bluuebunny/crossref_metadata_2025 huggingface dataset:
Field Development Plan (FDP) Cloud-based Data Integration Between Geology & Drilling Software Using Python Tools
Authors: Mwansa P. , Repilloza H. , Grebe S. , Hassan M. A. , Pietrzyk M. , Torsæter A.
Published: February 2024

The oil and gas industry generates vast amounts of data throughout its operations, from exploration to production. Collecting, connecting, and optimally utilizing this data is key to maximizing efficiency, accuracy, and access to new disruptive technologies.

In a typical well-planning cycle, an engineer will spend a significant amount of time looking for the data they require to do their jobs efficiently. The data are typically locked away in silos - trajectories in one data platform, Pore Pressure Gradient, Fracture Gradient or Targets in another, and so on.

A major Middle Eastern NOC and Two Norwegian software service companies teamed up to develop Proof of Concept (PoC) for a new workflow that integrates subsurface and drilling data between on-premises Geology E&P software and Drilling software through a proprietary Python Tool plug-in and Python library. This integration enables a streamlined connection to a cloud-based drilling and well planning software, facilitating collaboration among teams involved in well planning. The project's key challenges are the lack of a standardized communication, integration, and automation of data flows between subsurface and drilling teams, as well as the inability of engineers to access necessary data due to scattered information and access restrictions. The project utilizes a proprietary data science suite, named Cegal's Prizm, which allows easy configuration to integrate data from various applications, sources, and platforms. A proprietary Python Tool is used to merge data from various application silos and data sources, enabling enriched investigation. The process involves connecting to the Geology E&P software retrieving domain objects using the proprietary Python Tool, and converting these domain data objects into common Python data structures. The project aims to develop an innovative workflow that provides easier access to data for experts throughout the organization, leading to better decision-making during the well-planning cycle. This not only makes it easier, but it also ensures collaboration between the G&G and Drilling teams involved in new well planning
Development of a Hybrid Modelling Approach for Estimating Bottom Hole Pressure in Shale and Tight Sand Wells Using Smart Production Data and Machine Learning Techniques
Authors: Afagwu C. C. , Glatz G.
Published: February 2024

Well flowing bottom hole pressure is an important input parameter for well and reservoir performance evaluation. However, there are limitations in accurate downhole measurements due to a faulty gauge and, sometimes, the inability to obtain complete well test data to implement theoretical models. The goal of this work is to create a hybrid modeling approach for estimating bottom hole pressure in tight sand and shale wells using smart production data, engineering features and machine learning (ML) techniques. The robust feature selection process integrated the critical attributes in the traditional PTA methods. Four out of eight adopted variables were split into training, cross validation and test sets in 60:20:20 proportion and preprocessed by z-score normalization scaling. For the first time, the combination of gradient descent optimization (GDO) algorithm and Cauchy cost function was used in the estimate of bottom hole pressure from production data in this study. A smart data approach for developing ML models was used in this study. Starting with 100 data points, the training and validation input size were incremented and subject to the learning process using both Cauchy and traditional MSE cost function-based GDO algorithm to determine the optimum batch size required to train the BHP model with lowest cost. The results showed that the Cauchy based GDO algorithm provides slightly better performance in training, cross validation and testing data with a global minimum error of 0.82%, 0.64% and 0.41% respectively compared to the traditional MSE-based GD that reaches a global minimum with higher cost. However, the improved metrics scores with Cauchy loss optimization required additional expense of one to ten seconds execution time. The Cauchy cost function presents an alternative technique to obtain better optimized prediction models from production data and can be utilized in sensitivity studies for reservoir characterization and asset management purposes.
Exploration and Application of Integrated Approach for Sand Control and Remediation
Authors: Chen Huaxing , Zou Jian , Wang Yufei , Pang Ming , Liu Yigang
Published: February 2024

The objective of this paper is to explore and apply an integrated operation mode for sand control and sandstone acidization in offshore weakly cemented and loose sandstone reservoirs. The paper aims to investigate the use of a water-based resin for sand consolidation and chemical sand control in order to extend the effective period of sand control operations and mitigate sand production and particle migration. This paper is based on the analysis of reservoir particle transport mechanisms. It introduces the application of a water-based resin in sand control operations, forming an integrated approach combining acid stimulation and chemical sand control. The first step involves acid stimulation to restore high-permeability channels near the wellbore, followed by chemical sand control treatment to inhibit the migration of reservoir sand particles and prevent the blockage of near-wellbore flow channels, thereby extending the effectiveness of acid stimulation. Experimental results demonstrate that the resin can achieve a core permeability retention rate of 84.6%~91.4% and a compressive strength of 3.44~6.95 MPa. The integrated operation mode of acidization and chemical sand control is compared to the single acidization method, showing an 80% reduction in core plugging rate and a fourfold extension of the effective period of sand control. The application of the integrated operation mode of acidization and chemical sand control in a well affected by near-wellbore plugging (referred to as Well S) in offshore fields has resulted in a significant increase in oil production, absence of sand at the wellhead, and sustained stable production. The successful application of the integrated operation mode in offshore fields is of great significance for sand production and particle migration control in such wells. This paper presents a novel approach by integrating sandstone acidization and chemical sand control, which extends the effective period of acidization and provides a solution to sand control challenges in offshore sand and particle migration wells. The use of a water-based resin for sand consolidation and the implementation of a chemical sand control system contribute to the existing literature by offering an effective method to mitigate sand production and enhance reservoir productivity.
Engineered Low Salinity Waterflood in Carbonate Reservoirs?Boosting Fluid-fluid Interaction and Oil Recovery by Cost Effective Additives
Authors: Yonebayashi Hideharu , Hiraiwa Takeshi , Tange Masaaki , Sawata Masaru , Tareq Khlaifi Khuloud , Sakurai Risa , Bahri Sami , Abdelfattah Abed Abdalla , Inokuma Yuto , Hamdan Alkaabi Sultan , Fattahi Mehraban Mohammad , Stalker Robert , Graham Gordon
Published: February 2024

Low salinity water (LSW) enhanced oil recovery (EOR) has gained more attention in carbonate reservoirs with variety of mechanism hypothesis. Recent research focused on fluid-fluid interaction, forming micro-dispersion as an interfacial reaction of oil-water mixing, can reflect a main driver of oil improving mechanism. This paper focuses on the mechanism and demonstrates further boosting the fluid-fluid interactions using small amount of additives to improve LSW EOR value in an objective offshore giant carbonate field. Four stock tank oil (STO) samples were collected from multiple sub-layers (L1, L2, L3, and U). Brines were prepared as formation water (FW), sea water (SW), and LSW (diluted to 1-20%SW). The fluid-fluid interaction tests measured micro-dispersion ratios (MDR), which represent water content increment by the oil-water interfacial reactions, to screen the most positive oil for low-salinity effect. To boost the reaction in LSW, three additives: diethyl ketone (DEK), dimethyl ketone (DMK), and copper chloride were independently evaluated using the screened positive oil. The boosting effectiveness was investigated by MDR improvement and core flood tests.

The larger micro-dispersion phase was formed as switching from FW and SW to more diluted LSW in the fluid-fluid interaction tests. The STO-L2 was screened as the most positive oil because of the highest MDR. The two-staged MDR increase indicated the existence of threshold salinity (i.e., between 4-5%SW and 2-3%SW) for triggering the radical oil-water interfacial reaction. To clearly capture booster's impacts, the subsequent tests used 1%SW as a base LSW. The compatibility analysis determined 2.0 wt% of DEK and DMK as dosing ratio to LSW. The additive boosting impacts on fluid-fluid interaction revealed a noticeable MDR increase compared to that of pure LSW case. The boosting potential of oil recovery was evaluated by three core flood tests using the identical reservoir core (i.e., reused after solvent cleaning and aged again for avoiding a common core-nature uncertainties). Thus, common secondary SW injection achieved similar oil recovery among three tests. The tertiary untreated LSW injection revealed +3%IOIP additional oil recovery after the secondary SW injection. The largest oil recovery boosting occurred by the tertiary LSW+DEK injection as +10.7 %IOIP (three-times higher than that of pure LSW case). Finally, we found a linear correlation between MDR and oil recovery increment.
A Skin Factor Model of Sliding Sleeve and its Production Optimization
Authors: Binwang LI , Zhiming WANG , Quanshu ZENG
Published: February 2024

In order to effectively alleviate the problem of premature water breakthrough in horizontal wells, sectionalized variable-density perforation completion, stinger completion, ICDs and sliding sleeve based on control valve completion technology have been proposed. The sliding sleeve based on control valve completion technology can realize infinite adjustment and real-time control of the sliding sleeve opening to balance inflow effectively.

In order to study the interference of the sliding sleeve completion to the flow near the wellbore, a calculation model for the skin factor of sliding sleeve is established in this paper. Based on numerical simulation, the flow area is divided according to the pressure distribution characteristics during the flow process of the sliding sleeve completion. At the same time, the linear flow boundary and the radial flow boundary are determined by combining the geometric boundary and roundness. Finally, the skin factor is determined according to the flow difference between the fluid passing through the sliding sleeve completion and the open hole completion, and it is compared and verified with the theoretical prediction value.

The research shows that the flow in the near-wellbore of the sliding sleeve can be divided into six different zones according to the distribution characteristics of the pressure equipotential line. The radius of disturbance in the near-wellbore predicted by roundness is within 6% error of the numerical simulation results. By simulating the flow difference during constant pressure production, the error between the skin coefficient obtained by inverse calculation and the theoretical prediction value is within 12%. It was also observed that the water-cut decreased by 6.4% with the application of sliding sleeve completion compared to the normal screen pipe completion after 2 years of production.

The proposed model is robust and reliable. The skin factor model in this study can be applied not just to the optimal design of water control completion parameters, but to provide theoretical guidance for the real-time regulation of the sliding sleeve opening during production.
Extending Pulsed Neutron Logging Application in Reducing uncertainty in Low-Porosity, Complex Lithology Exploratory Field – A Detailed Case Study
Authors: Kozlowski M. , Eyuboglu S. , Adedamola A. , Aydemir P. , Armutlu T.
Published: February 2024

The assessment of oil and gas saturation behind casing by using Pulsed Neutron Logging technology (PNL) is not new to the industry. However, the assessment of low-porosity reservoirs has always presented challenges to the application of PNL. This is further complicated by the presence complex unknown lithology with rugose borehole architecture. In this paper, a detailed case study is discussed highlighting the job planning, logging execution, and integrated post-processing interpretation workflow with the obtained results.

In the subject well, limited open hole data was available and the rugosity of the wellbore posed some challenge to the conventional porosity measurements. After the review of the available data, a multidetector pulsed neutron tool (MDPNT) was deployed. Capture data, inelastic data as well as spectral gamma ray data were acquired. The statistical uncertainty of the acquired data was assessed real time to determine the number of inelastic passes required with the associated logging speed. Special hole size correction models were applied to correct for the impact of rugosity in the tool measurement.

Detailed mineralogical evaluation was done by comparing the capture elemental yields against the inelastic yields to ascertain the appropriate mineral model. Spectral gamma ray data was used for clay typing and also to confirm any possible presence of organic carbon/kerogen. Oil saturation was computed from carbon-oxygen measurement with detailed borehole corrections applied to correct for the effect of hole rugosity. Porosity data was computed from the pulsed neutron porosity indicators – the inelastic and capture ratios. Porosity was predominantly below 5% with mixed carbonate observed across the oil zone. Clay typing showed varied mix of various clay types with prevalent presence of chlorite and montmorillonite. Despite the very low porosity and low salinity, accurate hydrocarbon saturation was computed which was used perforation planning.

The value of pulsed neutron logging in newly drilled exploratory well was demonstrated in this case study. The importance of proper job planning, detailed environmental corrections and real-time assessment of statistical and saturation uncertainty was showcased, in order to achieve results with high confidence despite the low-porosity challenge.
Practical Implementation of Combining Wellbore Survey Tools for Optimized Wellbore Position Accuracy
Authors: Houbiers M. , ElGizawy M. , Ledroz A. , Bang J. , Lowdon R. , Aklestad D.
Published: February 2024

Techniques involved in combining Measurement While Drilling (MWD) and gyro survey tools have been developed previously, and it has been demonstrated that the advantages for wellbore position uncertainty can be significant. However, the implementation of these techniques on a practical level is not well understood. In this paper, we outline the practical implementation of combining MWD and gyro position surveys to take advantage of the improved wellbore survey accuracy both during planning and execution of drilling operations and afterwards.

Worldwide, multiple wellbore survey tools are run to ensure a well is drilled safely and in the correct place. The combination of survey tools normally involves an MWD and a gyroscopic tool, often run where there is magnetic interference from an offset well, for additional accuracy, or survey QA/QC requirements. Both survey tools are valid, assuming they pass their respective QA/QC parameters. For sections where the surveys overlap, a linear combination may be used to build the definitive survey of the well. This yields a new wellbore position with potentially significantly increased accuracy.

To assess the improvement in combining wellbore survey tools, an error model needs to be built describing the combined error terms, weighting functions, and their application. The ability to build region-specific error models for a given combination of survey tools will be discussed. Requirements for the overlapping survey data and practical steps to ensure safe and robust implementation of the combined survey position are presented. Moreover, the application of a combined survey delivered to the rig in real time (if this is necessary) will be investigated. Finally, operational workflows, survey data, and error model handling, QA/QC of the new combined survey, and limitations of the method will be discussed.

An adequate practical implementation will allow combined surveys to be modelled and applied to planned and existing wells, resulting in improved well placement accuracy and wellbore spacing, more safe space for a well to be drilled, and hence drive drilling efficiencies and maximum production.
Anisotropic Rock-Physics Model and its Applications to Laminated Reservoirs Analysis
Authors: Vorobiev S. , Zharnikov T. , Vorobiev V. , Ayadiuno C.
Published: February 2024

The proposed anisotropy model allows to produce five independent dynamic elastic moduli for the veetrtical transverse isotropy (VTI) case. The VTI elastic moduli matrix can be rotated to match wellbore inclination or observed lamina dips to produce tilted transverse isotropy (TTI) anisotropy matrix with thirteen elastic moduli. The model is designed for the laminated shaly sands but is applicable for other cases of thin laminated reservoirs as well.

The model is based on the rock-physics model, which assumes that the anisotropy is caused by the lamination of clay and sands with a dispersed clay incorporated into sands’ matrix. Dispersed clay modeling is done using a combination of the Upper and Lower Hashin-Shtrikman and Reuss bounds. Laminated clay is incorporated using Backus averaging technique. VTI matrix can be rotated to the borehole frame using Euler rotation. Six plots and comparison of the independent laminated and dispersed clay volumes estimation technique has been developed for the model calibration.

The model has been tested on a number of wells from different regions. The model has applications in geomechanics for the elastic moduli anisotropy analysis as well as for the quantitative seismic interpretation (QI seismic). Thomsen weak anisotropy parameters can be computed from the VTI elastic moduli. The model provides new tool for the analysis of lamination and for petrophysical analysis of low resistivity low contrast (LRLC) sands. The model allows to calibrate clay volume in cases when X-ray diffraction (XRD) data is not available. It allows to produce two independent estimates of the dispersed and laminated clay volumes using Thomas-Stieber and shear moduli-based methods. The latter has been put forward in the process of the model development. These dispersed and laminated clay volumes’ estimates enhance LRLC saturation evaluation.

This paper provides novel dispersed and laminated clay rock-physics model. In addition, it proposes the model calibration technique based on six cross-plots and measured to modeled logs comparison. Additional validation of the model calibration correctness comes from two independent laminated and dispersed clay volumes estimates. The model provides new method of the total clay volume calibration. It opens new applications for the QI seismic inversion analysis in LRLC environments. All examples in this paper are based on the analysis of a gas bearing well located in offshore Australia. Thylacine-1 is the taken from public dataset exploration well (available in the Australian National Offshore Petroleum Information Management System https://nopims.dmp.wa.gov.au/Nopims/).
Identification and Characterization of Sonic Dual Arrival Events in High-Angle and Horizontal Wells for Enhanced Formation Evaluation and Well Placement
Authors: Bennett N. , Donald J. A. , Akinyose O. , Liu J. , Ma S. , Ghadiry S. , Abdallah W.
Published: February 2024

It is often assumed that reservoirs are homogenous in nature when conducting petrophysical evaluation of vertical pilot wells. However, this may not be the case with high-angle or horizontal (HAHZ) wells. Dual arrival events are well known to occur in sonic logs acquired in HAHZ wells where the compressional P-waves and shear S-waves propagate within the layer containing the tool sonde and refract along nearby shoulder beds. Here we present methods to process these dual arrival events to distinguish the tool layer slowness and provide a curtain section of formation slowness along the well track.

Physics modeling shows how the shoulder bed and tool layer arrivals present themselves to an acoustic receiver array as functions of measured depth, source-receiver offset, and nominal receiver azimuth. Built around a series of tau-P transforms in the common offset, common shot, and common ring gather domains, an automated time pick is presented. A labeling procedure then distinguishes between the tool layer and shoulder bed arrivals based on their apparent slowness and creates a log of tool layer P and S slowness. Finally, a ray tracing inversion is used to invert the arrival times associated with the shoulder bed arrivals for a locally two-layer model of formation P or S slowness.

Results of the physics modeling show that shoulder bed events have arrival times that vary with distance to the shoulder bed, have an apparent slowness that is faster than that of the tool layer arrival, and exhibit a sinusoidal moveout as a function of nominal receiver azimuth that indicates whether the shoulder bed is above or below the well track. The automated time pick is a generalization of the slowness time coherence workflow of Kimball and Marzetta. The ray tracing inversion determines the distance to and relative dip of the shoulder bed and distinguishes whether the shoulder bed arrival event is a reflection or refraction. The ray tracing inversion results are then woven together into a curtain plot section of formation slowness along the well track. This workflow of dual arrivals is demonstrated with both modeled waveforms and field data examples.

The above workflow produces logs of tool layer P and S slowness that are critical for accurate formation evaluation answers such as porosity, compressional and shear wave velocity ratio, and mechanical properties to derive stress estimates particularly when the well trajectory is close to a faster shoulder bed. Moreover, the resulting curtain plot section of P and S slowness is an acoustics analog of curtain plot sections of horizontal resistivity derived from logging-while-drilling electromagnetics measurements and so opens new avenues for increasing the use of acoustics for formation evaluation, completion operations, and well placement in HAHZ wells and geologically complex environments.
Modification of Shale Inhibition Properties using Novel Drilling Fluids with Gemini Surfactant and Associative Polymer as Additives
Authors: Ahmad H. M. , Javaid A. , Baig N. , Yasin S. , Iqbal T.
Published: February 2024

Drilling fluids are known as specialized fluids to modify rheology, filtration, fluid loss control, and shale inhibition properties for drilling applications in the oil and gas industry. Various additives are employed to change the properties based on the requirements of the drilling well and to meet the objectives of the drilling process. Additives such as polymers are used for rheology modifiers, fluid loss control modifiers, and shale inhibition control modifiers. Apart from polymers, a novel class of Gemini surfactants is also employed to modify the shale inhibition characteristics. In this work, a combined effect of polymer and Gemini surfactant was studied on the shale inhibition characteristics.

Various drilling fluid formulations were prepared by adding 0.25 to 0.4% concentration of associative polymer and 0.25% concentration of Gemini surfactant. All the drilling fluids were prepared based on the American Petroleum Institute standards. Two major tests were performed to investigate the effectiveness of prepared drilling formulations for shale inhibition properties. These tests include steady shear rheology and linear swelling tests in the presence of real samples of shale pallets.

The rheology of drilling fluids including polymer solutions and polymer surfactant solution was measured over a wide range of shear rates ranging from 0.1 (1/s) to 1000 (1/s). The shear stress and viscosity of the polymer solution increased by increasing the concentration of the polymer. However, the shear stress and viscosity of polymer solutions are slightly affected with the addition of surfactant solutions. It was observed that high-concentration polymer solutions were less likely by the surfactant solution. The linear swelling tests were performed with pure polymer and surfactant solutions along with the polymer-surfactant combined solution over a period of 48 hours. The linear swelling of shale pellets in the Presence of DI water was maximum while the swelling of shale pallets in the presence of polymer solution, surfactant solution, and polymer-surfactant solution was greatly reduced as compared to the swelling in DI water. The linear swelling of shale pallets in the polymer-surfactant solution (0.4%) - (0.25%) was approximately 107%.

The associative polymer and Gemini Surfactant have positive pendant groups and long alkyl chains in their structures. The positive pendant groups attach with the clay content in the shale while long alkyl chains encapsulate the shale minimizing the interaction of water with shale. Therefore, the synergistic effect of both polymer and Gemini surfactant improves the shale inhibition characteristics. This combination of associative polymer and Gemini Surfactant would be potential additives for drilling fluids to modify shale swelling and hydration inhibition characteristics.
Performance of Polyamidoamine-Enhanced Inhibitor in Mitigating Silicate Scale from Alkaline Surfactant Polymer (ASP) Flooding
Authors: Tan B. C. , Saaid I. M. , Mahat S. Q. , Razak A. A. A. , Bhaskoro P. T. , Anuar A. , Ahmed A. A. , Abubakar A. U.
Published: February 2024

Alkaline surfactant polymer (ASP) flooding is an effective chemical enhanced oil recovery technique to recover more hydrocarbon from maturing oilfields. However, the alkaline slug with high pH would dissolve quartz mineral in the sandstone formation which will result in silicate scaling issue. Silicate scales would precipitate in the formation near the production wellbore region, and further deposit inside production equipment and facilities. Consequently, the productivity of a well will be impeded. Scaling issues can be treated using chemical scale inhibitor (SI) through the application of squeeze treatment, continuous injection, or both. Many commercial SI available are not intended to mitigate silicate scale and these chemicals possess low biodegradability. Hence, more environment-friendly or "green" SI are being developed and tested for their effectiveness on scale inhibition. This paper aims to evaluate the performance of developed green silicate SI in mitigating silicate scale formation. The developed green silicate SI are composed of pteroyl-L-glutamic acid (PteGlu) that has enhanced with polyamidoamine dendrimers, either PAMAM-1.0 or PAMAM-2.0. Several experiments are conducted to assess the SI compatibility with synthetic brines, SI thermal stability, as well as SI effectiveness in treating silicate scale formation in static and dynamic conditions. Static adsorption test is also performed to determine the potential of developed green silicate SI for squeeze treatment. Results revealed that all tested SI are compatible with different synthetic brines. Among all, PAMAM-2.0-PteGlu SI yielded the best laboratory results at its optimum ratio of 1:333. It has the highest thermal stability as it experienced 34% weight loss at temperature 95°C. This SI also achieved 73.1% effectiveness in static scale inhibition test. From dynamic tube blocking experiment, it also managed to delay silicate scale precipitation by 48 times longer than the base case. Besides that, the adsorption capacity of PteGlu SI on crushed sandstone is also improved by approximately 60% with the addition of PAMAM-2.0. The green silicate SI developed in this paper could be utilized as environment-friendly alternatives in silicate scale control.
An Innovative Approach to Real-Time NMR Permeability Calibration Utilizing Azimuthally Oriented Formation Testing While Drilling
Authors: Fouda M. , Taher A. , Ramadan O. , Binghaith A. , Saad M.
Published: February 2024

Evaluating lateral variations of permeability is usually attempted using conventional logging tools and relying on field-specific porosity-permeability relationships. These transforms are generally built on core analysis and previous reservoir knowledge. Many Carbonate reservoirs given their complex pore structure, however, exhibit poor relationship between porosity & permeability and would hence need other more sophisticated methodologies and workflows to evaluate permeability. Nuclear magnetic resonance (NMR) is a well-known measurement that can provide indications of pore size in heterogeneous reservoirs and can hence be used for permeability evaluation. Formation testing while drilling (FTWD) can be used for mobility estimation while drilling. This paper presents the benefits of integrating logging-while-drilling (LWD) azimuthally oriented FTWD and NMR to reliably evaluate lateral permeability variations in horizontal wells.

NMR log-derived permeability is achieved by analyzing the T1 or T2 distributions and applying a cutoff differentiating pore size variation. The classification of the pore size distribution is input into established NMR permeability equations. These equations, however, have coefficients that need to be determined. The optimum irreducible water saturation cutoff as well as the permeability equation coefficients are ideally established with core analysis techniques. In horizontal wells across heterogeneous reservoirs having no representative core plugs formation testing can be used to help establish these parameters. Formation tester tools have been traditionally utilized to acquire a single pressure measurement and mobility calculation at any specified depth station. LWD testers, however, can be oriented around the wellbore to acquire several pressure and mobility values at different orientations. After investigating real time azimuthal images for bed boundaries and azimuthal variations, specific orientations of the formation tester can be selected to provide the most representative.

LWD NMR real-time permeability indicators showed pore size variations at the same porosity range. FTWD mobility data has enabled normalization of NMR permeability curves by providing calibration points at the test stations. The azimuthal orientation of FTWD tests was selected using LWD real time density and resistivity images to ensure the FTWD probe is not pointing to a tight bed boundary. High-resolution resistivity images from memory data provided an understanding to the mechanism causing variation in the azimuthal permeability profile. Combination of oriented FTWD and NMR permeability indicators aided real-time well-placement decisions and helped placing the wells into the most permeable zones. This paper presents an innovative approach for evaluating real-time permeability utilizing oriented LWD formation-testing mobility data with NMR permeability indicators.
Hydrocarbon Generation from Oil Shale Using Thermochemical Fluids: Integration of Geochemical, Petrophysical, and Core Flooding Methods
Authors: Aljurf S. S. , Elyasa A. , Hassan A. M. , El-Husseiny A. A. , Abu-Mahfouz I. S. , Mahmoud M. A.
Published: February 2024

The oil and gas industry has shifted its focus towards maximizing hydrocarbon production from unconventional reservoirs. Oil shale is an important unconventional resource that contains significant amounts of organic materials known as kerogen. This study aims to examine the effect of using thermochemical stimulation on fracture propagation and hydrocarbon generation from oil shale and characterize the rock sample using integrated geochemical and petrophysical methods before and after the stimulation process.

An integrated workflow to characterize the petrophysical and geochemical properties of oil shale was used before and after thermochemical stimulation. Laboratory measurements such as X-ray diffraction (XRD), X-ray fluorescence (XRF), Rock-Eval pyrolysis, and micro-CT were carried out to characterize the oil shale. The thermochemical stimulation was done using two chemical fluids, which are sodium nitrite (NaNO2) and ammonium chloride (NH4Cl). The coreflooding system was utilized to mimic reservoir conditions, where the fluids were injected separately and allowed to interact only upon reaching the core inlet. The sample was ultimately cleaned with methanol to remove the precipitated salts in order to be able to capture induced fractures effectively.

The stimulation of organic matter can lead to several alterations such as the enlargement of pore space and pre-existing fractures. The proposed workflow was successfully applied to the hydrocarbon generation from the oil shale sample. The TOC value declined after the stimulation due to the conversion of organic matter into hydrocarbons resulting from the thermochemical fluid reactions. Furthermore, the micro-CT images show that the pre-existing fractures were enlarged and formed a bath for new fracture networks. Along with this, the porosity of the sample increased due to the generation of new fractures. The more fluid cycles there are, the more efficient it is to convert organic matter into hydrocarbons. Also, the characteristics of the sample itself can affect the results of the reaction; thus, the higher the silica content, the more challenging the reaction. The XRD results after stimulation show that the calcite percentage decreased from (37.6%) to (19.2%) and quartz from (60.5%) to (48.1%), suggesting dissolution driven by the acidic thermochemical fluids.

Overall, this study introduces a new technique that can be utilized to stimulate and generate hydrocarbons in situ from oil shale source rocks. Oil shale is not exploited properly due to the complex nature of organic matter. So, the suggested workflow can pave the way to introducing a downhole technique to stimulate and produce these resources more effectively.
Federated Learning for Seismic Data Denoising: Privacy-Preserving Paradigm
Authors: Guruprasad Kamalesh Kumar Mandakolathur , Ambulkar Gayatri Sunil , Nair Geetha
Published: February 2024

Federated Learning (FL) is a framework that empowers multiple clients to develop robust machine learning (ML) algorithms while safeguarding data privacy and security. This paper's primary goal is to investigate the capability of the FL framework in preserving privacy and to assess its efficacy for clients operating within the oil and gas industry. To demonstrate the practicality of this framework, we apply it to seismic denoising use cases incorporating data from clients with IID (independent & and identically distributed) and Non-IID (non-independent and non-identically distributed) or domain-shifted data distributions. The FL setup is implemented using the well-established Flower framework.

The experiment involves injecting noise into 3D seismic data and subsequently employing various ML algorithms to eliminate this noise. All experiments were conducted using both IID and Non-IID data, employing both traditional and FL approaches, various tests considering different types of noise, noise factors, number of 2D seismic slices, diverse models, number of clients, and aggregations strategies.

We tested different model aggregation strategies, such as FedAvg, FedProx, and Fedcyclic, alongside client selection strategies that consider model divergence, convergence trend similarity, and client weight analysis to improve the aggregation process. We also incorporated batch normalization into the network architecture to reduce data discrepancies among clients. The denoising process was evaluated using metrics like mean-square-error (MSE), signal-to-noise ratio (SNR), and peak signal-to-noise ratio (PSNR).

A comparison between conventional methods and FL demonstrated that FL exhibited a reduced error rate, especially when dealing with larger datasets. Furthermore, FL harnessed the power of parallel computing, resulting in a notable 30% increase in processing speed, enhanced resource utilization, and a remarkable 99% reduction in communication costs. To sum it up, this study underscores the potential of FL in the context of seismic denoising, safeguarding data privacy, and enhancing overall performance. We addressed the associated challenges by experimenting with various approaches for client selection and aggregation within a privacy-preserving framework. Notably, among these aggregation strategies, FedCyclic stands out as it offers faster convergence, achieving performance levels comparable to FedAvg and FedProx with fewer training iterations.
Wellbore and Caprock Integrity During CO2 Injection in Saline Aquifer
Authors: Han Y. , Liu H. H. , Alruwaili K. , Altammar M. J.
Published: February 2024

Deep geological formations, such as saline aquifers, unmineable coal seams, and depleted hydrocarbon reservoirs, offer a great potential for large-scale underground storage of carbon dioxide (CO2). Well injectivity, formation storage capacity, wellbore integrity and caprock integrity are among critical topics in CO2 underground storage. This work focuses on constraints imposed by the wellbore stability and caprock integrity on the wellbore injectivity. The buildup of bottom hole pressure, the evolution of CO2 plume, and the distribution and evolution of pore pressure in the geological formation are predicted using semi-analytical solutions. The disintegration risk of wellbore is assessed with updated bottom hole pressures at various injection times. The caprock integrity is evaluated by applying the evolving vertical total stress in the saline aquifer in contact with the caprock at the bottom of caprock layer to assess the risk of fracturing in caprock.
Application of Autonomous Real-Time Digital Twin for Structural Health Monitoring and Integrity Assessment of Damaged Fixed Offshore Structures
Authors: Shahir M. L. , Shawn E. L. , Wong B. S. , Ann L. L. , Ellis W. S. K. , Belden C. C. Y. , Michelle H. C. W. , Mekan S. N. , Anas K. A. A. , Sarah B. S. , Ickx K. B.
Published: February 2024

The objective of this study was to deploy an autonomous real-time Digital Twin (DT) Structural Health Monitoring (SHM) system on offshore platform to enable continuous real-time monitoring and automated evaluation of the structural integrity based on the offshore feeding data of a 4-legged fixed substructure which has experienced vessel collision earlier. The collaboration between asset owners, asset operators, and academic researchers aimed to develop an advanced DT SHM system for this purpose.

The SHM system implemented a comprehensive framework that integrated software and hardware components with Internet of Things (IoT) capabilities. The hardware facilitated the collection of raw data, while a proprietary physics engine was developed to enable autonomous structural analysis for calibration and subsequent integrity assessment to identify the most probable source of structural anomalies. Real-time data acquired online were used to derive useful structural engineering parameters, forming a digital twin that emulated the actual offshore condition of the structure.

The deployment of the autonomous SHM system provided asset operators with valuable insights into the structural performance of the substructure in real-time. This enabled fast decision-making aiming to improve the efficiency of engineering manhours as well as optimisation of inspection and maintenance practices. The system outperformed conventional methods by timely quantifying the influence of assessed damages on the global substructural integrity, allowing for more accurate benchmarking and up-to-date information.

This case study emphasizes the significance of adopting autonomous Digital Twin SHM systems for offshore structures, particularly when compared to manual assessments. The implementation of the autonomous system reduces both time and effort while providing reliable benchmarking and up-to-date information on the structural integrity of the monitored structure. This highlights the importance of utilizing advanced SHM technologies to optimise the inspection and maintenance practices of offshore structures.

The objective of this paper is to present the framework for a Digital Twin SHM system that is designed for real-time global structural monitoring.
Reservoir Quality Vertical Heterogeneity Characterization in Shale Oil Reservoir, a Case Study from Junggar Basin
Authors: Gan Ren Zhong , Fu Lian Ming , Fang Tao , Wang Wei , Cai Liang , Wu Jin Long , Zhao Xian Ran , Li Liu Zhong
Published: February 2024

Compared with the marine shale oil resource conditions in the United States, the lacustrine shale oil resource conditions in China are different and the lithology is complex. At present, PetroChina has successfully conducted shale oil horizontal well exploration in such strata as Fengcheng Formation in MaBei, Xinjiang, Kong2 member of Cangdong sag in Bohai Bay, and Qingshankou in Songliao basin has made some progress. However, the understanding and evaluation of "sweet spot" are not perfect, which results in some misleading information for current shale oil exploration, and it brings great challenges to test layer selection and horizontal well landing window selection. Vertical heterogeneity places additional obstacles for reservoir characterization. This paper introduces an integrated methodology for reservoir quality vertical heterogeneous characteristic identification and evaluation in shale oil reservoir by integrating advanced spectroscopy, 2D nuclear magnetic resonance (NMR), and borehole electric image data. Vertical heterogeneity for reservoir quality characteristics includes mineralogy and lithology, rock texture, total organic carbon (TOC), porosity and pore structure, and water saturation. Mineralogy and TOC difference was recognized by the advanced spectroscopy logging data. Rock texture was defined with an innovative edge detection method to identify the lamination status throughout the reservoir. T1-T2 based 2D NMR will solve for porosity, pore size distribution, and fluid identification. Case studies are presented from a shale oil reservoir in the Junggar Basin of Western China. Vertical variety inside the Fengcheng Formation is well defined based on several specs in this case study, including mineralogy and lithology, kerogen distribution, porosity and pore size distribution, and oil-water distribution; the reservoir producibility index was further calculated based on integrated analysis. From the vertical heterogeneity recognized from the above methodology, the sweet spot and horizontal well landing window was successfully recognized. In this paper, we discuss a novel combination of advanced logging methods in unconventional reservoirs, which can help the operators to analyze the reservoir quality vertical heterogeneous character of these reservoirs. The fine reservoir evaluation process helps to define the best oil zones, which will help ascertain the potential of the reservoir and boost the promising oil production. The integrated workflow illustrated in our case studies can be applied and extended to the exploration of other unconventional reservoirs in China.
Mechanical Properties of Cenozoic Organic-Rich Shale from North Sumatra and South Sumatra Basins, Indonesia
Authors: Lanin E. S. , Sone H. , Sapiie B. , Musu J. T. , Widarsono B. , Hatta M. , Nugraha A. , Gunawan B. K. , Nugroho D. A.
Published: February 2024

Indonesia is actively studying its shale resources’ potential to be developed. In contrast to other countries that have succeeded in developing their shale resources, Indonesian shale potentials are generally located at an active tectonic margin and are of younger ages (Cenozoic Era). This condition raises questions about the sustainability of its mechanical properties and development technique. Following our previous research, this paper presents the results of rock mechanical tests on shale from North Sumatra and South Sumatra Basins. The shale samples were prepared and tested by a rigorous multi-stage triaxial procedure. Eight (8) plugs representing the Baong and Belumai Formations of the North Sumatra Basin and eight (8) plugs representing the Talangakar and Gumai Formations of the South Sumatra Basin were prepared in vertical (V), horizontal (H), and 45° inclined (I) orientation relative to bedding. The test stages can be broadly categorized as the hydrostatic stage, triaxial stage, failure stage, and sliding-re-sliding stage. All the tests were conducted at a maximum confining pressure of 30 MPa to compare the results with results of our previous study and results from U.S. Shales. The tested shale plugs possess higher porosity than U.S. Shales for a given clay + organic matter (OM) content. Regarding rock strength, the analyzed plugs show a correlation with clay + OM content and inter-granular porosity. For the elastic properties, Young's modulus shows a decrease with clay+ OM contents, unlike the Poisson Ratio, which does not offer a clear trend. Meanwhile, creep compliance clearly shows the inverse trend of Young's modulus. The anisotropy of elastic properties is demonstrated by sample orientation, where the horizontal sample is the stiffest, the vertical sample is the softest, and the inclined sample is in between. Generally, the mechanical properties of the plug samples from Baong, Belumai, Talangakar, and Gumai Formations coming from two tertiary basins in western Indonesia show a relationship with clay+ OM content, in line with U.S. Shale data. However, regarding compressive strength and Young's modulus, the relatively younger western Indonesian samples show lower values than most. The novelty of this study is to report and analyze, for the first time, the anisotropy elastic properties of Indonesian shale samples by incorporating inclined-oriented samples in addition to the vertically and horizontally oriented samples. The results of this study also supported the mechanical maturity hypothesis from our previous research. Nevertheless, it needs to be tested further by analyzing samples from the eastern Indonesian basin, which generally has older source rocks (Mesozoic Era).