bluuebunny/crossref_metadata_2025 huggingface dataset:
Natural Fractures Sensitivity to Hydraulic Fractures in Abu Dhabi, UAE
Authors: Noufal Abdelwahab
Published: November 2020

Fractures serve as important conduits for subsurface fluid flow and their presence can transform an otherwise unproductive rock formation into an economic hydrocarbon reservoir. Natural fractures have a vivid impact on reservoirs, especially the low perm, as they control the hydraulic flow as conductors (open fractures) or barriers (sealed fractures). Abu Dhabi carbonates are dissected by many fracture clusters, but most of them are sealed, therefore it is critical to investigate, which sets are predicted to reactivate. Hydraulic fracturing in horizontal drilling are the primary enabling technology to gain economical production from the low perm reservoirs. However, fracture parameters are poorly constrained by reservoir data, due to they are subseismic and hard to predict their behaviour through the life-cycle of the reservoir. Addressing the structural patterns and using the geomechanical data along well bores help to assess their roles in production enhancement and sensitivity to hydraulic fractures initiation and propagation.

The spatial distribution of microfaults, hybrid fractures and pure opening mode fissures with wide variations in strike appears related to their location with respect to the deformation zones of the nearby fault segments in the reservoirs of Abu Dhabi. Usually not all fracture sets enhancing production and the best approach is to predict those sets that playing these roles.

The ability of fractured bedrock to transmit fluids depends upon the physical characteristics of the fractures and opening-mode fractures that make up the fracture system, such as fracture aperture, fracture length, fracture density, fault displacement and gouge thickness. Many of the hydraulically significant fractures at the reservoir scale cannot directly detected, neither by borehole imaging tools nor by seismic imaging. Thus, reservoir characterization, in terms offracture architecture models, are derived from a combination of well data and the factors that control fracture development in carbonate reservoirs of Abu Dhabi. These factors include stratigraphy, rock properties, kinematics, especially orientations and mechanics of fracture growth and principally their relation to the present day in situ stresses.

The results showing that, hydraulic fractures propagation is dependent on the natural fractures and bedding planes orientations and the well location relative to the fault segments deformation zones. Understanding and predicting the behavior of fractures involves the identification and location of hydraulically significant fractures. Such fractures are conduits for fluid flow, and are connected to other hydraulically conductive fractures to form conduit systems. Conductive fracture networks may include a large number of interconnected hydraulically active fractures, or may be limited to a very small proportion of the total fractures in the rock mass.
Control System Integration with Multiple Vendors Supports Drilling Optimization Software Application
Authors: Jeffery Christopher , Creegan Andrew
Published: November 2020

This paper details the integration of a software drilling optimizer to multiple drilling rig control systems. The drilling optimizer operates via communication of auto-driller setpoints to the rig's control system, continuously adjusting parameters to be optimum to wellbore conditions, and detected drilling dysfunctions. The integration process with each vendor's control system requires planning and work on both sides of the integration to ensure seamless communication of data. Integration performed over the last two years with three different control systems from two vendors was completed using various communication protocols.

The authors found that when a centralized process management solution, acting as a data broker between applications and the control system was present, the individual rig deployment configuration and installation effort was minimal. The study showed when performing direct integration to the control system; there is an increase in the configuration and installation effort for each rig deployment. Each rig required specific customization by engineering resources from both the software provider and the rig control system vendor. The development of user interfaces across different platforms creates an additional layer of synchronization to ensure the user experience is consistent. By ensuring consistency in each implementation of the user interface, the authors observed a reduction in training for the field support teams.

The project concluded that there is a need to centralize custom and complex user interface elements to improve the usability of the application for the driller. With the use of a centralized process management solution, companies can now minimize user interaction at the control system to avoid duplication of effort in design and engineering. The standardization of hardware to run the drilling optimizer simplified the deployment process and improved business efficiency.

The lessons learned from these processes contribute to the overall industry initiatives around data interoperability. These projects have laid the foundation between control system providers and software providers to increase the efficiency of future projects that necessitate data transfer through multiple communication standards.
Integrated Reservoir Model History Matching Workflow: Unlocking Reservoir Opportunities, Onshore Abu Dhabi, UAE
Authors: Setiyo Pamungkas Talla Gueye
Published: November 2020

Reservoir model history matching is the solving process of a complex inverse equation mainly relating reservoir and well properties to observed data using a time and space discretized numerical model. A challenging task for engineers but a prerequisite to a vital tool to field development and business planning. This paper presents the calibration of a giant Middle East carbonate reservoir from scratch following a major field review. The objective of this integrated history match was to provide a reliable and sustainable representation of the reservoir in order to:

Predict performance, necessary strategies and expenditures for field development Reproduce the fluid distribution and the flow mechanism Represent the areas of the reservoir where there are no data Discover then solve or anticipate any operational issue

It is a tedious work to calibrate coherently the static and dynamic models of a Giant field with complex geological heterogeneities, more than a thousand wells and forty-four years of history where multiple scenarios can coexist. This paper will present the workflow used to achieve a reliable and sustainable representation while narrowing down the number of solutions by using:

Theoretical and analytical calculations on paper to assess the foundation and physics behind the reservoir behavior Phenomenological models to understand the main drivers and reproduce the flow mechanism with a more flexible tool Regional geology and migration history to estimate untested parameters away from the oil pool especially inside the aquifer An iterative and innovative Static-Dynamic integrated process to generate a reservoir characterization honoring geology and performance at the same time

The applied workflow revealed for the first time the magnitude of the natural energy of the reservoir that contributes significantly (15-20%) to the energy loss. A revelation that changed the reservoir development strategy going forward. It inspired innovative methods to capture horizontal and vertical permeability needed to reproduce field performance on surface and flow dynamics inside the reservoir.

This comprehensive and integrated workflow generated a reliable and sustainable tool and put in place different technics to achieve an updated history match relatively quickly.
Blended Acquisition with Temporally Signatured/Modulated and Spatially Dispersed Source Array: The First Pilot Survey Onshore Abu Dhabi
Authors: Ishiyama Tomohide , Zhao Mingqiu , Hu Fei
Published: November 2020

We recently introduced a blended-acquisition method: temporally signatured and/or modulated, and spatially dispersed source array, so-called S-/M-DSA. This method jointly uses various signaturing and/or modulation along with dispersed source array each in the time and space dimension.

We just acquired and processed the first pilot survey with S-/M-DSA onshore Abu Dhabi. In this paper, we review the resulting acquisition-productivity enhancement in the time dimension, and discuss it in the space dimension as well. We then review the deblended-data-reconstruction processing, and discuss its results and performance. We last establish a relationship between the acquisition productivity and the deblended-data-reconstruction performance.

We found that S-/M-DSA significantly enhances the acquisition productivity compared to conventional blending methods. For the deblended-data reconstruction, the deblended data can properly be reconstructed, with a high repeatability over the full frequency band, from the blended data. This method owns a relationship: the deblended-data-reconstruction performance increases with the acquisition time (inversely proportional to the acquisition productivity) in general, up to a plateau to be reached in cases of conventional blending methods with much longer acquisition times.
Performance Comparison of Two Different In-House Built Virtual Metering Systems for Production Back Allocation.
Authors: Vitale Fabio , Oliva Marco , Montini Marco , Ponteggia Luca , Ursini Fabrizio , D'Addato Francesco
Published: November 2020

A virtual metering system is an alternative way to measure the flow rate of a well in real time. They can therefore improve the reliability and the effectiveness of the production back allocation process, providing redundancy to multi-phase flow meters (MPFMs) measures.

Scope of this work is to build and validate two different virtual metering systems highlighting their peculiarities and comparing their performance.

A virtual metering system can estimate the flow rates of each well of an asset by elaboration of pressure and temperature data coming from the field.

In both virtual metering systems, the core is a fluid-mechanical model of the production network of the same off-shore field, made of six wells flowing in two parallel lines. The model is run multiple times adjusting the wells flow rates according to two different minimization algorithms, to match the measured data as much as possible.

After validating the results, the performance of the tools has been compared against MPFMs, used as a common reference.

Both systems have been validated against officially allocated flow rates coming from MPFMs. At first, only pressure data have been used as inputs.

System number one, which exploits the Matlab minimization algorithm and an OLGA model of the network, showed great accuracy in the majority of the cases, with an error less than 5%, making it a great verification tool for measures coming from other instruments. Its simulation runtime, however, is still too long to make it usable in a real-time application scenario.

System number two relies instead on the gradient descent algorithm and on a GAP model of the network. This system is equipped with an automatic tool that can discard unreliable signals coming from damaged or out-of-calibration field sensors, while simulating. The resulting accuracy is acceptable, with an average error between 5% and 8% and the computational time is short enough to be used as a live measurement tool, in parallel to MPFMs.

The validation process has been repeated adding temperatures to pressures in the input dataset. No accuracy improvement has been shown by the new results for both systems, concluding that a leaner structure where only pressure is considered is to be preferred.

The two systems represent economic measurement tools for production allocation, showing a good ability in supporting field operation in case of instrument failure or unreliability.
Potential Utilization of Neutron Logging Technology for Casing Cement Evaluation - Feasibility Study
Authors: Dommersnes Espen , Khalifeh Mahmoud , Larsen Helge B.
Published: November 2020

Reliable cement evaluation is crucial for well integrity and optimal production. Current cement evaluation technologies have limitations and a fundamental analysis is performed to assess neutron logging for this purpose. Basic modelling has been performed to study neutron transmission for several realistic cases including good cement, channeled cement, foamed cement and through-tubing configurations. For a comprehensive review, other aspects such as health, safety and environment (HSE), cost and alternative approaches have also been assessed.

Results achieved show that neutrons have the potential to travel to the cement-formation interface and return to the detector without being completely attenuated. For single casing configurations, results indicate that cement channels produce distinguishable results from intact cement. For through-tubing logging it cannot be concluded that detected results are distinguishable. Even though neutron logging itself is likely to be more costly than cement bond logs, potential benefits in terms of other cost savings and decrease in HSE risks must also be considered.
First Successful Installation of Washpipe Free ICD Completion with Dissolvable Materials: An Optimized Design for Middle Eastern Fields
Authors: Corona Cortes Georgina , Ashraf Hamza , Kouadio Yao
Published: November 2020

Inflow Control Device (ICD) completions have been used widely in the energy industry to balance the inflow of produced fluids, while delaying water breakthrough. Improving the reservoir drainage results in higher oil recovery. Traditional completions are typically deployed with washpipe to provide washdown and circulation capability. This is especially advantageous for Run In Hole (RIH) through tight spots and extended-reach wells. A tailored ICD design with dissolvable materials was tested and optimized for Middle Eastern fields with the first successful installation in UAE of a washpipe-free ICD completion.

The washpipe-free adjustable ICD completion utilizes a combination of permanent and dissolvable temporary ICD plugs. A range of dissolving materials were developed and tested in a variety of representative downhole conditions, including temperature and pressure variables. The dissolvable materials were tailored specifically to suit the fluid program and fluid additives, common to the Middle East. Multiple plug designs were subjected to small-scale and full-scale tests. Computational Fluid Dynamics (CFD) simulations evolved the design of the ICD housing to ensure that the dissolution fluid would reach the ICD plugs.

The dissolution rates of the dissolvable materials were empirically established at representative downhole temperatures with field fluid samples. The degradation and pressure integrity of the materials was validated in small- and full-scale testing. Through full-scale testing, the operational sequences during RIH including displacement and filter cake breaker spotting were replicated with representative pressures, fluid rates, bottom hole temperatures (BHT), and fluid compositions used in the Middle East field.

The validated ICD plugging rod technology was successfully run in the UAE in an extended-reach horizontal well. The permanent plugs allowed for customization of the completion inflow profile as per the most recent logs, while the dissolvable temporary plugs provided a completion string with pressure integrity while running in hole - capable of washdown, circulation, and filter cake treatment placement. After installation, the temporary plugs dissolved, opening the completion to production through the ICDs for improved reservoir management.

The ICD with dissolvable technology allowed deployment of the completion successfully to target depth (TD) with the pressure integrity required for the displacement operations. In not running and retrieving an inner string, and achieving wellbore displacement at a faster rate, time savings for the 6000 ft OH completion were estimated between 35-50 hours, with an estimated cost saving of a half-million dollars.
Looking into the Deep: Seismic Reservoir Characterization for Understanding the Offshore Early Permian Clastic Reservoirs in Abu Dhabi
Authors: Caeiro Maria Helena , Al Kobaisi Abdulla , Parra Humberto , Tavares Julio , Lopez Diego
Published: November 2020

With the current increase of domestic and global demand for gas, exploring any gas accumulations has never been more attractive in Abu Dhabi. The deepest targets, such as the clastic Permian formations, are especially attractive due to their H2S free (sweet gas) characteristics. Nevertheless, understanding the deep reservoirs is still one of the main exploration challenges in Abu Dhabi. The primary Pre-Khuff reservoir potential within offshore Abu Dhabi is considered to lie within the siliciclastic deposits of the Unayzah Fm. The Unayzah Fm. comprises predominantly continental deposits ranging from alluvial fan, braided river, lacustrine facies in western Saudi Arabia to fluvial, eolian, overbank and interdune facies further east. Deltaic to shallow marine deposits are also present in eastern Abu Dhabi and Saudi Arabia.

Seismic reservoir characterization poses as one of the most significant options for understanding the reservoir architecture and properties. Pre-stack seismic inversion was conducted targeting the Pre-Khuff zone of two offshore fields in Abu Dhabi. The available seismic data is a full azimuth high-quality 3D ocean bottom cable (OBC), covering 1270km2, with wide radial offset range of approximately 9400 meters. Due to the long offsets, four partial angle stacks (up to 40° of mid angle) processed to relatively true amplitudes, after pre-stack time migration, allowed the extraction of seismic reflectivity information at the deep sections with confidence. Elastic properties were derived from seismic reflectivity data and reservoir properties were sub consequently obtained. Although the inversion resolution was led by the seismic bandwidth, lateral continuity of inverted properties (P-impedance and Vp/Vs ratio) benefitted from the good seismic coherency of reflectors and signal to noise ratio. The comparison between the recorded seismic and the inverted synthetics exhibited a high cross-correlation throughout the whole area, for all partial stacks.

The novelty of this study is the applicability of pre-stack seismic inversion techniques to the characterization of deep clastic reservoirs in offshore Abu Dhabi. The final products represent valuable information not only for further qualitative analysis in terms of reservoir geometry interpretation but also to derive some reservoir properties that could potentially optimize future exploration and appraisal activities.
30 Days to 36 Months Plus Operation-Reliability Improvement Journey of Integrally Geared Compressors
Authors: Pasha Khalifa , Kumar Rajeeva
Published: November 2020

Maintaining the high level of reliability of Instrument Air compressor is essential for safe operation of Oil and Gas facilities however challenges remains to maintain high level of reliability in integrally geared design instrument air compressor due to exceptionally high speed (50,000 rpm) and minimal clearance bearing..etc. This paper presents success story of such compressor`s Reliability and MTBF improvement from 30 days to more than 36 months.

Integrally geared compressor was installed and commissioned in year 2002 as facility upgrade project and never run continuously more than 30 days due to frequent high vibration trip and lead to consequence Risk of plant operation and upset due to non-availability of compressorExtremely high maintenance cost > $120,000 per year due to repeated maintenance intervention

Identifying the common vibration malfunction like unbalance, misalignment, rubs, cracks, shaft bows are relatively easy, as the behavior/characteristics of these problems are well understood, however challenge remains for identifying the rare uncommon problems with limited information so this paper details interesting achievement of, how we diagnose and eliminate vibration issues.

Structured root cause analysis of high vibration revealed cause of high vibrations are Bearing Frosting /Pitting contributed by buildup of Electrostatic current and discharge through bearing High residual magnetism, and compounded by Yellow deposits /varnish formation due to thermal oxidation which is result of high operating temperature and Oil disintegration.

To eliminate above uncommon problems, following solution were identified as. Installation of current diverter rings (CDR) in motor, which avoided development of high shaft voltage from either motor or compressor by discharging to the ground.Removal of residual magnetism from rotor by On Site degaussing process.Maintained the lube oil supply temperature less than 60°C by upgrading the temperature control elements.To identify varnish formation, Perform proactive varnish potential test like membrane patch colorimetric (MPC)

Implementation of above recommendations enhanced the equipment uptime with reduced maintenance effort and cost, which permanently resolved the high vibration issues and made the compressor reliable for uninterrupted supply of instrument air to process plant without major overhauling for more than 7 years as of now.
Cloud-Enabled Ubiquitous Collaboration on Large Models Using Augmented Reality
Authors: Boonyasaknanon Phathompat , Pols Raymond , Schulze Katja , Rundle Robert
Published: November 2020

A cloud-based augmented reality system is presented which is designed to enhance the real-time collaboration of domain experts involved in modeling large reservoirs. An evaluation of traditional techniques is compared with this new approach. Work-from-home (WFH) scenarios are becoming more important and, in some cases, critical. There is a need to untether the geologist and other domain experts from high end office-bound workstations.

Reservoir models in recent years have become increasingly large. The volume of seismic, well data and modeling data structures presents a challenge in both management of the data and making it accessible to domain experts and others. The traditional practice of siloing data in various disconnected data repositories in various corporate data centers is becoming increasingly untenable. What is needed is a comprehensive approach that scales to the largest models and is accessible anywhere for time critical analysis and collaboration. The authors have created a prototype of a potential solution to this problem, where the model resides in the cloud and can be visualized in augmented reality either as a hologram through a head mounted display or through the AR capabilities of tablets and smartphones. This technology is ideal for WFH scenarios: it is light weight, inexpensive and does not require broadband speeds in excess of what most home users can access.

What we have found is that AR based approaches to modeling large reservoirs can rival traditional workstation approaches. Furthermore, AR based approaches are superior for close collaboration among domain experts. Collaboration on 3D models has not changed significantly in a generation. For co-located personnel the approach is to gather around a 2D screen. For remote personnel the approach is sharing a model through a 2D screen along with video chat. Over the years various attempts have been tried to enhance the collaboration experience and have all fallen short. Virtual reality (VR) has been proposed as a solution. However, we have found that augmented reality (AR) is a much better solution for many reasons which are explored in the paper.

The cloud has been transformative for nearly every industry. The oil and gas industry has been slow to adopt cloud technologies for many reasons that have largely been overcome. AR has already acquired an impressive track record in various industries. AR will have applications in nearly all industries. For various historical reasons, the uptake for AR is much faster in some industries than others. It is too early to tell whether the use of cloud-based augmented reality for modeling large reservoirs will be transformative, however the results of this initial work are promising.
Prediction of Fluid Flow in Porous Media using Physics Informed Neural Networks
Authors: Almajid Muhammad Majid , Abu-Alsaud Moataz Omar
Published: November 2020

In the realm of reservoir engineering, we are categorized to be in the small data regime because of the complex physical systems we are dealing with as well as the inherent uncertainty in our problems. The objective of this paper is to present a physics informed neural network (PINN) technique that is able to use information from the fluid flow physics as well as observed data to model the Buckley-Leverett problem.

We use the classical problem of drainage of gas into a water-filled porous medium to test our implementation. The analytical solutions obtained using the method of characteristics are compared with solutions obtained using the DeepXDE library that is built on top of TensorFlow. The automatic-differentiation capability of TensorFlow allows us to interweave the underlying physics of the problem with any observed data to come up with a data-efficient universal function approximator. The flexibility of TensorFlow also allows us to set multiphase parameters to be trainable or not, which would ultimately assist in any inverse modeling efforts using the problem.

Several cases are presented that highlight the importance of the coupling between observed data and physics-informed neural networks for different parameter space. The cases demonstrate the capability of PINNs to augment data-driven solutions. Our results indicate that PINNs are capable of capturing the overall trend of the solution even without observed data but the resolution and accuracy of the solution are improved tremendously once the augmentation of data and physics is implemented. Even with a large mobility ratio, the predicted solution of the PINNs seems promising. The results in our paper indicate that such methods can be utilized to train models that could be used estimate a well-informed initial guess in a reservoir simulator because they capture the overall behavior but miss the intricate details that could be circumvented with conventional reservoir simulation.

The work presented in the paper demonstrates the importance and the capability of applying machine learning approaches in reservoir engineering problems. Additionally, it gives a forward-looking approach for the future of reservoir simulation techniques that could augment data with the physics.
An Efficient and Robust Method for Optimizing the Number of Non-Linear Iterations for Simulating Highly Heterogeneous Naturally Fractured Reservoirs
Authors: Mohajeri Sina , Eslahi Reza , Bakhtiari Maryam , Alizadeh Ali , Zeinali Mostafa , Madani Mohammad , Rajabi Hamed , Sharifi Ebrahim , Mortezazadeh Emad , Mahdavifar Yasser
Published: November 2020

For speeding up the complex fractured reservoir simulating, we have given more attention to reducing runtime and improving efficiency of the solver. In this work, we describe an improved and computationally efficient version of Newton's method, which reduces the non-linear iteration count, increases time steps, and furthermore reduces time spent in nonlinear loops of reservoir simulating. Safeguarded variants of Newton's method which have used in current reservoir simulators cannot guarantee convergence of the solution, especially in highly heterogeneous, detailed and fractured reservoirs. In such simulators time step chopping is often observed. From other hand, with growing complexity, convergence difficulties can lead to considerable losses in computational effort and prohibitively small time steps. For overcoming this problem, an improved and computationally efficient version of Newton's method, which uses higher order terms in the Jacobian matrix in addition to the Newton's basic linear terms to account for cross variable dependencies including a high-tech stable linear solver, is proposed. This scheme leads to a smaller number of non-linear iterations compared to other known commercial simulators with larger time steps. In addition to SPE10 model, an under saturated fractured black-oil reservoir model, including single and dual grid blocks together, with dimension of 124*105*60 grid blocks is used to evaluate the method efficiency, by comparing the results using the known commercial simulator. This heterogeneous model includes the features of hysteresis, gravity drainage, oil-gas surface tension, and moderate aquifer with 8 active production wells which have produced for 24 years. The numbers of time steps are 525 and 2693 for proposed method and the commercial simulator, respectively. The numbers of Newton iterations are 1667 and 9399, and the average time step size is 26.2 and 5.62 days, for proposed method and the commercial simulator, respectively. These results obviously indicate the efficiency of the proposed method in reducing Newton's iterations and accordingly increasing simulation speed. The novelty of the proposed creative method is in reducing non-linear Newton's iterations and increasing time steps which leads to reduced simulating elapsed time, which has never been observed in current simulators.
Best Practice for Inflow Control Technologies
Authors: Rinde Trygve , Jondahl Morten Hansen , Moen Terje
Published: November 2020

The use of Inflow Control Technologies (ICTs), both passive and active, has been motivated by the technology's ability to significantly improve the overall production from a reservoir. Increased oil production combined with reductions in volumes of both water and gas should be expected if these technologies are deployed correctly. These technologies may also affect the total reservoir drainage in a positively manner with less energy used for long term pressure support as result. ICTs are available in passive, active and autonomous versions, all with different physical working principles. Even though some of these are used world-wide, the lack of best-practice advisory documents for planning, implementation, and operation effectively hinder further acceleration of its deployment. Since the first inflow control device (ICD) was patented in 1992, it is response to varying production rates, phase fractions and reservoir pressures that has been addressed, tested, and modelled by many instances. Some of these models are available in today's commercial reservoir simulators, although with poor accuracy.

Today, 28 years after the first ICD patent, an important challenge to widespread deployment of the technology is believed to be the lack of established best-practice documents and adequate simulation models. This may hinder efficient comparison of the different technologies against each other and alternative barefoot completions.

This paper presents the establishment of such best-practice documents and the development and implementation of generic, effective, and high accuracy simulation models with the ambition to enable qualified selection processes within the different operating companies.

The project presented in this paper presents best practice workflow for selecting best ICD completion and the modelling challenges for these completions and their impact on the total drainage from the reservoir. The project has unveiled new understanding that led to drastic changes in the way ICD completions should be evaluated and compared by the operator to ensure maximum recovery.
Low Cost Solution for Marginal Subsea Field Development Based on Innovative Insitu Subsea Power Cells and Subsea Hydraulic Power Units
Authors: Elsabbagh Sameh , Elwakil Mohamed
Published: November 2020

This work studies how to build a simple yet efficient subsea field architecture utilizing emerging offshore wind, subsea power cells and subsea hydraulic power units. Such architecture eliminates expensive topsides equipment, subsea umbilical and related distribution equipment which reduce CAPEX for marginal field and lead to economical feasible development.

The emerging innovations in offshore wind, subsea power cells and subsea hydraulic power units will be surveyed and benchmarked against to actual needed subsea power and hydraulic requirements based on gained experience from Mediterranean subsea and deep water Egyptian gas fields. Advantage and limitation for subsea power cells and the subsea hydraulic units will be compiled through nonbiased reference along with their technology readiness. Also subsea storage units will be allowing for any chemical injection requirements. Furthermore, a buoy solution will proposed to locate control & monitoring equipment along with a downline connecting the subsea field. The downline will assure communication with subsea equipment and also will allow for filling the subsea storage units with chemicals needed as per flow assurance requirements.

The work is supported by insightful evaluations performed during participation in subsea gas projects. In addition, latest technologies/ solutions assuring tie-back with existing infrastructure and related potential de-rating requirements will be integrated to the overall system. The paper concludes with nuclei scalable architecture solving common marginal field challenges while assuring cost effective development. An illustrative example will be worked out.

The intended work is unique as it combines innovative technologies in a novel efficient architecture allowing for low cost marginal field development.
An Effectiveness Descaling Production Tubing Utilizing a Torque Action Debris Breaker TADB to Restore Wellbore Accessibility in Offshore Oil Wells
Authors: Al-Dhafeeri Abdullah M. , Al-Dhaferi Yousef R. , Al-Enezi Bader M. , Al-Fawwaz Abdullah A. , Atwa Elessawy A.
Published: November 2020

Several offshore oil wells suffer from the most common production problems which are related to scale blockages. The subject wells can not reach the target recommended production rate as well as issues with their wellbore accessibility. The scale can develop at different depths from production tubing. Based on the well intervention and integrity surveys in offshore fields, the subject wells can not be accessible due to an obstacle from scale deposition at a wellbore level.

An attempt to perform a downhole scale clean-up job using slickline operation was recommend as a field trial for first time in offshore oil field. Torque Action Debris Breaker (TADB) tool was utilized effectively in order to restore wellbore Accessibility in terms of scale removal and debris cleaning. The TADB tool is jarred down mechanically in oil wells as a unique helically split torque sub applies a short duration torque to its cutter below with each downward jar. The main torque body can be 1 ½ in, 1 7/8 in, and 2 ½ in with a number of different shoe sizes which it can be easily changed on the main body of the tool as a scale to be broken inside the wellbore.

Based on the evaluation results, the scale removal tool (TADB) can be mechanically efficient depending on the location of the scale and its physical properties. This tool showed overall reduction in time required for descaling, thus reducing intervention time and costs. In addition, an exist of left hand threads within the tool can prevent tool back-off-down-hole. It is also indicated that the tool provides cost-effective results compared to other descaling alternative such as mechanical, chemical or sonic break-down. The approach made a tremendous cost avoidance of utilizing rig operation in order to remove hard scale in the production tubing in oil wells.

The paper covered a first field trial in offshore oil wells utilizing a Torque Action Debris Breaker (TADB) tool to remove different type of scales deposition. The approach applied deep investigation by slickline operation technique to have better results based on a well selection and a problem identification. This paper illustrated the best practices on tool utilization in terms of designing, operating, and monitoring with a long-term strategy execution for advanced solutions related to scale issues at a wellbore level.
3D Static Model Robustness Indicator: A Sequential Blind Test Implementation in Abu Dhabi
Authors: Rodriguez Gonzalez Jose Gregorio , Al Blooshi Farah
Published: November 2020

Blind testing is an intuitive and well-known process for assessing how predictive an estimator is. The technique proposed below applies blind testing sequentially in a 3D geostatistical model. It is an adaptation of "Jacknife" technique to investigate and select the best geomodeling parameters and scenarios. As any method, it has its applications and limitations that are discussed in the paper. First, the 3D model is populated using all the available observations (ni), then the 3D estimation is recalculated with one observation less (n−1). For example, a data point is taken out at location Oth; then a comparison is made at this location (Oth) between the results from the extrapolation (i*ith) and the true value (ith). This is known as a single blind test. However, if the process is repeated for all samples, one at a time, bringing the previous sample back, it becomes sequential. This process continues through all the samples (n) or through a selected group of samples (a selective sequential blind test).

The error (ei) will be contrasted with a pass/fail threshold (PASS), such that if ei> PASS, then the test fails, and if ei ≤ PASS, it will pass. The number of well locations, Oth, that pass the test indicate the predictive nature of the estimation.

The Sequential Blind Test (SBT) results can be used as a ranking element for multiple realizations and/or scenarios and measure the 3D geomodeling quality before the model is sent to simulation. The application of SBT is extended to selecting model parameters, algorithms, and geological assumptions to maximize predictive ability (P).

SBT has been implemented in an onshore Abu Dhabi Gas where more than 4 geological scenarios and close to 12 parameters and modeling approaches were made. The SBT became a statistical tool to rank and select the most likely case (more robust) among them that was brought to simulation.
Evaluating Distribution of Circulating Temperature in Wellbores using Drilling Microchips
Authors: Li Bodong , Dokhani Vahid , Zhan Guodong David , Sehsah Ossama
Published: November 2020

Critical decision making requires accurate downhole data to determine proper action for drilling operation. Using cost-effective drilling microchips to collect near real-time temperature distribution in the wellbore is valuable to accurately predict control parameters such as drilling fluid rheology and density under in-situ conditions. This study presents an iterative method to calibrate microchip measurements with depth. The accuracy of a transient thermal model to simulate the measured temperature profile is also investigated.

Multiple sets of microchips were deployed into two wells, a vertical and an inclined well, to describe the dynamic temperature distribution along the wellbores. The retrieved data from drilling microchips are compiled and processed. An iterative algorithm is developed to calibrate the microchips time-scale to depth considering slippage of microchips in drillpipe and annulus. An in-house transient thermal model is modified to predict the variation of wellbore temperature during microchips circulation.

It is shown that the true velocity of tracers in each interval depends on the flow regime and the rheological properties of drilling fluid. Comparing the predicted arrival times of tracers with the actual arrival times conclude that the maximum fluid velocity in each interval shall be used for calibration of tracers' data. The study concludes that the prediction of the transient model differs from the measured temperature profile for downhole intervals in early times. The discrepancy can be attributed to unknown prior temperature distribution in the wellbore, inaccurate thermal properties of the drilling fluid, and inaccurate empirical correlations.

This new integrated measurement and analysis method can be used as a primary input for well planning, cementing design and a diagnostic tool for potential problems such as lost circulation. This study provides new insights about the temperature distribution along the wellbore and elaborates on the necessity to address the transient processes in wellbores particularly during startups in deepwater drilling.
A Cloud–Based Smart Engineering and Predictive Computation System for Pipeline Design and Operation Cost Reduction
Authors: Chowdhury Khairul , Lamacchia Diego , Frenk Feldman Vily , Mallik Akash , Rahman Israjur , Alam Zahedul
Published: November 2020

Considering the low and volatile oil and gas prices, cost reductions are an impending challenge in the oil and gas industry. For example, offshore pipelines constitute approximately 12% of total CAPEX and potentially 30% of the total OPEX of the entire offshore field development cost. Workforce shortages and manual engineering processes have a high cost impact due to the excessive time to optimize pipeline design, construction, and operation for a robust and efficient system. If the design phase takes excessive time, it is difficult to optimize cost for CAPEX and OPEX while managing risks, with the added complexity of price uncertainties in the market due to unforeseen geopolitical instability. The objective of this paper is to present an artificial intelligence and automation driven pipeline engineering computation system for performing pipeline design and integrity engineering that can save substantial engineering time with a better and optimized design that can accommodate to crude price uncertainty.

A comprehensive computational framework is utilized for pipeline conceptual/preliminary, FEED and operational integrity analysis. The digital computational framework is equipped with a distributed data intake, a robotics process automation, and a predictive analytics computation system. A self-service 3D digital twin creator is utilized to operate from the front end and receiving intelligence from the analysis. The automated design engineering engine is utilized to perform and create ready reports for conceptual/preliminary and FEED/Detail design of a subsea pipeline system. A predictive analytics computation system is utilized to perform pipeline operational integrity using in-line-inspection data and life prediction.

The computational system was tested for a subsea flowline conceptual, FEED level design (i.e. pipeline thermo-mechanical and on-bottom-roughness FEA analysis) and thermomechanical structural integrity during the operational phase. The design time was substantially lower than the traditional manual pipeline design suggested a saving as much as 80% of the engineering time. The computation engine was also tested to conduct pipeline integrity using machine learning from direct in-line-inspection data. The flexibility and scalability of the computational framework allow incorporation of any organization's existing pipeline data and engineering process.

The significant saving in the engineering time should be able to reduce contingency in hedging due to the price uncertainty. The novel computational framework is made available online offers real-time on-demand analytics for instant intelligence for making decisions for both in design and in operational phases. Reusing of all engineering efforts over the life of the pipeline or for other projects is another possibility offered by the cloud-based computational framework.
Generating Green Value from Data: Applying AI–Based Analytics to Monitor and Manage Energy Usage Across Oil and Gas Operations
Authors: Blumenthal Ralf , El Naser Ammar , Blug Christian
Published: November 2020

As upstream E&P operators increase their investments in digitalization and artificial intelligence to improve their cost structures and competitive advantage, they have a tremendous opportunity to generate green value from their energy usage data. In doing so, they can tap hidden sources of energy savings using cloud-based managed services, such as Energy Efficiency Analytics (EEA) and Power Quality Analytics (PQA). Both require high-frequency sampling rates of the energy usage by such common capital assets in E&P facilities as rotating equipment, compressors, and pumps. This paper explains how EEA and PQA work as well as the advantages of these managed services being cloud-based. Use cases are discussed to illustrate their operation and capabilities.
Sand Consolidation by Enzyme Mediated Calcium Carbonate Precipitation
Authors: AlAhmari Manar , Bataweel Mohammed , AlHumam Abdulmohsen , AlMajed Abdullah
Published: November 2020

Sand production from poorly consolidated reservoir formations has been a persistent problem in the petroleum industry. Sand production can cause erosion and corrosion to downhole and surface equipment's and loss of production. Several technologies are used to reduce sand production effects and subsequently maintain well production and safe operations. Such techniques include completion techniques, and in-situ chemical consolidation methods. The enzyme urease induced carbonate precipitation (EICP) is a reversible and environmentally friendly technique that can be used for sand consolidation. In EICP, urease enzyme catalyses the hydrolysis of urea in an aqueous solution, which results in ammonia and carbonic acid production. In the presence of calcium ions, the carbonate ions precipitate as calcium carbonate. It has been reported that urease enzyme starts losing its activity above 65 °C and thus this technology can only be applied in reservoirs with temperatures up to 65 °C. This study addresses an improved EICP method where protein is added and the technique can be applicable at high temperature reservoirs.

Two EICP solutions were prepared, EICP control solution (solution 1) which contains urease enzyme, calcium chloride and urea and modified EICP solution (solution 2) which consists of urease enzyme, calcium chloride, urea and protein. Test specimens were made by mixing sand with EICP solution and allowed to cure at different temperatures ranging from 25°C to 130 °C. Additionally, XRD analysis was performed to identify the type of calcium carbonate polymorph. SEM imaging was carried out to visualize the morphology of the calcium carbonate precipitation in the sand specimens.

Specimens treated with the solution containing protein (solution 2) had a high consolidation strength. As the temperature increases the strength of consolidation decreases in specimens treated with solution 2 and 1. However, the strength of consolidation of specimens treated with solution 2 that contains protein was considerably greater at all temperatures (up to 130 °C), than the strength of specimens treated with solution 1. Moreover, XRD analysis revealed that 70% of the calcium carbonate polymorph in solution 2 was calcite (which is the most stable polymorph). SEM images show that in the specimens treated with solution 2 the calcium carbonate precipitates at inter-particle contacts.

The impact of these results include the use of the EICP protein technique as a downhole sand consolidation method in high temperature reservoirs. Furthermore, the addition of protein in the EICP solution can lead to a reduction in the concentration of substrate and enzyme required to achieve sand consolidation, and subsequently reduction in undesirable ammonium chloride. These advantages enhance the potential use of the EICP protein system for sand consolidation in high temperature reservoirs.