bluuebunny/crossref_metadata_2025_split huggingface dataset:
Development and Field Testing of a Novel Multifunctional Drilling Enhancement Tool in a Middle East Field
Authors: Abdel-Aal Mohamed Ahmed , Mohamed Fahd Mohamed , Abdelkader Ahmed Galal , AbdulLatif Mohammed AbdulHamid , Koulidis Alexis , Ahmed Shehab 
Published: January 2020

Well drilling and wellbore conditioning typically involve multiple specialized drilling tools. Systematic application of such tools can be a challenge from a logistics and maintenance perspective, which eventually has an impact on the efficiency of the drilling process as well as the resulting wellbore condition. This paper presents a new multifunctional drilling tool developed to address such operational challenges. The tool’s effect on the drilling and logging process is illustrated through a field case study.
The CRS is a multifunctional drilling tool able to Cut, Ream and Stabilize when installing in a BHA. It is envisioned as an integral bottom hole assembly (BHA) component replacing the uppermost stabilizer while selectively acting as a fixed blade cutter, roller-reamer, lateral vibration damper, friction reducer, stabilizer and/or key-seat wiper. The specific function is dependent on wellbore conditions and is passively activated or engaged during operation. The CRS was successfully field-tested in a middle east field late 2018. Offset well data were used to validate the effectiveness of the tool and provide recommendations for future development.
An offset well was used as a benchmark for comparison to characterize CRS performance. The CRS replaced the stabilizer directly above the measurement while drilling (MWD) tools as part of the BHA used for drilling the interval from 1800 to 2520 meters. When compared to the offset well, the tool had no negative effect on trajectory or dogleg severity. Tight spots required significant back-reaming in the offset well during pull-out-of-hole (POOH). Using the CRS saved 63 hours of rig time when POOH due to the tool’s effective tight spot cutting capability. High torque fluctuations ranging between 2 to 13 klbs-ft were observed in the offset well while drilling formations mainly composed of sticky claystone and limestone. The resulting poor wellbore quality rendered significant logging challenges. The CRS’s ability to damp lateral vibration while engaging in its reaming function resulted in the mitigation of these challenges. Another innovative feature of the CRS’s reaming function is the complete elimination of cutter loss risk. The CRS body is, by far, the industry’s largest area bearing mounted reaming structure and its concentric design eliminates the possibility of it being lost in the hole. The CRS body rotates in response to lateral vibration and drill string whirl when in a vertical or deviated wellbore, effectively contributing to the damping of both vibration modes. The body acts as friction reducer at high deviations. The rotating body also translates on the tool mandrel when faced with a tight spot or pack-off. This translation is opposed by a unique spring assembly that can deliver full top drive torque to the body to cut through the formation.
Synthetic Well-Log Generation: New Approach to Predict Formation Bulk Density While Drilling Using Neural Networks and Fuzzy Logic
Authors: Gowida Ahmed , Elkatatny Salaheldin , Abdulraheem Abdulazeez , Shehri Dhafer Al 
Published: January 2020

Synthetic well-log generation using artificial intelligence tools is presented as a robust solution when the logging data are not available or partially lost. Formation bulk density (RHOB) logging data greatly assist in identifying downhole formations. It is measured in the field using density log tool either while drilling by logging while drilling technique (LWD) or mostly by wireline logging after the formations are drilled because of the operational limitations during the drilling process.
Therefore the objective of this study is to develop a predictive tool for estimating RHOB while drilling using artificial neural networks (ANN) and Adaptive network-based fuzzy interference systems (ANFIS). The proposed models used the drilling mechanical parameters as feeding inputs and the conventional RHOB log-data as an output. These drilling mechanical parameters including the rate of penetration (ROP), weight on bit (WOB), torque (T), stand-pipe pressure (SPP) and rotating speed (RPM), are usually measured while drilling and their responses vary with different formations.
A dataset of 2400 actual data points obtained from horizontal well in the Middle East is used for building the proposed models. The obtained dataset is divided into 70/30 ratios for training and testing the model respectively. The optimized ANN-based model outperformed the ANFIS-based model with correlation coefficient (R) of 0.95 and average absolute percentage error (AAPE) of 0.72 % between the predicted and the measured RHOB compared to R of 0.93 and AAPE of 0.81 % for the ANFIS-based model. These results demonstrated the reliability of the developed ANN model to predict the RHOB while drilling based on the drilling mechanical parameters. Afterwards, the ANN-based model is validated using unseen data from another well within the same field. The validation process yielded AAPE of 0.5 % between the predicted and the actual RHOB values which confirmed the robustness of the developed model as an effective predictive tool.
New Acid Fracturing Model on Reservoir-Centric Platform for Carbonate Formations
Authors: Kuznetsov Dmitry , Emelyanov Denis , Romanovskii Rostislav , Khudorozhkova Aleksandra , Oussoltsev Dmitri , Nakamura Fabio 
Published: January 2020

Acid fracturing is a widely accepted method for stimulation of carbonate reservoirs. A new high-resolution fracture hydrodynamics and in-situ kinetics model integrated on a reservoir-centric exploration and production platform improves acid fracturing simulation accuracy and performance for completion, stimulation, and reservoir engineering groups. This paper describes key features of the new acid fracturing model and the workflows that have been enabled on the E&P platform.
We demonstrate that the new acid fracturing model can simulate the key effects of acid fracturing at a new level of fidelity and quality. For example, it reproduces viscous fingering effects that occur naturally when alternating fluid systems of different viscosities are pumped into the fracture. The model simulates diverting agents that reduce leakoff in the fracture area and their effects on fracture geometry. Combining the 3D earth model in the E&P platform and high-resolution simulator allows the modeling of small-scale heterogeneities that affect fracture conductivity with a high level of accuracy. The model is also capable of simulating hybrid acid-proppant treatments. Finally, a fluid and materials database is incorporated to capture the impact of modern acid systems and diversion agents. The new model was validated against the results of laboratory experiments and published data. The first results of the platform stimulation-to-production workflow implementation are presented for a formation with high calcite content. The new approach enables engineers to evaluate completion and stimulation designs directly by quantifying the impact on hydrocarbon production and seamlessly integrates carbonates completion design and reservoir engineering disciplines.
The novel high-fidelity approach to acid leakoff, diversion systems, and rheology of different fluid mixtures significantly extends the design and evaluation tools for acid fracturing treatments in carbonate formations. Integrating the acid fracture model and E&P platform enables simulation of multiple acid treatments all the way to production evaluation and opens the path towards optimal design of single- and multiple-well treatments.
Application of Statistical Analysis to Optimize Rate of Penetration
Authors: Abbas Ahmed K. , Alqatrani Ghassan , Al Saba Mortadha , Mohammed Haider Q. , Al-Bazzaz Waleed 
Published: January 2020

Drilling optimization consists of selecting operational parameters that maximize a desirable rate of penetration (ROP). There are many factors, which determine the ROP. Typical factors include rig- and bit-related parameters, formation properties, and drilling fluid properties. To be able to maximize ROP successfully, it is critical to develop a deep understanding of the relationship between controllable drilling parameters and ROP. To this end, ROP model was developed based on statistical analysis method using the key parameters that can be modified quickly to adjust the ROP.
This study describes a statistical evaluation of wells drilled in Southern Iraq. The analysis attempted to discover the key operational drilling parameters that drive well-optimizing drilling operations. Some key questions to be addressed include: What is the wellbore trajectory (azimuth (AZI) and inclination (INC)) that could result in better drilling performance? What is the effect of total flow area (TFA) on drilling performance? What is the effect of the rig- and bit-related parameters on drilling performance? Is there a relationship between marsh funnel viscosity (MFV), plastic viscosity (PV), yield point (YP), and drilling performance? These and more questions were addressed in this study. This study supplies knowledge that can be used to conduct drilling optimization study and determine the optimum controllable drilling parameters that maximize ROP and economic objectives.
A Stochastic Approach to Economic Modeling of Unconventional Resource Play
Authors: Abdulazeez Mehaboob , Rabines Jaime , Siddiqui Ammar , Bukhamsin Khadija , Asiri Rawan 
Published: January 2020

In unconventional reservoirs, not only do we have to concern ourselves with having a sufficient hydrocarbon volume to justify development (Resource Fairway), but also whether producibility characteristics, especially the ability to effectively fracture stimulate, are favorable (commercially). While volumetric characteristics tend to be regionally variable resulting in changes in hydrocarbon fluid types, reservoir pressures, thickness, porosity, saturation, etc., at the basin scale, producibility characteristics tend to be more locally variable resulting in changes in natural fracturing, subsurface stresses, permeability, effectiveness of fracture stimulation barriers, etc., at the field scale. A stochastic approach encompasses both these trend variations (regional and local) while assessing the commerciality of the play.
This paper will explain the workflow involved in creating a probabilistic model using a commercial tool for engineers to understand the mechanics of the model, quality-check the input distributions, compare the model results to those from other sources (such as empirical, analytical, or numerical models). This workflow also will help in seamlessly modifying the input parameters to generate "what-if" scenarios and stress test the base case of development projects.
Due to the capital-intensive nature of Unconventional projects, it is important to economically model a series of staged-investments. The purpose of the staging is to responsibly expose incremental capital and identify course corrections. Several factors and combination of inputs affect the commerciality of unconventional developments. These inputs will then be sampled using Monte Carlo simulation to generate a multitude of trials and their summary statistics. The recoverable resources, costs, and economics can also be exported for any given trial, and the ranges of input parameters sampled to generate a given trial can also be extracted
Five critical parameters and their ranges were identified for developing a stochastic Before Tax (BTAX) economic output reflecting the full range of outcomes. Well type curves and select components of Capex and Opex were identified as the primary drivers. Associated products, such as condensate, NGLs, ethane, sulfur and water, were modeled as a function of the primary product using dependent ratios. Variability in cycle time was added to account for delays in implementation and acceleration as learnings are applied.
This paper will present how technological integration between legacy in-house developed tools and stochastic analysis engines, as the centerpiece, can provide management the required level of visibility on project economics and evaluation ranges. With the considerable time spared in carrying out economic assessments due to this workflow, engineers are able to spend more time in developing case scenarios, run sensitivities, and analyze outcomes and results to make informed portfolio management decisions.
Modeling and Prediction of Resistivity, Capillary Pressure and Relative Permeability Using Artificial Neural Network
Authors: Ba alawi Mustafa , Gharbi Salem , Mahmoud Mohamed 
Published: January 2020

Capillary pressure and relative permeability are essential measurements that are directly affecting multi-phase fluid flow in porous media. The difficulty of calculating them rises being constrained to core analysis in the laboratory with many challenges of mimicking reservoir conditions. This makes capillary pressure measurement process to be both time consuming and expensive. However, as resistivity is conveniently obtainable, it can be used to predict both capillary pressure and relative permeability given all relation to wetting phase saturation.
Artificial intelligence methods have achieved promising results in modeling extremely complicated phenomena in oil and gas industry. This study aims to find a relation between all of resistivity, capillary pressure and relative permeability. Ultimately, we are going to generate a model by utilizing Artificial Neural Network (ANN) technique to predict both capillary pressure and relative permeability from resistivity. In addition, the implemented technique will be used to improve the data quality and to extend its resolution to thousands of data points. After that, as countless artificial neural network architectures can be created, the most efficient one will be evaluated given its performance and accuracy results.
This paper presents the use of artificial neural network technique to both model and predict capillary pressure and relative permeability from resistivity attained from core analysis, and define core samples pore distribution systems. It was found artificial neural network architecture captures the complexity of the physics of the problem. Thus, it successfully fulfilled the required prediction objective. Additionally, compared to the traditional methods, this is proved to be accurate, fast, and significantly cost effective. Consequently, this process could replace the current traditional approaches. Finally, as artificial intelligence techniques are improving exponentially over time nowadays, this will increase the accuracy of the model predictability majorly.
Detecting Porous Gas Accumulations through Seismic Amplitude Analysis in Paleo-Zoic Siliciclastic Reservoir, Saudi Arabia
Authors: Alwusaibie Abdullah , Mahozi Ali 
Published: January 2020

A siliciclastic gas reservoir is analyzed through two seismic attributes, root mean square (RMS) ampli-tude and reservoir to shadow mono frequency (RSMF) to detect and quantify porosity and gas accumu-lation. The objectives are to apply forward modeling to design the interval for amplitude mapping to de-lineate porosity; to analyze the amplitude of the frequency to generate the RSMF map; and to validate the RMS amplitude map with porosity, and the RSMF map with gas test results.
One well was modeled for two cases, a tight and porous reservoir, to establish an appropriate RMS amplitude extraction window for reservoir porosity. The amplitude around the reservoir was extracted and validated by wells. The seismic volume is decomposed in the frequency domain for the gas detec-tion technique. This technique measures the amplitude attenuation in the dominant frequency between the reservoir level and the zone just beneath it to produce the RSMF map, with the assumption that the frequency amplitude attenuation increases while passing through the gas reservoir. The RSMF map was validated by the normalized gas test results of several wells.
The forward modeling indicates that up to 20 ms below the reservoir is an optimum window to corre-late the targeted reservoir with the RMS amplitude. The RMS amplitude was found to be directly pro-portional to porosity, with the modeled tight reservoir case having lower RMS amplitude than the porous reservoir case within the optimum window. The RMS amplitude response for the modeled tight reservoir case almost matches the in-situ case. There is a correlation coefficient of approximately 70% between the average reservoir porosity of the wells and the RMS amplitude map extracted from the seismic volume within the optimum window. At the dominant frequency of 20 Hz, a correlation coeffi-cient of around 82% is observed between the gas test results and amplitude attenuation. The RMS and RSMF attributes are affected by seismic amplitude preservation as well as signal-to-noise ratio, which can impact the level of uncertainty between these two attributes and the extracted maps.
The integration of RMS amplitude and RSMF attributes complemented the characterization of the si-liciclastic gas reservoir for detecting high porosity zones with gas accumulations. Zones with high RMS amplitude and attenuation were highlighted to be targeted for well placement.
The Use Of Aerated Drilling Fluid Technique Through Top Fractured Formations In A Deep Gas Field - A Case History
Authors: Javay Alexandre , Nafi Mohamed Khalil , Mathur Anil , Alvidrez Levario Jesus 
Published: January 2020

The aerated drilling fluid technique was introduced to a deep gas well drilling project as a solution to overcome the challenges posed by top fractured formations and highly water-sensitive shales. The top holes were originally drilled with a diesel oil-emulsion drilling fluid which was later changed to a high-bentonite content drilling fluid system. The aerated drilling fluid aimed at improving the overall drilling performance and addressing top hole geological complications.
The main objectives behind the introduction of aerated drilling were the mitigation of mud losses in Wasia and Shu’aiba formations and improvement of the penetration rate across the lowermost abrasive Biyadh interval. The aerated drilling fluid technique was successively implemented in four wells in different areas of the field. The system was a mixture of air and polymer-based fluid pumped inside a closed circulation system with the use of a rotating circulating head. The system provided the necessary viscosity to entrap the air downhole while allowing it to easily break out at surface in the separation equipment.
The technique proved to be an excellent solution for drilling through lost circulation zones across the Wasia and Shu’aiba fractured limestone formations. Equally important, this technique delivered much higher penetration rates while drilling across the Biyadh interval.
An effective oil-emulsion system used to be run to lighten the fluid column to prevent losses but was replaced by a high-bentonite drilling fluid for environmental reasons. The latter system was believed to seal the formation fractures due to its high gelation characteristics, thereby preventing losses. Despite being effective at preventing losses, this drilling fluid returned poor performance while drilling compacted clay intervals toward the end of the section. As a result, the casing point had to be set shallower thus complicating achieving the objectives of the subsequent hole section.
The results of implementation exceeded expectations both in terms of ROP improvement and control of downhole losses, reducing the section drilling times by more than two in comparison to the high-bentonite content drilling fluid and up to 35% over the oil-emulsion drilling fluid. This technique was also remarkable in reaching the designed casing point in all sections drilled.
This paper will describe in length the performance of the trial jobs, present the lessons learned from the implementation of this innovative drilling fluid technique and highlight the best practices utilized to make it a cost-effective solution.
Coiled Tubing Gas Lift: An Innovative Solution for Reviving Dead Wells in Southern Pakistan
Authors: Khalid Aizaz , Molero Nestor , Hassan Ghassan , Lovie Eric , Khan Rao Shafin Ali 
Published: January 2020

In southern Pakistan, most wells in mature fields do not flow naturally and require delivery of supplemental energy into the wellbore through an artificial lift system. The existing portfolio of techniques, however, faces technical and economic challenges. Operators have tried numerous methods of deliquification such as soap injection, jet pumps, electrical submersible pumps, and conventional gas lift (GL). Those solutions differ in methodology and efficiency, but they unfortunately have failed either technically or economically in Pakistan.
Because reviving dead wells is key to maximizing production with the most efficient and cost-effective method in Pakistan, a detailed screening of candidate wells was carried out to identify innovative artificial lift solutions. The deployment of GL valves using coiled tubing (CT) soon emerged as the best option, because it offered the highest returns in a cost-benefit analysis. Coiled tubing gas lift (CTGL) is a rigless solution that enables setting GL valves at the required depth, during any stage of a well life. It allows gas to be injected through CT with production through the CT-to-tubing annulus. This technology is also retrievable and replaceable when needed.
Two pilot wells, that had been shut in since 2015, were selected from four shortlisted candidates through nodal analysis. Each system consisted of one CT string with multiple stations of unloading and orifice valves, spaced out at depths engineered to maximize each well’s productivity. In addition to a GL valve, each station included two CT external connectors and one self-aligning connector, which enabled efficient and safe connection between both CT ends during the deployment of the CTGL station.
Additionally, specific CT pressure control equipment and wellhead adapters were used to secure and hang the CT string in the production tree and provide connection with the gas injection facilities at the surface. The first installation was conducted in a vertical well originally completed 4 1/2-in. monobore, deploying 1 1/2-in. CT string with four CTGL stations. The second installation was performed with 1 1/4-in. CT and five CTGL stations in a well originally completed with 7-in. liner and 2 7/8-in. production tubing. The wells were commissioned using existing surface infrastructure and were unloaded smoothly until the production stabilized at optimum rates near 420 B/D and 325 B/D respectively.
This innovative artificial lift technique represents an effective and economical solution to restart production in mature fields where conventional artificial lift methods challenge well economics. This approach greatly rests on a thorough candidate selection process. The design and installation of two new CTGL systems was a first in the Middle East region and helped identify numerous best practices and lessons learned, which will speed up implementation of the methodology in other parts of the world.