bluuebunny/crossref_metadata_2025_split huggingface dataset:
Zonal Flow Allocation: Practical Experience Using Real-Time Data and Advanced Completion and Near-Wellbore Modeling
Authors: Lasrado Vineet , Kalyani Tejas , Regulacion Rhandy 
Published: June 2017

Abstract
Previous approaches to downhole flow allocation have used traditional nodal analysis software. This paper provides practical experience developing a solution for zonal flow allocation using an advanced completion and near-wellbore (NWB) hydraulics simulator. This solution was implemented in a green field development in the Middle East where three oil-producing wells completed with an intelligent well completion (IWC) system commingle production from multiple reservoirs. These smart wells were installed with interval control valves (ICVs) to control the commingled flow and permanent downhole gauges (PDHGs) to provide real-time pressure and temperature (P/T) data that were used in flow allocation.
Dynamic Analysis of Plasticization Phenomenon: an Experimental Study of High-pressure CO2 Separation Using Modified Polysulfone Membrane
Authors: Adewole Jimoh K. , Ahmad Abdul Latif , Sultan Abdullah S. , Khan M. Yusuf 
Published: June 2017

Abstract
Natural gas is often coproduced with CO2 which need to be removed in order to increase the calorific value of the gas. High pressure membrane separation is one of the widely used technologies for this removal. However, one major challenge of high pressure operation is penetrant-induced plasticization phenomenon which is caused by increasing the feed pressure. High pressure gas permeation studies were performed to evaluate the plasticization response of a modified polysulfone membrane. This is necessary in order to establish the highest possible feed pressure which can be attained during CO2 removal without plasticization. Gas transport properties of the membrane were evaluated using permeation tests at pressure up to 57 bar. The dynamic evaluation of the response was done above and below the plasticization pressure using time-dependent permeation experiments over a period ranging from 5 hours to 1080 hours (45 days) at various pressures between 6 and 57 bar. The time-dependent permeability tests revealed a continuous decrease in permeability with time at pressure below the plasticization pressure but a continuous increase in permeability at pressure higher than the plasticization pressure. Generally, the overall results revealed that there is a certain pressure at which the two competing phenomena of physical aging and plasticization counter balance each other. This pressure was suspected to be at the plasticization pressure. It can be concluded that the economic advantage of high pressure operation is particularly true only if the membrane is maintained at an equilibrium pressure which coincides with the plasticization pressure.
Novel Algorithm to Quantify Productivity of Multi-layered Gas Condensate Heterogeneous Reservoirs
Authors: Janjua Aneeq Nasir , Alnuaim Sami , Sadeed Ahmed 
Published: June 2017

Abstract
Performance prediction of multi-layered gas condensate reservoirs is challenging in order to maximize the recovery and operate gas wells effectively. Gas condensate reservoirs may undergo liquid condensation without significant liquid production at the surface. Pressure decline and skin are the main factors that cause condensate banking around the wellbore resulting into loss in well deliverability. In this study our key objective is to investigate the effect of multi-layered system on gas condensate productivity and to develop a novel empirical algorithm to quantify productivity of multi-layered gas condensate heterogeneous reservoirs.
This paper describes the potential benefits of establishing a new algorithm that considers the effect of different permeability layers in the system. The concept of semivariogram function has been introduced to take into account the effect of reservoir heterogeneity. Most of the previously developed empirical models are for conventional homogeneous or naturally fractured gas condensate reservoirs. The results of this work are obtained from a 3D reservoir simulation model built using a commercial reservoir simulator. A base case is modeled with radial reservoir and simulation model is developed using black oil formulation with characteristic rock, fluid and reservoir properties. Logrithmic radial grid distribution is used for single well modeling. Vertical well is placed at the center of the reservoir. Reservoir heterogeneity is included in the simulation model utilizing semi-variogram function. Dimensionless inflow performance relationship (IPR) curves are generated by plotting flowing bottomhole pressures versus gas production rates in a dimensionless form. Non-linear regression techniques are applied to fit dimensionless flowrate as a function of dimensionless pressure.
Sensitivity analysis of different parameters like porosity, reservoir temperature and vertical permeability on generated inflow performance curve is also performed. The results are analyzed, converged and validated. The generated novel empirical algorithm was found giving accurate results with less than 2% error when compared to other existing models. The new IPR is very useful in improving the flow rate and modeling gas condensate reservoirs when we have multi-layered systems.
Evaluating Hybrid Fire Suppression Systems for the Protection of Aero-derivative Gas Turbines
Authors: Christian Dan , Verstrynge Cedric 
Published: June 2017

Abstract
The purpose of this project was to evaluate the effectiveness of a hybrid inert gas/water mist fire suppression system on aero-derivative style gas turbines. A utility company and its fire protection engineer provided the opportunity to test the system on an operating unit under load, enabling the research team to assess system efficacy in real-world scenarios. The utility company established the test criteria; testing would be deemed successful if the system could cool the turbine skin to less than 380°F within 10 minutes. 380°F represents the auto ignition temperature of lube oil and turbine fuel plus a safety factor, as determined by the company. The 10-minute timeframe was established to match the performance of the existing CO2 extinguishing system.
A series of tests were devised to demonstrate the suppression system's effectiveness for cooling. The tests involved operating a Pratt and Whitney FT4 aero-derivative turbine generator off and on the power grid at full speed/base load and allowing the unit to cool naturally, as well as on the grid and allowing the system to discharge. Systematic changes in water flow and installation parameters were used to find optimal results. Temperatures were recorded at the compressor section, combustion section front, combustion section rear, hot turbine section, exhaust diffuser and in the enclosure.
Testing demonstrated that the hybrid fire suppression system is capable of quickly cooling the turbine skin to below 380°F—within 33 seconds, in fact—without damaging the turbine. The test results show successful cooling with the emitters installed overhead and aimed toward the hot section of the turbine. Results indicate that the hybrid fire suppression system adequately protects aero-derivative turbines under normal operating conditions. The testing offers a proof point that the system is not damaging to equipment, overcoming historic objections to the use of water mist style systems.
Successful Debottlenecking of a Surface Injection Facility
Authors: Bangkong Sabut A. , Alrabaei Rayan A. , Al-Ajmi Mohammed D. , Al-Hajri Nasser M. , Al-Otaibi Mohammed A. , Al-Shammari Nayef S. 
Published: June 2017

Abstract
This paper will present a dedicated field case study that shows effective optimization of injection facilities obtained by hydraulic simulation. Water Injection Plants (WIPs) in the fields under study are operated as a secondary oil recovery method by means of peripheral injection. Field production strategy dictates water injection requirements in a given field. A core area of Field-A was identified with a need for increased injection pressure support. However, existing injection facilities could not meet the demand of increased injection rates. The injection capacity constraints were discerned by conducting a selective injection system capacity test. The feasibility of future improvements to the injection system using hydraulic simulation forecasts provided valuable and vital inputs. Accordingly, the most reliable and cost effective option was implemented in the field.
Hydraulic simulation along with network pipeline modelling was utilized on this case study with the objective of debottlenecking the overall injection system. Well performance models for the water injection wells to represent the reservoir inflow performance relationships (IPRs) were built. The most recent injectivity indices and static bottomhole pressures were used to construct the IPRs. Calibrations were then performed using current injection rates and wellhead pressures to history match the data and produce representative individual wells IPRs. On the other hand, piping network simulation incorporates surface injection lines sizes and ground elevation to account for pipe friction losses and gravitational pressure differences. Additionally, data from WIPs pump performance curves were inputted into the simulator to integrate surface and subsurface flow and capture the working mechanisms of the injection systems in this case study.
Surface piping network optimizations were achieved using the outputs of the hydraulic simulator runs and sensitivity analysis based on proposed corrective scenarios. The effect of these scenarios to the existing system was forecasted in terms of the ability to achieve the required individual wells injection targets. The simulated options were conceived on the following basis:
Utilizing an identified extra injection capacity from one of the WIPs. Looping the injected water through pipelines network connecting different WIPs. Constructing new injection lines to the field flanks that need additional injection.
Integrated Topographic Multiphase Flow Modeling in Surface Pipelines - A Case Study
Authors: Homoud A. A. , Ayub M. , Mohammed E. 
Published: June 2017

Abstract
Several steady-state multiphase flow modeling softwares have been utilized to optimize production pipelines and injection networks. These softwares lack suitable integration tools to incorporate geospatial data. Recently a new study was completed by integrating a modeling software with the Geographic Information Systems (GIS). GIS technology is widely used in oil and gas pipeline networks for data storage and retrieval purpose but not as an analysis and decision making tool. GIS handling of topographic and linear features was utilized for simulation purposes in the model. This study highlights the benefits of integrating pipeline simulation software with GIS on an existing complex surface production network. This integration became a tool that enables engineers to better manage field production and unlock production potential.
In order to improve the modeling of a field surface network with variable surface topography, an integrated wells model was constructed with the corresponding surface facilities. The integrated model took into account elevation profiles captured directly from the GIS and calibrated against field data. Over 40 oil wells and their respective flow lines were modeled, and then connected to the Gas/Oil Separation Plant (GOSP). The elevation aspect of the topography made the modeling results more reliable. To capture the value of this technique the results were analyzed against the existing network models that did not consider the elevation changes. The new technique honored the elevation of the wells with respect to the GOSP leading to unlocking more production potential.
The successful integration between GIS and the pipeline simulation software resulted in unlocking oil production potential and accurately modified choke adjustments. This methodology greatly improves the process of optimizing the existing pipeline networks by adding more layer of complexity to the models, which is topography. It also enables engineers to better plan future wells placement by taking into account the area topography.
Holistic Management of Calcium Carbonate Scaling in a Mature Field: A Case Study
Authors: Malik Ankit , Tiwari Amitosh , Fartiyal Prashant , Lele Sarang , Manickavasagam Chandran , Sharma Neel Mani 
Published: June 2017

Abstract
Calcium carbonate scaling within well tubing and surface piping leads to significant production loss in many oilfields across the world. Scaling tendency of produced fluids increases multi-fold in a mature reservoir with increase in water production and decline in operating pressures. This paper demonstrates the use of modelling to help anticipate scaling issues and convert predictions into operational decisionmaking which has prevented significant value erosion in a mature field.
Majority of the efforts in tackling scaling related losses have traditionally been centered on performing scale treatment after observing a significant change in flow parameters. Although this approach delivers value, it is more reactive in nature and becomes challenging to address in a logistically constrained offshore environment. This paper presents a case study on a new proactive framework on Scale Management. This new framework is driven by P2P approach - Prediction to Prevention.
Prediction of scale formation tendency in wells was carried out using a thermodynamic model. Once wells with scale formation tendency were identified using thermodynamic model, scale prevention was done by selection and application of scale inhibitor chemical along with progressively reducing number of surgical acid washes. The scaling behavior was compared against the operating conditions of wells and the findings complemented the understanding from thermodynamic simulations. Paper deliberates on the cost optimization while application of this approach so that it remains extremely cost efficient in comparison to traditional approach. It details the evolution of scale management strategy right from project initiation to field maturation spanning across 30 years of production.
With periodic reviews of this framework, additional ~10% of available well stock was identified as new wells migrating into scaling envelope over the last one year and added to Scale Inhibitor dosage program. This prevented production losses and well integrity issues in these wells. Wells put on continuous scale inhibitor injection as per recommendations of this approach did not have down-hole safety valve failures, protecting 35% of field oil production volume and ensuring safer operations demonstrating strong business value. Overall, application of this P2P framework has helped asset to reduce yearly scaling related losses by more than 90%.
An Analytical Model to Evaluate the Capillary Trapping during CO2 Storage in Aquifers
Authors: Zhu Langtao , Liao Xinwei , Chen Zhiming , Mu Lingyu , Wang Tianyi 
Published: June 2017

Abstract
Storage CO2 in brine aquifers is considered as a promising option to reduce CO2 emissions. Many simple analytical and semi-analytical techniques have been proposed to support screening analysis and performance assessment for potential carbon sequestration sites. However, these analytical techniques have ignored the capillary trapping mechanism, which is important to the carbon sequestration in aquifers.
In this paper, a new analytical method to evaluate the saturation profile and CO2 trapped quantity was derived. First, the fractional theory (Buckley–Leverett type model) is applied to simulate the multiphase flow. And the trapping and hysteresis models are adopted to model the capillary trapping mechanism. Then, the transient-pressure solution of injection well was solved by applying the quasisteady state theory. Subsequently, this analytical method is applied to evaluate the saturation profile and CO2 trapped quantity when gas alternating water (GAW) injection (strong imbibition phenomenon). After that, we applied this new analytical method in a real case to evaluate the CO2 capillary trapped quantity and assess the saturation profile. Finally, model verification and sensitivity analysis were conducted.
The results of model verification show satisfactory match and justifies, which shows our methodology is reasonable. Furthermore, the CO2 trapped quantity can account for about 24.25% of total trapped quantity, which indicates that the capillary trapping can't be ignored for long-term storage. In addition, results of sensitive analysis show that as the residual gas saturation increases, the capillary trapping capacity increases.
This work provides a new approach to the quick assessment of the capillary trapping quantity and the location of mobile gas left during gas alternating water injection.
The Impact of Salinity on Water Dynamics, Hydrocarbon Recovery and Formation Softening in Shale: Experimental study
Authors: Mehana Mohamed , AL Salman Mohamed , Fahes Mashhad 
Published: June 2017

Abstract
The low reocvery of Slick water used in hydraulic fracturing treatments and the better performance observed for low salinity floods reveal the impact of water dynamics on well and reservoir performance. The focus of this study has been to develop and implement an experimental workflow to investigate the impact of water salinity on wettability, hydrocarbon recovery and formation softening in shale rock samples varying in mineralogy. We are trying to provide a better understanding of the mechanisms of water dynamics and entrapement along with the driving forces associated with these mechanisms.
Samples from Woodford and Caney outcrops in the Unites States of America were obtained. The mineralogy of the cores was measured using the FTIR technique. While the Woodford samples turned out to be Dolomite rich, the Caney samples were Quartz and clay rich. Spontaneous imbibition and contact angle measurements were conducted for these samples using slickwater with an added KCl weight percentage of 0, 5 and 10. Both the rock-water-gas and the rock-water-oil systems were examined. The formation softening was quantified by recording the rock mechanical parameters before and after the imbibition and soaking tests. The results were analyzed in terms of the capillary suction characteristics for each formation.
According to the experimental results, a positive correlation was observed between water salinity and imbibition in Caney formation. However, the opposite was observed for Woodford samples. The formation mineralogy was identified to be the major factor in this reversal of wettability. Similar trends were observed for the recovery of both oil and gas where the low salinity imbibition yielded a higher recovery factor for the Caney formation samples and a lower recovery factor for Woodford. In addition, tangible increase in the compressive strength of Caney formation was reported with the increase in KCl concentration. However, a non-monotonic trend was observed for Woodford samples.
This study provides insights into the water dynamics in ultra-low permeability reservoirs. The formation mineralogy is a key factor for properly describing the water dynamics whether in fracturing treatments or in low salinity flooding projects. Low salinity flooding does not always imply better hydrocarbon recovery, based on what we observed in Woodford samples.
Effect of Carbonate Microfacies on Contact Angle: Study from Middle Jurassic Tuwaiq Mountain Formation
Authors: El-Yamani Mahmoud M. , Sultan Abdullah S. , Al-Ramadan Khalid A. 
Published: June 2017

Abstract
Tuwaiq Mountain Limestone Formation (TMLF) is an important Middle Jurassic formation in Saudi Arabia as it encompasses two reservoir rocks, one source rock, and unconventional reservoir in Jafura basin. It is important to characterize the rock fluid interaction properties of the different microfacies of TMLF. Different samples were taken from different microfacies; spiculitic wackstone, coral floatstone, coral rudstone, and foraminiferal wack/pack-stone. The selected samples have four different facies with variable mineral composition, mud ratio, sorting, roundness, different types of porosities. Because of that, the petrophysical properties of different facies are different and this was governed by the different depositional and diagenetic controls on each microfacies. These differences affect the rock fluid interaction in terms of contact angle and adhesion forces between surface of rock plate and oil.
The study showed that the difference in concentration of major and trace elements (especially Al+3, Mn+3 and Fe) in different microfacies controlled the difference in contact angle measurements. This difference is governed by the effect of the binding energy of Al+3, Mn+3 and Fe with polar substances in oil which in turn affect the oil adhesion on the rock surface. Also, it should be noted that the composition of oil has an interaction with microfacies as in case that the oil doesn't have polar substance (Resins and Asphaltenes), the differences in the concentration of major and trace elements in different microfacies might not have any effect adhesion and thus wettability and contact angle measurements.
Improving the Drilling Fluid Properties Using Nanoparticles and Water-Soluble Polymers
Authors: Ahmad Hafiz Mudaser , Kamal Muhammad Shahzad , Murtaza Mobeen , Al-Harthi Mamdouh A. 
Published: June 2017

Abstract
Water-based drilling fluids are utilized to carry out efficient and smooth drilling operations of oil and gas wells. Bentonite is a basic constituent of water-based drilling fluids. It has excellent swelling properties, ability to make gel structure and acts as viscosifier to tailor the rheological properties of drilling fluids. Deep well drilling with bentonite drilling fluids at high temperature and pressure conditions will severely affect the performance of drilling fluid in term of degradation and flocculation due to thermal induce swelling of bentonite. High salts contamination during the drilling process reduces the hydration and dispersion of bentonite and results in flocculation.
The aim of this study was to improve bentonite drilling fluid performance using novel water-soluble polymers and nanoparticles. Nanoparticles significantly improved the filtration properties by reducing the fluid loss into formations and by making a thin filter cake for smooth drilling operations. Novel water-soluble polymers such as acrylamide/2-Acrylamido-2-methylpropane sulfonic acid copolymer and acrylamide/2-Acrylamido-2-methylpropane sulfonic acid/ N-Vinylpyrrolidone terpolymer were used to improve the rheological properties and dispersion of bentonite. Rheological and filtration properties were evaluated using functionalized carbon nanotubes and graphitized nanotubes by varying the temperature from 25°C-85°C. Herschel-Bulkley and Bingham model were used to calculate various parameters such as plastic viscosity and yield stress. It was observed that incorporation of 0.25 wt.% polymers and 0.25 wt.% nanoparticles improved the filtration and rheological properties such as yield stress and steady shear viscosity.