bluuebunny/crossref_metadata_2025_split huggingface dataset:
Maximizing Recovery by Integrating an Advanced Reservoir Simulation Approach into the Drilling Process of Horizontal Wells
Authors: Salim D. , Couto P. , Alves J. L. , Freitas E. , Haq S. , Denichou J. M. 
Published: September 2015

Abstract
The successful drilling of horizontal wells is extremely difficult, mainly due to lithological discontinuities and seismic uncertainties. To overcome such challenge, Well Placement technique is used to interactively position the well based on geological and seismic criteria together with LWD measurements. While covering drilling, geology and geophysics, most Well Placement approaches rarely consider reservoir engineering aspects. This paper presents an innovative methodology that integrates reservoir engineering into Well Placement workflow to improve well's productivity performance.
The applied method is based on advanced 3D modelling, where by means of numerical reservoir simulations, productivity predictions are performed not only on the planned well but also at the executed trajectory. To increase prediction accuracy, a refined gridding with variable cell size technique is applied to enhance pressure and saturation sensitivity. The level of precision is improved by using LWD measurements, such as most precise formation pressure, permeability near wellbore and remote boundary mapper technology that provides a detailed reservoir structure based on formation resistivity contrast.
This methodology was employed in a real case study of a horizontal well drilled in an offshore sandstone field in Brazil. As common occurrence in Well Placement operations, the executed trajectory had significant geometrical differences compared to the planned one. For both planned and executed wells, a detailed reservoir model was created using the inputs of LWD measurements. Numerical simulations were then applied to both wells in order to evaluate the impacts caused by the trajectory variations, showing the expected productivity results versus the actual ones obtained at the drilling operation. The results demonstrated indeed a major productivity impact in all reservoir fluids when a well trajectory is subjected to geometrical changes. However, only through the use of this integrated approach could such impact be quantified, since the traditional Well Placement methodology cannot determine the effects on the productivity response based only on the geological and petrophysical aspects.
The work delivers a novel ability to construct optimal horizontal wells not only by including conventional Well Placement technique, using geological and geophysical criteria, but also by introducing into the workflow an advanced numerical simulation approach. Such integration allows the operator to predict the impacts on the productivity as the trajectory is being changed, and the actual reservoir geometry and its properties are determined by LWD measurements.
Performance Evaluation of First Horizontal Well Implementation in Tight Carbonate Reservoir Yields Critical Results in Western Desert, Egypt
Authors: Salah Mohamed , Bereak Ahmed , Gabry M. A. , Gallab M.. , Fattah S. I. 
Published: September 2015

Abstract
Abu Roash-D (AR-D) is a common carbonate reservoir in Abu Gharadig (AG) field, Western Desert of Egypt. It is characterized as a limestone reservoir which has good lateral continuity, contains natural fractures with poor connectivity in addition to formation tightness. The heterogeneity and tightness of AR-D reservoir are the main challenges to maintain economical well productivity.
Initially, Several vertical wells had been drilled in AR-D reservoir and stimulated via matrix acidizing, but could not achieve or sustain the economical target production rates. Recently, two vertical wells were acid fractured as a trial to produce conductive fracture with sufficient length to allow more effective drainage around the wellbore, but test results showed higher flash production of 3,000 BOPD then rapid decline and low recovery occurred. This awesome results encourage embarking on field development and additional production data gathering for development optimization. The large interest in developing such low permeability reservoirs has been a direct result of the favorable economics achieved by the advancements in horizontal well drilling and stimulation technologies hold great promise to increase production by dramatically increasing the contact area with the producing interval, maximizing the drainage volume around a well and link those natural fractures network.
So, In order to economically develop AR-D reservoir resources a comprehensive parametric study was conducted on low permeability AR-D reservoir of western desert (through gathering of additional data during the development a major reservoir, the review of the core and test permeability data across the reservoir as well an evaluation of the uncertainties and associated development risks) has documented some critical results, showing the productivity index ratio between stimulated vertical and horizontal wells illustrates the improvement to be obtained from higher reservoir contact.
This paper takes a multidisciplinary approach to better understand how to enhance the productivity of low permeability AR-D reservoir in Western desert of Egypt through a detailed analysis of well performances and exploitation approaches after the successful Implementation of horizontal wells to maximize drainage volume around the well to revive low producing wells due to reservoir tightness and discuss the actual performance of the horizontal wells and compares them with the offset conventional vertical wells and highlights the productivity gain.
Pressure Drop Due to Multiphase Flow Using Four Artificial Intelligence Methods
Authors: Attia M.. , Abdulraheem A.. , Mahmoud M. A. 
Published: September 2015

Abstract
The evaluating of the pressure drop due to multiphase flow in vertical pipes and inclined pipes is crucial for oil and gas industry. Numerous correlations and models have been developed to calculate the pressure drop in vertical wells but the effectiveness of these models is still under debate. Most of the correlations and models were developed to calculate the pressure drop due to multiphase flow based on accurately and reliably measured flow parameters. However, they can work best within the proposed data ranges. Their accuracy degrades if they are used for data out of the measured ranges.
Artificial Intelligence (AI) has proven to be an alternative solution to many of the problems where physics and classic statistics fail to provide satisfactory solutions due to limiting assumptions and complicated reality. Different AI methods, viz., Fuzzy Logic (ANFIS), Neural Networks (ANN), Support Vector Machine (SVM), and Decision tree (DT) were used in predicting the multiphase flow pressure drop in surface pipeline and production tubing for oil fields. 239 published real field datasets were used in constructing the flow line model and about 795 datasets were used to construct the pressure drop from the well head pressure to the bottom hole flowing pressure (tubing model).
The models were tested by dividing the data into three categories:, (60%) were used for training and (15%) for validation, and (25%) for testing. The results of testing showed that ANN, ANFIS, and SVM give better predictions than the common correlations in case of pressure drop from the wellhead to the GOSP (flow line) or from the wellhead to the bottom hole location (tubing). The average absolute percentage error (AAPE) was 1.15% for ANN, 0.39% for ANFIS, and 9% for SVM, and 77% for DT for the flow line model and the error was 3.8% for ANN, 4.5% for ANFIS, 4.3% for SVM, and 3% for DT for the tubing model.
Experimental Investigation of Alkaline/Surfactant/Polymer (ASP) Flooding in Low Permeability Heterogeneous Carbonate Reservoirs
Authors: Shedid Shedid A. 
Published: September 2015

Abstract
Carbonate reservoirs have been recognized as very heterogeneous formations due to complex depositional environments, which complicate application of Alkaline/ Surfactant/Polymer (ASP) process.
The main objectives of this study are to (1) present progress of screening criteria for chemical EOR processes, (2) investigate the feasibility of Polymer flood (P), Alkaline/Polymer (AP), Surfactant/Polymer (SP), and Alkaline/Surfactant/Polymer(ASP) processes in low permeability carbonate reservoirs, (3) study the effect of using high concentration of surfactant in the ASP slug on oil viscosity and attained recovery, and (4) study the effect of initial oil saturation at the start of the ASP process on the oil recovery. Actual crude oil, formation brine, and low permeability carbonate reservoir samples are used to undertake this experimental study. Viscosity, pH, and Interfacial tension (IFT) for oil-water, and different chemical systems are measured. Additionally, eight core flood experiments are carried out to test different formulated chemical slug volumes and concentrations on oil recovery.
The results indicated real progress in screening criteria of polymer EOR processes and thier successful applications in lower permeability reservoir (&gt; 10 md). This study proved that ASP process is successfully applied as an enhanced oil recovery in carbonate reservoir having permeability less than 5 millidarcy (md). Moreover, addition of sodium hydroxide (NaOH), or surfactant (F75N) in polymer constituting a single slug has important effects on viscosity and pH of the different chemical slugs applied.
The results also pointed out that the application of ASP process at higher mobile oil saturation leads to higher oil recovery than when applied at later stages of water flooded low permeability carbonate reservoirs. In addition, Alkaline/ Surfactant/Polymer (ASP) process has successfully recovered the highest recovery in comparison to other chemical processes. The application of the attained results develops a new window for more applications of chemical EOR processes in lower permeability carbonate reservoirs.
Innovative PDC Drill-Bit Cutter Technology Leads to Performance Improvements in Western Desert, Egypt
Authors: Ismail Ahmed , Stockey David , DiGiovanni DiGiovanni , DiGiovanni Anthony , Burch Connie , El-Moniem Mohamed Abd , El-Desouky Waleed , El-Sawy Ahmed , Galal Mohamed 
Published: September 2015

Abstract
The ongoing drilling campaign for an operator drilling in Egypt's Western desert area involved drilling vertical and directional wells approximately 5,000- to 5,500-m deep. The application involved drilling through very hard and abrasive sandstones, and intercalations of shale, sand, silt and dense dolomite inter-beds of about 25,000 psi unconfined compressive strength (UCS). Historically, poly crystalline diamond compact (PDC) drill-bit showed inconsistent bit performance that included premature bit failure and low rate of penetration (ROP), resulting in costly bit trips to the surface.
New and improved bit technology was required to improve the penetration rate and footage to reduce bit trips to the surface and improve the overall drilling performance. An in-depth study of the formation properties, wireline logs, drilling parameters and bit dull analysis was performed. Detailed analysis identified this application can benefit from running cutters with a non- planar cutting face on a field-proven seven- blade PDC bit frame. The bit was run on a Rotary Steerable System (RSS) coupled with a positive displacement motor (PDM) on top of the BHA to further improve the drilling efficiency and overcome any challenges.
Upon deployment, the 8½-in bit design with the new 16-mm cutters with non-planar cutting structure combined with optimized depth-of-cut control, stability, hydraulics efficiency and balling prevention features led to improved performance when drilling the complex, hook-shaped well profile (where torque and drag were an issue in the past). Compared to field offsets, the bit drilled very smoothly and aided the operator in placing the well in the correct direction with minimum bit- torque caused from bit and formation interaction. Offset bits fail to achieve the required directional plan in the past because of the severe nature of drilling in the area.
This integrated solution resulted in a 15% improvement in the ROP as compared to the offsets and a 57% improvement in footage drilled. This performance replaced six drill bits, which were used to drill the same interval in the offset wells. The new innovative PDC cutter technology saved the operator at least USD 250,000 from the planned authority for expenditure (AFE) cost, as well as set two consecutive footage records. This paper outlines the problems in drilling this challenging area, the thought process behind using the various technologies incorporated in the PDC bit design and the keys to overall success.
Borehole Stability and Field Stress Analysis with Azimuthal Logging-while-Drilling Technology: A Case History
Authors: Azim Shaikh Abdul , Chowdhuri Sankar , Sahib Mohammad Raffi , Mohammad Tarek Abdel , Abdulkarim Anar , Samie Mohamed , Aki Ahmet 
Published: September 2015

Abstract
Real-time azimuthal acoustic measurements were introduced recently in the logging-while-drilling (LWD) industry. For the first time, this technology was used as part of the bottomhole assembly (BHA) to acquire information related to principal stress orientations in the deltaic to marine Zubair clastic sequence of onshore Kuwait.
A deviated 8.5-in. hole section of the well was planned through sand-shale sublayers with a borehole inclination ranging from 46 to 88°. This section is characterized by time sensitive borehole deterioration and significant variations in pore pressure. These factors result in severe hole instability and ultimately stuck pipe events and require relatively high mud weights to maintain wellbore stability. LWD azimuthal acoustic technology, free from chemical sources, was used for the first time both in drilling and wipe modes to facilitate time-lapse field stress and wellbore stability analysis.
Principal stress orientations were identified from three different sources, including borehole breakouts from azimuthal acoustic caliper, density image, and acoustic anisotropy evaluation. The results were then compared with the existing offset well data and an existing geomechanical 3D model. Variations in observed stress orientation, seismic reflection pattern, and pressure history in offset wells were used to map a fault that is responsible for bypassed oil and for the occurrence of tar and gas. The interpretation was extended to other low throw strike-slip faults; additional fault compartments were identified that could affect the pressure maintenance scheme of the field.
This paper discusses the planning, design, and use of LWD azimuthal acoustic technology in this case history well. It also describes the viability, integrity, and reliability of the interpreted results and their use in a detailed geological interpretation in terms of stress orientation, fault trapping, and areal fluid variation. The optimization of real-time drilling operations and petrophysical data acquisition requirements are also investigated to improve future field development and overall reservoir management strategies.
Optimal Field Development of Immature Clastic Heterogeneous Brownfield with Waterdrive: Subba Field, South Iraq Case Study
Authors: Al-Khazraji Ahmed Khalil , Shuker Muhannad T. 
Published: September 2015

Abstract
This paper presents an optimization analysis of different development options of Nahr Umr reservoir in Subba oilfield. Nahr Umr reservoir is a highly heterogeneous clastic reservoir with moderate edge a bottom waterdrive and it has a short production history for six months. Many different development scenarios have been conducted in this study to test possible predictive scenarios to determine the most significant development option. The black oil commercial software simulator, Eclipse-100 was used to study fluid flow in the reservoir and to predict the future behavior of reservoir. The prediction scenarios considered in this study include, natural depletion through the existing wells, determine the optimal number of infill producers, and waterflooding option through conducting peripheral and five-spot patterns. The development plan assumed to commence at January 2017, then couple of runs using simulator flow model were conducted for ten years. The waterflood sceneries startedup on January 2023 and January 2027 for inverted five-spot and peripheral patterns respectively with 58 producers and 66 injectors for peripheral pattern and 102 producers and 77 injectors for inverted five-spot pattern. The results are analyzed based on economic criteria to optimize the number of infill drilling. The optimization of development options was achieved based on net present values analysis.
Supramolecular Viscoelastic Surfactant Fluid for Hydraulic Fracturing
Authors: Yang Jiang , Lu Yongjun , Zhou Caineng , Cui Weixiang , Guan Baoshan , Qiu Xiaohui , Liu Ping , Ming Hua , Qin Wenlong , Ji Sixue 
Published: September 2015

Abstract
This paper studied a new fracturing fluid based on a supramolecular complex of associative polymer and vsicoelastic surfactant. The crosslink complex gel was based on weak physical attractive forces such as van der waals, hydrogen bonding and electrostatic interaction between associative polymer and wormlike micelle of viscoelastic surfactant. The fluid contained surfactant ten times less than that of conventional viscoelastic surfactant fracturing fluid. The combination of viscoelastic surfactant and associative polymer synergistically enhances the viscosity ten times more than that of the individually components alone. The fluid system was optimized by experimental design. The microstructure of wormlike micelle was verified by cryo-transmission electron microscopy. The fluid is shearing-stable at high temperature for 1 hour. The dynamic rheological properties of the new VES fluid showed high viscoelasticity, in which elastic moduli is higher than loss moduli at angular frequency 0.1 rad/s. The proppant transport test in a large-scale fracture simulator showed good proppant suspension ability. The fluid has 50% lower formation damage than that of conventional guar. The fluid was prepared with less additives and formed gel instantly which can be mixed on the fly in the field. The gel can be completely broken with almost no residue. Field application of the new fracturing fluid in a gas field showed the enhancement of gas production over 100%. The fluid has 20% lower friction pressure than that of guar fluid. Hence, the new supramolecular viscoelastic surfactant gel is an effective fracturing fluid with less formation damage.
Integrated Field Management Using Advanced Techniques for Offshore Gas Condensate Field
Authors: Fadel A.. , Safwat H.. , Dabbour M.. , Labib A.. , Belli A.. , Darwish H.. , Nagy M.. 
Published: September 2015

Abstract
Abu Qir Petroleum Company (AQP) is one of the most important gas operators In Egypt. AQP Holds 100% of the exploration, development and production rights of the Abu Qir concession in the Nile Delta offshore. The offshore facilities include six platforms, 34 wells and a network of sea pipelines. Abu Qir Petroleum Company currently is interested in modeling their entire production system from the perforations to the onshore Facility to understand and identify all constraints in the system and the way to improve it. In addition, AQP is interested in identifying any bottlenecks either currently or in the future after adding any platforms or wells according to their intended FDP and to test some operational scenarios like changing terminal pressure, separator pressure, installing compression station, etc.
The main objective of this project is to identify any current and future bottlenecks in the production system while honoring operational constraints on wells, production separators, pipelines, and total field gas/liquid processing capacity and identifying any flow assurance issues taking into consideration different field development scenarios for an offshore gas condensate field in the Mediterranean (Abu Qir Field). In many mature gas fields, reservoir pressure decline as a result of gas depletion tends to lead to the onset of liquid loading. Liquid loading in gas wells occur when the gas flow rate falls below a critical rate due to reservoir depletion where the accompanying liquids cannot be lifted to surface. Such liquid accumulations at the wellbore can cause the gas well to cease production eventually. Transient simulation was used to build transient well models that replicate observed field data, and these models are then used to evaluate specific gas well deliquification techniques.
This document summarizes the methodology and the results of the complementary work carried out to conduct the project. The document presents the methodology to review, evaluate and optimize the offshore production system from reservoir sand-face up to wellhead starting from data gathering and QC up to estimating the missing reservoir parameters needed for well history matching ending with history matched well models and surface network ready for any optimization if the conditions change.
Core Study of Tunisian Late Jurassic Mrabtine Reservoir: Lithological Heterogeneity and Rock Typing
Authors: Alaya S. Ben , Reguiga M. S. 
Published: September 2015

Abstract
Late Jurassic Mrabtine formation, limited at the bottom by Tlalett formation and overlain by Early Cretaceous silicoclastics, is both reservoir and seal. It is a proven oil bearing complex sandstone reservoir, in southern Gulf of Gabes, onshore Tunisia. The seal consists in the upper evaporitic Member of Mrabtine formation. Detailed core study provided better knowledge of its heterogeneous lithology and petrophysical properties, in order to identify the different rock types and evaluate the reservoir potential.
In Jeffara Basin, the gross reservoir thickness can reach more than 300 m. Detailed sedimentological and petrophysical study of more than 40 meters of core, consisting in core logging, microfacies analysis, SEM analysis and routine core analysis (He-porosity, horizontal air-permeability and grain density) were undertaken to determine the different facies types and their relative petrophysical properties. In fact, the sampling was made considering the changes in the lithology. Both sedimentological and petrophysical analyses were used to define the different rock types characterizing Mrabtine reservoir.
The study revealed complex lithology and mineralogy of Mrabtine formation. The sandstone levels are, indeed, intercalated by several thin (millimetric to centimetric) and relatively thick carbonate layers (up to 60 cm). At the base of the reservoir, the carbonates thickness may extend to 7 m. Furthermore, there are frequent silty and shaly layers intercalated within the reservoir. Eight facies types may be distinguished: 1) sandstones with small scale cross-stratifications, 2) bioturbated sandstones, 3) silty sandstones, 4) bioturbated dolomites, 5) dolomitic limestones, 6) bioclastic limestones and/or dolomites, 7) siltstones and shales and 8) Evaporites. The sandstones are mostly fine quartzitic, with common occurrence of clay minerals (kaolinite, dickite and illite) and some iron sulfides and carbonates (pyrite, ankerite and siderite). The facies associations correspond to shallowing upward cycles, going from shaly, carbonate and silty deposits, to mostly fine sandy wave- and tidal-dominated shallow marine sediments, capped by evaporitic chicken-wire anhydrites. The routine core analysis confirmed the heterogeneity of the reservoir due to its complex lithology and mineralogy. The sandstones present the best reservoir potential (up to 25 % porosity and up to 425 mD permeability) and the best poroperms are recorded within cross-stratified sandstones.
The fine low poro-perm carbonate, silty and shaly layers constitute flow barriers which should be considered in geological reservoir modeling. The complex lithology of the Mrabtine formation should also be taken into account in case of scale prevention studies to avoid injecting fluids which are incompatible with the variable matrix nature of Mrabtine reservoir.