bluuebunny/crossref_metadata_2025 huggingface dataset:
Longest Extended Reach Drilling Well Drilled in Middle East Geosteered Within 5 Ft Stratigraphic Thickness Target Zone
Authors: Abbas Nashat , Al Nokhatha Jamal , Haider Syed , Radwan Khaled , Al Hashmi Mustafa , Al Nayadi Khaloud , Alqaydi Nouf , Fares Wael , Aki Ahmet , M.K. Abdou Eslam
Published: October 2022

In order to develop a giant mature carbonate field offshore Abu Dhabi, four environmental Islands were built in shallow water. Due to the large areal extension of the field, most wells are Extended Reach. This paper presents a case study of the longest well drilled in the UAE. Planning to drill such an Extended Reach well with maximum reservoir contact, starts long before execution. Not only, competent rigs, capable of delivering enough mechanical and hydraulic energy to drill such well, but also placing and navigating the lateral section in multilayered anticlinal reservoir with layer cake geometry. Significant geologic uncertainties of complicated carbonate facies heterogeneities is a major challenge. Detailed study of the reservoir behavior according to pre-existing nearby wells was carried out, as well as understanding the geologic structural setting of the area since the target zone consists of 5ft thick limestone layer that overlays a 3 ft. thick dolomitic limestone with excellent permeability. The crucial success factors were; firstly, to steer in such a thin reservoir for long distances, using LWD tools to differentiate dolomite from the nearby limestone layer. Secondly, to account for possible lateral facies change, the sensors needed to be as close as possible to the bit. Considering +28600 ft. horizontal section, remarkable challenges arose related to drilling tool capability and well path smoothness. The drilling team was concerned about using nuclear source density tools to navigate the well path and needed to avoid high dogleg to prevent any fishing jobs associated with source tools, especially in fractured areas. The well was drilled to record depth of more than 45300 ft. with a horizontal section of 27,500 ft. inside reservoir. Utilizing Rotary Steerable System in all hole sections helped to minimize hole tortuosity along the well and with the help of LWD tools the well was accurately steered within target zone boundaries. Utilizing advance mud telemetry made it possible to receive data from 45,300 ft. away from surface. Successful well placement was the main factor to achieve positive overall performance in the field. This success has opened the door to drill more wells that are more challenging. In addition, it practically proved that proper planning and execution can push the limits further and gave confidence to drill even deeper. As a result, we are now aiming to drill deeper wells up to 50,000 ft.
Horizontal Well Calibration Using Zone Log Matching and Machine Learning
Authors: Hasan Hesham , Parra Humberto , Gerami Arshia , Singh Manish Kumar , El Jundi Obeida , Stojic Slobodan , Jeddou Houcine Ben , Gacem Tarik , Kloucha Chakib Kada , Mustapha Hussein
Published: October 2022

Placing horizontal wells in the correct zones of the producing reservoir in static/dynamic models is important for robust model quality and essential for production history matching. A laborious technique of manually generating correction points around each un-calibrated well is often used by geomodelers. This technique is not systematic and is highly interpretive. We present an automated global solution that leverages not only the well tops, but also the well trajectory information to calibrate the horizontal wells.

The solution comprises a series of processes that can all be run through a custom built graphical user interface (GUI). The processes are designed to a) detect the calibration problems with the ability to visualize them, b) correct each surface separately for zone mismatch and c) retrieve original zone thickness whenever possible. Treating each surface separately simplifies the problem and causes great reduction in run time compared to simultaneous correction of all surfaces in one go. However, the final results are essentially global, which is insured by maintaining the input zone thicknesses (except if well data confirms otherwise).

The correction is achieved by ensuring that model zones (between the input surfaces) match the "optimum zone logs" at all wells in the model. The term optimum, in this context, means that the zone log should only contain the zones to be modeled, no more no less. These optimum zone logs are typically calculated from the well tops, which implies having an impeccable set of well tops.

In most cases, well tops sets may contain extra tops (that are not included in the model) and missing tops at some of the wells. While the latter problem is more difficult to solve, both problems must be detected and corrected for a successful run of this solution. Fortunately, the "diagnosis" step at the beginning of this solution detects all these problems, which reduces the time needed to review the well correlation, especially in fields with hundreds of wells. Moreover, machine learning techniques are used to suggest the position of the missing well tops. The user gets to either approve the suggestion or change it manually.

The solution we are presenting is fully automatic and fully reproducible. It is given with four parameters to control the amount and influence of the correction applied to the horizon intersecting the trajectory when it is not supposed to. If optimum zone logs are ready, the solution can run in few minutes to correct large models with hundreds of wells and tens of surfaces. This has the potential of reducing months of work to few days to calibrate horizontal wells in a structural model. The few days may include optimization of the solution parameters to achieve the desired results.
Internal Deformation of Layered Evaporites, Gotnia Formation, North Kuwait: Insights from Seismic Characterization and Sandbox Experiments
Authors: Pichot Thibaud , Doublet Stefan , Rao Narhari , Odreman Allan , Kidambi Vijaya , Al Rashedi Hamad , Al Mutairi Talal , Bansal Parshant , Ahmad Munir , Schueller Sylvie , Mengus Jean-Marie , Richard Pascal
Published: October 2022

The Late Jurassic Gotnia evaporites of Sabriyah (SA) and Raudhatain (RA) fields, North Kuwait, provide an example of Layered Evaporite Sequences (LESs) in which well-preserved internal geometries resulting from a complex polyphased tectonic deformation can be investigated. The Gotnia LESs represent a unique opportunity to study the mechanisms of internal deformation of rheologically contrasted layers of anhydrite (strong) and halite (weak) matrix present in the km-scale SA-RA structures.

Combining seismic data characterization and sandbox experiment approaches, we describe in detail the spatial variations of deformation and place them in a sequential evolution of regional and local stress regimes. Seismic mapping was focused on the thickest anhydrite layer of the Gotnia LESs (i.e., 1st anhydrite). As anhydrite has a strong lithological and acoustic impedance contrast with respect to halite, seismic mapping was carried out on an impedance cube and a derived seismic attribute (salt probability index), thus increasing the confidence level of the map. A series of sandbox experiments focused on the SA structure was carried out. The experiments were coupled to X-Ray CT scanner to enable 3D geometries to be reconstruct at different deformation stages

Three types of internal structures delineating structural domains were identified on seismic: boudins and imbricated thrusts were observed above major reactivated faults (SA and RA), while isolated thrusts were restricted to the terrasse between SA and RA. Seismic imagery clearly illustrated the structures at present day, but it did not account for the genesis of boudins, imbricated stringers and isolated thrusts, nor their spatial distribution, as well as the potential link existing between them. Sandbox experiments provided critical insights into the way internal geometries deformed through the successive tectonic phases. Sandbox experiments demonstrated the sequential evolution of internal geometries of competent sand layer (anhydrite layer equivalent): the phase of transtension triggered the dislocation of the stringer encased in the silicone. However, the development of boudins was restricted to the footwall block. During the subsequent transpressional phase, thrust imbricates developed where sand stringers were previously ruptured.

It is suggested that internal geometries driven by salt tectonic processes, may have played a significant role in the actual layering of the LESs and could contribute to observed changes in thickness and compartmentalization of intra-Gotnia reservoirs. This result could bring new insights into reservoir facies layering and pore pressure distribution in LESs.
Maximizing the Value of NMR Logging while Drilling, a Combination of Laboratory Measurements and Well Log Data concept.
Authors: Serry Amr Mohamed , Yousif Sharifa Yousif , Budebes Sultan Ahmed , Zakaria Hasan Mohamed , Efara Mohamed Saher
Published: October 2022

The application of segmented, smart completion strings is expanding to enhance the hydrocarbons production along extended horizontal drains that are drilled across heterogeneous carbonate reservoir units, Offshore Abu Dhabi. Conclusive formation evaluation answers are required to support the well completion design. Nuclear Magnetic Resonance well logging while drilling "NMR-WD" supports the operations efficiency, HSE and adds a wealth of input to the completion design in a time-efficient process. A quantitative matrix independent porosity and permeability are required. In this case, we present the value of laboratory NMR measurements to maximize the value of the log interpretation process, adding a conclusive picture of the pore size distribution and reservoir quality as critical inputs.

Representative core plug samples of the different major rock types have been selected along the Upper Jurassic Carbonate sequence, Offshore Abu Dhabi. The plugs have undergone Soxhlet cleaning, and routine core analysis measurements before Mercury injection capillary pressure measurements were carried out on plug trims too. Saturation of the plugs was conducted using synthetic formation brine and desaturation has been conducted over porous plate. A complete scanning of the pore size and pore throat distributions was made available and the transverse relaxation time T2 cutoff for the irreducible fluid was identified, then applied to the NMR-WD dataset.

The laboratory measurements could be used to reprocess the log data, bridge the gap between the Coates permeability computation and the offset core values based on the measured benchmark T2 cutoff values. The integration between the porous plate, MICP and NMR laboratory measurements is utilized to qualify the NMR-WD as a vital tool for the future similar formation evaluation operations across the same target reservoir.

NMR-WD log data interpretation is enforced with a representative pore size distribution. The quantitative matrix properties representation improves the well completion design.
Deep Learning Based Seismic Elastic Properties Inversion Guided by Rock Physics
Authors: Ahmad Fuad M Izzuljad , Jaya Makky Sandra , Abdrahman Sharif , Lew Chean Lin , Law May
Published: October 2022

Submitted Abstract

The aim in characterizing reservoir on seismic is to be able to precisely assess rock and fluid properties from seismic data. Despite several approaches available, geoscientists still facing issue to accurately characterize the elastic & reservoir properties from seismic. This mainly because of the implementation of simplified linearized algorithms and assumptions which unable to fully address problem with non-linearity and non-uniqueness solution. Besides, the conventional approaches also typically take a very long turnaround time due to extensive computational works. Hence, implementation of deep learning-based seismic inversion with incorporation of a generalized rock physics knowledge for elastic properties prediction perhaps might be able to address the issues. The proposed approach consists of 4 main phases. The first phase is to develop rock physics understanding based on in-situ available reference well data. In the next phase, realistic synthetic dataset library at various pseudo well location is generated that mimic the actual subsurface reservoir condition and the corresponding seismic data from those pseudos well library is subsequently simulated. The third phase is to implement U-net deep learning network architecture with residual blocks of ResNet-18 for training, validation, and testing, utilizing synthetic data library generated in the previous phase. The fourth phase is to apply the pre-trained predictive network model on the actual seismic dataset as input for rock properties estimation. The robustness of the proposed approach is first evaluated based on synthetic dataset. Exceptionally good coefficient cross-correlation is obtained after evaluation on the predicted and true elastic properties; while results on the blind test dataset are slightly less compared to the training performance. This shows that the implemented model architecture with specially designed residual blocks can generalize quite well. The network model able to qualitatively distinguish the properties variation and capture the background trend of each elastic property. Besides, the proof-of-concept exercise also is successfully verified on a fluvial dominated field in Malay basin. Qualitatively, the predictive network model able to capture the background trend with some minor overfitting and identify the relative deviation of the elastic properties. The promising results are also comparable with results produced from commercial software, yet with faster turn-around time and more efficient workflow. In this work, a new approach of deep learning-based seismic inversion is introduced for elastic properties prediction which incorporates a generalized rock physics knowledge and a complex deep learning networks architecture of U-Net with residual block ResNet-18.
Study on the Influence of Natural Fracture Modeling on Hydraulic Fracture Propagation for Horizontal Wells in Unconventional Resource - A Case Study from China
Authors: Li Jie , Xu Hanbing , Xiong Qiyong , Yi Yonggang , Zhou Wei , Zhang Liwei , Chen Shengen , Lian Liming , Zeng Meiting , Yang Xiao , Huang Xingning
Published: October 2022

Low-permeability oil reservoirs generally have the low production, production rapid productivity decline, and low-ultimate recovery. Staged fracturing is usually conducted for horizontal wells. Hydraulic fracturing technology is generally used to improve fracture conductivity and well productivity, which is one of the key technologies for Enhance Oil Recovery (EOR). How to accurately characterize and simulate the distribution characteristics of hydraulic fracture network in 3D space is particularly important. The stress interference between hydraulic fractures as the objective mechanical behavior in the process of staged fracturing affects the geometry fracture network and the productivity of the reservoir post-fracturing. The hydraulic fractures simulation in natural fractured reservoirs is complex shapes, mainly because natural fractures affect the propagation path of hydraulic fractures. The theoretical model used to describe the hydraulic fracturing in homogeneous reservoirs cannot accurately show the complexity of the spatial morphology of hydraulic fractures in naturally fractured formations. CNCP (the operator) urgently need a mechanical model that can show the stress interference behavior between multiple fractures and the direction of hydraulic fracture propagation, and be used to simulate the spatial form of multiple hydraulic fractures in staged fracturing of horizontal wells and their propagation behavior in naturally fractured formations. Aiming at the impact of natural fractures in the reservoir on the propagation path of hydraulic fractures, this paper established a mechanical model for distinguishing interference behavior of natural fractures and hydraulic fractures. And analyzed the stress field at the tip of the hydraulic fracture and the stress field acting on the natural fracture surface based on the theories related to rock mechanics and fracture mechanics. On the basis of coupling the 3D geomechanical model and the 3D Discrete Fracture Network (DFN) model, this paper established the discriminant model for hydraulic fractures penetrating natural fractures in 3D space to conduct hydraulic fracture propagation simulation for the horizontal well. The research results can be used to optimize the hydraulic fracturing treatment design, and provide technical support for the effective production and profitable development of low-permeability reservoir resources.
Monitoring Injected Magnetic Nanoparticles Movement with Distributed Magnetic Sensor
Authors: Hafizal Mad Zahir Mohamad , Zainal Suzalina , Lin Lew Chean , Zhafri Kamarul Bahrim Ridhwan
Published: October 2022

The hydrocarbon business employs nanoparticles for a number of purposes, most notably to increase oil and gas output (Sircar et.al., 2022). Nanoparticles, nanosensors, nanocomposites, coated nanoparticles, nanofluids, and many other forms of nanomaterials find usage in the petroleum industry. While this technique has found widespread application, the development of a robust approach for monitoring nanoparticles’ behavior at depth is still in its infancy. For waterflood IOR initiatives, where it is used as proactive tracer technology: 1) to distinguish injected fluid from background (Commer et. al., 2020), 2) to understand injected-water direction in reservoir (Eltoum et.al., 2021), fluid flood front, and updating/improving dynamic model, the use of nanoparticles combined with geophysical data monitoring will be a useful risk-mitigation strategy (Huang et.al., 2021).
Application of Logging While Drilling - Nuclear Magnetic Resonance in Reservoir Evaluation and Geosteering: A Case Study in Marrat Reservoir, Umm Roos Field, West Kuwait
Authors: Nguyen Kim Long , Fahmy Mahmoud Fawzy , Dzhaykiev Bekdaulet , Odiase Paul Osadebamwen , Al-Morakhi Rasha , Al-Ajmi Mohammed Mubarak , Verma Naveen Kumar , Quttainah Riyad
Published: October 2022

The Jurassic Marrat reservoir in Umm Roos field of West Kuwait (WK) is a low-permeability carbonate reservoir with heterogeneous petrophysical character that limited the predictability of reservoir properties and highly deviated development wells are preferred to maximize the exposure of the reservoir. However, there is an environmental risk and high operational cost when running radioactive-based porosity logging tools in such complex well profiles. To avoid that risk, Nuclear Magnetic Resonance (NMR) with conventional resistivity and gamma ray in a logging while drilling (LWD) program is proposed to achieve real-time formation evaluation and efficiently support well placement to maximize the reservoir contact. This paper presents the application of LWD-NMR as an alternative solution to evaluate reservoir properties as well as to land the highly deviated well successfully in the best reservoir sweet spots to achieve the maximum outcome for production.
Best Practices and Lessons Learnt from a Comparative Study of LWD Formation Pressure Measurement in Static and Circulating Wellbore Conditions in ERD Wells
Authors: Javid Khalid , Sainz Alvaro , Bascialla Guido Carlos , Alkendi Mohamed Ali , Al Shehhi Hamad Rashed , Al Hammadi Amina , Meherbi Salama , Telang Viraj Nitin , Majid Mohammed Abdul
Published: October 2022

Pressure measurements in low permeability reservoirs are generally supercharged and cannot be used for mud weight optimization, selection and placement of in-flow control devices (ICD) in lower completion design and future reservoir management. The paper focusses on analyzing the effects of static and circulating wellbore conditions on the formation pressure data acquired using logging while drilling (LWD) tools in extended reach drilling (ERD) wells.

Supercharging is commonly observed in low permeability zones mainly due to poor quality mud-cakes having low thickness and high permeability. Thus, pressure measurements using LWD tools read erroneous values almost equivalent to the annular circulating pressure. To reduce the effective overbalance and emulate wellbore environment for wireline logging, pressure measurements were performed in static conditions using LWD tools powered by batteries instead of downhole turbines. This paper discusses formation pressure datasets acquired using LWD tools in eight wells and thereby recommends best practices from the lessons learnt through the pressure testing campaign.

By reducing the effective overbalance from circulation (ECD) to the static mud weight, the effect of supercharging on formation pressure measurements was reduced. However, in lower mobility ranges, less than 5mD/cP, the supercharging effects were prominent in static wellbore conditions as well. In such cases, using a sampling tool to pump out and relieve the supercharged pressure in the near-wellbore invaded zone is the best method to acquire accurate and reliable formation pressure data in such low mobility zones.

ERD wells require formation pressure measurements done using LWD tools to mitigate pipe sticking risks and acquire formation evaluation data in a single pass resulting in saving rig time. While deploying batteries to acquire accurate formation pressure data in static wellbore conditions in every operation is a robust solution, it should be weighed against the formation testing objectives, borehole stability and differential sticking risks to avoid further down time in resolving these issues.
Exploration History and the Application of New Technologies Contributes to the Discovery of New Reserves in a Marginal Field in a Mature Basin, Abu Dhabi
Authors: Yamanaka Motoyoshi , Al Shamsi Jawaher , Aitken John
Published: October 2022

In 2021 INPEX/JODCO, successfully produced oil, gas, and condensate through drill string tests (DSTs) from Well-L located in Onshore Block 4, Abu Dhabi (INPEX, 2021). Two major factors contributed to the discovery: (1) application of new technological advances to exploration; (2) analyzing and integrating past geological interpretations. Onshore Block 4 is near existing oil and gas production infrastructure, which raised expectations for early-stage development and reduced time to market for any potential discoveries. Given the successful exploration results, further analyses of data collected from the well logs, core, and produced hydrocarbons will support continued exploration activities and play de-risking. Historically, exploration in Abu Dhabi has focused on large closure present-day anticline trends. Over time, new oil and gas discoveries have become scarcer and the discovered volumes smaller. One strategy to open new plays and unlock larger possible reserves is focused on drilling low-relief structures.

Well A was drilled in 1956 in the Onshore Block 4 area. Following this 1st well, 6 wells were drilled up until the mid-1970's. These wells were located using early stage 2D seismic and geological surface investigations. In the mid-1970's, due to the development of 2D seismic, it was possible to extract the top structure and a further 5 wells were drilled from the mid-1970's to 1990's. Most of the Onshore Block 4 area is located within a transition zone between sea and land, therefore, it was difficult to detect the top of the structure, even with 2D seismic.

In 2017, mega-3D seismic was acquired across Abu Dhabi by ADNOC. Based on interpretation of the newly acquired 3D seismic, certain anticline axis trends were identified that were drilled by deviated wells because of surface limitations.

Generally, if the source rock potential is high in the center of the intra shelf basin in Abu Dhabi, it is possible that hydrocarbons are charged to any porous zone. In addition, past geologists identified and drilled the major anticlines with limited information. It is important to know the related exploration history and apply new technologies to existing knowledge to find new reserves. Dry Hole analysis is a crucial evaluation method to understand the thoughts and rationale of previous geoscientists and used to augment the exploration and de-risking of various plays. Based on using this dry hole analysis, in 2021 oil, gas and condensate successfully flowed from an exploration well.
Data Integration of Reservoir Architecture & Petrophysical Properties from Extra-Deep Azimuthal Resistivity Inversions to Optimize Lower Completions Designs
Authors: Mutairi Bandar , Wang Yanhui , Alahmadi Mohammed , Ferreira Enrico , Mumtaz Asim
Published: October 2022

This article proposes a workflow that combines reservoir mapping by logging while drilling (LWD) Extra- Deep Azimuthal Resistivity (EDAR) Inversions, LWD azimuthal bulk density image (ABDI) interpretation and calculation of true formation resistivity (Rt) to acquire an expected permeability index. It helps to understand the architecture of the reservoir while also providing an insight to optimize zone selection to optimize intelligent completions design (ICD) for production enhancement in a timely fashion.

Initially, EDAR inversions provides geostructural information within depth of detection (DOD), which includes apparent formation dip, layer resistivity and pay zone thickness (PZT). It defines cap rock boundaries and fluids contacts while drilling and layer boundaries are subsequently confirmed by ABDI in real time. Structural Inversions based on ABDI interpretation are performed, resulting in calculated Rh and Rv, unaffected from resistivity artefacts of each layer.

The resultant Rt will be used as an input to calculate the permeability index from various formulas. Finally, all outcomes listed above will feed the flow and storage Stratigraphic Modified Lorenz Plot (SMLP) and Modified Lorenz Plot (MLP).

Well Placement in layered thin carbonate reservoirs can result in LWD measurement uncertainties caused by artefacts, such as polarization horns in high angle wells, and therefore induce over-evaluation of a reservoir's flow and storage capacity. SLMP and MLP illustrate potential ICD zonation based on calculated permeability index, enabling identification of high-quality and low-quality productive zones while integrating it with wellbore shape and petrophysical analysis. Additionally, PZT can influence ICD selection due to its influence on maximum storage capacity formula. EDAR inversions change perspective of ICD zones by effectively mapping wellbore position within reservoir architecture and its closeness to fluid contacts.

Available cases of wells drilled in Middle East show that thickness from EDAR effectively changes each zone HC storage capacity, which leads to a different ICD setting to conclude the production workflow. which can result in CAPEX investment inefficiency, increased post-well OPEX, low ultimate hydrocarbon (HC) recovery or water injectivity and extended field development. Henceforward, it can support energy transition applications by ensuring optimum flow in the reservoir with possibility of using sourceless technology, therefore reducing carbon footprint (i.e. geothermal wells).

The value of this approach can contribute to production KPIs and justify the well construction investments at minimum risk by enhancing lower completions design utilizing EDAR technology.
Effective Interbed Multiple Attenuation with Exploration-Scale Seismic Data
Authors: Jia Xueyi , Wang Haiyang , Baumstein Anatoly , Cha Young Ho , Gottumukkula Vijay , Dura-Gomez Inmaculada , Martinez Alex
Published: October 2022

If not properly handled during seismic processing, strong interbed multiples pose serious challenges to seismic interpretation in complex subsurface environments. Conventional data-driven interbed multiple prediction and attenuation (IMA) methods can produce high quality interbed multiple models. However, they also come with technical difficulties in reading, mapping, storing and calculating billions of traces, and have huge computation cost. Thus, multiple runs of conventional IMA for different multiple generating interfaces are not always practical.

A Marchenko-based IMA method can predict all multiples generated from an overburden with two stages, which can significantly reduce the computation cost for complex structures with more than one strong interbed multiple generator. We propose a practical approach to combine the two stages into one algorithm by storing and reusing a common intermediate product, aiming to predict all multiples in one run. With our approach, the runtime for Marchenko-based IMA is equivalent to one run of conventional IMA, making this technology computationally affordable and fitting into industrial seismic processing timeframes.

Synthetic and real exploration-scale seismic data examples will be used to demonstrate how the multiple generation mechanism is identified and the interbed multiples are accurately modeled from an overburden above a user defined horizon and mitigated at the target reservoir level with advanced post-migration domain adaptive subtraction. The results show that the strong migration swings due to interbed multiples can be removed very effectively and efficiently, and aid in subsequent structural interpretation. The proposed Marchenko-based interbed multiple prediction and subtraction approach can be cost-effectively incorporated into an established seismic processing and imaging workflow, providing an additional multiple-free volume for interpretation and well planning.
Automating Trajectory Design in a Cloud-Based Planning Solution
Authors: Suryadi Hendrik Gunawan , Li Haifeng , Jiang Lu , Liu Qing
Published: October 2022

Well trajectory design is an essential part of well planning that affects the entire well design and drilling program. Until today, many well trajectories were designed in a silo by directional service company well planners based on surface coordinates, subsurface targets coordinates, and constraints provided by operators. Geologists also designed trajectories in the geology and geophysics (G&G) applications and then transferred them to well-planning applications. There are many trajectory path possibilities, and the proposed design depends on the designer's experiences. Engineering validation, such as geomechanics, torque and drag, bottom-hole assembly (BHA) tendency, etc., was not checked during generating trajectories and analyzed in different workflows or applications. With the siloed approach and disconnected workflows, trajectory design has become time-consuming because of multiple iterations, discussions, and data sharing. The engineer tries to solve the design constraint and validation issue identified by other workflows one-by-one.

Today, we have various map applications that can design and propose the best route from the start point to the target destination. The application can provide multiple options, including performance indicators such as the shortest distance, shortest time, fewer traffic-lights, or lower cost. Users can also provide some constraints on the proposed route, such as avoiding tolls and avoiding highways.

A new collaborative well planning application was developed in a cloud-native environment, which includes validation workflow. The application can perform automated trajectory design and calculate all possible paths for the given surface location, target location, and other constraints defined by the engineer. Engineers can evaluate every result and select the optimum trajectory based on key performance indicators such as total length, maximum dogleg severity, and kick-off depth.

Additionally, various engineering analysis validations are performed simulatenously, such as anti-collision, hole stability, torque and drag, hydraulics, and BHA tendency. The result is compared with the limit or criteria to give the engineer instant feedback if the new trajectory design causes potential risk in other workflows. The anti-collision analysis is fully automated, from selecting the offset wells, calculating the separation factor, and displaying the result as a traffic light visualization. The cloud-based geomechanics application provides a mechanical earth model that enables auto-validation when the trajectory is created and flags hole stability risks.

In this well construction planning solution, a cross-domain team can collaborate on well-planning tasks simultaneously, with automation that improves working efficiency.
Wellbore Stability Analysis Using Elastoplastic and Thermo-Elastoplastic Approaches
Authors: Hamid Osman , Oluyemi Gbenga , Sanaee Reza
Published: October 2022

Wellbore stability modeling has been known in the oil and gas industry and academia for a long time. The instability-related issues significantly impact field developments, especially in complex deep reservoirs. This instability can substantially jeopardize the drilling objectives, leading to poor wellbore conditions. Most available software uses simple linear elastic modeling approaches to predict wellbore failure and determine the safe mud weight for the planned boreholes. This assumption might lead to inaccurate results.

The main objective of this research is to use an elastoplastic modeling approach to predict a yielded zone around the wellbore using Finite Element Modeling (FEM). These elastoplastic models were used in conjunction with the Drucker-Prager yield criteria.

The yielded zone is interpreted utilizing volumetric strain analysis. The result of this study will be used for any potential breakout development while drilling that might lead to increase wellbore stability-related problems. The damage or yielded zone results will be used for completion packer positioning to avoid pressure communications while packers expand.

These novel techniques will be applied to compute wellbore stability for tight sandstone formation. The methodology can be applied to other locations using the FEM approach.
Minimizing Salt Creeping Through Geomechanics Application and Systematic Drilling Fluids Design in Ultra Deepwater Wells - Operator's First Experience in West Africa
Authors: Zainal Abidin Faieqah , Toha Rozaidi , M. Zin M. Nizam , M. Abdullah M. Baihaky , M. Amin Remy Azrai , A. Razak M Solehuddin
Published: October 2022

In 2017, 2019 and 2021, an Operator drilled 3 ultra-deepwater exploration wells in offshore West Africa. The water depth for well A is around 2900m, well B is around 2800m while well C is circa 2100m. The objective of these wells is to evaluate the potential hydrocarbon accumulation in the subsurface area. Besides the usual challenges being wildcat wells and located far offshore, the wells drilled through pre-salt formations. Hole enlargement due to salt dissolution is also a concern apart from salt movement to close the hole owing to its plastic nature. Furthermore, the lack of offset wells for determining wellbore behavior also caused another challenge. Experiences from the nearby wells showed many signs of wellbore instability such as tight spots and losses.

The common causes of wellbore instability are unbalanced stress dependent on stress change and rock strength, and shale-fluid interaction due to hydration of clays. A geomechanical model was constructed and detailed salt creep modelling was developed.

Well A was drilled until the final target depth with minimal wellbore instability and encountered no losses at all while drilling. Well B which was drilled later, also drilled to the final target depth with very minimal wellbore instability. Well C was drilled with longer salt exposure around 490m. The mud weight selected for all wells also successfully minimized salt creeping. These are strongly evident while drilling and running in casing, no tight spots were encountered. Both wells successfully drilled through salt formation with very minimal salt dissolution.

Through the application of geomechanics and systematic drilling fluids design reduce potential non-productive time (NPT) related to salt plastic movement that could be faced by Operator eventually saving Operator's drilling hours.
Drilling to the Limits. A Step Change in Drilling Operations by Utilizing Innovative Drilling Scrapers Technology Tools Enable to Optimize the Drilling Performance with Low Risk and Saves 1.5 Rig Days Per Well in UAE Onshore Fields
Authors: Bethancourt Roswall Enrique , Sarhan Mohammed , Al Reyami Mazin , Mwansa Peter Levison , Kodiah Basma Naeem , Sam Sneha , Gaurav Anchit , Abdelhalim Khaled
Published: October 2022

Optimization of drilling performance with low-risk technologies has become the main challenge for Abu Dhabi Onshore Operator. This paper presents a step change in the drilling operations with the successful deployment of a proven technology solution (of wellbore clean up scrapers which can be added to the drilling assembly) in the new wells, allowing an improvement of the well's drilling time by 1-1.5 rig days for each well.

Following the successful implementation in Abu Dhabi Onshore pilot wells, deployment of the Scraping While Technology (or, SwD) in the new wells have now become part of the standard operations, bringing in direct savings of 65 million-USD to the Operator.

The proposed innovative application allows to combine the wellbore clean up scrapers for 7 inches liner and 9.625 inches casing as part of the drilling Bottom Hole Assembly (BHA) for the last open hole section (6 inches or 6.125 inches) of the well. The Scraper While Drilling tools are dormant while the drilling activity is ongoing and can be hydro-mechanically activated on-demand by dropping steel balls from surface at the end of the drilling activity. Upon activation, the scraper blades from the SwD tools extend outwards and push against the ID (inner diameter) of the casing or liner. The solution allows scraping the casings and liners across the completion packer setting depths while pulling out of the drilling assembly and thereby leaving the completion interval ready for either recording the cased hole logs or running the completion jewellery. This implementation of the SwD saves the operator between 1 to 1.5 rig days per well by allowing the operator to cancel dedicated clean out scraper run(s).

There is no limitation for Scraper While Drilling deployment with regards to the horizontal hole section lengths. Using the SwD in the drilling assembly eliminates the need for a dedicated well bore clean out conventional scraper run; it also reduces the risk factors by eliminating the pickup, lay down, run in hole, and pull out of hole activities of the dedicated well bore clean out runs with conventional scrapers.

The Scraper While Drilling technology hence revolutionizes a typical well design and its drilling operations by eliminating dedicated clean out scraper runs with conventional scrapers and allowing the operator to drill more wells based on the days saved per well in a long-term drilling campaign.
Successful Deployment of Drill Through Turbine Casing Reamer Shoe in Longest Challenging Intermediate Sections on Abu Dhabi Jack Up Operations
Authors: Biyanni Hanifan Mayo , Gohel Prashant , Jadallah Omar Nazih , Rabis Philippe , Couzigou Erwan , Al Ameri Fahed Salem , Law Callum , Charles David , Robertson Kevin
Published: October 2022

The trial of a turbine powered Motorized Reaming Shoe (MRS) was conducted on two fields offshore Abu Dhabi involving the running of 9-5/8″ casing to planned depths in long intermediate sections. The trials involved running casing in the longest12-1/4″ sections to date on each field.

This paper will elaborate on detailed parameters, Motorized Reaming Shoe features and operating practices recorded while reaming through multiple restrictions with a cumulative length of more than 200 ft, across various formations, successfully running casing to the planned depth.

It will also elaborate on casing cementing and shoe-track drilling operations where MRS were deployed.

Referring to the average NPT duration of similar incidents, this initiative has saved 6 to 7 days of operation (eliminating requirement to pull the casing, perform a wiper trip, and re-run back the casing). This is estimated at an average of approximately 1M$ cost savings per NPT event.

The failure to run casing to section TD with the MRS in one of the trial jobs is also analyzed including detailed operational learnings and design changes that could positively impact running long casing strings in complex wells.

This paper details the technical features and potential benefits of Turbine Powered Reaming Systems, how the trials were conducted and their impact on de-risking casing deployments, with specific reference to application in long intermediate casing sections offshore Abu Dhabi.
Synthesis of Epoxy Resin Based Geopolymer Utilizing Saudi Arabian Volcanic Ash for Primary Well Cementing Applications
Authors: Alanqari Khawlah , Al-Yami Abdullah , Wagle Vikrant
Published: October 2022

Conventional cement production possess huge environmental concerns. Which is considered globally the third largest source of CO2 emissions into the environment. This is due to the decomposition of carbonates that produce around 900 kg of CO2 for every 1000 kg of cement production. As a substituent, geopolymer cement can reduce the CO2 emissions by 80% because there is zero CO2 emissions through the geopolymer cement production. Moreover, Geopolymer cement can be prepared utilizing waste materials such as fly ash. In Saudi Arabia, we have enough volcanic ash to sustain the development of this eco-friendly cement. Furthermore, geopolymer binders show an exceptional mechanical, chemical and environmental benefits in comparison to conventional cement. In addition to geopolymer properties, liquid epoxy resins are known to increase bonding with casing; thus, increasing the wellbore integrity.

In this study, we successfully developed a novel epoxy resin based geopolymer cement utilizing a Saudi Arabian volcanic ash for primary cementing applications for the oil and gas industry. This was done by adding an epoxy resin formulation to the geopolymer slurry. This novel cement shows an excellent strength and good rheological properties with a controlled setting time. The objective of this paper is to detail and explain the synthesis of this cement, geopolymer slurry preparation and epoxy resin formulation. Also, to investigate the effect of adding the epoxy resin formulation to the geopolymer slurry in terms of the final cement strength, thickening time and rheological properties as well as to detail lab testing.

To prepare the epoxy resin based geopolymer, the volcanic ash particles were activated first by a mixture of NaOH, sodium silicate and water. Then, an epoxy resin formulation was added to the geopolymer slurry that contains an epoxy resin along with a curing agent. The amount of the epoxy resin formulation was varied in order to study the effect of adding the epoxy resin into the geopolymer slurry in terms of the final cement's setting time and compressive strength. This was done to develop a cement with excellent strength and controlled setting to assure a right cement placement. In addition, the chemical conditions were evaluated to simulate a variety of downhole conditions to prove the effectiveness of this novel geopolymer composition as a cement for primary cementing applications. The lab testing includes gelling time and compressive strength measurements as well as a chemical analysis of the Saudi Arabian volcanic ash.
First Run of 17 Swellable Packers in Sahil Field with 15 AICV as a First New Technology Trial in ADNOC Onshore
Authors: Yahya Maryam Ali , Alhathnawi Mohammad Ibrahim
Published: October 2022

In south-east field, the normalized number of running swellable packers is 7 to 8 swellable packer, and yet with this number holds up occur and could raise other operational issues. In the Onshore operated field, a designated well was nominated to trial an Autonomous inflow control valve (AICV) which is a technology that improves oil production by reducing unwanted gas and water breakthrough. To have the proper implementation of the trial, the development department required 15 swellable packers to be run in the horizontal hole part of the lower completion to assure segmentation isolation and a proper positioning of the AICV. The requirement was challenging, as it was not experienced in the specified site to run this amount of swellable packers, as each swellable packer could create a force which could cause hold up and even a stuck.

Part of the well planning phase, torque and drag simulation, hydraulics simulations and risk assessments were prepared and analyzed to study and evaluate the possibilities of running the 17 swellable packers along a horizontal hole section. During the execution phase, a proper drift run was in place to provide an indication of a smooth run of the lower completion. In addition to that, to assure well bore trajectory accessibility and suitability for the lower completion, a Mechanical Caliper Log run on Tubing Log conveyed (TLC) was in place. As a contingency during running the lower completion, a remote actuated sleeve was placed at the bottom of the lower completion to avoid having a close system in the hole with no circulation, which could case difficulties in releasing the string in case of any hold up or stuck.

The completion deployment was successful, which was a result of a proper planning and communication from all the parties involved. The combined skills of the Operations and Engineering team was key to the safe and efficient execution of the project as a proper and continues follow up was in place by a high-competent members during the execution phase which assured the completion of the well as planned.

This job was a start to encourage other fields to implement new technologies after evaluating each case separately to get the full benefit of it. In case any high risk/ unexperienced circumstances operations, with the proper planning and study, alternative procedures, processes, and technologies can be implemented to add a bigger value to the organization.