bluuebunny/crossref_metadata_2025_split huggingface dataset:
Separable Multiple-Point Geostatistical Modeling of Three-Dimensional Discrete Fracture-Vug Networks
Authors: Fadlelmula F. Mohamed M. , Qian Sun , Wang Yuhe , Fraim Michael , He Jie , Gao Sunhua , Killough John E. 
Published: November 2016

Abstract
Most of the world's massive fields produce from naturally fractured vuggy carbonate reservoirs. However, modeling such reservoirs is a challenging task due to the co-existence of porous and free-flow domains over a wide range of scales. Realistic characterization of fractured vuggy reservoirs requires preservation of the geological structure and reproduction of patterns. In this study, we model a discrete fracture-vug network using microtomography and multiple-point geostatistics (MPG) modeling technique. For this purpose, micro-CT scan images of a real core is used to generate two micro-scale geological models (2D and 3D reference models, which are used as original training images) with three structures; matrix, fractures, and vugs.
The structures in the reference models are also separated into matrix-fracture and matrix-vug to construct two other training images for each of the 2D and 3D original training images. The three training images are then used in MPG to generate multiple equiprobable models that mimic the original networks of the fractures and vugs. The models created using the original training images are called direct models. The others that are generated using the training images after separating the structures (matrix-fracture and matrix-vug), referred to as separable training images, are combined into fracture-vug-matrix models by superimposing the fracture networks from the matrix-fracture models on their corresponding matrix-vug models. These final three-structure models are called the combined models. The spatial continuity, connectivity, patterns reproduction, and flow performance of the generated models are compared with those of the reference models (original training images).
The results show that, the separable modeling method produces better results when used in 2D modeling, however, that is not the case for 3D modeling. All the generated realizations preserved the structures and reproduced the spatial continuity of the reference models for 2 and 3D cases. In addition, the patterns are well reproduced in both cases. However, the connectivity and the flow performance of the traditional (direct) MPG method are found to be more accurate in the 3D case than those of the separable MPG method. These results proof that the separable MPG method is not suitable for real 3D naturally fractured vuggy reservoirs modeling applications. However, more detailed sensitivity analysis of the MPG parameters could provide new insights in utilizing this method for 3D reservoir modeling applications.
Enhance Energy Efficiency Through Advanced Process Control APC
Authors: Kumar M Suresh , Ganapathy Kumar , Al Yahyaee Nawal , Ayoub Abdulla 
Published: November 2016

Abstract
Advanced Process Control (APC) has been used extensively to assist in operating Gas Plants for increased reliability and profitability. But the constant increase in fuel, operating, and environmental costs, coupled with constant pressure to achieve higher efficiency levels from the existing facilities, has led to looking at APC applications for enhancing the energy efficiency.
Process control of Acid Gas Removal units, Condensate Stabilizers, Utility sections, large Compressors/turbo generators which usually form part of the Gas Plants, and the need to handle feed disturbances, seasonal and ambient variations provide considerable opportunities to enable maintain stable operation, pathways for achieving high energy efficiency at the equipment/ Process Level and to strike an optimum between yield and energy performance of the gas plant. GASCO's APC implementation strategy laid sufficient emphasis on to the holistic energy scenario across the plant and incorporated that into the APC ambit in addition to the traditional control strategies for yield improvement. This approach has resulted in identifying and hence realizing higher energy efficiencies in different areas of the plant. This paper discusses the potential use of APC with an energy perspective, and describes real-life applications that will be of particular interest to Gas plants, in order to incorporate such strategies in their new/existing APC Applications and benefit as a result.
Optimization of Hydro-Fracturing Fluid for Enhanced Well Performance in Deep Volcanic Gas Reservoir
Authors: Goyal Rajat , Tiwari Shobhit , Tibbles Raymond Joseph , Anand Saurabh , Ranjan Vishal , Sidharth Punj , Pathak Shashank , Aggarwal Vishal , Shado Olushola Horatio-da-Costa , Ray Maria Fernandes 
Published: November 2016

Abstract
The Raageshwari Deep Gas (RDG) field in Barmer Basin was discovered in 2003 by Cairn India. The RDG field has excellent gas quality with low CO2 and no H2S. The average well depth is 3300m with bottomhole pressure of 5500 psi and bottomhole temperature of 123degC – 135 degC. Typical gas production rate is up to 12 MMSCFD with CGR of 50-60 bbl/MMSCF during initial well testing. The field is developed with 3.5" monobore vertical wells suitable for multistage hydraulic fracturing. Hydraulic fracturing treatment is required as thin laminated volcanic comprise most of the reservoir section having permeability of ~ 0.1 mD. Till date, Cairn India the operator has undertaken four hydraulic fracturing campaigns in Raageshwari gas field with over 100 successful fracs pumped in 25 wells. One of the critical components that lead to a successful hydro fracturing job is fracturing fluid. The properties of the fracturing fluid impact the fracture geometry, the proppant pack conductivity, and ultimately the productivity of the well. Extensive lab tests were done to determine the optimum fracturing fluid recipe to achieve multiple objectives such as minimum viscosity requirement, clay stabilization, effective breaking of fluid, increased fluid recovery, etc. Concentration of various additives were determined in conjunction through extensive laboratory testing. Further flowback samples were collected and tested to evaluate the correct recipe which was most suitable for Raageshwari gas wells hydraulic fracturing treatments. The current frac fluid design is the result of continuous improvement/learnings from the successive frac campaigns in Raageshwari gas field and has resulted in improved frac fluid recovery and overall well performance. This paper summarizes the basis of fluid design and various imporovements made in the frac fluid that was used in Raageshwari field. Key results and findings are discussed from over 65 lab tests performed for fluid optimization.
Characterizing a Deep Jurassic Carbonate Reservoir Using Slim Magnetic Resonance
Authors: El Dien Mahmoud Fawzy , Nugroho Cahyo , Al-Qattan Abdul Wahab , Verma Naveen Kumar , Qutainah Riyad 
Published: November 2016

Abstract
This paper documents first deployment of slim 4.75-inch logging-while-drilling (LWD) Magnetic Resonance (NMR) for characterizing deep Jurassic carbonate reservoir in West Kuwait. It is a complex reservoir comprising carbonate sequences having alternations of mudstone, wackestone, packstone and grainstone. Use of conventional logs presents challenges in identifying rock types with different depositional textures. The results are valuable in identifying and quantifying the carbonate rock types of varying depositional textures and support the interpretation of depositional environment across a horizontal wellbore.
The reservoir was drilled as a 6-inch horizontal well to 16000 ft, with a horizontal drain-hole section traversing 2300 ft over a depth interval thickness of around 200 feet. The NMR was run with a pre-designed setup in Dual Wait Time (DWT) mode which enabled NMR to differentiate fluids of hydrocarbon and water. The NMR T2 measurement was later processed to interpret lithology. Fluid saturation was calculated from the DWT data by exploiting the contrast in T1 polarization times between hydrocarbon and water after Rate-of-Peneteration(ROP)-flow and ROP-polarization corrections. Rock type was calculated by using parameters of T2 measurement, total and effective porosity and water saturation.
Results were classified based on the Dunham classification of depositional texture. NMR logging and processing allowed the identification of hydrocarbon bearing zones and distinguished five textures related to grain and pore size, namely: clay to siltstone, mudstone to wackestones, packstone, grainstoneandfloattstone based on core calibration of offset well. The NMR results show the presence of hydrocarbons which, however, were not clearly detected by the neutron density measurements. There are some intervals in which the neutron and density logs measure a low porosity and in which the NMR data demonstrate higher porosity and movable fluid. Calculation of hydrocarbon and water saturation indicate presence of two additional hydrocarbon bearing intervals ranging from 50 to 60 feet with low resistivity and neutron density separation.
NMR data acquisition and processing has added value for reservoir characterization in this challenging tight and heterogeneous carbonate reservoir. Identification of carbonate texture based rock types has potential for reservoir navigation and well placement particularly to distinguish tight resistive formation from hydrocarbon bearing zones. Identification of reservoir facies will help interpretation of depositional environment for reservoir development while aiding optimized stimulation and completion across long drain-hole sections.
Desanding at the Wellhead for Optimal Well Productivity and Minimal Risks to Surface Facilities
Authors: Opawale A. O. , Arreola S. , Ciprick K. , Ibouhouten B. , Kruijtzer G. L. , Verbeek P. H. , Akdim M. R. 
Published: November 2016

Abstract
Wellhead desanding may increase the productivity of an oil/gas well as it opens the opportunity to a minimized choked-back production. Utilizing a wellhead desanding system upstream of the choke valve, minimizes the risk of erosion of the downstream equipment as for example; valves piping, etc. In addition, better sand separation may be achieved at high pressures due to presence of dissolved gas in the crude oil. These benefits motivated the development of the Wellhead DeSander technology as a significant improvement to conventional cyclonic desanders, gravity-based sand traps and strainers.
The novel desander system utilizes a stationary non-rotating swirl element which removes sand particles from produced multiphase fluids driven by a centrifugal force. Separated sand particles are temporarily stored in an accumulator vessel designed with an automated system that detects the level of accumulated solids and initiates the flushing procedure. In this paper the development and qualification of the Wellhead DeSander technology will be extensively described.
Case studies describing flowback operations at shale plays across the US are presented. Field data is shown demonstrating the separation performance of the Wellhead DeSander at various operating conditions such as: fluid production rates in the range of 1,500 to 14,700 Barrels Per Day (BPD), produced sand concentration upto 5 % volumetric (V/V), heavy paraffinic hydrocarbon, Gas Volume Fraction (GVF) &gt; 90 % and watercut upto 84 %. Separation performances of the Wellhead DeSander have been measured with and without an upstream conventional sand trap. Separation efficiencies upto 99 % have been achieved with the Wellhead DeSander technology. The Wellhead DeSander can provide substantial economic benefits such as reduced erosion of a process facility and minimized operating costs with sustained optimal well productivity when solids are produced.
Application of Drag Reducing Agent in Pipeline handling High Water Cut Fluid - Case Study from a Mature Field in Mumbai Offshore Region
Authors: Tiwari Amitosh , Fartiyal Prashant , Sharma Neel Mani , Manickavasagam Chandran , Toshniwal Vaibhav , Dwivedi Priyanka , Mathur Anubhav 
Published: November 2016

Abstract
Pipelines are usually considered the most effective and economical means for transporting fluids from satellite wellhead platforms to central processing platforms. However, the actual production from the reservoir during field life could be different than expected due to associated uncertainties in various production phases. As a result, pipeline flow assurance issues are the most common challenges faced in mid-to-late life phase of an oil field.
In mature oil fields, water cut increases with time. The total fluid flow through a pipeline may also increase due to better reservoir deliverability than expected, infill wells opportunity, workovers, zone change, gas lift deepening, etc. An increase in total fluid content causes a higher frictional pressure drop in the pipeline and increases the backpressure on flowing wells. This detrimentally affects well deliverability at declining reservoir pressure in mature fields.
A traditional approach to reduce backpressure on flowing wells is to flow the selective wells in a satellite platform. In short, the risk of increased backpressure can prevent the opening of additional available wells, thereby significantly limiting the production from a satellite platform. Another approach is to lay a new pipeline, but this is capital-intensive and time-consuming option that is often uneconomical in the late-life phase of an oil field.
This paper explores a chemical route, the application of drag-reducing agent (DRA), to address the issue of high frictional pressure drops in pipelines. DRAs have traditionally been used in pipelines handling fluid with low-to-moderate water cuts (&lt;50%). However, their application in high water situations (fluid having water cut higher than 80%) have been rare and met with limited success.
A trial of a new DRA was carried out in a mature oil field in the Mumbai offshore region. A pipeline handling high water cut fluid (&gt;80%) was selected for this application. This DRA is a long-chain polymer that attaches to water molecules, thereby streamlining the flow. The DRA reduces the frictional pressure by acting as a buffer along the pipe wall to decrease the amount of energy lost in turbulent flow. Application of this DRA in high water cut pipeline lowers the pressure drop with a given fluid flow, enabling the operator to flow additional wells into the same pipeline.
This paper discusses the rationale behind the identification of a problem using pipeline flow modeling (using water cut, production rates) and the selection of the appropriate chemical (considering water chemistry), along with the results from a successful field trial.
In the future, many mature oil fields will deal with issues like higher water cut fluid flow in a smaller diameter pipeline. In these situations, a drag-reducing chemical can significantly improve overall recovery.
Less Money for More Oil - Advanced Drill Cuttings Analysis Improves Post Fracture Oil Production, Wolfcamp Example
Authors: Stolyarov Sergey , Roberts Kenneth , Sadykhov Said , Rebol Amanda , Vinh Chi 
Published: November 2016

Abstract
"How do we reduce the cost of producing a barrel of oil and improve well productivity?" This is probably the most frequently asked question by operators. According to a US Energy Information Administration study, average drilling and completion costs in 2015 in five major unconventional plays in the US dropped 25 to 30% since 2012. Despite an overall price drop in drilling and completion, which accounts for up to 65% of capital expenditure, unconventional oil and natural gas extraction remains non profitable for many operators at current oil prices.
Increasing well productivity often requires well intervention with expensive logging tools and high-tech equipment. The use of these technologies is cost prohibitive for some unconventional plays during a market downturn, and incurs the additional risk of the loss of tools downhole.
Drill cuttings analysis during mud logging, a well-known formation evaluation tool in conventional drilling, is often overlooked or ignored in unconventional well evaluation because of the limited data from conventional techniques. However, with the development of advanced drill-cuttings analysis such as scanning electron microscope-based automated mineralogical techniques can now provide data-rich information such as brittleness, rock elastic properties and rock typing that can improve completion design and post-stimulation production. One of the main advantages of drill cuttings is that they are readily available and advanced analysis is relatively inexpensive and low-risk.
This paper reviews the use of advanced drill cutting analysis (ACA) for hydraulic fracture treatment design optimization in well 1-H in the Wolfcamp formation. The results from the review show the correlation between some formation properties obtained from the ACA and fracture treatment parameters such as treating pressure and pump rate. The post-fracture oil production of well 1-H is compared to the offset geometrically completed well. Limitations of ACA and other factors that can affect the post-stimulation production are also discussed.
Significance of Multi-Phase Pipelines Transient Analysis Using OLGA on EPC Project Schedules
Authors: Valand Bhavesh , Subramanian Senthilkumar , Singh Harendra , Kamal Faris Ragheb , Takieddine Oussama 
Published: November 2016

Abstract
The transient analysis of multi-phase Pipelines is primarily performed for flow assurance purposes i.e. to assure the adequacy of design to transfer wellfluids economically from the reservoir to the export line over the life of a field. The technical data considered in the study as well as the stage in project life cycle at which this study is performed, both have significant bearing on many aspects of design. These can potentially impact the overall project schedule.
Generally, the transient analysis of multi-phase pipelines using OLGA software is performed during early stages of project such as FEED which lacks the level of details required for accurate prediction of transient effects. When such details are included at later stages such as EPC, the transient results are found to be quite different impacting the procurement of long lead items and thus the project schedule.
Design of equipment such as slug catchers, separators, chemical dosing packages and pumps etc, the adequacy of equipment in brownfield projects and decision on pipeline route grading especially in cases of pumped systems are dependent on pipeline transient analysis results. For example, conventionally the slug catcher is designed based on the slug volumes predicted by transient analysis during early stages (FEED) and includes some margin. However, transient simulations with more detailed pipeline profile information provide significant differences in estimated slug volumes and increased back pressures at source. The differences in results for various actual project and potential impact on project schedule are presented in this paper.
Typically, a transient simulation model includes wellhead topside piping, infield pipelines and a common manifold connection to the inlet of slug catcher to analyze the slugging behavior of wellfluid lines and the total slug volumes at the inlet of slug catcher. These simulation models incorporate the detailed geometry of all infield pipelines as per geo-physical survey data and topside piping.
Generally, the transient simulation of pipelines during FEED are not modeled with large number of XY data of pipeline route profile, as the software takes enormous time to simulate the various transient scenarios (i.e. normal operation, turndown, ramp up and pigging). However, due to the detailed geometry of pipelines and topsides employed during EPC, the estimated slug volumes / back pressures results have significant differences, sometimes as high as 50%. This may lead to bottleneck or inadequacy of slug handling capacity for existing slug catchers if not designed with adequate margin.
The objective of this paper is to highlight the significance of multi-phase pipelines transient analysis using OLGA during EPC in finalizing the design and operating philosophy of the facility and thereby impact on project schedule in procuring long lead items based on NPCC experiences.
Successful Implementation of EPC for New WAG Wells Project at SE-Field at ADCO
Authors: Ghazo Samer 
Published: November 2016

Abstract
The Water Alternative Gas Injection Wells (WAG) are newly type of wells that ADCO start using in theory Fields, therefore, I decided to share the experience, lessons learned, challenges, mitigation criteria and some of the formats, that we used during the implementation of the EPC New WAG Wells & Conversion of Existing Gas Injectors Wells to WAG Wells at SAHIL, which awarded on March. 2014 for 18 months with budget of 109 Million DH, and completed without LTI after 1.2 Million man-hour.
The EPC new WAG wells project was completed and the target achieved, therefore in this work we highlighted the following:
Theory about the WAG wells, the importance of this type of wells in the oil and gas fields, and explains its components. EPC, Engineering Procurement and Construction, definition, phases, and risks associated with those types of projects. EPC for New WAG Wells & Conversion of Existing Gas Injectors Wells to WAG Wells at SAHIL. State a facts about the projects, scope of work, Duration, resources required, and then highlight ADCO specific requirements for such projects. Successful criteria that led to the success of the project; anticipation, preparation and execution at the right time were the main factors in the success of the project. Challenges that faces the project; share some of the challenges and how to mitigate them.
This work will help all the project management team to manage such projects, and provide a guideline for how to manage similar projects, where this project was an example of a successful projects that ADCO accomplished recently.