bluuebunny/crossref_metadata_2025_split huggingface dataset:
PVT Characterization of a Wet Gas Reservoir and its Impact on Reserves Estimate
Authors: Al Marri Hamad , Kabir Akim 
Published: June 2015

Abstract
Wet gas reservoirs with very low Condensate Gas Ratio (CGR) are very simple hydrocarbon system to deal with. However, accurate reserves calculation requires an accurate knowledge of gas compressibility factor (z) at reservoir Pressure and Temperature. In the absence of laboratory PVT data, very often correlations are used to estimate Bg (formation volume factor) for these reservoirs. Then accuracy of those estimates remains a question which may have significant impact in the Gas Initial in Place (GIIP) calculation.
In this paper we review our experience in estimating and validating Bg for a wet gas reservoir system. Wellhead samples were taken from exploration, delineation and then development wells. Initial GIIP was calculated from Bg estimated using a popular Standing-Katz correlation. Then more rigorous equation of states (EOS) were used to compare the values against those derived through z-factor correlations. Peng-Robinson and Soave-Redlich-Kwong (SRK) EOS based estimates were about 8% apart. A laboratory PVT study was carried out to accurately measure formation volume factor at various pressure and temperature including the reservoir P and T. Results showed that Peng-Robinson EOS over estimates Bg by 1%, while Standing-Katz z-factor correlation and SRK EOS underestimate this by 3% and 7% respectively. The use of detailed PVT data for Reservoir Engineering calculations provides more accurate GIIP, 3% higher than the simple compressibility factor based gas equation of state in this case.
Comprehensive Reservoir Vertical Interference Testing to Optimize Horizontal Well Placement Strategy in a Giant Carbonate Field
Authors: Al-Harthi Mabkhout A. , Pardo Cesar , Kilany Khalid , Al Otaibi Majid , Zeybek Murat , Amin Asif 
Published: June 2015

Abstract
This paper discusses the early evaluation of vertical connectivity with vertical interference tests (VITs) using an advanced multi-probe wireline formation tester in a giant carbonate field in Saudi Arabia. The objective was to determine the vertical permeability of low permeability layers within the reservoir. Early understanding of the vertical connectivity is required to ensure the optimum development for new fields with limited dynamic data.
To conduct the evaluation, a multi-probe advanced formation tester was utilized in five key wells around the field to obtain vertical and horizontal permeabilities with several VITs creating pressure pulses at the dual packer, which produce pressure responses monitored at the two observation probes in real time. The vertical connectivity was assessed from the pressure response to the transient generated across stratigraphic layers. Comprehensive interference tests were conducted across all the layers. Advanced nonlinear regression analysis techniques were utilized for pressure transient analysis at test intervals. The results were further confirmed with a fine gridded 3D reservoir simulator. The integration of all vertical permeability results obtained so far indicated a good degree of reservoir vertical connectivity.
The VIT results were used as input in the field simulation model improving the accuracy of the vertical permeability in different areas of the reservoir, which in turn supported changes in the well placement strategy to maximize recovery.
Fracturing a Tight Sand Formation with High Frac Gradient Onshore Saudi: Challenges and Solutions
Authors: Al-Momin Ali , AlSaihati Ali , AlHamed Khalid , Rabines Jaime 
Published: June 2015

Abstract
Saudi Aramco has recently embarked on an exploration program targeting unconventional gas reservoirs to meet the ever increasing local gas demand. One of the targets is a tight sandstone play located to the east of a giant hydrocarbon reservoir with limited reservoir data through the few exploratory wells drilled in that play. The target formation is considered a deep reservoir with very low permeability and high fracture gradient. In order to evaluate the potential of the subject formation, wells have to be completed with a hydraulic fracture. Given the challenging nature of the reservoir in terms of stress, pressure and temperature, a sophisticated design of both well completion and fracturing treatment must be performed to successfully evaluate the potential of those wells.
This paper highlights all the challenges encountered and overcome from completing to fracture stimulating one of the wells in the target tight sandstone formation. Among the challenges is dealing with the completion limitation in terms of the maximum allowable pressure during the fracturing operations. Detailed simulations of the stress and thermal conditions mimicking the fracturing treatment have been analyzed to maintain the integrity of the well during the stimulation operations. Another challenge is the high fracture gradient and high closure pressure which resulted in limiting the injection rate to place the proppant. A cost effective fracture fluid formulation has been adopted to be able to frac and place the proppant without exceeding the tubing maximum allowable injection pressure. The fluid used was a linear gelled fluid system consisting of heavy brine which was selected after extensive laboratory testing. Acid spearhead along with sand slug was also employed to overcome the high NWB (Near Wellbore) friction and the proppant was placed successfully.
This paper presents a step-by-step design process which could be applied by other engineers to help in placing proppant into challenging formations with similar attributes of the subject formation.
First Fractured Horizontal Well with Offset Horizontal Microseismic in KSA
Authors: Kurdi Mohammed , Bartko Kirk , Alfataierge Ahmed , Alghamdi Fahad 
Published: June 2015

Abstract
With Saudi Aramco's recent ambitious endeavors toward exploring unconventional resources in the Kingdom, the Unconventional Resources Program at Saudi Aramco has adopted a robust technology – microseismic monitoring – that pinpoints where hydraulic fractures are induced.
Microseismic monitoring is a relatively new technology to Saudi Aramco for monitoring hydraulic fracturing. Microseismic events can pinpoint where the formation is sheared and can detect events to show excessive downward growth. Also, it can identify the occurrence and the azimuths of faults and natural fractures.
After analyzing the results from a well in a Saudi unconventional play, microseismic monitoring resulted in revising future fracturing designs. The fracturing treatment in the subject well was designed for a crosslinked fluid, creating excessive downward growth. Therefore, the team believes a slickwater treatment would be preferred to stay in the zone. Also, faults and natural fractures were observed around a stimulated area. Therefore, future fracture treatments will be placed away from these faulted and fractured areas to capitalize on stimulating the pay zone.
Microseismic monitoring has played a key role in optimizing upcoming fracture treatments, which in turn will affect future field development strategies, especially for unconventional plays. It is worth noting that this was the first time a horizontal well was used for microseismic monitoring for another horizontal well in Saudi Arabia.
Evaluation of Damage Mechanisms in Tight Gas Reservoirs: Field Example from Perth Basin
Authors: Bahrami Nick , Soroush Samaneh , Hossain Mofazzal , Lashari Arshad , Daloma Muhammad , Kabir Akim 
Published: June 2015

Abstract
Tight gas reservoirs represent a significant portion of natural gas reservoirs worldwide. Production at economical rates from tight gas reservoirs in general is very challenging not only due to the very low intrinsic permeability but also as a consequence of several different forms of formation damage that can occur during drilling, completion, stimulation, and production operations. Tight gas reservoirs generally do not flow gas to surface at commercial rates, unless the well is completed using advanced technologies and efficiently stimulated.
One of the major damage mechanisms in tight gas reservoirs is liquid phase trapping damage that is controlled by pore system geometry, capillary pressure, relative permeability and interfacial tension between the invading trapped fluid and reservoir fluid. The liquid invasion damage into the rock matrix reduces the near wellbore permeability as a result of temporary or permanent trapping of liquid inside the porous media, and results in low productivity in tight gas reservoirs.
This study presents evaluation of damage mechanisms in tight gas reservoirs and the methods that can provide improved well productivity by minimizing damage to the formation. Numerical reservoir simulation is integrated with tight gas field data analysis and core flooding experiments to better understand the effect of different damage mechanisms on well productivity in order to propose the possible remedial strategies that can help achieve viable gas production rates from tight gas reservoirs.
Chemically-Induced Pressure Pulse: A Novel Fracturing Technology for Unconventional Reservoirs
Authors: Al-Nakhli Ayman R. 
Published: June 2015

Abstract
The huge resources of unconventional gas worldwide along with the increasing oil demand make the contribution of unconventional gas to be critical to the world economy. However, one of the major challenges that operators face to produce from unconventional resources is commercial stimulation technique that creates sufficient stimulated reservoir volume. Unconventional reserves trapped within very low permeability formations, such as tight gas, or shale formations, exhibit little or no production, and are thus economically undesirable to develop with existing conventional recovery methods. Such reservoirs require a large fracture network with high fracture conductivity to maximize well performance.
One commonly employed technique for stimulating low productivity wells is multi-stage hydraulic fracturing, which is costly and typically involves the injection of high viscosity fluids into the well. Fracturing fluid by itself could form a damaging material for the fracture due to high capillary forces. Thus, additional needs exist for an economical method to enhance production within a tight gas formation.
This paper discusses a new stimulation method to increase stimulated reservoir volume (SRV) around wellbore and fracture area, and therefore, improve unconventional gas production. The method entails triggering an exothermic chemical reaction in-situ to generate heat, gas and localized pressure sufficient to create fractures around the wellbore. In controlled experiment, chemical reactants were separately injected into core samples with a minihole and upon mixing inside the core, an exothermic chemical reaction occurred and the resultant heat and gas pressure caused macro-fractures. NMR-porosity imaging showed significant increase in macro pores throughout the core. Additionally Large scale experiments using cement blocks with a simulated wellbore cavity were performed. Once the wellbore was filled with the chemicals and upon introducing a triggering catalyst an in-situ chemical reaction took place which generated heat and gas with sufficient pressure to cause shear fractures in the surrounding rock. These experiments showed extensive fractured and shattered pieces and also provided preliminary design requirements for a field test. The chemical reactants then incorporated into a fracturing gel to simulate creating additional fractured from the main induced hydraulic fracture. The results were very encouraging and the generated high temperature and pressure caused the gel to break thus it is concluded that this technique effectively contribute to fracture cleanup in addition to creating required SRV. The experiments were very successful in proving the new concept of generating SRV in tight gas well and the developed stimulation technique is fairly easy to implement in the field.
Adaptation of Modern Techniques in Economic Exploitation of Unconventional Gas Reservoirs in the Emerging Regions
Authors: Dusterhoft Ron , Sharma Puneet 
Published: June 2015

Abstract
Although the reported potential unconventional gas resource volumes in emerging regions (Middle East, North Africa, and South Asia) are almost similar or higher in size to North America, the exploitation of such resources has been very limited. Using North America as an analogy, unconventional gas production is proposed to drastically increase globally in upcoming decades. However, many challenges are associated with developing and evaluating unconventional resources.
Exploitation of tight-gas plays borrows extensively from a suite of technologies that are already available within the conventional oil and gas industry. However, there are several aspects of unconventional reservoirs that make them difficult to understand. New techniques are compulsory to demonstrate and evaluate this new era of hydrocarbon resource exploration.
Highly specialized designs and an integrated approach of all technologies are essential to unlocking these significant unconventional resources. Accomplishing efficient tight gas stimulation also requires paradigm shifts from what is currently being performed, particularly in the emerging regions, as most of the hydraulic fracturing processes presently being used heavily depend on large volumes of available water, and water scarcity is historical in many of these areas.
This paper highlights challenges associated with developing tight gas resources and the role of cutting-edge technologies to answer several pertinent questions about unconventional reservoirs. Also provided is a technical overview of the best strategies for field development to capitalize on the promising potential of these reservoirs. Additionally, alternative approaches are proposed that appear to be imperative to enhance the current stimulation technologies for tight gas formations. This can act as an enabler to address challenges presented by unconventional resources in the emerging regions and harness the trapped energy, which can work as a cornerstone to fuel the economic growth of the world.
Slim LWD Spectral Gamma Ray for Both Well placement and Petrophysical Evaluation of Clastic Reservoirs in Saudi Arabia
Authors: Zeghlache Mohamed Larbi , Palmer Richard , Abdelkader Alibassiouny 
Published: June 2015

Abstract
With the world's increasing energy demand, it has become more crucial to safely and efficiently maximize recovery from existing assets. In this effort, there are compelling reasons for focusing on clastic reservoirs where horizontal wells are drilled to maximize reservoir contact and drainage area. In this environment, well placement and real-time petrophysical evaluation are the keys to maximizing net- to-gross ratios.
Technology has recently evolved toward the adaptation of a multi-disciplinary approach and integration of real-time answer products to address formation evaluation challenges. To this end, Saudi Aramco has introduced into their lateral operations the slim size LWD spectral gamma ray in combination with the multi-functional logging while drilling (LWD) technology.
By measuring a formation's three naturally occurring radioactive components: potassium (K), uranium (U), and thorium (Th) in real-time, petrophysicists can identify clay mineral types in addition to the standard evaluation. This information allows for more accurate formation evaluation through reliable optimizing petrophysical modeling of mineral and fluid types and volumes. It also minimizes uncertainty on the volume of shale (Vsh) estimation, which has an impact on the effective porosity calculations.
From real-time 16-bin spectral gamma ray data and X-Y magnetometers to track the detectors azimuthal position, a high resolution image is preferred — over the standard gamma ray — for properly identifying target entry and for optimizing well trajectory in clastic formations where the lithology changes vertically and laterally.
Productivity Increase Estimation for Multi Stage Fracturing in Horizontal Wells for Tight Oil Reservoirs
Authors: Baig Mirza Talha , Alnuaim Sami , Rammay Muzammil Hussain 
Published: June 2015

Abstract
Hydraulic fracturing is widely used to exploit the tight and low permeability oil and gas reservoirs. With recent technological advances, horizontal wells, along with Multi Stage Fracturing (MSF) have come up with a great effective combined solution for tight reservoirs. The combined technologies overcome formation damage, increase reservoir contact, enhances productivity from fractures; hence make tight reservoirs development economical.
On the other hand, drilling a horizontal well with placing multi stage fractures along its lateral is an expensive job. The feasibility of this job should be done to analyze the productivity enhancement provided by the Multi Stage Fracturing before commencing drilling operation. This work developed a simple, easy to use empirical correlation to calculate oil productivity enhancement in terms of fold of increase (FOI) for Pre-Frac analysis. In this paper, an approach has been put forward to evaluate the FOI in Multi Stage Fractured system for horizontal wells in the form of a correlation. The approach used is based on two 3-D simulation modelling scenarios; one with hydraulic fractures and the other without. The fracture case has been run for a wide range of parameters like number of fracture stages, formation permeability, fracture spacing, fracture conductivity and fracture half length, while the other case was run with changing formation permeability only, which served as the base case. The productivity index for both cases corresponding to same formation permeability was used to compute FOI for all different scenarios.
A general empirical correlation for estimation of increase in oil productivity due to multi-stage fracturing in horizontal wells is derived through the use of multivariate regression. Correlation is obtained by 70% data points with the accuracy results of 5.20%, 0.54% and 7.79 Mean absolute percentage error, Mean percentage error and standard deviation respectively. The obtained correlation is tested against 30% of unused data points and found to generate acceptable results with 5.20%, 0.50% and 7.40 Mean absolute percentage error, Mean percentage error and standard deviation respectively.
The developed correlation is accurate enough to capture even the minor changes in flow inside wellbore as well as interference between adjacent fracture stages. It will serve as a handy tool for pre analysis of fracture performance as compared to the costly and time consuming analytical or simulation models.
A New Practice of Streamline Simulation for Compositional and Miscible Floods
Authors: Nagib Mohamed , Burns Alan , Ingham Derek , Al-Banbi Ahmed 
Published: June 2015

Abstract
Performance evaluation of miscible and near-miscible gas injection processes is available through conventional finite difference (FD) compositional simulation, which is widely used for solving large-scale multiphase displacement problems that always require large computation time. A step can be taken to reduce the time needed by considering low-resolution compositional simulation. The model can be adversely affected by numerical dispersion and may fail to represent geological heterogeneities adequately. The number of fluid components can possibly be reduced at the price of less accurate representation of phase behavior. Streamline methods have been developed in which fluid is transported along the streamlines instead of the finite difference grid. In streamline-based simulation, a 3D flow problem is decoupled into a set of 1D problems solved along streamlines, reducing simulation time and suppressing any numerical dispersion.Larger time steps and higher spatial resolution can be achieved in these simulationsparticularly when sensitivities runs are needed to reduce study uncertainties. Streamline-based reservoir simulation, being orders of magnitude faster than the conventional finite difference methods, may mitigate many of the challenges noted above. For gas injection, the streamlines approach could not provide a high resolution or adequate representation for the multiphase displacement.
In this paper, the streamline simulations for both compositional and miscible gas injection were tested, in addition, the conventional gas injection scheme and detailed comparison between the FD simulation and the streamline approachareillustrated. Also, guidelines of how streamline can be potentially used to visualize the effect of gas displacement are presented in this paper.
The Attempt To Assess The Technical Condition Of A Gas Turbine Blade When Information On Its Operating Condition Is Limited
Authors: Błachnio Józef , Spychała Jarosław , Pawlak Wojciech , Zasada Dariusz 
Published: June 2015

Abstract
The paper discloses a non-invasive method of visual inspection based on processing of images taken for blade surfaces in the spectrum of visible light and then analyzed with the use of a computer-aided technology. The method of computer-aided analysis of images for blade surfaces is presented in details along with the obtained outcome, whilst the results from metallographic investigation of the blade superalloy are disclosed as well. The comparison is made between the results obtained from the analysis of images for blade surface and the results from the metallographic investigation of their structures. Finally, the relationship is established between parameters of digital images taken for surfaces of gas turbine blades in the visible spectrum of electromagnetic waves and microstructural parameters of the turbine blade metal. The completed investigations and analyses reveal that troubleshooting of gas turbine blades, which employs digital processing of images taken for its surface, offers new opportunities to determine the condition of blades after a long-term impact of a working agent at high temperature.
Computational drug ZINPIP-Analog an ultimate solution to cure conserved domains of mutant EGFR, ALK and BRAF Proteins in NSCLC
Authors: Munir Anum , Khan Sajid , Azam Shumaila 
Published: June 2015

Mutations in different genes such as EGFR, ALK and BRAF results in non-small cell Lung cancer (NSCLC). The most ordinarily discovered EGFR mutations in patients with NSCLC are deletion in exon 29 or in 21. Mutations initiate the tyrosine kinase activity of EGFR and are connected with the affectability to small molecules results in the formation of NSCLC. The missense mutations of BRAF have been detected in exon 11 and 15. Mutation of ALK occurs as a result of small inversion. The primary objective of study was to design novel chemical compound to block the targeted sites for receptor proteins, present on cells surface which control the growth or stop the proliferation of cancer cells. After screening large amount of data we have designed Novel Insillico drug compound Zinpip analog for NSCLC that blocks the EGFR, ALK, and BRAF. In docked complexes ALA, LYS, and ARG were common interacting residues for EGFR and ALK. ALA and GLY were common for ALK and BRAF mutant protein and Ligand complex interaction. ALA was common among all interactions. Molecular formula of Zinpip analog completely satisfies the Lipinski rules of five. It shows less side effects and long resistance against for non-small cell lung cancer. We conclude that our drug Zinpip analog is superior to commercial drugs available in market. As it is non-toxic in nature and has no side effects.International Current Pharmaceutical Journal, June 2015, 4(7): 396-401