrosion micro-vents, and accurately localizing existing leaks during pressure tests. The demonstrated results emphasize the efficacy and adaptability of Vibroacoustic Technology across several applications.
The novelty feature of this pipeline management and integrity tool lies in its unparalleled flexibility in deployment options. This achievement allows the system to be installed across a diverse range of challenging scenarios, in liquid or gas pipelines, ensuring outstanding performance in each instance.
Novel Approach to Stimulation Design Optimization for Ultra-Deep, 200°C Temperature Formations: A Case Study in Kunteyi Block
Authors: Hou Tengfei , Lin Hai , Wu Xi , Wang Xiaolu , Li Zhanchun , Zhang Shiling , Feng Shengli , Zhang Yang , Liu Yong , Shang Litao , Bai Haoli 
Published: May 2024

Abstract
The kunteyi Block, a domestic gas field, poses unique challenges with its ultra-deep, 392°F high-temperature conditions. These extreme environments significantly challenge the safety and efficiency of well testing and stimulation. The block faces issues such as:1) Difficulty in reservoir coring and low accuracy in mechanical parameter interpretation from conventional logging data; 2) Challenges in fracture initiation under pressure constraints in ultra-deep (20,964 ft TVD), high-stress, high-angle wells; 3) Lack of experience in fracturing operations for ultra-deep, high-angle wells at 392°F.
This paper presents a design methodology and process tailored for ultra-deep, high-temperature, high-angle wells. It begins with cutting test technology for in-depth rock mechanics testing, followed by an innovative mechanical specific energy calculation method, factoring in actual drilling bit selection. This approach, combined with rock mechanics parameters, facilitates the identification of optimal cluster locations. Key construction parameters like inter-stage spacing, perforation cluster number and hole count, measure displacement, and fluid volume were further refined through three-dimensional fracture expansion modeling. Moreover, for a suspected aquifer 30 feet below the first section, a targeted low-displacement, small-scale acidification process was implemented.
The results demonstrate that this method effectively quantifies the rock mechanical parameters of the Kunteyi Block. The optimized perforation locations achieved lower breakdown pressures of 13,778 psi; an 8.5% reduction compared to neighboring wells at 15,055 psi. The high-angle wells, segmented into four stages with differentiated fluid scales ranging from 56,504 to 63,566 cubic feet and a pump rate increase from 18.9 bpm to 62.9 bpm, enabled efficient fracture initiation. The implementation of small-displacement acidification effectively prevented communication with the water layer, thus enhancing the project's feasibility.
This paper validates the effectiveness of cluster location enhancement using cutting tests and mechanical specific energy methods. These findings offer valuable insights and practical experience for the efficient stimulation of ultra-deep, high-temperature, high-angle wells.
Status, Experience, and Inspiration of Unconventional Resources Hydraulic Fracturing Technology
Authors: Jie Li , Shuai Li , Jianmin Li , Jiacheng Li , Xinbin Yi , Mingxing Wang , Gang Tian , Junchao Wang 
Published: May 2024

Abstract
China's recoverable tight/shale oil resources amount up to 32 billion barrels, and 92% of the newfound proven reserves are low/ultra low permeability or unconventional reserves. Complex sedimentary structure & geological conditions, deeper reservoir burial and worse reservoir characteristics, fast decline, low recovery and high cost these all make it very hard to develop these kinds of reservoirs.
In this paper, we firstly introduced the geology and reservoir characteristics of unconventional tight/shale oil and tight/shale gas reservoir, compared with North America, the organic-rich shales in China are characterized by large burial depth (about 65% of the shales with a burial depth &gt; 3,500 m), complex surface conditions, and variety of types of organic-rich shale. These characteristics determine that the resource characteristics of these shale oil and gas are different from those of the widely developed in the United States.
We summarized the past 30 years’ progress of hydraulic fracturing technology, from vertical well acidizing, vertical well hydraulic fracturing, and horizontal well multi-stage multi-cluster hydraulic fracturing. Small well spacing, dense cutting and 5-6m length per clusters is the optimal artificial fracture spacing for this kind reservoir via Geo.-Eng. integrated fracturing design. Extreme Limited-Entry (XLE) perforation design, 3-8 perforation holes per cluster is best for equilibrium artificial fracture initiation, 6-8 clusters per stage and over 85% fractures can be opened via downhole cameral monitor. P’N’P completion method and soluble well downhole plugs, saving non-pumping time and reducing fracturing costs. Multifunctional fluids and reusable low-cost variable-viscosity slickwater, featured with imbibition mechanism and increase oil recovery. Low-cost quartz sands wildly be used to reduce costs. Factory style hydraulic fracturing mode, increase the fracturing efficiency and reduce on-site organizational costs.
The integrated technologies have been widely applied in unconventional wells. Application of the integrated technologies and the experience can be references for the development of similar marginal reservoirs.
Deep Transient Testing Enhanced by Real Time Wellbore Dynamic Simulations
Authors: Lopes Velerian Sanjao , Kumar Arvind , Nukala Poorna Venkata Sai Teja , Wydiabhakti Tety Benedicta 
Published: May 2024

Abstract
Wellbore dynamics play a crucial role in reservoir testing, serving as a crucial link between the reservoir and surface measurements. This research aims to tackle the challenges faced in well control and highlight the benefits of using wellbore dynamic simulation to improve the safety of formation tester (FT) sampling and deep transient tests (DTT) conducted in wells. Special attention is given to pre-job simulations and multi-parameter sensitivity analysis. The focus is on advancing our understanding of the interaction between hydrocarbons and wellbore mud during and after FT pump-out operations. Recent advancements in DTT technology allow for the pumping of larger volumes of hydrocarbons into the wellbore compared to conventional formation tester operations. During DTT, formation fluids pumped from the well mix with drilling mud from the surface in the annulus. This fluid mixture is then circulated out from the annulus to the surface during the flowing period. Understanding these procedures is crucial for ensuring well control safety. Therefore, the use of a dynamic multiphase flow simulator that considers the interactions between downhole pumped hydrocarbons and drilling fluids becomes essential to improve the accuracy of pressure simulations during DTT operations. To enhance safety in oil and gas operations, a cloud-based wellbore dynamics simulator allows for precise quantification of drilling fluid adjustments, circulation rates, hydrocarbon composition, downhole pump rates, well depth, hole diameter, overbalance pressure, and pump duration for various FT design sequences. This enables accurate forecasting of downhole well pressure and the distribution of free gas throughout the well, with adjustments made as necessary. Furthermore, scenarios with kick potential and risk mitigation strategies are explored. This paper presents 15 case studies involving different hydrocarbon types and overbalance scenarios, where cloud-based wellbore fluid simulations were conducted for various flow rate scenarios to predict potential well control situations. Special attention is given to near-critical hydrocarbon fluids such as condensate, volatile oil, and wet gas.
A Morphological Method for Predicting Permeability of Fractured Tight Sandstone Reservoirs Based on Electrical Imaging Logging Porosity Spectrum
Authors: Li Jiaqi , Zhang Wei , Liu Tianding , Xue Weifeng , Xiao Liang 
Published: May 2024

Abstract
Permeability is crucial for formation evaluation, it reflects the reservoir fluid fluidity, and it directly affects subsequent development and production. In conventional tight sandstone formation, it has proposed many methods to predict reservoir permeability. However, influenced by the heterogeneity of fractured tight sandstone reservoir, the accuracy of permeability calculated by the proposed method is not high, and there has been little research on permeability evaluation for this type of reservoir. it's difficult for conventional wireline logging and nuclear magnetic resonance (NMR) logging to evaluate fracture parameters, but electrical imaging logging can well reflect fracture information. Therefore, we adopted electrical imaging logging to evaluate the permeability of fractured tight sandstone reservoir.
We proposed a morphological method to predict permeability: Firstly, the electrical imaging logging data is processed and the formation porosity spectrum is obtained, then the position of primary porosity spectrum peak is determined. Afterwards, extract the mean and standard deviation parameters based on the distribution morphology of the primary porosity spectrum and combine the normal distribution function to fit a single primary porosity spectrum. Accumulate the amplitude of the original porosity spectrum and the fitted primary porosity spectrum respectively. When the cumulative amplitude of the fitted primary porosity spectrum remains basically unchanged, the corresponding porosity is the boundary point between primary pores and secondary pores. Based on this boundary point, the proportion of primary pores in the formation can be calculated. Permeability was influenced by both primary pores and secondary pores in fractured tight sandstone formation, and it has a good correlation with the proportion of primary porosity. Finally, permeability evaluation model is established based on total porosity and matrix pores proportion.
The permeability evaluation model was validated using the core physical experimental data of the Triassic Chang63 Member in the Jiyuan area of the Ordos Basin. In formations with underdeveloped fractures, the permeability calculated by this model was close to that calculated directly using total porosity. In formations with fractures, the predicted permeability is more consistent with the permeability analyzed by core experiments compared to the permeability calculated by conventional methods.
Engineered Solution to Reduce the Impact of Lost Circulation During Cementing in South Iraq Field, Iraq
Authors: Ahmed Khan Danish , Renato Hernandez Jesus , Kumar Tripathi Naveen , Centeno Acuna Manuel , ElHariry Haitham , Saad Mandoob Mohammed , Fayyaz Jaffery Maimoon , Abdul Rahim Syed , Saeed Khurram , Murad Mohammed Saeed 
Published: May 2024

Abstract
Curing lost circulation, one of the greatest contributors to drilling non-productive time (NPT), may impair the final well construction process, including securing production casing/liner and ensuring zonal isolation between target formations. This problem was faced in the South Iraq oil field, where conventional practices were to cure losses in a highly heterogeneous reservoir carbonate formation (vugs, fractures) before proceeding with the cementing operation ensuring the well integrity during the production phase. As Common field operational practices dictated that whenever losses were encountered, drilling was stopped to cure the losses (Dreger, 2014 1), often by spotting acid-soluble cement plugs before drilling ahead. The time spent on curing losses encountered while drilling plays an important role in the total well construction and delivery. This paper presents how engineered solutions were applied in the design and execution phase of cementing operation by running production casing under losses but still achieving well integrity and zonal isolation.
The foundation of the proposed engineering and operational approach is the characterization of the wellbore with the caliper and formation image logs for better understanding of fractures and estimation of fracture volume (Arshad, Umar, 2015 2). The results and information were shared with cementing team as redesigning the cement slurry formulation was the key objective. To overcome the challenge, innovative solution for the problem, which was the implementation of dispersible inert fibers mixed in specified concentration conventional spacer and had the capability of plugging fractures of 5 mm successfully. Synergy effect of degradable fiber in spacer and fibrous mesh material in the slurry strengthened the loss zone and enabled to achieve top of cement.
Successful Reinstatement of Oil Production and a Reduction in Water Cut Through Implementation of an Autonomous Lower Completion
Authors: Alawadhi A. , Kherroubi D. , Douik H. , Alkindi A. , Celma R. 
Published: May 2024

Abstract
Well WELL-Z is a horizontal well located in a highly fractured reservoir in Abu Dhabi, making the prediction of sudden water production due structural features a major challenge. During the planning phase this well predicted 600 bbl. of oil without water, based on studies. However, immediately after commissioning, the well experienced an unexpected water breakthrough reporting on the initial test a production of 12 bbls of oil with a water cut of 95%.
To restate the oil production and control the water, different action plans were taken in place such as: side-track, water shut off or implement a smart lower completion. The study leads to lower completion with inflow control devices being the best option.
As a part of the data requirements surveillance logs were acquired but not in full (production logging could not be conducted due accessibility issues), hence, the actual distribution of oil and water was uncertain. A set of resistivity, density and caliper data were acquired during the condition trip, by using logging while tripping technique. The results help to assess the oil and water saturation, evaluate the depletion on the borehole and refine the design, ensuring the location of the packers and the control devices along the horizontal section.
Once the data was gathered, an analysis of different lower completion designs was in place and contrasted in various simulation scenarios. The optimum result was dividing the 3000 ft horizontal section into 15 compartments with 19 Autonomous Inflow Control Device (AICV®) to maximize the oil contact and improve the water management.
Several challenges were encountered during the well commissioning, such as a unique ESP start up sequence and the requirement to maintain a sufficient intake pressure margin and avoid fluctuations that could lead to ESP tripping. This behavior was exclusively observed in this well because the borehole was full of killing fluid causing the AICV's to be closed and not working for the designed purpose. This lesson learnt led to the creation of a new standard operative procedure (SOP) for commissioning wells this type of completions.
Following successful commission after the implementation of the new SOP, the well tested 250 barrels of oil with a 20% water cut, which is in line with the prediction during the design and planning stage. The approximate cost for a workover with a common inflow control device (ICD) completion compared with an AICV is 1.3 times less but assuming an oil price of 50 USD/bls, this workover will be recovered in approximately 2.25 months of production.
The results of this work its aligned with the vision of environmental sustainability since was lowered the power requirements due less surface water processing and leading to lower the carbon emission and lifting costs in 45%.