bluuebunny/crossref_metadata_2025 huggingface dataset:
Historical Strategy Roadmap to Reduce the Operation Time for Drilling 8-1/2 Inch Production Hole Section in an Unconventional Drilling Operation
Authors: Yin G. , Ramos D. A. , Sinesi J. P. , Jan M. A.
Published: February 2024

Historically, it was time consuming to drill an unconventional horizontal well with 7,000 ft horizontal length. The most time-consuming part of drilling operation was the production hole section. The drilling team made series of significant efforts to continuously perform various trials to seek the performance improvement. By revising the casing design, optimizing the bottom hole assembly (BHA) and bit, improving the drilling practices and enhancing the drilling parameters, a similar well can be delivered with more than 50 percent time reduction. This paper presents the team strategy roadmap for achieving this improvement.

At first, the rotary BHA was used to clean-out 9-5/8" casing and drill the vertical section to kick off point (KOP), then it was pulled out of hole (POOH) and changed to the motor BHA for drilling the buildup section, and finally switched to rotary steerable system (RSS) to drill the horizontal section until total depth (TD). Later on, with the horizontal length of the well extended, the motor was replaced with RSS, and both the buildup and horizontal sections were drilled with RSS in one run. Afterwards, the performance motor replaced the rotary BHA and was used to drill the vertical section, resulting in significant rate of penetration (ROP) improvement. Last step, the entire production hole section was drilled with one single run utilizing a new RSS BHA. The tripping time was minimized, the operation troubles were reduced and the well delivery became tremendously efficient.

Among all the trials, it was found that drilling the entire production hole section in one single run without any extra dedicated clean-out run for 9-5/8" casing is the most efficient way to deliver the well. After drilling and delivering more than one hundred wells using this practice, it was found that this strategy can most efficiently help the team deliver the wells in a faster, safer and more cost-effective manner due to the elimination of the trips to switch BHA and performance enhancement during the drilling process. This one single run option was well established because of the utilization of more reliable directional drilling tool, the better cutting technology of the PDC bit, the best practice and other advanced technologies applied to the operation.

Drilling the production hole section with one BHA in one single run is a unique example of innovation. This does not only apply to the well with a short to medium (5,000-7,000 ft) horizontal length, but also for those with excessively long horizontal length such as 10,000 ft or even longer. The road map history as stated in this paper will help those who are still seeking the strategy find the better option that fits for their own purpose.
Advanced Technology Upgrades in Downhole Torsional Dysfunctions Mitigation to Improve Rotary Steerable System (RSS) Reliability
Authors: Quiroz J. , Yambao N.
Published: February 2024

High frequency torsional oscillations (HFTO) are detrimental to Rotary Steerable Systems (RSS) which are extremely costly to be fixed. This paper will describe some innovative upgrades in downhole torsional mitigation tools and will evaluate their performance in a field case study. The paper will showcase the development of a downhole technology aiming to alleviate the torsional vibrations and increase downhole drilling equipment reliability.

The overall approach of the project consisted of first, identifying the magnitude and frequency of the torsional dysfunctions in three wells utilizing high-frequency downhole sensors in the bottom hole assembly (BHA) which is placed below the mud motor. Secondly, after identifying the main causes of the downhole failures in the RSS and measurement while drilling (MWD) tools, a solution was created to address these dysfunctions. Lastly, two different downhole torsional technologies were designed for field trials and performance evaluation to confirm the anticipated performance of the upgraded tools.

Before performing the three wells study to identify the main types of vibrations, the operator believed that stick-slip was the only dysfunction causing the downhole tools failures, but the findings from the downhole sensors’ study showed high levels of HFTO as well. Based on the identified source of vibrations, the study came up with two technology modifications (Technology A and B), both aimed to mitigate stick-slip and HFTO and they were deployed for field trials after the design and manufacturing stages. Both technology upgrades tackle torsional dysfunctions but have different working mechanisms; technology A introduces mud lubrication to specific elements in the tool while technology B has internal upgrades for extra vibration dampening. Both downhole torsional technologies were trialed each in four wells drilling in the same formations to compare the effects of deploying both technologies in mitigating stick-slip and HFTO. Downhole torsional technology B showed significant improvements in decreasing stick-slip and HFTO, reaching as high 50% when compared with downhole torsional technology A which showed improvement not exceeding 15%.

This paper introduced, for the first time, an innovative technology that can introduce remarkable improvement in the performance of Rotary Steerable System (RSS) as shown in the case study. The paper discusses two technology upgrades to the RSS and compares them in terms of field deployment and efficiency.
Curing Total Lost Circulation on Deepwater Well by Pumping Multi-Purpose Cement Plug through Side Sub
Authors: Spagnolo S. , Abdallah A. , Emam M. , Abdulaa Ahmed , Younan Joseph , Bogaerts Martijn , Fayed Mohamed
Published: February 2024

Loss of circulation is one of the most challenging complications during drilling a well. The problem is even more severe in exploratory wells due to the absence of a clear understanding of the formation pressure and the presence of any high-pressure zones that may cause well control problems due to loss in hydrostatic pressure associated with loss of circulation. Furthermore, the problem will have a substantial budgetary impact, especially in deep water environments, considering the high running cost of the rigs along with all the side services that must be on standby on the rig. With the operator's decision to drill a sidetrack from the original well, an engineered cement slurry was designed to cure losses, plug and abandon the original hole, and act as a kick-off point for another trajectory. The cement job was intended to be pumped and displaced through the drilling assembly and through the side circulating sub. After the planned wait on the cement period, the plug was successfully tagged, pressure tested, and used as a kickoff point to start drilling the sidetrack section. The purpose of this paper is not to recommend such a procedure but to discuss a successful case study and the mitigations and measurements that must be taken and ensured before deciding to execute such jobs.
Successful Utilization of Managed Pressure Cementing During Running and Cementing 7 Inch Liner Through Rotating Control Device in a Narrow Mud Weight Window for an Unconventional Well
Authors: Alzahrani Z. G. , Albaraa A. A. , Iturrios C. O. , Aldhaif M.
Published: February 2024

Formations with a narrow mud window between the pore pressure and fracture gradient have always imposed a significant risk on well integrity during drilling and post-drilling operations. One of the main risks associated with such formation behavior is complete or partial loss of returns while drilling or cementing leading to many counterproductive consequences. For example, complete or partial loss of drilling fluid while drilling a hole section could reduce the hydrostatic pressure to below the bottom hole pressure resulting in the intrusion of formation fluid into the well bore. Another major risk is differential sticking of drilling and casing strings while performing well control securement procedures or by being stationary for any other reason. As a result, Managed Pressure Drilling (MPD) system was introduced to drill an 8-3/8" hole section in an unconventional well with a 3,500 ft interval that has a narrow mud window. The well was drilled with 106 pcf while maintaining an EMW of 120 pcf where the required overbalance is met. Other wells on the same area have suffered tremendously while drilling the same interval conventionally yielding high non-productive time which proved the concept of utilizing MPD system as a pro-active solution instead of reactive once needed. The next major challenge was to run and cement 7" liner to achieve the required cement barrier for isolating the problematic interval. Losses or well control while cementing 7" liner would compromise the integrity of cement barrier. Therefore, to mitigate losses and keep the required overbalance simultaneously during running and cementing 7" liner, Managed Pressure Cementing (MPC) was the effective solution.

This paper illustrates the entire procedure and results of successfully utilizing MPD system for running and cementing 7" liner string twice in a challenging environment where various stuck pipe and well control incidents occurred. Despite the fact of the extra budget and time for utilizing such systems, the increased safety risks, such as influx or well flow, and the extra cost that are associated for fixing what a stuck pipe can create is much higher.
Dispersion Corrections on LWD Quadrupole Data: Methods and Results
Authors: Schimschal S. , Geerits T. , Wu L. , Sy R.
Published: February 2024

In slow formations borehole acoustic Logging While Drilling (LWD) operations, it is common to obtain formation shear slowness from the dispersive borehole quadrupole wave. Due to poor signal to noise ratio and/or tool eccentricity effects, it is not always possible to obtain formation shear slowness directly via conventional Slowness-Time-Coherency (STC) methods. Consequently, a dispersion correction is frequently needed to QC and/or correct the STC result. We propose a hybrid method that allows for a model-based (MB) as well as a phenomenon-based (PB) approach. The latter is ideally suited to address, identify, and overcome the limitations and dependence of the former, on tool eccentricity, tool model, inaccurate knowledge of borehole fluid slowness, formation anisotropy (Vertical Transverse Isotropy), and other unknown acquisition circumstances.
Influence of Acid Type on Wormhole Generation and Carbonate Rock Properties
Authors: Alomair A. , Almubarak T. , Alqahtani N. , Caliskan Sinan
Published: February 2024

Matrix acidizing is one of the most effective techniques to restore formation permeability and increase production rate. It is typically performed using different types of treatments, such as mineral acids, organic acids or chelating agents. These stimulation treatments tend to generate pathways known as wormholes through a chemical reaction with target carbonate formations. Bottom hole conditions play an important role in the treatment selection since they influence the reaction rate, wormholes structure and wellbore integrity. This work shows an experimental study of the impact of acid type on wormholes generation in carbonate rocks at different temperatures.

Three different acids were used which were hydrochloric (HCl), formic (HCOOH) and acetic (CH3COOH) acids. These acids were injected at a fixed rate of 2 cm3/min into Indiana Limestone core plugs at two different temperatures: 150 and 250°F using coreflood equipment. Non-destructive visualization and analyses were conducted by using the Computerized Tomography (CT) scanning technique, which provided wormhole patterns, slice images with a thickness of 625 micron as well as statistical comparisons. Furthermore, dynamic acoustic velocities and elastic parameters were determined at different confining pressures for the post treatment core plugs to compare their values.

The use of different acids at the same temperature conditions formed different pathways and patterns of wormholes. In addition, the temperature effect has a clear relationship with the required pore volume to breakthrough (PVTB). At low temperature, HCl demonstrated an outstanding performance by having the least required PVTB, while at high temperature acetic acid showed an improved generated wormhole pathway compared to the other acid types. Nonetheless, the different acids did not show a significant impact on the dynamic mechanical properties of the rock samples.

This work evaluated the effect of temperature on the rock wormholes patterns using different types of acids based on their dissolving power. The study concluded that the temperature has a significant effect on carbonate matrix acidizing operations. The study also focused on how the selection of the acid type can make a huge impact related to bottom hole conditions.
Multi-Level Transfer Learning for Optimal Features Prediction
Authors: Sajid Muhammad
Published: February 2024

The quality of the final predictions in machine learning (ML) depends on a multitude of factors, and among these factors, the generalization of features within the input dataset plays a pivotal role. This generalization is particularly crucial when dealing with seismic data, as the complexity of the underlying geological structures and the seismic characteristics themselves exhibit substantial variability across different geological study fields. Such variations pose unique challenges when it comes to model training and achieving optimal predictions for specific seismic features. Considering these challenges, the research proposes a comprehensive approach that involves the application of three stages of transfer learning. This approach has been designed to facilitate the seamless convergence of the model towards an optimal level of adaptability for the extraction of seismic features. Each step of transfer learning in this method incrementally enhances the model's ability to accommodate the idiosyncrasies of seismic data from diverse study fields, ultimately leading to the desired seismic feature prediction. The research seeks to improve the overall accuracy and robustness of seismic feature prediction across varied geological contexts, thereby contributing to the advancement of seismic data analysis and geological interpretation.
Physics-Informed Neural Networks for Modeling Flow in Heterogeneous Porous Media: A Decoupled Pressure-Velocity Approach
Authors: Alhubail Ali , Fahs Marwan , Lehmann Francois , Hoteit Hussein
Published: February 2024

Physics-informed neural networks (PINNs) have shown success in solving physical problems in various fields. However, PINNs face major limitations when addressing fluid flow in heterogeneous porous media, related to discontinuities in rock properties. This is because automatic differentiation is inadequate for evaluating the spatial derivatives of hydraulic conductivity where it is discontinuous. This study aims to devise PINN implementations that overcome this limitation. This work proposes decoupling the mass conservation equation from Darcy's law and utilizing the residuals of these decoupled equations to train the loss function of the PINN, rather than using a single residual from the combined equation. As a result, we circumvent the need to find the spatial derivative of the discontinuous hydraulic conductivity, and instead, we impose the continuity of fluxes. This decoupling necessitates that each primary unknown (pressure and velocity components) be computed by the neural networks (NNs) rather than deriving the velocity (or fluxes) from the pressure. We examined three NN configurations and compared their performance by analyzing their accuracy and training time for various 2D scenarios. These scenarios explored various boundary conditions, different hydraulic conductivity fields, as well as different orientations of the heterogeneous media within the domain of interest. In these problems, the pressure and velocity field are the primary unknowns. The three configurations include: (a) one NN with the three unknowns as its outputs, (b) two NNs, one outputting pressure and the other outputting the velocity, and (c) three NNs, each having one primary unknown as an output. Utilizing these NN architectures, we were able to solve the heterogeneous problems with varying levels of accuracy when compared to results from numerical simulators. While maintaining a similar number of training parameters for a fair assessment, the configuration with three NNs yielded the most accurate results, with a comparable training time to the other configurations. Using this optimal configuration, we performed a sensitivity analysis to demonstrate the effect of modifying the NN(s) hyperparameters, such as the number of layers, the number of nodes per layer, and the learning rate, on the accuracy of the results. We introduce a novel PINN approach for modeling fluid flow in heterogeneous media. This proposed method not only preserves the inherent discontinuity of rock petrophysical properties but also leverages the benefits of automatic differentiation. By incorporating this PINN architecture, we have opened up new possibilities for extending the application of PINN to realistic reservoir simulations that capture the complexities of the subsurface.
Breaking New Ground: Exploring the Connection Between Drilling Parameters and Formation Properties through Advanced Multi-Source Data Pattern Analysis
Authors: Abouhamed Moustafa , Elmasry Hesham , Borayek Ahmed
Published: February 2024

In the oil and gas industry, an extensive volume of logging data is routinely generated and acquired during operations. This data is accumulated across various phases of exploration, production, and subsequent operations. The challenge lies in extracting meaningful insights from this high-dimensional dataset. Constraints in data visualization (such as the three spatial axes, x, y, and z) and manipulation further complicate the process of drawing valuable conclusions.

As a method to tackle this challenge, a technique has been devised to streamline data visualization by reducing high-dimensional data to a lower dimensionality, while retaining vital features crucial for big data analysis. Principal component analysis (PCA) emerges as a prominent approach employed for data dimensionality reduction. PCA simplifies multivariate datasets encompassing well-logging tools (e.g., gamma ray, density, neutron porosity, and resistivity) and drilling parameters such as rate of penetration, weight on bit, and vibration data, condensing them into a reduced number of factors known as principal components (PCs).

The results of the dimensionality reduction technique show that various logging data and drilling parameters were condensed into a set of principal components (PC1, PC2…PCx), where x corresponds to the number of utilized variables. The analysis indicates that the first two components (PC1, PC2) capture most of data patterns. The graphical representation of these components (PCA biplot) reveals distinct clusters with clear patterns, facilitating the identification of separate electro-facies. Moreover, PC1 exhibits a strong correlation with lithology variations, enabling its utilization in well-to-well correlation. Additionally, regression analysis demonstrates a significant predictive relationship between PCA components and well logging variables, allowing the use of the R-squared regression technique to forecast a result curve based on PCA input. Higher principal components are found to be more associated with formation fluid, thus complementing the standard petrophysical analysis.

The industry's current shift is from data collection to practical applications. By employing diverse dimensionality reduction techniques, the workflow enables the analysis of big data in a more comprehensive manner, unveiling concealed trends and insights. This approach not only facilitates machine-learning and artificial-intelligence applications but also enables a deeper understanding of the data through descriptive forms, thereby supporting industry advancements.
Predicting Subsurface Reservoir Flow Dynamics at Scale with Hybrid Neural Network Simulator
Authors: Maucec Marko , Jalali Ridwan , Hamam Hassan
Published: February 2024

In this paper we demonstrate the application of state-of-the-art deep learning using hybrid neural networks (HNN) that generalize and scale to multi-million, structurally diverse reservoir model grids and generate long-term spatio-temporal predictions of fluid and pressure propagation. The HNN simulator (HNNS) is a surrogate framework that consists of a subsurface graph neural network (SGNN) to model the evolution of fluids, and a 3D-U-Net to model the evolution of pressure. We benchmark the HNNS with two conceptually different reservoir models: a) modified SPE-10 model, with approx. 1 million grid size and variable number and positioning of vertical producers and injectors, b) synthetic fractured model, 15+ million grid size and 100+ injector and producer wells with variable geometry. We construct the network graph, where graph objects (nodes), representing reservoir grid cells are encoded with tens of static, dynamic, computed (relative permeability, gradients) and control (well rates) features. The graph edges represent interactions between the nodes with encoded features like transmissibility, direction and fluxes. We implement sector-based training with multi-step rollout to avail for the use of large-scale models. To properly perform the sector-based training the masking of sector boundary effects, sector stride and mixing sectors were used. We present the comparative results between the HNNS and the full-physics simulation for up to 30-year prediction of the 3D flow dynamics.
Production Analysis of Offshore Gas Wells (UK North Sea) Using Bootstrapped Arps Method: Reserves Estimation Without Reservoir Model
Authors: Afagwu C. C. , Weijermars R.
Published: February 2024

This study analyzes recently released proprietary daily production data from 31 decommissioned dry gas fields located on the UK Continental Shelf (UKCS). First, the hydrocarbon fields in the UKCS region were assigned to five groups, based on their geological source origin. The data analyzed here are from two lease areas comprising gas fields, sourcing from two of the five groups distinguished. One set of wells produced from Carboniferous Westphalian sandstones, the other from Permian Rotliegendes sandstones: both reservoir types remain active sub-salt targets. The production profiles of the 31+ legacy wells analyzed were grouped into four types: (1) Wells part of multi-well clusters producing from large fields, with production output controlled by facility access allocation; (2) Problem wells, with poor production and long downtime; (3) Wells with frequent shut-in days but excellent recovery; and (4) Fast clean producers; single well production profiles showing continuous decline without major interruptions, other than slight adjustments of choke settings. Two Permian gas fields (Mimas and Tethys) and one Carboniferous gas field (Kelvin) were produced with fast and clean producer wells. These wells appeared also equipped with bottomhole gauges which together with choke-settings and wellhead pressures, gives a comprehensive record of historic well performance. The historic well performance was analyzed using various bootstrapped data sets (6, 12- and 18-months production), which were least-mean-square-error (LMSE)-fitted with a traditional Arps decline curve analysis (DCA) method. The EUR forecast based on the bootstrapped Arps DCA (6, 12, 18 months) was compared with the known actual EUR based on the full historic well performance record. Based on our evaluation, a fast LSME fit of Arps DCA on early bootstrapped well data for 18 months appeared to give reliable estimates for the actual long-term EUR/well for two fields (Kelvin and Tethys). However, a third field (Mimas) required 5 years of bootstrapped data to achieve reliable EUR estimates.
Experimental and Numerical Study on the Phase Behavior and Distribution Characteristics of Oil-CO2-Water Three-Phase Fluid During Pre-CO2 Energized Fracturing in Shale Reservoirs
Authors: Han Xiao , Song Zhaojie , Deng Sen , Li Binhui , Li Peiyu , Zhang Lichao , Song Yilei
Published: February 2024

Analogous to the technique CO2 huff-n-puff, it has been determined that the preliminary injection of a predetermined volume of supercritical CO2, serving as a pre-fracturing fluid, holds significant promise in augmenting EOR and facilitate carbon storage from shale oil reservoirs when applied prior to hydraulic fracturing procedures. However, regardless of whether it's pre-CO2 energized fracturing or post-hydraulic fracturing CO2 huff-n-puff, the coexistence of oil-CO2-water in shale reservoirs leads to complex phase behavior and flow characteristics. To this end, this study firstly designs and conducts three-phasic experimental tests involving shale oil, CO2 and water. This is achieved by varying the order of CO2 and water injections into the shale oil to simulate both pre-CO2 energized fracturing and post-hydraulic fracturing CO2 huff-n-puff. Subsequently, based on the results of PVT experimental, further established a phase behavior calculation model of oil-CO2-water and used it to construct a numerical simulation model that takes into account the stress sensitivity of the SRV transformation zone, formulated the injection and production parameters of pre-CO2 energized fracturing and explored the fluid distribution mechanism at different stages. The equilibrium experiments and numerical simulations indicate that due to the dissolution of CO2 in water, the presence of the aqueous phase reduces the solubility of CO2 in oil, thereby diminishing the interaction intensity between CO2 and crude oil. The saturation pressure under the coexistence of oil-CO2-water three-phase behavior is lower than that of the oil-CO2 system. Furthermore, this phenomenon becomes more pronounced with the increase in water saturation. For pre-CO2 energized fracturing, compared with post-hydraulic fracturing CO2 huff-n-puff, the degree of dissolution of CO2 in water can be significantly reduced, which is conducive to the dissolution of CO2 in oil. Therefore, pre-injection of CO2 can maximize the use of CO2 and reduce unnecessary waste. Pre-CO2 energized fracturing can make CO2 spread more widely, effectively promote contact with oil to improve oil physical properties, and inhibit CO2 flowback ratio during the drainage process, which is conducive to carbon storage. Compared to the conventional CO2 huff-n-puff technique, pre-CO2 energized fracturing in horizontal wells can markedly ameliorate crude oil recovery. This research enhances our understanding of the oil-CO2-water phase behavior and fluid distribution with pre-CO2 energized fracturing in shale reservoirs, potentially offering insight for efficient shale oil reservoir development.
Polyols: A Green, Non-Toxic, High Temperature Stabilizer for Hydraulic Fracturing Fluids
Authors: Almubarak T. , Alabdrabalnabi M. I. , Albaiz A. , Yami M. Al
Published: February 2024

High-temperature fracturing fluids are in demand as we explore deeper and lower permeability reservoirs. Fracturing fluid stabilizers are divided into three categories: crosslinking delay additives, pH buffers, and reducing agents. Current technologies pose risks due to toxicity concerns and their harmful environmental effects. Consequently, the industry is continuously pushing towards green solutions. This work showcases the use of low-calorie sweeteners such as polyols as an environmentally friendly fracturing fluid additive.

The paper presents a guar derivative fracturing fluid system prepared at pH 10. The tests were performed in a high-pressure/high-temperature (HPHT) rheometer to evaluate the rheological performance at 300°F for 1.5 hours. The rheological schedule measured viscosity at 100 s-1 shear rate with varying lower shear rates ramps in between. Experiments are completed to recognize how polyols influence the rheological behavior of the fracturing fluid under a variety of crosslinker concentrations.

The results showed that using polyols can function as a crosslinking delay additive to control viscosity buildup, thus aiding in high-temperature stability. This was determined by varying the ratio of polyol to crosslinker concentration. Achieving a balance between the polyol and crosslinker concentration produced fracturing fluids that maintain a viscosity above 300 cp for 1.5 hours at temperatures of 300°F. Common oxidizer breakers were evaluated with this system and exhibited a controlled viscosity breakdown profile at these conditions. Proppant settling tests were also shared and showed the ability to suspend proppant for the duration of the treatment.

This study shares the use of polyols in fracturing fluids. Polyols not only provide excellent crosslinking delay properties but also protect organisms and the environment by mitigating the toxicity and health-damaging effects of commonly used high-temperature stabilizers.
Internal Multiple Suppression Method and Its Application in Complex Buried Hill of Bohai Bay
Authors: Duan X. , Ding H. , Zhang J. , Ma Z. , Han Z.
Published: February 2024

As the largest offshore oilfield in China, Bohai Oilfield has made good exploration discoveries in various target strata in the past decade, especially in the exploration of deep buried hills. Because the shallow favorable targets have been nearly drilled out, the exploration focus of Bohai oilfield is gradually shifting to the middle and deep layers. The buried hill have become the most important research hots pot of Bohai oilfield, and several large gas reservoirs have been discovered in Archean strata. The main reservoir type of buried hill oilfield is fracture, which has complicated characteristics with low porosity, strong heterogeneity and complex fracture distribution. The average depth of buried hill is about 4500m, so it is difficult to accurately predict and describe good fractured reservoir in the exploration and development.

Because of the deep buried depth, the quality of seismic data is usually very poor. On the one hand, the effective signal of fractured reservoirs are very weak, and the low S/N seismic data is hard to recognize fractured reservoir. On the other hand, there are a lot of residual internal multiples, and their amplitude is even stronger than the reflected wave of fractures. Taking the normal processing procedure into consideration, most of the multiples like surface-related multiples have been well suppressed during the seismic data processing. In order to clearly identify the real reflection wave of fractured reservoir, it is necessary to suppress the internal multiples and enhance the effective signals.

Generally, the methods of suppressing multiple waves are divided into two categories: one is the filtering method based on signal analysis and processing, such as t -p transform and f-k transform; the other is the prediction subtraction method based on wave equation, such as wave extrapolation method and inverse scattering series method. The first kind of methods have certain limitations: the dynamic correction speed of multiple waves and primary waves is similar, which weakens the effectiveness of t -p transformation, multiple and primary waves have similar slopes, which weakens the effectiveness of f-k filtering. The second type of method mainly uses the generation mechanism of multiple waves to predict and suppress multiple waves. It comprehensively considers the kinematic and dynamic characteristics of multiple wave propagation and can adapt to complex underground structure. It uses its own data as a multiple wave prediction operator, requires less or no assumptions about underground structure, and attenuates multiple waves without damaging the primary reflected signal. For internal multiple waves, the current effective method is the inverse scattering series method based on the point scattering model. This method does not need a prior velocity structure model, and has a good adaptability to complex structures, but the calculation is very large.
Breakthrough Solutions for Lost Circulation Control in Oilfield Drilling: Unleashing the Power of Biopolymer Modified Graphene and CaCO3 synergy
Authors: Ahmad Hafiz Mudaser , Kamal Muhammad Shahzad , Murtaza Mobeen , Nabbat Yousif Al , Arifi Sulaiman Al , Mahmoud Mohamed
Published: February 2024

Lost circulation is a common problem encountered during drilling operations, where drilling fluids escape from the wellbore into the surrounding geological formations, resulting in reduced drilling efficiency and increased costs. Conventional lost circulation materials (LCMs) like calcium carbonate (CaCO3), mica, ground walnut shells, fibrous materials, and cross-linking agents are usually added to drilling fluids to plug the lost circulation zone. Further, nanoparticles, such as graphene and carbon nanotubes, offer a new generation of solutions for controlling fluid loss into lost circulation zones. The particle size distribution of LCMs, their stability, and dispersion play a significant role in controlling losses. The combination of LCMs and nanoparticles can provide a synergistic effect for lost circulation control. In this study, a mix of biopolymer-modified graphene and CaCO3 is proposed as a potential solution for lost circulation control that combines the unique properties of biopolymer, graphene, and CaCO3. The potential of the novel solution was investigated by conducting rheology and fluid loss tests. Their synergistic effect was investigated by incorporating them in different concentrations in drilling fluid and the optimum concentration was chosen based on rheology and fluid loss results. Experimental observations revealed that the combination of biopolymer-modified graphene and CaCO3 resulted in the formation of a durable and impermeable mud cake on the wellbore wall, effectively bridging the lost circulation zone. This innovative approach significantly reduces fluid loss in comparison to the conventional use of CaCO3 alone. By filling the nanopores of the CaCO3 bridge, the modified graphene contributes to a robust and reliable lost circulation control solution. Moreover, the inclusion of modified graphene improves the rheological properties of the drilling fluid, facilitating easier pumping and enhancing its capacity to suspend CaCO3 and other weighting materials. The proposed solution is biodegradable, environmentally friendly, and can withstand HPHT conditions, making it a viable option for real drilling conditions.
Fracture Monitoring and Characterization Using Unsupervised Microseismic Data Analysis
Authors: Misra Siddharth , Chakravarty Aditya
Published: February 2024

The study shows the use of unsupervised manifold learning on microseismic data for fracture monitoring and characterization. Manifold learning condenses complex, high-dimensional data into more concise, lower-dimensional representations that encapsulate valuable underlying patterns and structures of the data. The study leverages Uniform Manifold Approximation and Projection (UMAP) methodology to efficiently convert high-dimensional data into a graph-based, lower-dimensional representation. This transformative approach adeptly captures meaningful patterns and structures while preserving both local and global distances; thereby, the topology. In this study, the unsupervised manifold learning is applied on accelerometer and hydrophone data obtained during an intermediate field-scale hydraulic stimulation experiment conducted at the Sanford Underground Research Facility in South Dakota to measure, monitor, and characterize fracture propagation in near-real-time. Each micro-earthquake location identified using travel-time information is assigned a fracture type using unsupervised manifold learning, and later is assigned a fracture-plane label using semi-supervised manifold learning. Our findings highlight the precision and accuracy of our proposed method in preserving fracture network clusters and fracture-plane labels using signals from both accelerometers and hydrophones. These remarkable results underscore the potential of the Uniform Manifold Approximation and Projection (UMAP) technique as a versatile unsupervised-learning tool for unveiling the intrinsic structural features embedded within microseismic signals generated during hydraulic fracturing for purposes of fracture monitoring and characterization.

Next, this study addresses the challenge of reliably assigning fracture-plane labels to microseismic events created during hydraulic stimulation. Most events lack clear labels due to scattering and uncertainty in event locations. To tackle this, the study introduces a semi-supervised learning strategy based on UMAP that utilizes a sparse dataset with pre-labeled fracture-plane categorizations. By combining event coordinates and Fourier spectra from geophone signals in a low-dimensional manifold, this approach achieves precision and recall rates exceeding 92% while using only about 20% of labeled events. This method remains robust even in the presence of location errors, making it valuable for enhancing fracture network characterization in various applications, including hydrocarbon and geothermal production.
Research and Application of Adaptive Ghost Wave Suppression Method in Time-Space Domain
Authors: Wang Yichuan , Ma Xugang , Liu Gongli
Published: February 2024

Source ghost waves and cable ghost waves can generate frequency trapping effects, resulting in the loss of low-frequency and high-frequency information in seismic data, seriously affecting the imaging quality of seismic data, and increasing the difficulty of later seismic data interpretation and reservoir inversion. The ghost wave delay time can be expressed as a function of the depth of the detector. When the cable depth is accurate, the difference between the total wave field minus the primary wave field and the ghost wave energy should be minimized. Convert the automatic optimization problem of cable depth into a least squares problem, and obtain the true cable depth by solving the objective function. By scanning the depth of the cable and combining it with the matching subtraction algorithm, accurate cable depth can be obtained. Design an anti filter to effectively suppress ghost waves. By designing a single-layer reflection model for algorithm testing, the effectiveness of this method is verified. After removing ghost waves, the energy of the trap points has been greatly restored and improved, and the energy of the low-frequency and high-frequency ends of seismic data has been well improved. Adaptive ghost wave suppression technology can effectively suppress source ghost waves and cable ghost waves, achieving the goal of eliminating traps, expanding seismic frequency bands, and improving seismic data resolution. This method not only has good processing results in actual marine seismic data processing, but also has high processing efficiency and good applicability to seismic data. It can be well applied to conventional horizontal cable seismic data and oblique cable seismic data. Significant improvement in the quality of seismic data provides an important data foundation for reservoir research.
Cased Hole Reservoir Evaluation in Old Wells with Complex Completion and Lithology – A Case Study from a Mature Gas Field in the Dnieper-Donets Basin, Ukraine
Authors: Petrokushyn O. , Abliakimov L. , Kuznetsov V.
Published: February 2024

The Dnieper-Donets basin (DDb) is the biggest and most explored hydrocarbon region in Ukraine. The DDb is a Late Devonian rift, filled with pre- and syn-rift Devonian sequences and overlaid with post-rift Carboniferous, Permian, Mesozoic and Cenozoic fill. The depth of the basement is found at a depth of approximate 4–5 km in the northwestern part of the basin. However, it dips along its strike southeastward and lies below about 15 km near the Donbas foldbelt (Figure 1). DDb is also a salt basin. While in its axial part salt penetrates over 10 km thick Carboniferous-Permian sequence, this part of the basin accommodates the biggest known hydrocarbon field (Figure 2) (T. Petrovska et al., 2021).

The dominant reservoir lithologies that contain most of oil and gas reserves in DDb are clastic rocks. Lower Carboniferous-Lower Permian carbonates and fractured anhydrites near the top of Paleozoic sequence contain comparatively smaller quantities of hydrocarbons. Hydrocarbon accumulations in the DDb are primarily structural traps, however faults and stratigraphic pinchouts usually control outlines of individual pools. Majority of the hydrocarbon fields in Upper Carboniferous-Lower Permian reservoirs are in faulted anticlinal uplifts covered by Permian salt seal, while fields in Lower Carboniferous reservoir rocks are usually associated with salt-assisted structural traps in deep, central basin areas. The first hydrocarbon shows in DDb were first recorded in 1936. The industrial hydrocarbon extraction has begun in 1950s-1960s when several significant gas fields were discovered (Ulmishek, 2001). There are over 200 hydrocarbon accumulations under production in the basin.

At present, most of these fields are depleted and the gradual decrease in reserves is pushing the operator companies in Ukraine to look for the bypassed intervals in existing wells or explore new prospects. Another important aspect is understanding the actual formation pressure of each producing zone as it is a crucial piece of information for optimizing production. One of the logging technologies that is widely used to address these challenges is Multidetector Pulsed Neutron Logging (MDPNL). MDPNL has proved its efficiency in locating bypassed reserves that were missed during early open-hole evaluation and as well through monitoring the changes in formation properties that have occurred since the casing was set and production begun.
Enhanced Reservoir Insight and Precise Well-Placement in a Karstic Carbonate Layer With Real-Time Ultra-Deep 3D Inversion: A Case in a Horizontal Appraisal Well, Offshore Abu Dhabi, UAE
Authors: Wahbah Salima , Bellah Samir , Hattori Tadataka , Tsuda Ryuchi , fares Wael , Ghobashy Ahmed , Clegg Nigel
Published: February 2024

This paper details challenges in placement of an appraisal horizontal well. Challenges are associated with reservoir geology and well requirements. The top boundary of the fractured carbonate reservoir holds large uncertainties in depth and in structural dip and it also suffers from severe karsts. Well requirements are related to constraints on placing the horizontal well within a certain offset below the top reservoir to avoid the karst features while avoiding the potential for water or early water breakthrough.

Preparation, execution and evaluation phases of well placement demonstrates the importance of Morzhov the geosteering approach for successful completion operations in complex geology. An Ultra-Deep Azimuthal Resistivity (UDAR) tool was deployed as the main geosteering tool, because the low resistivity contrast between the carbonate reservoir and above shale is too small for conventional deep-resistivity tools to deliver on the well objectives. An advanced 1D inversion algorithm provides high certainty on detecting boundaries around 100 ft from the wellbore, allowing early identification of changes in the karstic surface. Pre-well Modelling enabled optimal tool selection and simulated 1D inversion responses to the challenging geology. Resistivity image and Nuclear Magnetic Resonance (NMR) were also included to improve geological understanding.

The horizontal section was targeted to stay within a certain offset below the top reservoir. At this depth, both top boundary of the reservoir and below water zone were mapped and identified by the real-time UDAR 1D/3D inversion. Moreover, a potential target zone was mapped at a deeper depth below the top boundary.

While geosteering to avoid karsts, the Borehole Assembly (BHA) was stuck and a sidetrack was planned based on the new real-time info obtained from the inversion in the first horizontal. The new deeper target zone was drilled and the UDAR Inversion mapped further karstic features. Towards the TD, the inversion showed a sharp boundary that correlates with a sharp Bit-Gamma ray increase suggesting another karstic feature. Application of UDR-Image-NMR assembly provides critical insights and comprehensions of appraisal areas; Laffan-Mishrif boundary is positively shallower than expected and a new unit with excellent properties is mapped and produced.

The appraisal well was successfully placed in the optimum zone, with oil saturation up to 69%. Mapping the upper boundary provided additional understanding of the geological uncertainty caused by the Karstic surface. Mapping of the aquifer allowed the assessment of the impact of changing the trajectory relative to the top boundary when required to increase distance from the upper karst boundary.
Lost Circulation Material Size Selection for Naturally Fractured Rocks
Authors: Nguyen K. , Mehrabian A. , Santra A. , Phan D. , Bathija A.
Published: February 2024

This paper presents a scheme for designing lost Circulation Material (LCM) blends that are commonly used to mitigate loss of wellbore drilling fluid through natural fractures of rock formations. The method involves using the history of drilling fluid loss rates to estimate the mean aperture size of the formation natural fractures. This estimate is enabled via an inverse solution based on a nonlinear optimization algorithm to obtain the most likely value of the effective permeability of the natural fractures network. The inverse solution embeds a forward semi-analytical solution that models the displacement of formation rock fluid by the drilling fluid as the losses occur. The forward solution accounts for yield-power law rheology of drilling fluid and considers the formation fluid displacement occurring through a network of connected natural fractures, as opposed to a single isolated fracture. Once the mean aperture size is determined, a blend of selected LCMs may be recommended via a particle size criterion that optimizes the LCM particle size distribution for effective plugging of fractures. The overall LCM design scheme is discussed via a case study.