bluuebunny/crossref_metadata_2025_split huggingface dataset:
3D Petrophysical and Geomechanical View for Enhancing Hydraulic Fracturing of Horizontals and Highly Deviated Wells
Authors: AL Isaee Omar , Chavez Florez Juan , Ali Nada , AL Ghatrifi Rawan , Al-Yaqoubi Mazin , AL Abri Ahmed , AL Hinai Mohamed 
Published: November 2019

Abstract
In Oman, the unique geological properties of the reservoirs require different fracture strategies and technology deployment to make them commercially viable. Highly deviated wells, with multiple hydraulic fractures, have been identified as key technology enabler for the development of tight gas accumulations in Oman. The main objective of this study is to generate a 3D petrophysical and geomechanical view of the reservoir, to have a better understating of Hydraulic Fracturing for Horizontal and Highly Deviated Wells
The comprehensive amount of data captured during the initial implementation phase of highly deviated wells covering reservoir characterization, fracture geomechanics as well as production logs in combination with the existent data captured in vertical wells, proves to be complex to analyze due to the volume of information and the multi variable nature associated with fracture and inflow predictions. A methodology was required where correlations and tendencies were identifiable at structural level, covering all target gas accumulations using all the static and dynamic captured data. The definition of a 3D Grid Visualization Block (3D-GVB) was introduced where all the captured parameters were distributed for analysis and interpretation.
As a result of the appraisal and initial field development with vertical wells, it was possible to identify tight accumulations that will require dedicated highly deviated wells for its development. The initial phase of the implementation of highly deviated wells proves to be challenging, as the observed heterogeneities on geomechanical and petrophysical properties across the target gas accumulations, combined with differential depletion and the wells orientation to generate transverse fractures, creates a complex environment for fracture initiation and propagation, impacting not only fracture deployment but inflow deliverability of this wells. This paper will describe how the methodology uses a cycle of data analysis and interpretation to identify tendencies, that will lead to correlation and new algorithms that are retrofitted on the 3D-GVB platform, leading to optimization of well positioning at structural level, drilling and completion of this highly deviated wells.
It will be described how this methodology is used for well positioning at structural level, to define well architectures oriented to enhance not only drilling, but also hydraulic fracturing and hydrocarbon deliverability on highly deviated wells.
Reservoir Connectivity Analysis for a Complex Channelized Reservoir to Reveal By-Passed Pays: Serpent Field, Offshore Nile Delta, Egypt
Authors: Sakran Shawky , Gaafar Gamal , Latif Shaker , Taman Saad , Abdel Razek Ahmed 
Published: November 2019

Abstract
The West Delta Deep Marine concession (WDDM) lies offshore in the Deep water of the present day Nile delta. WDDM consists of many Pliocene submarine channel complexes. The Serpent field is one of those slope marine channels and consists of two separate channels namely channel 12 and channel 13. Channel 12 is divided into three compartments by gravitational faults and channel 13 is composed of two compartments separated by stratigraphic barrier. Gas water contact (GWC) in channelized turbidities reservoir might create an intricate reservoir relationship. Gas water contact becomes complicated when the faults and the facies lateral change provide seals. Those hydrocarbon contacts depths become unpredictable without a distinct system to understand the cause of those variable contacts. Water break-through occurred earlier than expected in Serpent production wells as there was no proper modeling for reservoir facies heterogeneity and facies associated petrophysical parameters. A further compartmentalization of channel 12 arose as the sealing capacity of the gravitational faults cast a doubt over channel-12 compartmentalization and the connected gas initial in place (GIIP). The geological foreknowledge of Serpent field, the production issues and the dire need for further development plans in Serpent field were the motives to initiate this study. Integrated study was designed to answer the unsolved challenges of characterizing the reservoir heterogeneity and faults' sealing capacity. 3-D (three dimensional) high quality seismic data and different seismic attributes were integrated with different well data to build a robust 3-D static model. Static model was the way to elaborate the facies accurate distribution and the different petrophysical parameters in Serpent reservoir. In addition, the 3-D static model was used in the prediction of the faults' sealing capacity through the fault rock facies, fault rock petrophysical properties and transmissibility. In a nutshell, the resultant static model answered the field's issues regarding the early water production, facies heterogeneity and Successfully isolate the different reservoir compartments then run into prediction to assess the potential of the existing well-stock and any future development plans in Serpent field.
Case Study of Self-Adjusting PDC Bit Technology Reducing Drilling Dynamics, Improving Performance and Avoids NPT in the Western Desert of Egypt
Authors: Hafez Mohamed , Aboulfotouh Mohmoud , Abd El Moneim Mohamed 
Published: November 2019

Abstract
The 12 ¼" section in the western desert, Bapetco concision is challenging to be drilled as of the highly interbedded carbonate and shale formations, which are known to exhibit high levels of vibrations (torsional and lateral) associated with high drilling torque. Such high drilling torque lead-to increasing the Mechanical Specific Energy (MSE), reduction in Rate Of Penetration (ROP) and early dull for used bits. While in some cases it can even lead to twist-off incidents and major Non- Productive Time (NPT) events.
Customer NPT can cost up to $ 450k in case of sidetracking the well. In case the Bottom Hole Assembly (BHA) stands the vibration level, the parameters would have been controlled losing ROP which resulting in lost time that cost at least $ 35K.
The solution of adjusting the depth of cut downhole (Self-Adjusting) which have been newly introduced to the market targeting to decrease downhole vibrations, specially torsional vibrations and allow smoother transition between lithologies with different compressive strength and help in a smooth transition between the different layers while optimizing the depth of cut control
When the self-adjusting feature engages with rock for steady state drilling, the feature gradually retracts, controlling DOC to find the optimal exposure of the element for the current drilling parameters and formations. As dynamic instabilities occur, the self-adjusting feature reacts at fast time scales to mitigate the event. This should result in optimizing the bit response to deliver the best performance real time, decreasing the torsional vibration, NPT & MSE. This will lead to increase the drilling efficiency. The 12 ¼" PDC bit with the self-adjusting was tested with one Shell/Bapetco in the western desert wells, resulting in decreasing the vibration levels, decreasing the MSE hence increase the ROP 57% compared to average of the field which resulted in significant reduction to the drilling cost compared to the offset wells while achieving 35K of savings compared to the best offset
Below will present how the latest self-adjusting PDC technology had a significant impact on drilling time and cost savings by mitigating drilling dysfunctions that could result in unplanned trips and drilling inefficiencies if not addressed in a timely manner
Transforming Local Sands into a Reliable, Alternative Proppant Source
Authors: Khamatnurova Tatyana , Nguyen Philip , Inyang Ubong , Shen Dong , Gashimov Ruslan , Larsen Travis 
Published: November 2019

Abstract
An abundant supply of low-cost local sands and their associated logistical advantages have incentivized operators over the last couple of years to use them in hydraulic fracturing treatments of unconventional reservoirs. Local sands are known for their low crush strength and high angularity and can contain other mineral particulates, besides quartz, compared to high-quality sands. This paper describes laboratory tests to demonstrate that low-quality sands, when treated with a binder, can generate stable, highly conductive channels within a simulated propped fracture, which could help maximize and also maintain production of hydrocarbons from the reservoir.
Laboratory experiments were conducted to evaluate the performance of local sands when used in aggregate structures, simulating proppant ridges or partial packs formed in a propped fracture. These aggregates were formed by coating sand grains with a binder and placing them in molds to be cured before testing. The sand aggregates were then placed in API conductivity cells to determine the effect of closure stresses on aggregate height, size expansion, binding agent concentrations, and conductivity measurements. Cyclic stress testing was also performed to evaluate the stability of the aggregate structure and conductivity retention of flow channels as the aggregate was subjected to varying stress loads.
The results obtained during this study indicate that the flow capacity of conductive channels prepared from proppant aggregates using local sands is comparable to those prepared using high-quality sand or high-strength manufactured proppant. Fines migration from proppant crushing within the aggregate was observed not to be a concern because sand grains connected and encapsulated by the binder helped lock the crushed sand together. Despite having diminishing permeability within the aggregates, flow capacity of solids-free channels between aggregate masses dominates flow through the propped fracture, making formation of proppant aggregates with high-quality sand or high-strength proppant (HSP) unnecessary.
This suggests that using local sands, despite their low crush resistance, during fracturing treatments can effectively enable well production by forming highly conductive voids or channels on top of the settled sand packs in the propped fractures in a shale reservoir.
Development of Novel Composition for Controlling Moderate to Severe Losses
Authors: Wagle Vikrant , Kalgaonkar Rajendra , AlYami Abdullah , AlKhalaf Sara 
Published: November 2019

Abstract
The loss circulation composition comprising the nanosilica based dispersion and a chemical activator has been designed to treat moderate to severe losses. The nanomaterial used in this loss circulation composition is an environmentally friendly material and a chemical activator. The loss circulation composition is so designed so as to give delayed gelling of the nanoparticle based dispersion. A major advantage of this technology is its ability to place the loss circulation treatment composition in to the target loss circulation zone before the nanoparticle based dispersion gels up. Premature gelling of the nanoparticle based dispersion would avoid premature setting of the treatment fluid before it reaches the target zone. The newly developed system can be used effectively up to 300°F.
In this paper, experiments have been performed with three different types of nanoparticles differing in their surface charges and particle sizes. Two negatively charged nanoparticle-based dispersion with a particle size of 5nm and 17nm respectively and one positively charged nanoparticle with a particle size greater than 17nm have been evaluated as loss circulation materials. Two different types of chemical activators, one organic and the other inorganic have been used in this study and their effect on the gelling time has been evaluated. The gelling time experiments have been done at four different temperatures viz. 150°F, 200°F, 250°F and 300°F. The effect of activator concentration and different shear rates on the gelling time of the three nanoparticle-based dispersions has been studied. Permeability plugging tests have been performed on the three nanoparticle-based dispersions using 2mm slotted disks and their effectiveness in controlling moderate to severe losses has been evaluated
The loss circulation composition can be designed so as to control its gelling time by adjusting the activator concentration. The results show that a specific gelling time of the loss circulation composition can be obtained to achieve a predictable and controllable pumping time. This pumping time can range from a few minutes to several hours at over a wide range of temperatures. A predictable gelling time would allow the nanoparticle-based dispersion to remain pumpable for sufficient time before being placed in the loss circulation zone. The loss circulation composition which turns from a liquid to a gelled solid is then expected to seal off the loss circulation zone and thereby prevent fluid loss.
Best Operational Practices to Optimize the Time & Cost for Drilling in Appraisal Unconventional HP/HT Wells Across Deyab Formation, Abu Dhabi - UAE
Authors: Ruiz Fernando , Hebish Ayman , Negoi Adrian , Al Hendi Mohammed , Hamdy Ibrahim , Nunez Ygnacio , Mandal Vivekananda , Al Samahi Musabbeh , Al Hadidy Khaled , Al Awadhi Eman , El Yossef Bassem , Coscia Marco 
Published: November 2019

Abstract
This paper has the recommended procedures to be carried out in each phase: Surface, Intermediate I and II, horizontal and completion with frac string, for Unconventional Appraisal HP/HT wells across Deyab formations in Abu Dhabi (UAE), as well as the technology to be used and avoid, to drill the wells saving time and money helping to make a rentable project.
Due to the information received of the zone was scarce, in addition the first well in the area (offset well and taken as a reference) had many operational problems. The operations during drilling the next three wells in PAD # 1 were recorded, analyzed and optimized, resulting in a learning catalog for the area, saving a considered quantity of rig days with a huge impact in the budget and the most important, the exposure of the crews/people at the location was minimized to this hazard environment.
The PAD# 1 has 03 horizontal wells, the design is Heavy Casing Design, where each phase has its characteristics to be drilled and cased. The reservoir consists of 03 cl early identified formations: Jubaila, Hanifa and Tuwaiq Mountain into the range from ± 12330 ft. TVD to ± 12900 ft. TVD. Reaching the targets with horizontal wells from 16,000 ft. MD to 17,500 ft. MD.
After analyzing each section and getting the recommendations from different service companies and specialist, the changes were implemented in the next well regarding drilling fluid MW, BHA's design, bit type & design, wiper trips, slurries, trajectories, etc. taking as result drilling wells more complicate d without operational issues, in deepest formation, drilling more than 1000 ft. MD and 600 ft. TVD, and saving 3.25 MM$ and 15.2 days per well
The PAD # 1 in Deyab field, is the pioneer for the initial development of fracking in UAE. There hasn't had a drilling procedure in detail to reach the target without having issues. This new concession has been already of interest to be developed in conjunction with the National Company, so create a Drilling Learning Catalogue as add value at the moment to handover the wells is a must.
High Resolution Reservoir Quality Prediction at the Reservoir Scale Through Diagenetic Modelling
Authors: Ortenzi Andrea , Camocino Davide , Daturi Cristina , Geloni Claudio , Pontiggia Marco , Valdisturlo Antonio 
Published: November 2019

Abstract
The reservoir quality prediction is carried out at the exploration scale through software that try to model the diagenetic evolution of the reservoir. The input data are quantitative petrographic data, core analysis results and the burial and thermal history of the wells either 1D or 3D (PSM). The procedure starts from the calibration of the model on a well with cores or sidewall cores for petrographic-diagenetic data and RCA and with a calibrated burial and thermal history. Once calibrated, the model extends to the whole area of interest following the 3D burial and thermal history model of the reservoir.
The extension of the approach to the reservoir scale requires a dedicated work-flow that comprises the following points: -Identification of the main diagenetic issues from petrographic studies;-Use of the information coming from logs of the non-cored wells in a diagenetic perspective; this step comprehends the realization of detailed CPI of wells and, if necessary, additional mineralogical analyses in order to fix a valuable mineralogical model;-3D burial and thermal history reconstruction at the reservoir model scale using the reservoir model surfaces; the step implies the reconciliation of the regional explorative model with the layers and cell dimension of the reservoir one;-Modelling of specific diagenetic phenomena through transport-reaction models, in order to assess the areal distribution of diagenetic drivers in the reservoir to be used as trends; as an example, carbonate cementation though faults is one of the issues; in this step, also the structural evolution of the reservoir is a key point;-Reservoir quality prediction maps of the reservoir layers;-Use of the maps as soft drivers in the reservoir models and results comparison with other model scenarios (e.g. inversion-based model) ;-Evaluate the match with model prognosis and new well results
The work-flow was applied to a Cretaceous reservoir in West Africa. The reservoir quality variations are usually subtle at the reservoir scale and the effect of local variables may be strong. The resulting reservoir quality maps provided trends for properties distribution in the reservoir model obtaining remarkably different results compared to the inversion-based distribution and providing additional data for uncertainty analysis.
The reservoir quality prediction at the reservoir scale implies a new approach to the diagenetic problems and to the integration of log and petrographic data. The work-flow has to encompass all data in a collaboration space in order to produce a valuable tool for reservoir models.
Carbon Composite Rod Deployment System Enables Surveillance and Intervention Operations in Extended Reach, Maximum Reservoir Contact Wells that were Previously Inaccessible
Authors: Troup Duncan 
Published: November 2019

Abstract
Current drilling practice allows the drilling of wells whose horizontal drain sections maximise reservoir contact by remaining within a single productive zone. The well path may include sharp azimuth changes, which increases friction drag along the wellbore and precludes access and egress by conventional intervention techniques. This paper aims to demonstrate that a low weight, low friction and high strength carbon composite rod can reach the toe of even the most challenging profile of well.
A carbon composite rod of small diameter and containing an embedded electrical conductor is used in combination with standard tractors to deploy logging or other intervention tools into challenging wells. In such wells, the limiting factor for well intervention is the friction drag of the deployment system along the wellbore, especially where azimuth changes. The light weight of the rod combined with its extremely low friction coefficient means that drag is reduced to a minimum allowing access to TD while also ensuring safe retrieval without exceeding safe working load.
The carbon composite rod system has been used on a number of interventions that provide proof of concept for combined operations with a tractor in horizontal well systems. In each case the well and BHA was extensively modelled using the proprietary software designed specifically for the carbon composite rod system. In one case the objective was to maximise the payload that could be conveyed rather than the absolute depth achieved. Following extensive modelling including tractor performance, a toolstring measuring 459ft and weighing 7,260lbs was selected and run successfully in a horizontal well. The predicted behaviour compared very favourably to the data recorded during the job, confirming the accuracy of the models.
For an extended reach well where the objective is to obtain production and reservoir data all the way to the toe, the relatively small size and weight of the logging tools means that achievable depth is increased. A number of wells with challenging profiles that had never been successfully logged post completion were modelled using the latest software and operational parameters derived from recent experience. In each case, it was predicted that TD could be achieved and that the string could be safely retrieved from the well.
Demonstrating the convergence of predicted and actual performance of the carbon composite rod under a number of scenarios gives confidence in the validity of the models incorporated in the simulation software. Using these models to predict the performance in extended reach wells, especially in the cases where there are significant azimuth changes, will allow planning for rigless interventions where access or successful retrieval has been impossible up until now.
State of the Art Approach on Mega Rich Gas Condensate Development: Sectorization Approach - Case Study, ADNOC Onshore Fields, UAE
Authors: Al Awadhi Fatima , Al-Ameri Ammar , Al Bairaq Ahmed , Mohamed Ihab , Latypov Eduard , Sudarev Maxim , Pramudyo Yuni 
Published: November 2019

Abstract
The study was conducted for Giant Gas-Condensate reservoir under Recycling mode in order to achieve the high condensate recovery and maintain the reservoir pressure by sectorize the reservoir into the different sectors. Especially with under-injection mode when no make-up gas is availableor sellable gas is required. The available amount of gas for injection should be properly distributed across the reservoir to maintain the reservoir pressure where it is most required and same time to prevent the early gas breakthrough. The study was aimed to sectorize the reservoir into thedifferent sectors which will lead to improve the reservoir management including the re-distribution of injection and full field development strategies.
The two approached have been created for sectorization: first approachwas based on the geological definition and second approach was based on the well level optimization. Many reservoir data have been utilized in this study including the surface facilities layout.
Initially, the available geological data such as Facies has been used to generate the above explained approaches. The actual tracer and other production/injection data used to confirm the above explained sectorization. Finally, the simulation model was re-build to address the sectorization. Moreover, several sensitives were simulated assume the 50%-80% RecycleRatio to come up with the optimum setup for gas injection distribution for the existing wells including the newly 2018 commissioned peripheral gasinjectors.
This work has resulted in positive outcome with few millions additional condensate recovery with zero investment. According the outcomes analysis the implementation plan is designed with allowable per each gas injector.