bluuebunny/crossref_metadata_2025_split huggingface dataset:
Best Leadership Style to Lead Multi- Cultural Teams of Service Companies in the Oil & Gas Industry in the Arabian Gulf
Authors: Nassef Amr , Albasha Hussain 
Published: March 2019

Abstract
This paper is dedicated to enhancing Organizational Health and Adaptability by finding a suitable leadership model for service companies in the oil & gas industry in the Arabian Gulf. This becomes a more challenging task if you are dealing with multicultural teams.
The author relied on literature review to define the variables that can be correlated with or impact the choice of leadership styles. Variables such as the culture of the team, the characteristics of the leader, Industrial or occupational constraints. All these variables were considered & studied. A field research was also conducted to stand on the views of both the field personnel & management and test their perceptions regarding the subject matter.
A quantitative approach relied on a questionnaire that was used as the base for testing field team's perception. And a qualitative approach relied on one to one interviews with members in management in leading positions to stand on the applicability of leadership models and the constraints involved. Three main leadership models were tested. Transactional, where leadership style is more authoritarian and relies on close supervision, strict organizational procedures, and is performance oriented through rewards & punishment. Transformational, where leadership style is based on a certain vision, and is more into inspiring a committed team to be creative, identify the aspects that require change, and execute plans as a team to march towards that particular vision. Laissez-Faire, where leadership style is more into delegating the leaders’ authority to the team who are given complete freedom to take decisions in order to achieve objectives, while the leader tries to provide the required resources and tools for his team. The results of the research recommend the Transactional model of leadership as the most appropriate style or model of leadership as both the qualitative and quantitative approaches recommend it.
This research paper is believed to add value to the body of knowledge as it focuses on a specific sector of a specific industry in a specific region and guides its leaders towards being more effective in their roles in order to achieve better results.
Numerical Simulation of Waterflooding Process using Lattice Boltzmann Method to Estimate Relative Permeability for Fractured Unconventional Reservoirs
Authors: Li Zhuoran , Chen Tianluo , Ning Yang , Zhang Kaiyi , Qin Guan 
Published: March 2019

Abstract
Shale formations exhibit multi-scale geological features such as nanopores in formation matrix and fractures at multiple length scales. Accurate prediction of relative permeability and capillary pressure are vital in numerical simulations of shale reservoirs. The multi-scale geological features of shale formations present great challenges for traditional experimental approach. Compared to nanopores in formation matrix, fractures, especially connected fractures, have much more significant impact on multiphase flows. Traditional flow models like Darcy's law are not valid for modeling fluid flow in fracture space nor in nanopores. In this work, we apply multiphase lattice Boltzmann simulation for unsteady-state waterflooding process in highly fractured samples to study the effects of fracture connectivity, wetting preference, and gravitional forces.
Polymer Flooding Simulation Modeling Feasibility Study: Understanding Key Aspects and Design Optimization
Authors: Hidayat Wahyu , ALMolhem Nasser 
Published: March 2019

Abstract
The paper discusses the feasibility study approach of polymer flooding enhanced oil recovery. This work is focused on understanding and quantifying key aspects of polymer flooding and design parameter optimization case. A synthetic reservoir simulation model was employed for the study.
The first stage is to identify and understand key factors that have most significant impact to polymer flooding response. There are eight parameters that are considered in the analysis, such as polymer concentration, polymer thermal degradation, polymer injection duration, and polymer-rock properties (adsorption, residual resistance factor, etc.). The impact of each parameter to oil recovery response was sensitized with its low, mid, and high values. The difference of high to low oil recovery output for all parameters was ranked to determine their significance levels. The top three parameters obtained from the sensitivity analysis are polymer injection duration, thermal degradation, and polymer concentration. Sensitivity cases of polymer injectivity and thermal degradation effects were covered in this work.
The second stage is to determine optimum design parameters of polymer flooding. The most significant parameters from the sensitivity analysis results were considered for further optimization. Three parameters that were selected for design optimization include polymer injection duration, polymer concentration, and well spacing. An optimization workflow with simplex algorithm is linked with a reservoir simulator to generate optimization cases by varying values of optimized parameters. The optimization iteration stops when the maximum value of the objective function, which is the net revenue, is reached. The optimization cycle was done for rock permeability of 500 md and 1000 md.
For a low rock permeability reservoir, the well spacing should be short and a lower polymer concentration is sufficient to provide a good response, in addition to avoiding potential injectivity problem. There should be minimum injectivity problem for reservoir with permeability above 1000 md. It is very important to apply polymer thermal degradation in the simulation model to avoid an optimistic performance prediction. The sensitivity analysis results provide a good understanding on the significance impact of parameters controlling polymer injection response and potential challenges. The optimization approach used in the study aids in investigating many optimization scenario within a short period of time.
Evaluating the Feasibility of Waste Slurry Injection in an Oil Prospect in the Western Desert, Egypt
Authors: Kholy S. M. , Sameh O. , Mounir N. , Shams M. , Mohamed I. M. , Abou-Sayed A. , Abou-Sayed O. 
Published: March 2019

Abstract
Oilfields produce huge amount of waste on daily basis such as drilling mud, tank bottoms, completion fluids, well treatment chemicals, dirty water and produced saltwater. These waste types represent a real challenge to the surrounding environment especially when the oilfield is located within a sensitive environment as in the Western Desert where there are natural reserves and fresh water aquifers. Waste slurry injection has proven to be an economic, environmentally friendly technique to achieve zero waste discharge on the surface over the past years. This technique involves creating a hydraulic fracture in a deep, subsurface, non-hydrocarbon bearing formation which acts as a storage domain to the injected slurrified waste. The objective of this study is to evaluate the feasibility of waste slurry injection in an oil prospect located in the Western Desert. The evaluation includes assessing the subsurface geology, recognizing the possible candidate injection formation(s), and designing the optimum injection parameters.
Both geological and petrophysical data have been used to create the geomechanical earth model for an oil prospect located at Farafra oasis in the Western Desert. This model defines the mechanical properties, pore pressure, and in-situ stresses of the different subsurface formations. Afterwards, a fully 3D fracture simulator has been used to simulate the fracture growth within the candidate injection zone at different injection scenarios. Additionally, the fracture simulator has assessed the containment of the created fracture within the candidate injection formation(s) due to the presence of stress barriers above and below the formation. Finally, the formation disposal capacity has been calculated for each of the injection scenarios using a stress increment model.
The geomechanical earth model shows that there is a good candidate injection zone which is upper/lower bounded by stress barriers. More importantly, it is located deeper than the local fresh water aquifer and thus no contamination is expected to the fresh ground water. In addition, the possible candidate is not a hydrocarbon bearing formation.
A 3D fracture simulator has been used to determine the optimum injection parameters such as: the injection flow rate, the volumetric solids concentration, the slurry rheology and the injection batch duration. These optimum parameters are defined to minimize the stress increment rate over the well life, which ensure the highest disposal capacity and to contain the fracture within the candidate injection formation.
Guidelines to conduct waste slurry injection technique in a new oil prospect that is located within a sensitive environment as in the Western desert are presented in this study. Also, the study highlights that this technique is economic for disposal of the different oilfield waste types in an environmentally friendly fashion.
Novel Empirical Approach to Supercharged Pressure Test Analysis
Authors: Smith Steve , Khairy Hamad , Emma-Ebere Chinwenwa , Ismail Mostafa 
Published: March 2019

Abstract

Objective/ Scope
Supercharged pressures exist when drilling fluid losses (spurt, dynamic and static) invade the near well-bore region and creates a ‘supercharged’ pressure zone that is higher than the reservoir pressure but lower than the wellbore hydrostatic pressure. Due to the overbalanced hydrostatic pressure the fluid invades but cannot be disbursed because of the low mobility of the rock. This creates a near well-bore region with pore pressures between hydrostatic (wellbore) and reservoir pressure. This typically occurs in low mobility formations where the dispersion of the invaded drilling fluids is not efficient. Determining true reservoir pore pressure in these conditions is difficult for formation pressure testing tools (FPT's) which measure elevated pressures above true reservoir pressure in these conditions. Analyzing the change in measured pressures from repeated tests using FPT's may help estimate the true formation pressure.

Method, Procedure, and Process
One characteristic indication of supercharging is successive pressure build-up tests (after small drawdown volumes) that stabilize at lower pressures with each subsequent test as more supercharging fluid is removed from the near well-bore region. The successive decrease in build-up pressure as a function of volume can provide information on the dynamic pressure environment in the near wellbore zone and the reservoir pressures further from the wellbore. Plotting the pressure drop as a function of fluid volume removed from the formation and fitting an exponential decay curve to the data provides an estimate of the reservoir pressure. The curve is optimized using a regression algorithm to find a best match. Because one of the unknown variables is the desired formation pressure, a range of formation pressures are evaluated and a χ-squared error function is minimized, thus approximating the true reservoir pressure.

Results, Observations, Conclusions
Numerical simulation models with known formation pressures were set-up with a static supercharged near well-bore environment and various pressure tests were conducted. Analysis was performed on a number of tests to optimize the regression algorithm. The optimized regression provided an indication of the reservoir pressure within 2% of the simulated value. Real data examples were also analyzed with good results.

Novel/ Additive Information
This analysis technique provides a novel empirical method for estimating reservoir pressures in supercharged environments by investigating the change in build-up pressures in successive tests. The analysis can be accomplished with pressure measurement data from standard FPT's. Furthermore, the individual pressure tests do not need to stabilize because the change in pressure is used nor do the pressure tests need to measure the true reservoir pressure because it is determined by a regression analysis.
Three Dimensional Compositional Variation in Gas Condensate Reservoirs
Authors: Kabir Akim , Ahmed Mahbub , Elew Dhaher 
Published: March 2019

Abstract
Gas condensate reservoirs are a major player in the oil and gas industry. Proper understanding of reservoir fluid composition and their spatial distribution helps define our resource base and forecast field production profile. In a gas accumulation with substantial vertical span, a composition gradient is expected, where heavier molecules gravitate towards the bottom end and lighter components' concentration increases towards the top of the column. However, in the literature some investigators have reported both condensate content and heavy hydrocarbon components decrease with increasing depth and temperature. Their observations appear to be contradicting the expected gravity driven compositional gradient as per thermodynamic equilibrium.
In this paper, we have done an integrated areal and vertical composition trend analysis of some gas condensate reservoirs across a big area i.e. a three-dimensional trend analysis. Field wide areal and vertical reservoir anhydrite content has been mapped. The areal composition gradient that defies expected gravity driven composition gradient, while honoring vertical thermodynamic equilibrium has been reconciled. Post depositional fluid/rock thermochemical reaction and low areal diffusivity has resulted in this areal variation. In-situ H2S generation has been enhanced where reservoir deepens and temperature increases, thus overcoming the activation energy hump. H2S concentration increase has happened at the expense of the hydrocarbon concentration as per the thermochemical reaction stoichiometry. It was found that the vertical compositional gradient is consistent with thermodynamic equilibrium calculations. Some observed trend anomalies have been explained using rock composition and geological information.
Thus, a three dimensional compositional gradient was deciphered for reservoirs with such behavior. The aim of this study has been to provide a better quality forecast for reserves, rate, recovery and composition mix for gas condensate fields.
Acid Fracturing Was Selected to Stimulate the Potential Production in Low Permeability Reservoirs in Ahdeb Oilfield, Iraq
Authors: Xiao Yong , Wang Hehua , Guo Jianchun , Lu Lize , Cheng Yi , Chen Mengting , Fan Fengying , Xue Heng 
Published: March 2019

Abstract
The low permeability reservoir of Ahdeb field discovered in the 80's, has more than 250 active wells with low initial production and rapid decline compared to other reservoirs. Matrix acidizing is the main stimulation method to recover and enhance production performance in Ahdeb oilfield, but short-distance deblocking acidizing can't communicate with the deep reservoir, and it is impossible to expand the effective seepage radius. Therefore, High reservoir heterogeneity, low permeability, poor pore pressure necessitates the move from conventional matrix stimulation to acid fracturing technology targeting better fracture conductivity and deep penetration for effective productivity and recovery enhancement.
The acid fracturing feasibility research shows that the interlayer characteristics, lithologic barrier, stress barrier and oil-water relationship of the low permeability reservoirs are favorable for fracture initiation, expansion and geometry control. Acid fracturing is one of the best ways to stimulate the potential production in low-permeability reservoirs of the Ahdeb oilfield. The acid fracturing optimization includes fracture conductivity, fluid system and fracturing parameters. Pad acid fracturing and gel acid with multi-stage alternating and closed acid fracturing are the suitable technologies for low permeability reservoir stimulation.
An experiment well has been simulated and designed, and the expected production increase is 1.5 times. Base on this paper's research, a wide-scale development strategy will be planned, and many wells will be stimulated for increase the production performance.
Proactive Utilization of ESP Performance Monitoring to Enhance Productivity
Authors: Al-Sadah Hashim , Abo Khamseen Mohannad , Al-Ghamdi Abdullah , Fardan Ali 
Published: March 2019

Abstract
As the electric submersible pump (ESP) population increases, the requirement for continuous operation is required to ensure optimum oil sweep rather than depending on fewer number of ESPs. ESP outages, shutdowns and underperforming pumps have to be minimized to reduce operational cost and deferred production. In efforts to reduce pumps downtime, ESP monitoring operations were centralized in a production surveillance and optimization center. This paper illustrates the practices followed in the hub to enhance productivity, by preventing ESP trips and failures, and conducting optimization initiatives through collaborative efforts with different parties.
By remote monitoring of real-time data of downhole sensor readings and surface data, the hub can identify ESP units operating in conditions that could lead to shutdowns and are identified to be preventable ESP trips. By capturing and predicting the downtime events, the objectives of reducing ESP downtime and production deferral is achieved. The hub monitors the individual unit's parameters with its operational confines to ensure that the ESP is running within the preferred boundaries to preserve the equipment's electrical and mechanical health. The observed conditions are referenced against the design and actions are taken accordingly to avert unnecessary trips.
Upon the deployment of ESP monitoring, many benefits were realized ranging from improved asset performance to raising efficiency of manpower usage besides saving time. Deferred production was avoided through eliminating preventable trips under ESP monitoring. This practice not only prevents ESP downtime, but also has the goal of improving ESP efficiency levels, regarding motor and pump performance.
Proactive measures are crucial in ESP production operations. In events where a probable ESP trip is predicted and actions are taken to optimize its operating conditions to prevent the trip, the number of ESP outages at the field level is reduced, thereby helping to sustain a healthy ESP well life cycle.
Fluid Characterization Using a Novel Formation Testing Technology, A Case study
Authors: Padhy Girija Shankar , Kasaraneni Pruthvi Raj , Al-Rashidi Tahani , Tagarieva Larisa , Abba Abdessalem 
Published: March 2019

Abstract
Carbonate Reservoir characteristics and fluid properties can vary among multiple layers within the same stratigraphic unit. The objective of this case study is to emphasize the added values of integrating the data from a newly introduced formation testing technology along with open hole logs and core data to enhance the understanding of the Minagish Ooilte reservoir permeability distribution and fluid typing.
The methodology implies the first time application of the newly introduced formation testing techology external mounted quartz pressure gauge and fluid typing sensors (density, viscosity, resistivity, capacitance, pressure and temperature), which could minimize reservoir fluid samples contamination and later validated by comparison to laboratory analysis results. The fluid sampling operation was conducted in different reservoir units with varying mobility values where the tested zones were selected based on the pressure pretests done prior to the sampling deployment. The success criteria to evaluate the pressure measurements capability of the new techgnology was met as set by the operator to have accuracy within 0.1psi range for two build-up in pretest at the same point. The data was integrated with open hole logs and laboratory measurements to provide a comprehensive formation evaluation and conclusive reservoir characterization after validation of the permeability.
Heterogeniety in permeability measured/captured through RFT-tool was helpful to understand the reservoir flow capacity at the well location and subsequently select the right perforation intervals. Multiple fluid samples collected during this job aided in understanding the compositional variation with depth in the reservoir. Conjoining fluid variation with flow capacity of the reservoir was immensely useful to understand the true oil potential of the well and eventually select right production allowables. Production performance and productivity of the resulting well obtained after completing in the appropriate interval is better than other wells in the near vicinity.
The high well performance and productivity reflect the value of the information provided by the novel formation testing technology sonde helped, as it achieve the well objectives, design the appropriate completion and most importantly resolve many Minagish Oolite reservoir characterization uncertainties in a timely efficient operation.
Developing a Polymer Scale Inhibitor for a Combined Fracture and Inhibitor Squeeze Treatment for High-Temperature Reservoirs
Authors: Chen Ping , Rawlins Scott , Hagen Thomas , Huijgen Martijn , Yue David Zhiwei , Hamam Mohammed , El Hajj Hicham , Al-Ghamdi Tawfik 
Published: March 2019

Abstract
A strategy combining fracturing and downhole scale inhibitor squeeze treatments was employed in an extremely tight high-temperature gas reservoir (200°C) with calcite and sulfate scaling problems. Challenges included developing a scale inhibitor that is thermally stable at this high temperature, fully compatible with the fracture fluid used, extremely beneficial with a low minimum effective concentration, with good adsorption/desorption properties for a long squeeze treatment life. Literature survey verifies that few reports are published discussing application of a combined fracture and downhole scale inhibitor squeeze treatment under such high-temperature reservoir conditions.
Multiple laboratory tests were performed to qualify the scale inhibitor, including inhibitor dynamic tube blocking, static beaker, and fracture fluid property testing. Standard inhibition tests were adapted to confirm tests were designed to confirm that the scale inhibitor was thermally stable under application conditions (i.e., the scale inhibitor was blended with the fracture fluid (including breaker) at given concentrations and aged together at 200°C for a certain period). The aged scale inhibitor sample was then tested for its performance against scale and results compared to the unaged inhibitor sample. Further tests were designed for fracture fluid rheology and breaking time with the blended scale inhibitor to help ensure the scale inhibitor was fully compatible with the fracturing fluid and would not interfere with its properties.
Laboratory test results demonstrated that the scale inhibitor is fully compatible with the fracturing fluid and formation brine. An extremely low minimum effective concentration of the scale inhibitor was determined to be 5 ppm with the aged and unaged scale inhibitor samples. With the addition of the scale inhibitor, the breaking time and rheology property of the fracture gel met all application requirements. The chemistry of the amine-containing polymer inhibitor and advantages of using this chemistry as a downhole squeeze product are discussed. Successful field treatment with the combined scale inhibitor and fracture fluid was conducted.
A new scale inhibitor chemistry was developed for a high-temperature reservoir for combined fracture and downhole inhibitor squeeze treatments.