bluuebunny/crossref_metadata_2025 huggingface dataset:
Automated Drilling Data Quality Control Using Application of AI Technologies
Authors: Battocchio Francesco , Sreekantan Jaijith , Arnaout Arghad , Benaichouche Abed , Al Shamsi Juma Sulaiman , Awad Mohamad Abdul Salam , Alnuaimi Mohamed Ahmed , Peraza Luis Ramon Baptista
Published: December 2021

Drilling data quality is notoriously a challenge for any analytics application, due to complexity of the real-time data acquisition system which routinely generates: (i) Time related issues caused by irregular sampling, (ii) Channel related issues in terms of non-uniform names and units, missing or wrong values, and (iii) Depth related issues caused block position resets, and depth compensation (for floating rigs). On the other hand, artificial intelligence drilling applications typically require a consistent stream of high-quality data as an input for their algorithms, as well as for visualization. In this work we present an automated workflow enhanced by data driven techniques that resolves complex quality issues, harmonize sensor drilling data, and report the quality of the dataset to be used for advanced analytics.

The approach proposes an automated data quality workflow which formalizes the characteristics, requirements and constraints of sensor data within the context of drilling operations. The workflow leverages machine learning algorithms, statistics, signal processing and rule-based engines for detection of data quality issues including error values, outliers, bias, drifts, noise, and missing values. Further, once data quality issues are classified, they are scored and treated on a context specific basis in order to recover the maximum volume of data while avoiding information loss. This results into a data quality and preparation engine that organizes drilling data for further advanced analytics, and reports the quality of the dataset through key performance indicators.

This novel data processing workflow allowed to recover more than 90% of a drilling dataset made of 18 offshore wells, that otherwise could not be used for analytics. This was achieved by resolving specific issues including, resampling timeseries with gaps and different sampling rates, smart imputation of wrong/missing data while preserving consistency of dataset across all channels. Additional improvement would include recovering data values that felt outside a meaningful range because of sensor drifting or depth resets.

The present work automates the end-to-end workflow for data quality control of drilling sensor data leveraging advanced Artificial Intelligence (AI) algorithms. It allows to detect and classify patterns of wrong/missing data, and to recover them through a context driven approach that prevents information loss. As a result, the maximum amount of data is recovered for artificial intelligence drilling applications. The workflow also enables optimal time synchronization of different sensors streaming data at different frequencies, within discontinuous time intervals.
New Recommendations for Offshore Wellhead Platform Structural Design Due to Well Conductor Casings Failures: Outcome of a Study Based on Actual Findings
Authors: Varikkodan Abdul Gaffur , Sarkar Anjan , Mohammed Mohammed Eissa
Published: December 2021

Detailed study on structurally failed well conductors on offshore wellhead platforms lead us to believe that existing assumptions of conductors transfer only lateral loadings to wellhead platforms while entire well vertical loading will be carried by conductor itself; could be wrong. The well conductors could become ‘forced’ to carry a very large vertical loads incase the conductors are structurally failed; especially once exceeded its original design life. As such, some new considerations during the wellhead platform design, which need to be followed, are recommended here. These are to cater any catastrophic eventuality of conductor failures which will restrain further collapse of the conductors or to avoid any progressive collapse of the platform. The recommendations are from a study based on actual findings observed recently in the offshore field.

The connection between conductors and platforms are conventionally designed as guided based on the load transfer assumptions. That is the huge vertical loadings from internal conductor casings and associated items were not a concern for platform design structural engineers, traditionally, and as such the conductors were designed to be structurally connected to the wellhead platforms using vertical guides. Due to extended design service life of platforms, in many cases the design life went up to two times of their original design life, severe degradation of structural integrity of the conductors were observed in the field. Structural analysis and assessment were carried out on many old intact and failed conductors, in the offshore field, in order to assess its structural and loading behavior with respect to supporting wellhead platforms.

The study provided that the failed conductors were leaning / collapsing to the wellhead platform resulting in transferring a huge vertical loads which originally were designed to be carried by conductors alone. This huge transfer of vertical loads from conductor to the platform was unexpected and was not considered in platforms original design. Therefore, the platform should have sufficient structural strength to cater such extreme eventuality to avoid the risk of complete collapse. A risk assessment of a tilted / failed conductors indicated that the consequence of total failure of a conductor could be catastrophic in case the platform failed to resist the collapsing conductors. This paper presents the details of the study carried out on aged wellhead platforms, having failed long serving conductors, in Giant offshore field, Abu Dhabi, along with details of new recommendations to be followed while designing new wellhead platforms.

The paper also recommends the structural design consideration to be followed while designing wellhead platforms in-case a conductor repair is necessitated in future.
Pushing the Limits for Open Hole Zonal Isolation – Design and Qualification of Expandable Steel Packer
Authors: Md Noor Mohd Nazri , Batita Nabil , Gaby Mohamed , Riou Yoann , Roselier Samuel , Saltel Benjamin
Published: December 2021

Enhancing gas productivity is linked to multistage stimulation (MSS). Choosing a cemented over uncemented solution is driven by factors such as operational efficiency, drilling practices, and isolation techniques. Swellable and mechanical packers have been used widely. A new packer type, an expandable steel packer, has been qualified recently, the expandable steel packer combines the strengths of mechanical and swellable packers and will provide an option for openhole completions.

The 4.5-in. expandable steel packer design was optimized to meet most demanding applications with the following characteristics: reduced running outside diameter (OD) to 5.6 in., premium assembly technique by crimping, double sleeve pressure self-compensation, and use of nickel alloys for sour environment. After the design of the packer was completed, the 4.5-in. expandable steel packer was qualified according to the API Spec 19OH (API 2018) standard protocol at 15,000 psi with thermal variation between 320°F and 68°F. The packer was tested in a casing with inside diameter (ID) of 6.5 in.

The test casing had an ID of 6.5 in. whereas nominal hole size ranges from 5.875 in. to 6.125 in. It was chosen to simulate a washout and considering the calculated maximum expansion ratio for the steel to verify the 15,000-psi pressure rating capability. The test casing was built with a heat exchanger, high-pressure pump, and pressure and temperature sensors.

The packer was expanded inside the dummy well with all the measuring instruments in place. Expansion pressure signatures were observed as predicted. The analysis of the packer setting pressure curves showed expansion initiation and full casing ID contact. The liquid differential pressure test from each side of the packer proved the internal pressure compensation performed as expected. No leak was observed during the pressure steps of 15.000 psi held for 15 minutes while cycling the temperature from 320°F to 68°F and back to 320°F.

The expandable steel packer utilizes a unique double-sleeve system for self-pressure compensation during ball-drop stimulation operations. The packer expandable sleeve is protected during deployment by the end fittings. Expandable steel packers exhibit robustness during running in hole, enable setting on demand, have a high expansion ratio, require no de-rating vs. hole size, and have low sensitivity to thermal variations.
Optimizing Rotating Equipment Maintenance Through Machine Learning Algorithm
Authors: Beduschi Francesco , Turconi Fabio , De Gregorio Basso , Abbruzzese Francesca , Tiozzo Annagiulia , Amabili Matteo , Prospero Alberto
Published: December 2021

This work highlights the development and results of a Rotating equipment predictive maintenance tool that allows to monitor the status of rotating machines through a synthetic "health index" and early detection of anomalies. The data-driven proposed solution is of great help to maintenance engineers, who, alongside the existing methodologies, can apply an effective tool based on artificial intelligence for early prevention of failures.

Taking advantage of the high availability of remote sensors data, an anomaly detection machine learning model, which relies on Principal Component Analysis (PCA) and Kernel Density Estimation (KDE), has been built. This model is capable of estimating, in real time, the health status of the machine, by matching the sensors actual values with the reference ones based on the Normal Operating Conditions (NOC) periods, that have been previously identified. If an anomalous behavior is detected, the Fault Isolation step of the model allows to evaluate which are the most contributing sensors for the investigated anomaly. These outcomes, combined with a failure mode matrix, which links the sensors deviations with the possible malfunctions, allows to highlight the most likely failure modes to be associated to the investigated anomaly.

The developed predictive tool has been implemented on operating sites and it has demonstrated the capability to generate accurate warnings and detect anomalies to be processed by the maintenance engineers. These alerts may be aggregated into events in order to be monitored and analyzed by remote and on site specialists. The availability of alerts gives to the users the possibility to predict any deterioration of the machines or process fluctuations, that could lead to unplanned events with consequent mechanical breakdowns, production losses and flaring events. As a consequence, tailored operative adjustment to prevent critical events can be taken. Thanks to the tool, it is also possible to monitor over time the equipment behavior in order to provide suggestions for maintenance plans optimization and other useful statistics concerning the most recurrent failure.

The tool's innovative feature is the ability to utilize the giant amount of data and to reproduce complex field phenomena by means of artificial intelligence. The proposed tool represents an innovative predictive approach for rotating equipment maintenance optimization.
Optimizing CAPEX and OPEX for High CO2 and H2S Field by Using Mechanistic Corrosion Modelling Approach
Authors: Saleh Ahmad Fahdlam , Kamardin Muhammad Zaid , Safiin Shahrun Nizam , Ahmad Mohd Farizan
Published: December 2021

The gas contaminants especially CO2 and H2S from the well is a major threat to oil and gas production facilities and pipeline. Developing this type of reservoir cost enormous CAPEX and OPEX due the need for expensive materials or the need of continuous chemical injection. This paper outlines the opportunity of cost optimization for future field development and operational through mechanistic corrosion modelling approach. This method was embedded to an in-house corrosion prediction model that was first developed by collaboration with Ohio University in 2008 with capability to predict corrosion rate for partial pressure more than 20bar of CO2 and up to 1bar of H2S. The model validation was performed based on actual field production operated at 55°C and 22 bar of CO2 partial pressure followed the methodology as outlined in NACE paper C2012-0001449. Upon successful validation, the model has been deployed to assist an Operator of an offshore pipeline in Southeast Asia, operating at 97°C and 17 bar of CO2 partial pressure, to ascertain the risk due to CO2 corrosion and review the original pipeline design adequacy. Subsequently, the model has been utilized for an Operator of onshore facilities in Middle East to address specific issue encountered during the final stage of development for one of the wellpad in which the wells are expected to experience increase of H2S from 100ppm in original design to more than 1000ppm during actual production. This process changes raised a serious concern on the integrity of the materials as potential corrosion issue and the need for corrosion mitigation such as H2S Scavenger injection was not originally considered during early stage of engineering.

The corrosion rate from the model has been validated against the intelligent pigging (IP) data and proven to be able to predict corrosion rate with +20% accuracy and more than 99% confidence level for CO2 partial pressure up to 25 bar with the presence of H2S. Based on deployment and utilization of the model, the high confidence in the model ability to accurately predict the corrosion rate will lead to potential CAPEX and OPEX optimization for the field development and during operational stage.
The Role of Legacy Seismic in Enhancing the Image in the Current Seismic Data – Abu Dhabi: Case Study
Authors: Elasrag Ramy , Al Ghafri Thuraya , Al Katheer Faaeza , Al-Aufi Yousuf , Mihaljevic Ivica , Al Battashi Majid Mohammed , Trezzi Stefano , Vasilyev Pavel , Tham Michelle
Published: December 2021

Acquiring surface seismic data can be challenging in areas of intense human activities, due to presence of infrastructures (roads, houses, rigs), often leaving large gaps in the fold of coverage that can span over several kilometers. Modern interpolation algorithms can interpolate up to a certain extent, but quality of reconstructed seismic data diminishes as the acquisition gap increases. This is where vintage seismic acquisition can aid processing and imaging, especially if previous acquisition did not face the same surface obstacles. In this paper we will present how the legacy seismic survey has helped to fill in the data gaps of the new acquisition and produced improved seismic image.

The new acquisition survey is part of the Mega 3D onshore effort undertaken by ADNOC, characterized by dense shot and receiver spacing with focus on full azimuth and broadband. Due to surface infrastructures, data could not be completely acquired leaving sizable gap in the target area. However, a legacy seismic acquisition undertaken in 2014 had access to such gap zones, as infrastructures were not present at the time. Legacy seismic data has been previously processed and imaged, however simple post-imaging merge would not be adequate as two datasets were processed using different workflows and imaging was done using different velocity models. In order to synchronize the two datasets, we have processed them in parallel. Data matching and merging were done before regularization. It has been regularized to radial geometry using 5D Matching Pursuit with Fourier Interpolation (MPFI). This has provided 12 well sampled azimuth sectors that went through surface consistent processing, multiple attenuation, and residual noise attenuation. Near surface model was built using data-driven image-based static (DIBS) while reflection tomography was used to build the anisotropic velocity model. Imaging was done using Pre-Stack Kirchhoff Depth Migration.

Processing legacy survey from the beginning has helped to improve signal to noise ratio which assisted with data merging to not degrade the quality of the end image. Building one near surface model allowed both datasets to match well in time domain. Bringing datasets to the same level was an important condition before matching and merging. Amplitude and phase analysis have shown that both surveys are aligned quite well with minimal difference. Only the portion of the legacy survey that covers the gap was used in the regularization, allowing MPFI to reconstruct missing data. Regularized data went through surface multiple attenuation and further noise attenuation as preconditioning for migration. Final image that is created using both datasets has allowed target to be imaged better.
MSE Based Drilling Optimizer Project for Large National Drilling Contractor
Authors: Al Hamlawi Imad Tawfiq , Creegan Andrew , Baptista Luis Ramon , Azizuddin Khaja Mohammed
Published: December 2021

A large GCC National Drilling Contractor is planning to trial a new MSE (Mechanical Specific Energy) Drilling advisory system based in artificial intelligence (AI) on a conventional drilling rig. This system works by means of calculating the optimal auto driller input parameters to achieve higher drilling efficiency.

The objective of the MSE based Drilling Optimization system is to drive drilling efficiency by way of advising surface drilling parameters (WOB and RPM).

The system will be tuned to advise/automatically modify WOB and RPM for each specific run, section, or well. The parameters can be adjusted in one of the two following ways:

Advisory Mode: A recommended WOB and RPM value is sent to the driller, who then manually applies the setpoint change Control Mode: The setpoints are sent to the automatic driller for instant and automated application

The system shall enable reduction of NPT and rig days to drill wells by increasing efficiency with consequent cost reduction efficiency by utilizing advanced elements of Artificial Intelligence (AI).
New Approaches for Drilling Highly Depleted Reservoir in Deep Water Wells
Authors: Balbaa Ola Mohamed , Mohamed Hesham , Elkholy Sherif Mohamed , ElRashidy Mohamed , Munger Robert , Najwani Mohamed
Published: December 2021

While drilling highly depleted gas reservoirs with a very narrow drilling window, Common drilling methods like utilizing loss of circulation pills, wellbore strengthening materials and managed pressure drilling (MPD) are being used in several reservoirs, yet it cannot be successful or cost effective if applied in a traditional manner.

Innovative approaches to enable drilling wells in highly depleted reservoir in the Mediterranean deep water were adopted. The approaches incorporated design changes to the well and Bottom hole assembly (BHA), optimized drilling practices, and unconventional use of MPD while drilling and cementing production liner.

Well design change in comparison to offset wells to allow drilling the reservoir in one hole section. Several design changes were considered in the BHA and drilling fluids to prevent as well as mitigate losses and differential sticking risks. From the BHA viewpoint, one of the key successful prevention measures was maximizing the standoff to reduce the contact area with the formation, this was achieved through utilizing spiral heavy wall drill pipe (HWDP) instead of drill collars in addition to a modeled placement of stabilizers and roller reamers. While on the drilling fluid side, Calcium carbonate material was added to strengthen wellbore, prevent losses and avoid formation damage. Particle size up to 1000 micron and concentration up to 40ppb was used to strengthen the depleted sands dynamically while drilling. Furthermore, as mitigation to stuck pipe, Jar and accelerator placement was simulated to achieve optimum impulse and impact force while maintaining the Jar above potential sticking zone. Whereas to address the consequence of a stuck pipe event, disconnect subs were placed in BHA to allow for recovering the drill string efficiently.

MPD was first introduced in the Mediterranean in 2007 and continued to develop this well-known technique to mitigate various drilling challenges. For this well, MPD was one of the key enabling factors to safely drill, run and cement the production liner.

Surface back pressure MPD allowed using the lowest possible mud weight in the hole and maintaining downhole pressure constant in order to manage the narrow drilling window between the formation pressure and fracture pressure (less than 0.4 ppg). MPD was also applied for the first time for running and cementing the production liner to prevent losses and achieve good cement quality which is a key to successful well production.
Addressing the Limitations of Oil and Gas 4.0 Surrounding Distributed Fiber Optic Data Streams
Authors: Ramsay James , Noble Lilia , Lockyer Glynn , Alyan Mohand , Al Shmakhy Ahmed
Published: December 2021

This paper outlines how the problem of previously unmanageable data volumes produced by distributed fiber optic well monitoring systems is solved through the use of the latest sensing and analytics platform.

The platform significantly reduces fiber optic data volumes enabling data to be streamed, processed, stored and visualized; all in real-time. The platform was effectively utilized for real-time data processing and visualization of well injection profiles of fields in the Middle East.

The platform addresses the big data challenge associated with streaming distributed fiber optic data in three key areas: Edge processing reduces Distributed Fiber Optic (DFO) data rates by orders of magnitude so it can be streamed from the edge to the end user in real-time.Tiled data storage utilizes innovative data storage strategy to enable fast query responses whether visualizing years or just seconds of DFO data.Elastic infrastructure of processing and storage enables the platform to seamlessly scale and handle variable data rates.

Raw Distributed Acoustic Sensing (DAS) data can be generated at rates of 100 MBs per second and cannot feasibly be transferred over a standard internet connection. The sensing and analytics platform's algorithms extract features at the edge which reduce data rates by three orders of magnitude whilst still preserving all key information from the data.

Processed DFO data is aggregated and tiled in real-time at tens of different resolutions with respect to both time and fiber length. This enables sub-second query response times even when requesting DFO data across years of historical data.

All platform processing logic is designed to run asynchronously on serverless infrastructure. This enables the platform's infrastructure to rapidly scale up or down in response to variable data rates.

The result is a cloud-based visualization dashboard capable of displaying DFO data in near real-time across any time range and fiber length.

Use of this sensing and analytics platform allowed for seamless streaming of fiber optic data on the Middle East field for injection monitoring, allowing the operator to visualize injection profiles and optimize the injection program in real-time.

This sensing and analytics fiber management platform enables the user to highly successfully stream and visualize DFO data in real-time. It enables visibility into the subsurface for production and injection wells, enabling field-wide efficiencies and optimization.
Leak-Off Pressure Prediction with the Integration of Fully Coupled 3D DFN Modeling in Fractured Reservoir
Authors: Xie Dan , Zhou Wei , Cheng Sinan , Tian Gang , Zheng Sheng , Lian Liming , Xu Hanbing , Jiang Zhibin , Zhao Yiqing , Qu Liming , Qi Lisha , Yang Xiao
Published: December 2021

Leak-off pressure is a main factor to induce formation leak-off so that it can be utilized as a crucial parameter to analyze the causation of well leak-off accidents, and that in-depth investigation on leak-off pressure is of vital importance for secure drilling. By analyzing the characteristics of leak-off formation, this paper divides the leak-off into natural leak-off and fractured leak-off, and then defines the conception of minimal leak-off pressure. The leak-off mechanism of fractured formation is investigated. Investigation results show that the currently existent prediction method of fracture pressure is established on the foundations of non-filtration borehole wall assumption as well as the Terzaghi effective stress model. These foundations are not consistent with the practical features of thief formation, which would inevitably cause deviation of calculated results with actualization. Natural leak-off formation constitutes the majority of formation leak-off phenomena. Therefore, it is urgent to build up the leak-off pressure curve instead of fractured pressure curve and take precautions against natural leak-off. The technique of leak-off pressure prediction with fully-coupled 3D natural fracture modeling was applied in the fractured reservoir which located in the northwest of Junggar Basin, China. Case analyses have proved that this lost circulation pressure model is of sufficiency in scientific bases and pertinence. The prediction result derived from the model is relatively consistent with the actual situation and consequently provides a substantial basis for a rational design of the drilling fluid density as well as the leak resistance and sealing. Therefore it is suggested that the design of drilling engineering should take the lost circulation pressure into consideration.
Optimized CO2 Capture Solutions for Carbon Free Hydrogen Production with Development of New Demixing Solvent Technology DMX™
Authors: Salais Clément , Normand Laurent , Streicher Christian
Published: December 2021

CO2 capture & storage is foreseen as a necessity to limit global warming, as indicated by the recent reports from International Energy Agency. Major initiatives have to be initiated in a near future with concrete actions to get efficient results in limiting global warming. Based on its decades of experience in gas sweetening AXENS has developed an expertise in CO2 removal technologies. While conventional amine based processes can be used for some CO2 capture applications like for instance the treatment of process gas streams under pressure, other applications for low pressure gas streams like flue gases will require innovative advanced solutions.

AXENS has studied various options for the removal of CO2 in SMR based hydrogen schemes, including the treatment of the process gas or the treatment of the flue gases from the SMR furnace, evaluating the respective merits of those options. For the treatment of the flue gases a new technology developed by IFPEN and AXENS based on a second generation amine solvent is considered : DMX™

DMX™ process, is foreseen as a key contributor for the removal of CO2 from all kind of low pressure gas streams. This process allows drastic reduction of CO2 capture cost in comparison to more conventional solvent such as MEA and others available solvents. The specific features of this solvent allows significant reduction of the heat requirements for the regeneration of the solvent. It also allows regenerating the solvent directly under pressure up to 6 bara, reducing the costs for downstream CO2 compression

Preliminary techno-economic studies show significant advantage of DMX™ technology relatively to MEA : up to 30 % reduction in OPEX can be obtained for lower or similar CAPEX, depending on the condition.

This process has been developed at the lab scale and is now going to be demonstrated in an industrial pilot unit installed in ArcelorMittal's steel mill plant in Dunkirk (France). This demonstration benefits from the support of EU's H2020 programme, under 3D project.
Tight Jurassic Carbonate Reservoir Characterization and Fluid Typing Identification by Integrating Magnetic Resonance, Elemental Spectroscopy and Micro-Resistivity Image Data in Umm Ross Field, West Kuwait, Case Study
Authors: Mohamed Said Beshry , Ali Sherif , Fahmy Mahmoud Fawzy , Al-Saqran Fawaz
Published: December 2021

The Middle Marrat reservoir of Jurassic age is a tight carbonate reservoir with vertical and horizontal heterogeneous properties. The variation in lithology, vertical and horizontal facies distribution lead to complicated reservoir characterization which lead to unexpected production behavior between wells in the same reservoir.

Marrat reservoir characterization by conventional logging tools is a challenging task because of its low clay content and high-resistivity responses. The low clay content in Marrat reservoirs gives low gamma ray counts, which makes reservoir layer identification difficult. Additionally, high resistivity responses in the pay zones, coupled with the tight layering make production sweet spot identification challenging.

To overcome these challenges, integration of data from advanced logging tools like Sidewall Magnetic Resonance (SMR), Geochemical Spectroscopy Tool (GST) and Electrical Borehole Image (EBI) supplied a definitive reservoir characterization and fluid typing of this Tight Jurassic Carbonate (Marrat formation).

The Sidewall Magnetic resonance (SMR) tool multi wait time enabled T2 polarization to differentiate between moveable water and hydrocarbons. After acquisition, the standard deliverables were porosity, the effective porosity ratio, and the permeability index to evaluate the rock qualities. Porosity was divided into clay-bound water (CBW), bulk-volume irreducible (BVI) and bulk-volume moveable (BVM). Rock quality was interpreted and classified based on effective porosity and permeability index ratios. The ratio where a steeper gradient was interpreted as high flow zones, a gentle gradient as low flow zones, and a flat gradient was considered as tight baffle zones.

SMR logging proved to be essential for the proper reservoir characterization and to support critical decisions on well completion design. Fundamental rock quality and permeability profile were supplied by SMR. Oil saturation was identified by applying 2D-NMR methods, T1/T2 vs. T2 and Diffusion vs. T2 maps in a challenging oil-based mud environment.

The Electrical Borehole imaging (EBI) was used to identify fracture types and establish fracture density. Additionally, the impact of fractures to enhance porosity and permeability was possible.

The Geochemical Spectroscopy Tool (GST) for the precise determination of formation chemistry, mineralogy, and lithology, as well as the identification of total organic carbon (TOC).

The integration of the EBI, GST and SMR datasets provided sweet spots identification and perforation interval selection candidates, which the producer used to bring wells onto production.
First Successful Run of 17.5 Inch Hybrid Bit in ADNOC Onshore to Drill Deviated Section
Authors: Khan Asif M. , Chiodini Frederic , Shamsi Juma Al , Bashir Munir , Mohammed Aseel , Mounir Hesham , Adams Adeniyi
Published: December 2021

In the onshore drilling operation the main objective is always finding ways to optimize cost and improve the efficiency of drilling operations. Among the various available option, one possibility was to drill 17.5" deviated section in one run through the interbedded formation, which cause high vibrations and risk of twist-off. This section previously was drilled with minimum 2-3 bit runs for a heavy casing design. This would definitely reduce the well duration and cost. The plan involved to drill 17.5" deviated section using rotary steerable system using hybrid bit technology.

Recent advances in drilling bit design has proved to be very effective in drilling surface hole sections but are limited to drill vertical holes and require multiple runs to complete a section. Special design and cutting structure is required when it comes to drill deviated hole. One supplier has combined the traditional design and come up with hybrid bit structure to achieve this goal of drilling surface deviated hole in one run.

This special hybrid bit, drilled successfully 17.5" deviated section in one run with enhanced ROP by 40% compared to previous wells. This saved additional trips to change bit and avoided any stuck pipe and twist off. This kind of strategy has helped to maximize average ROP of 64 ft/hr for the entire section. The main element in optimizing the performance of is the systematic approach towards the bit selection, hydraulics and mud parameters. Outcome of this optimization resulted in case history data which shows that this kind of hybrid bit technology can be used to drill deviated wellbore with better penetration rates, lesser washouts and longer on-bottom time.

This technical paper describes the results of first well drilled by a service provider using hybrid bit technology with rotary steerable system in one run. This has resulted in increasing the rate of penetration for the 17.5" deviated top hole section. Applying this kind of hybrid bit technology has not only enhanced the ROP but also helped to save rig days and cost.
ADNOC's Smart Liner Initiative – A Step-Change in Matrix-Acid Stimulation Efficiency
Authors: Mogensen Kristian , Edmonstone Graham
Published: December 2021

ADNOC is progressing with large-scale rig-less high-rate matrix stimulation by deployment of advanced lower completions. A key contribution to future production growth is expected to come from these "Smart Liners" that rely on the principles of the limited-entry technique. The concept is based on a number of small, pre-drilled and unevenly spaced holes which enable an even distribution of acid along the entire reservoir drain to be stimulated. The smart liner incorporates swellable packers to avoid annular flow of acid to preferential zones and to isolate segments with heterogeneities.

In this work, we focus on aspects related to planning, design and execution of high-rate matrix-acid stimulation of wells. We demonstrate that short wells need a different design approach compared to extended-reach wells and we provide guidelines on how to achieve the highest achievable pump rate and desired acid volume subject to reservoir, well and equipment constraints.

The carbonate reservoirs typically exhibit considerable variation in permeability along the well, hence techniques for production profiling, such as inline tracers, are valuable for assessing the actual stimulation effectiveness. Wormhole penetration for a particular acid system will vary depending on the rock petrophysical properties and the reservoir properties; therefore, a systematic data analytics project is on-going.
Successful Case of Resin-Based Chemical Sand Consolidation as a Remedial Sand Control Treatment
Authors: Mahardhini Antus , Yudis Putu , Abidiy Izzad , Bawono Yolani , Pradityo Rico
Published: December 2021

The Mahakam delta in east Kalimantan, Indonesia, yields gas as the main hydrocarbon production with giant reservoirs ranging from shallow to very deep zones. Reservoirs consists of clean sandstone with high permeability. Due to the field maturity, production gradually moved from the deep, consolidated zones into very shallow, unconsolidated zones.

Sand production often causes significant problems at the surface when the well is online. The best approach to sand control is to keep it inside the reservoir, because it could create problems not only at surface but within the wellbore as well.

Sand consolidation has been a common approach applied in Mahakam field for more than a decade. Several products have been utilized, including laboratory testing and field trials.

The case history is based on a well that had been treated using 2 different sand consolidation products in the past, but both eventually produced inadequate results. Sand continued to break through after each treatment, hence the reserves could not be drained in full. Since the reservoir still had promising reserves, another remedial sand consolidation treatment was planned. This treatment was executed by utilizing a tension packer with a J-slot mechanism in order to focus injection of the resin into the zone of interest. Additionally, there was a challenge with another open zone above the subject interval. The remedial sand consolidation treatment using a resin-based chemical delivered excellent results. Even though this reservoir had been exposed to 2 different chemical treatments in the past, by using the resin-based sand consolidation product, the well was still able to be produced at target rates without sand production. In conclusion, resin-based sand consolidation solutions can unlock prolific reserves that may have been a significant challenge with traditional methods.
Fracture Height Prediction Model Utilizing Openhole Logs, Mechanical Models, and Temperature Cooldown Analysis with Machine Learning Algorithms
Authors: Khan Abdul Muqtadir , BinZiad Abdullah , Subaii Abdullah Al , Bannikov Denis , Ponomarev Maksim , Parkhonyuk Sergey
Published: December 2021

Vertical wells require diagnostic techniques after minifrac pumping to interpret fracture height growth. This interpretation provides vital input to hydraulic fracturing redesign workflows. The temperature log is the most widely used technique to determine fracture height through cooldown analysis. A data science approach is proposed to leverage available measurements, automate the interpretation process, and enhance operational efficiency while keeping confidence in the fracturing design.

Data from 55 wells were ingested to establish proof of concept.The selected geomechanical rock texture parameters were based on the fracturing theory of net-pressure-controlled height growth. Interpreted fracture height from input temperature cooldown analysis was merged with the structured dataset. The dataset was constructed at a high vertical depth of resolution of 0.5 to 1 ft. Openhole log data such as gamma-ray and bulk density helped to characterize the rock type, and calculated mechanical properties from acoustic logs such as in-situ stress and Young's modulus characterize the fracture geometry development. Moreover, injection rate, volume, and net pressure during the calibration treatment affect the fracture height growth.

A machine learning (ML) workflow was applied to multiple openhole log parameters, which were integrated with minifrac calibration parameters along with the varying depth of the reservoir. The 55 wells datasets with a cumulative 120,000 rows were divided into training and testing with a ratio of 80:20. A comparative algorithm study was conducted on the test set with nine algorithms, and CatBoost showed the best results with an RMSE of 4.13 followed by Random Forest with 4.25. CatBoost models utilize both categorical and numerical data. Stress, gamma-ray, and bulk density parameters affected the fracture height analyzed from the post-fracturing temperature logs. Following successful implementation in the pilot phase, the model can be extended to horizontal wells to validate predictions from commercial simulators where stress calculations were unreliable or where stress did not entirely reflect changes in rock type.

By coupling the geometry measurement technology with data analysis, a useful automated model was successfully developed to enhance operational efficiency without compromising any part of the workflow. The advanced algorithm can be used in any field where precise fracture placement of a hydraulic fracture contributes directly to production potential. Also, the model can play a critical role in cube development to optimize lateral landing and lateral density for exploration fields.
Holistic Customized Approach to Address Practical Challenges for the Large Scale Implementation of Limited Entry Liners Completions at ADNOC Onshore Fields
Authors: Talib Noor Nazri , Ramarao Subba Venkata , McNeily Kevin , Barragan Ernesto , Maheshwari Yugal , Ahmad Bilal , Abdelhalim Mohamed Emam , Abdelrahim Samy Mohamed , Punnapala Sameer , Al Nuimi Saber Mubarak , Al Taee Arif Saeed
Published: December 2021

Limited entry liners (LEL) implementation strategy is one of the key solutions to to improve the well productivity by maximizing the reservoir contact and matrix stimulation carbonate reservoirs. This strategy requires conducting high rate and high volume acid stimulation with high pressure pump after the installation of limted entry liner, that poses practical concerns to be addressed for adopting conventional well completions and existing resources. In addition, implementation of the LEL completion and stimulation for a large scale application within the minimum time frame and limited resources is a challenge.

This paper provides the detail of challenges faced and solutions adopted to implement the LEL completions amd stimulation at onshore fields. Challenges including suitable candidate selection, completion design, limited materials for well construction to handle high-volume acid stimulation, limited well head injection pressure, contractual limitations for securing the tools and pumping equipment. Further, this paper discusses about the temporary solutions adopted for executing the LEL implementation in the best economical way within near future and provide the long term solutions for LEL implementation in the next 5 years business.

The first three LEL completion wells that were successfully installed and stimulated at ADNOC Onshore are currently producing at more than 2 times higher PI (productivity index) compared to the pre-stimulation rate. The same apply to the injector wells, in which significant improvement on the injection rate of up to 18bbl/min (26000 bwpd) was observed. Currently ADNOC Onshore is planning to execute the LEL completion and stimulation in additional 15 wells during 2021 along with plan for up to 300 LEL completions during the next 5 years. The LEL technology is a key technology to support ADNOC lower completion strategy which aim to minimize the bare foot completions in order to increase the horizontal wellbore accessibility and effective stimulation. Overall, the first LEL installation and stimulation completed within 8 months from the candidate finalization using the existing resources available in ADNOC Onshore.

This paper describes an economical solution for implementation of LEL completion strategy at large scale for major fields within minimum time frame by utilizing the existing resources while adhering to HSE rules.
Agile Smart Completion Application for Effective Water Production Control in Heterogeneous Carbonate Reservoir in Abu Dhabi Offshore Reservoir
Authors: Abdelkerim Ali Issa , Bellah Samir , Ziad Ahmed , Yamamoto Kei
Published: December 2021

This paper provides the learnings from a successful application of a smart completion in a complex heterogeneous carbonate reservoir. It details the study, planning, coordination, and implementation process of two pilot wells by a multidisciplinary team, and pilot production performance results, illustrating the success.

First, to select an optimum completion design for the field, multi-segment well option and local grid refinement option were applied to the reservoir simulation model including calibration of faults/fractures. Second, based on the modified model, sensitivity analysis was conducted; 1) by selecting different types of completion including Open-hole, blank pipes (BP), compartmentalized slotted liners (SL), inflow control device (ICD) and hydraulic flow control valve (FCV); 2) by optimizing the number of compartments (packer and blank pipe placements for all cases), and ICD / FCV numbers and nozzle sizes. Using the data from the modeled cases, economic analysis was conducted, which indicated that the ICD in conjunction with sliding sleeves (SSD) was the best option.

Two candidate wells were selected to cover the variation of reservoir characteristics: one well representing the heterogeneous part of the reservoir with high-density of faults, fractures and kurst, and another one representing the relatively homogenous part of the reservoir suffering from heel to toe effect. A multidisciplinary implementation team was set up to align all stakeholders on subsurface requirements, following up the completion design, coordinating material procurement and logistics for mobilizations, daily drilling operations follow-up, real-time logging data interpretations and completion design adjustment.

Evaluation of the two pilots’ results based on predefined KPIs during the study, exceeded overall expectations.
Firefighting Drones - A Safer & Efficient Technology to Confront Industrial Fires
Authors: Almughani-Alnaqbi Mohamed Abdalla
Published: December 2021

Objectives/Scope

This paper presents the variety of possibilities that this new technology can offer and how we can apply those technologies to optimize our HSE and take preventive measures that will be economically and humane solutions to crises. New technology, including Artificial Intelligence & Robots, does not necessarily mean it will replace human jobs and human judgment but will be used as tools to minimize hazards in critical situations and helps to solve the problems in a faster and efficient way.

Methods, Procedures, Process

The recommended technology to fight fire in hazardous zones can be described as a “firefighting drone.” This drone can be considered a faster and safer approach for fire suppression that can respond to any fire alarms and fly in narrow places inside the live plant, crude oil storage tanks, and navigate quickly to exact fire location without any fear of crashing it to anything and eliminates the risk of reaching high rise buildings where it is not secured and has low visibility.

One such method is a firefighting drone that carries fire extinguisher balls, where it mainly consists of dry powders that contain melamine phosphate as an extinguishing component. This extinguishing ball works as a fire auto hydrant that is attached to the drone.

This mechanism helps the drone carry the fire extinguisher balls to any place and throw the ball into the fire to suppress it. The main advantage of such fire extinguisher balls is its lightweight comparing to water, and it is environmentally safe and harmless to the human body if used in hazardous zones such as oil and gas plants.

Results, Observations, and Conclusions

Studies show that fire extinguisher balls have high extinguishing effectiveness and serve a wide range of applications. Results show that around 0.5 kg ball size has the ability to extinguish a 1-meter radius.

This paper explains how easy its to build such a drone. However, due to the nature of this application using thermal resistance material is a must, and utilizing Artificial Intelligence will enhance the drone capabilities & will help to improve firefighting methodology. This type of drone is designed to be used in very high-temperature conditions and can be controlled safely from a ground station manually where you can see the fire location and assess the situation without the need to be there and wait for the fire team's presence.

Novel/Additive Information

With the use of the new lightweight fire extinguish ball, we can enhance the typical current firefighting method for small and medium-scale fire, where it puts out the fire faster & help us prevent it from growing to a more significant fire.

The ultimate goal of this drone is to save the life of firefighters, plants, and equipment. Since the oil and gas industry is of high importance in the UAE, using proper and enhanced HSE measures will maintain our assets and avoid crises that will have a massive impact on business continuity.