bluuebunny/crossref_metadata_2025 huggingface dataset:
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

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 > 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

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

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

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

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%.
Unlocking the Downthrown Potential of Mature Brown Fields, A Success Story from Amal Field, Gulf of Suez Rift, Egypt
Authors: Okeil Mohamed , Abd El-Moniem Mohamed A. , Abd El-Maboud Mohamed , Osman Heidar , Abd El-Rahman Raafat , Keshta Emad , Khafagy Abd El-Nasser
Published: May 2024

The Gulf of Suez rift basin continues to unveil its secrets with each new discovery. Among these discoveries, the Amal field, with more than thirty years of production, stands out as a significant brown mature field that recently revealed a downthrown oil discovery of a prolific structure trend (B-trend fault) in the offshore southern province. While this discovery bears some resemblance to other analogues of proven downthrown fields, it holds a unique distinction. Specifically, the oil-water contact in this discovery is located even deeper than the up-thrown contact in the main field by over 200 meters within the same reservoir. Moreover, it is deeper than the deepest recorded oil-water contact in the main field by 80 meters, a phenomenon not previously observed in similar downthrown traps.

This paper provides a comprehensive workflow that has been integrated prior to this discovery, highlighting the associated risks. The paper also addresses the challenges regarding the poor seismic data quality that hinders the better subsurface reservoir structure image and explains how the integration of all available data has helped to overcome this limitation. Despite being a remarkable success story, the drilling results revealed valuable lessons learned and unexpected risks that should also be considered in future prospect evaluations.

This remarkable discovery encourages additional near-field exploration in other mature brownfield locations across the entire Gulf of Suez rift, as it demonstrates the hydrocarbon potential within downthrown traps. Additionally, the discovery has the potential to reshape exploration strategies, particularly to the significant bounding faults that encompass extensive undrilled regions within development leases.
Impact of Spacer Structure on Organic Acids Desorption Efficiency Induced by Gemini Surfactants
Authors: Deng X. , Kamal M. S. , Patil S. , Shakil S. M. , Shalabi E. A. , Hassan A.
Published: May 2024

Organic acids, together with other polar molecules, constitute the oil-wetting components in crude oil. A commonly adopted understanding is that the adsorption of organic acids leads to the further adsorption of organic materials on the hydrophobic tail groups of the adsorbed organic acid molecules, making the rock surface oil-wet. Although the impact of organic acids in oil-wetting of the rock surface has been unfolded for many different conditions, there are still some questions around the oil-wetting reactions induced by organic acids. A group of in-house synthesized cationic gemini surfactants have been shown effective in altering rock wettability from oil-wet to water-wet conditions. To study the impact of spacer structure on organic acids desorption, experiments were taken to show the impact of the water film in the oil-wetting process of rock by organic acids, and the effectiveness of different cationic gemini surfactants in wettability alteration. SEM and zeta potential experiments were conducted to show the adsorption and desorption of organic acids. Static contact angle measurements were conducted to show the wettability change. Difference in the wettability alteration performance was closely related with the spacer structure. Results showed that polarity of the spacer group is not the only factor that impacts the surfactant's potential in changing rock wettability.
4D Ultrasonic Caliper While Drilling Enables Advanced Wellbore Evaluation in Slim Hole Size
Authors: Fouda M. , Taher A. , Soelem R.
Published: May 2024

Evaluation of hole conditions is a key measurement for safe drilling and completion operations. Acquiring an accurate hole size measurement has been traditionally performed using wireline mechanical calipers deployed after drilling operations have been completed. This paper demonstrates how logging-while-drilling (LWD) ultrasonic sensors can be used to provide a time-lapse (4D) alternative azimuthal measurement of hole size, enabling data acquisition in different phases of drilling and tripping operations.

LWD ultrasonic caliper measures the travel time and computes the tool’s stand-off to the wellbore wall. Acquiring azimuthal data around the wellbore during different logging passes enables acquisition of 4D caliper information. After being calibrated inside casing, the ultrasonic sensor provides azimuthal travel-time images, based on which minimum, maximum, and average hole sizes can be computed.

Data have been acquired in drilling, trip-in, and trip-out modes and compared to wireline-oriented calipers. The data has been evaluated considering time-dependent deterioration, washout, and breakout developments.

Recently introduced LWD slim ultrasonic imaging and caliper tools have multiple transducers and fast sampling rates. The hardware and algorithm design improves the hole size computation and wellbore evaluation. The tools provide a viable alternative to wireline mechanical calipers. While field data showed a good match in competent formations, differences between data acquired in multiple LWD logging passes and wireline mechanical caliper runs have provided 4D caliper information for evaluating time-dependent changes in hole conditions enabling future optimization of well construction.

This paper illustrates the utilization of LWD ultrasonic sensors integrated as part of the drilling assembly to provide a 4D azimuthal measurement of hole size at different times, during drilling and tripping in and out of the hole.
A Machine Learning Based Framework for Brine-Gas Interfacial Tension Prediction: Implications for H2, CH4 and CO2 Geo-Storage
Authors: Pan Bin , Song Tianru , Yin Xia , Jiang Yiran , Yue Ming , Hoteit Hussein , Mahani Hassan , Iglauer Stefan
Published: May 2024

Brine-gas interfacial tension (γ) is an important parameter to determine fluid dynamics, trapping and distributions at pore-scale, thus influencing gas (H2, CH4 and CO2) geo-storage (GGS) capacity and security at reservoir-scale. However, γ is a complex function of pressure, temperature, ionic strength, gas type and mole fraction, thus time-consuming to measure experimentally and challenging to predict theoretically. Therefore herein, a genetic algorithm-based automatic machine learning and symbolic regression (GA-AutoML-SR) framework was developed to predict γ systematically under GGS conditions. In addition, the sensitivity of γ to all influencing factors was analyzed. The prediction results have shown that: the GA-AutoML-SR model prediction accuracy was high with the coefficient of determination (R2) of 0.994 and 0.978 for the training and testing sets, respectively;a quantitative mathematical correlation was derived as a function of pressure, temperature, ionic strength, gas type and mole fraction, withR2= 0.72;the most dominant influencing factor for γ was identified as pressure.

These insights will promote the energy transition, balance energy supply-demand and reduce carbon emissions.
Gas Rate Predictive Model as an Alternative to Choke Equations
Authors: BinZiad Abdullah , Khan Abdul Muqtadir , Alshammari Fahad O. , Alsubaii Abdullah
Published: May 2024

Choke equations are usually developed for specific conditions, calibrated, and validated with separator data. There is a vast opportunity for data model deployment in this space, which can enhance the accuracy of gas rate predictions further. In this work, a data model approach uses machine learning (ML) techniques to predict gas rate for a given set of measured inputs.

A structured, relational dataset was created from 1,181 wells where full separator setup was utilized. A total of 18 variables such as choke size, flowing wellhead pressure, fluid flow rates, gas-liquid ratios, and PVT properties were captured and subjected to data cleaning, feature engineering with correlation matrices, feature scaling, and other techniques to reduce the number to 11 important variables. A comprehensive ML workflow was utilized with exploratory data analysis using a 65:35 set split for training and holdout sets with a fivefold cross validation and considering feature importance, utilizing seven regression algorithms and a neural net.

Exploratory data analysis led to some data cleaning based on missing values and data QC, leaving data from 448 wells. This final dataset was then subjected to cross validation and hyperparameter tuning. Several algorithms were compared utilizing the performance metrics such as root mean squared error (RMSE), average absolute percentage error (AAPE), mean absolute percentage error (MAPE), and R-squared (R2). The XGBoost model performed the best with the AAPE and MAPE of 1.9%, MSE of 0.04, and R2 of 0.996. As a result, an application based on the XGBoost model was developed to improve the gas rate accuracy during flowback operations. Feature importance was also studied and showed that total condensate volume and condensate gas ratio were the most important predictors. In comparison with the traditional and modified Gilbert choke equation, with an average error of ~5 to 8%, and RMSE of ~14, the error with this ML approach is a few folds lower because the data approach captures and handles the variance better. In addition, the choke equations yield much higher errors in eccentric conditions of low gas rates and high water condensate ratios. The error comparison with a few different analytical models is presented here and shows that the XGBoost performed better than the existing models. To simplify the computational time and resources, an attempt to map the XGBoost output into a simple linear equation is also presented, along with its accuracy.

Data-based approaches provide a high level of operational and cost relief in the surface well testing domain, but this space has not been well explored. This work shows the value and benefits of the ML models in well testing domain.
Innovative 15K Cemented Multi-Stage Fracturing Technology- Minimizing Deployment Risks and Enhancing Time Efficiency in Complex Horizontal Wells
Authors: Agarwal Rohit , Essmat Nooruldeen Zeyad , Levario Jesus , Bansal Sarvodaya , Corona Mauricio , Alismail Ahmed , Almuallim Mustafa , Paz Daniel
Published: May 2024

Deployment of Open Hole Multistage Fracturing (OH MSF) completion system in long horizontal wells has always been a daunting task, and often presents high risk of getting stuck in open hole due to complex completion design with very stiff assemblies that include multiple large OD - hydraulic set open hole packers. This paper introduces a novel technology called Cemented MSF, which addresses the deployment risks associated with conventional OH MSF and cemented liner. Notably, this technology eliminates the need for time-consuming coil tubing operations for plug-and-perf (in cemented liner), thereby avoiding production delays.

The paper examines the major bottleneck in deployment of OH MSF, a very stiff completion string, which is particularly influenced by the number of stages/ open hole packers, elevating the risk of equipment getting stuck in the open hole due to ledges and washout created while drilling the reservoir. Consequently, there is a constant trade-off between maximizing deployment chances and minimizing the risk of getting stuck by reducing the number of stages. However, this trade-off comes at the expense of production efficiency.

Cemented MSF is a hybrid integrated system that provides all the production benefits of OH MSF with significantly reduced deployment risk. In this novel solution, OH packers are eliminated, and the completion is run in a similar process like a cemented liner. The cemented MSF lower completions were successfully implemented in a long horizontal well with > 6,000 ft of reservoir contact. While drilling the lateral section, this system enables greater degree of directional flexibility and navigation control as compared to conventional OH MSFs, which have very strict limitations for dogleg and inclination citing risk of deployment complexities with the stiff completions string. Having no OH packers eliminate the need to record open hole logs for packer's placement and further eliminates the need for a simulation run (Dummy Run) to simulate actual completion string stiffness, resulting in a direct savings of minimum six-days. Furthermore, to ensure that the frac ports are not activated prematurely, a fit for purpose cementing program was developed using precise volume and hydraulic displacement calculations and optimum shoe track length. Among the unique features of this system is its ability to run maximum possible stages, ensuring that productions will not be compromised. At the end of completion phase, the frac Ports can be activated by dropping balls just like a conventional OH MSF system and get the well for production.

The paper outlines essential design considerations, checkpoints, an execution phase roadmap, and potential contingencies related to the deployment of the Cemented MSF technology.
The Road to Enhanced Quality: Lessons from a Company's Transition to APIQ2 From ISO9001:2015
Authors: Akram A. , Yahya A. , Affandi B.
Published: May 2024

This paper describes the pivotal journey of a local upstream service provider in transitioning its Quality Management System (QMS) from ISO 9001:2015 to API Q2:2021, with a specific focus on the upstream services sector within the petroleum industry. The primary objective of this transition was to align the company's QMS with international service standards, thereby enhancing its global competitiveness and service quality. This study offers a comprehensive examination of the strategic approaches employed, the inherent challenges confronted, and the significant benefits realized through this transition.

Initially, our methodology entailed a thorough benchmarking of the existing QMS against the standards set by leading international service providers in the petroleum sector. This process involved a detailed gap analysis between the ISO 9001:2015 and API Q2:2021 standards to identify critical areas for improvement. The transition strategy was meticulously structured, encompassing comprehensive staff recruitment and training, process optimization, and rigorous internal audits. A key aspect of our approach was the active engagement with subject matter experts and stakeholders, ensuring our practices were in strict alignment with international standards. The implementation of this transition was executed through a series of iterative enhancements in our service delivery processes, with a relentless focus on aligning with the superior service quality norms of leading international players.

The results from this transition were profoundly positive. We observed a 35% increase in compliance with global quality standards, coupled with an enhancement in customer satisfaction ratings. These improvements underscore the robust focus of API Q2:2021 on service quality and risk management, essential for matching international standards. The transition not only elevated the service quality of our local operations but also improved our global competitive position and recognition in the international market. Furthermore, the process instilled a culture of continuous improvement and operational excellence among our staff.

While ISO 9001:2015 lays a foundational framework for quality management, the adoption of API Q2:2021 is instrumental for local service providers in the petroleum industry to not only meet but exceed international service standards. This transition is pivotal in enhancing service quality and strategically positioning local service providers on the global map. Our study contributes significantly to the existing body of knowledge, providing a practical blueprint for similar organizations aspiring to elevate their service standards to meet international benchmarks in the petroleum industry.
Aligning Upstream Operations with Sustainable Technology: High Power Lasers
Authors: Alghamdi S. , Batarseh S. , Alharith A. , San Roman Alerigi D. P. , Alrashed A. A.
Published: May 2024

The application of practical sustainability and safety principles in a perforation job is pivotal to safeguard not only the environment and workers’ well-being but also, the long-term viability of resource extraction. In light of the first industrial high-power laser perforation, the objective of this work is to explore the sustainability and safety aspects of laser perforation with a focus on factors such as water requirement, asset integrity, logistics, safety and surface footprint.

This work examines the operational conditions of conventional stimulation methods and the first industrial successful deployment of high laser perforation tool in the field with a focus on safety, logistics, environmental impact, surface footprint and technology efficiency. Furthermore, the paper presents the effect on well integrity after the perforation process with a laser tool including debris management, steel integrity, effect on the formation properties, quality of perforation tunnels. Experimental data obtained from photomicrographs, acoustic testing, and imaging were used for validation and analysis.

The design of the laser system deployed is enclosed with small surface footprint. It comprises a laser energy generator, nitrogen tank, coiled tubing unit, and the tool. The laser tool eliminates the use of explosives, such as shaped charges, promoting safety and eliminating the extensive logistics of handling explosives in the wellbore. The laser tool can perform as many perforations as required in a single trip reducing rig time efficiently. This technology provides versatility to suit the wellbore specification in terms of size, shape, and depth of perforation, promoting efficient completion of wells. After perforation, photomicrographs and acoustic testing proved that the use of high-power laser does not compromise the integrity of steel, maintaining the existing asset integrity. Furthermore, the precise control over the phase of the rock maintained the perforation tunnel and formation integrity. The non-explosive effect of laser perforation eliminates compaction around perforation tunnels abolishing post-stimulation formation damage, which provides long-term viability of resource extraction. The waterless, rigless, and non-explosive, features of the laser perforation technology align seamlessly with the International Petroleum Industry Environmental Conservation Association's (ipieca) roadmap to achieve the United Nations Sustainable Development Goals (SDGs) in the oil & gas industry.

High power laser is an innovative breakthrough technology that will revolutionize the industry, this paper demonstrated the potential of the technology and its alignment with the recommended sustainability and safety practices. High power laser tool is a multifunctional tool that can provide different applications with the same power source and tool.
Perf, Wash and Bismuth : First in the World Innovative Technology - Implementation for Gas Leak Isolation in Plug and Abandonment (P&A)
Authors: Hamid A. Abdul , Razak M. N. Abdul , Zawawi A. , Shah S. Masroll , Khalid M. I. , Ezani F. S. , Kumar A. Kishore , Sellapan S.
Published: May 2024

A gas leak incident, from the Casing Annulus of a well, reported in Malaysia Platform. This event involved the release of a gas cloud from the well and surfacing of water and mud through the surface casing. It necessitated an immediate evacuation. In response, the decision was made to plan for the P&A of the well, resulting in temporary production halts and the suspension of nearby drilling operations. This had financial repercussions for the company. In light of the intricate nature of P&A, the team conducted an evaluation and introduced a ground breaking technology, "Perf, Wash, and Bismuth," which is the first of its kind in the world. This technology was implemented to create a robust well barrier, ensuring the well's security and preventing leaks in both the well and its annulus.

A custom tool was meticulously designed to align with the well's plugging and abandonment (P&A) process, involving extensive technical consultations and problem-solving sessions before the Bismuth's fabrication. This technology's application in the context of an HWU Rig setup introduced various limitations and challenges, including restricted crane capacity and deck space. To address communication within the casing annulus, the team creatively adapted the traditional Bismuth application, implementing the "Perf, Wash, and Bismuth" technique to create a secure seal behind the casing, ensuring a Casing Pressure reading of 0 psi. Before placing the Bismuth Plug, the leak point was identified, and a Perforation Gun and Wash tool were employed to perforate and cleanse at the specified depth. Bismuth activation relied on a time-based mechanism, with three separate Bismuth plugs, each about one meter in length, installed. This comprehensive Bismuth plug operation, from setting to retrieval, Run In Hole, setting, and tagging, took roughly 18 hours.

Three Bismuth plugs were successfully set and tagged on the well. Each plug was tagged to determine its top, and this information confirmed that the Bismuth had entered the annulus through the pre-perforated channel, demonstrating the effective deployment of the Bismuth Plug using the HWU rig when proper planning was in place. After placing the Bismuth plug, the absence of pressure within the annulus indicated the well was secured. This newfound confidence in the well status enabled the platform to resume production and come back online.

The "Perf, Wash & Bismuth" Innovative Technology, a ground breaking world-first, provides a solution for addressing complex P&A wells with annulus casing leaks. This paper outlines the utilization of bismuth in P&A wells, its deployment through the HWU Rig, the associated engineering and installation procedures, and offers a comprehensive overview of its implementation. It also hints at the future potential of this technology in the realm of P&A wells.
4D Seismic Inversion of Quality Factor and Velocity
Authors: Chen Jianming , Zhao Yansheng
Published: May 2024

Rock properties play a crucial role in influencing the propagation of seismic waves within the Earth, providing valuable insights into various aspects such as the presence of hydrocarbons, porosity, saturation, and permeability variations. Seismic imaging serves two main purposes: mapping the heterogeneity of underground reservoirs and monitoring recovery processes on-site (Nur, 1989). Over time, both production and injection activities alter the response of the reservoir. Time-lapse (or 4-D) seismic monitoring is an essential tool for reservoir management, enabling the tracking of displacement processes. Changes in seismic properties, such as velocity and quality factor Q, can offer quantitative estimates of fluid changes.

Some rock properties related to fluid saturation in the reservoir, such as anelastic absorption quantified by the quality factor Q, can undergo more significant changes than others, such as oil and gas mixed with brine or CO2. To estimate the quality factor Q from seismic reflections, a tomographic inversion algorithm is utilized based on the frequency shift method (Quan and Harris, 1997). This algorithm generates a macro-model for anelastic attenuation. In order to enhance resolution and obtain a micro-model, Poggiagliolmi and Vesnaver (2014) propose a new algorithm that is stable and reliable for computing the instantaneous frequency, which represents the centroid of the instantaneous spectrum. This algorithm improves the stability of calculating the instantaneous frequency and provides a high-resolution image of anelastic absorption. By utilizing this approach, the resulting broadband image of anelastic absorption in depth can offer superior monitoring of reservoir changes compared to conventional methods.
Distribution of Jurassic Clastic Reservoirs in the Sudochi Depression of the East Ustyurt Basin (Uzbekistan) Based on the Results of Seismic Reservoir Characterization
Authors: Shaikhina D. , Yessalina S. , Muratov A. , Muminov M. , Gulamov R. , Mallaev S.
Published: May 2024

The goal of the current work is a detailed study of the reservoir architecture, stratigraphy, and properties of Uzbekneftegas (UNG) assets within the Sudochi depression of the East Ustyurt basin, that is urged by low success rates of drilling and declined gas production. Until today, the approach to drilling exploration and production wells was based on the concept of conformably layered reservoirs, that has changed dramatically as a result of the current work.

Limitations in data quality and availability was the most challenging aspect of this study. Image processing of the seismic data in the color domain has increased the resolution of the seismic data. Together with spectral decomposition, chromatic extraction yields valuable results in analysis of seismic facies, a tool for automatic well tie allowed to extract the wavelets of best shapes and time-depth relationships (TDR) in optimal time. Rock physics study was performed and justified the feasibility of acoustic inversion. A post-stack inversion was performed to describe reservoir properties and distribution. Application of seismic reservoir characterization techniques and integration of the other domain data resulted in the interpretation of the depositional environment, geometry, and quality of Jurassic reservoirs.

As a result of the successful implementation of the mentioned tools, the reservoirs of East Ustyurt basin are seen to be represented by alluvial and fluvial deposits, which are traced and predicted in inter-well space. This information was a valuable input to geological and dynamic models. Different overprints of paleodepositional settings on the reservoir architecture, heterogeneity, and facies distribution of each study area can explain why drilled wells were not identically productive. Eventually, consideration of the seismic reservoir characterization results has significantly changed the location of planned exploration and production wells and led to drilling successful wells with high production rates.

The novelty of the work is in the results obtained for the South-Eastern part of Ustyurt basin, specifically the Berdakh high and the Sudochi depression. We have interpreted paleogeographic development in Jurassic period, the reservoir architecture, quality and facies distribution by seismic reservoir characterization tools and integrated analysis of other data, that has not been extensively studied and published before. This study can contribute to the development of the region.
CFD-DEM Simulation Analysis of the Effect of Sweep Stages on Proppant Placement within Rough Fracture
Authors: Song Xianzhi , Yang Zhichao , Zhou Mengmeng , Xu Zhengming , Zhou Qianqian , Abderrahmane Hamid Ait , Wang Bin , Zheng Yong
Published: May 2024

Hydraulic fracturing is a conventional measure to enhance recovery. Proppant transportation as a critical technology of hydraulic fracturing can maintain the effect of production enhancement. A validated Computational Fluid Dynamics - Discrete Element Method (CFD-DEM) method is used in this paper to study the generation condition of blocky dune and the impact of proppant placement in rough fractures during the sweep stages. The results indicate that medium-sized aperture proppants have more possibility of generating blocky dune. These blocky dunes possess distinctive properties that can lead to complications, such as the plugging of fractures. Intriguingly, this phenomenon is unique to proppant transport within rough fractures. Contrary to initial predictions, concentration, and injection velocity exert minimal influence on the genesis of blocky dunes. Dunes formed at lower injection velocities should be subjected to water scouring at higher velocities. Additionally, a critical velocity threshold, determined by the fracture's characteristics, exists for the injection velocity during the sweep stage. If the velocity dips below this critical threshold, the sweep stages lose their effectiveness. This investigation elucidates the generative conditions of blocky dunes and their properties about rough fractures during sweep stages, offering valuable insights for the optimization of proppant placement strategies in practical engineering scenarios.
Fault Pattern and Structure Configuration of Apsheron Sill, South Caspian Basin, New Insight from High Quality OBN Seismic
Authors: Dengyi Xiao , Rouis Lamia , Xiaoliang Li , Khdhaouria Mourad , Aldrin Rondon , Ameish Giamal , Qingfeng Huang , AlDahmani Abdulla , Oweini Tarek , Gibrata Muhammad , Qiang Li , Xin Chen , Kongzhi Huang , Bo Wang
Published: May 2024

As one of the major oil-producing belts in the South Caspian basin, the Apsheron Sill holds tens of structure-related reservoirs which are closely originated with the tectonic evolution and performed complex fault patterns. Previous study paid high attention to the east Azerbaijan area with reporting lots of case study, however, the west Cheleken peninsula is still in high ambiguity.

To enhance understanding of the east Apsheron ridge, an integrated study is conducted mainly based on new acquired 3D OBN seismic in Cheleken concession. The AI-based technology is adopted to illustrate the complex fault system for the first time with using huge database of similar structure cases. Seismic geometrical attributes and RGB fusion method are used to demonstrate the fault assemblage. Analogue study was also carried out between the Cheleken faults and physical stimulation, aiming to better understand the geometrical and kinetic feature. Furthermore, the structure reconstruction technique is used to capture the strati-structure evolution.

According to this study, two typical fault patterns are identified, positive flower structure cut in the middle-deep red series, and negative flower structure bearing in Apsheron-middle red bed series. The flower structure sometimes shows the schematic of complex palm-tree. These two sets of structure patterns represents the trans-pression in early-middle Pliocene and trans-extension in the late Pliocene-Pleistocene. Some detached faults cut from Apsheron stratigraphic interval and terminated at CH1 shale which related to the later regional extension and strain releasing. In Cheleken concession, two fault belts are identified, Zhdanov in the north and Lam in the south. Some transform faults occurs between these two belts to accommodate the lateral strata shearing or rotation. In the map view, fault assemblage performs feature of en-echelon and horsetail spray, which represents the dextral strike-slip of Apsheron Sill. Typically, the Lam and Zhdanov reservoirs are fault-derived structure with continuous growth from middle Pliocene to late Pleistocene. Occurrence of mud volcano in the concession indicates the faults are still active.

For the first time, this study gives systematic illustration on the fault pattern and structure configuration of the east Apsheron Sill in terms of good image OBN seismic. The enhancement in structure feature could facilitate the current producing and help de-risk drilling hazards. Furthermore, it would also provide new insight for adjacent reservoirs from the aspect of regional tectonic understanding and structure configuration.
Unlocking Potential: Re-Accessing Left-Behind Potential in GS365 Field GoS, Egypt: Navigating Through Challenging Historical Data, Compositional Gradient Reservoir, Multi-Layer Stacked Reservoir, and Complex Structure Setting
Authors: Rashad O. M. , Samaha A. A. , Emam M. , El-Ghalid M. , Fargal M. , Kamal O. , Ibrahim N.
Published: May 2024

GS365 oil field sits in the southern Gulf of Suez faced significant challenges in development plan: limited historical data, restricted accessibility, and single mudline producer from thin oil rim overlain by a sizeable gas cap. This presented challenges for both geological and reservoir engineering teams, including defining reservoir geobodies, estimating fluid contacts, optimizing well spacing, infill drilling, and maximizing recovery. Well engineering faced the additional challenge of managing gas cusping and maximizing reserves through trajectory and perforation design.

To overcome these challenges, this study employed a comprehensive approach integrating static and dynamic reservoir modeling. Key uncertainties addressed included reservoir pressure, fluid contacts, reservoir quality variations, and aquifer description. Lack of dynamic data due to limited accessibility necessitated utilizing surface parameters like wellhead pressures and temperature as model control points. Production uncertainties from limited surveillance data were addressed through historical data analysis, Prosper modeling, fluid characterization and PLT interpretation. A 3D model was built and history matched to refine the estimated oil initially in place (STOIIP) range. This integrated approach yielded valuable insights for infill drilling and optimizing target location selection to manage uncertainties.

A slanted well design was chosen to maximize reservoir contact and minimize gas cusping while maintaining low drawdown pressure. Post-drilling results exceeded expectations: encountered pressures were on the high side, and new sands with virgin pressure were discovered, indicating untapped potential in the reservoir of interest. Revisiting the initial gas-oil contact (GOC) with updated pressure data and detailed fluid characterization revealed a shallower GOC by +100 ft, leading to an increase in STOIIP estimates. Accessing the shallower reservoirs was as prognosis, highlighting its importance in field development and potentially influencing future infill well strategies.

This study demonstrates the successful reviving of untapped potential in mature field through a data-driven approach addressing uncertainties in historical data, reservoir characterization, production performance, and pressure assessment. By integrating deep analysis, 3D simulation modeling, and cross-checking with analytical methods, this study validates the effectiveness of the applied methodologies and strategies. This approach offers valuable insights for maximizing recovery from similar challenging reservoirs, contributing to long-term production sustainability in aging fields.