bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Method to Determine Friction Factor of Cuttings Slip Velocity Calculation in Vertical Wells Using Neural Networks
Authors: Kamyab M. , Dawson R. , Farmanbar P. 
Published: October 2016

Abstract
The slip velocity of cuttings is a calculation of the settlement velocity of a particle in a stagnant fluid. In dynamics, the slip velocity is defined as the difference between the solid and the fluid velocities. If the cuttings velocities are low, the cuttings may not be transported efficiently to the surface, causing a variety of inefficiency issues. For example, they may accumulate at the bottom of the wellbore and get regrinded by the bit. Determination of the correct value of this parameter in vertical wells has been the concern of many investigations in the oil and gas industry.
API RP 13D (2010) standard uses Walker and Mayes' study (1975) to calculate the slip velocity for vertical wells but as discussed below, this model does not show accurate results compared to other models. Moore's model (1974) provides better slip velocity calculation compared to Walker and Mayes' model. These methods are based on providing three sets of equations for laminar, transition, and turbulent to correlate Reynolds number to friction factor for an average value of sphericity for the drilling cuttings.
This paper describes a new method to determine the cuttings slip velocity in vertical wells using neural networks. Artificial neural networks have been successfully implemented in many disciplines in the oil and gas industry. The interconnected network between the neurons provides a nonlinear approximation of the data to solve complex models. The "Reynolds number vs. friction factor" data at different particles' sphericity graphs has been used to determine the friction factor and then apply it to the Stokes slip velocity equation.
Moore's model does not consider the sphericity of the particles because it uses a generic value for this figure, however, the new technique covers a wider range of the sphericity of particles from 0.125 to 1.0. In addition, this model gives higher accuracy compared to the afformentioned models.
World's First Optical Venturi Flowmeter
Authors: Ünalmis Ö. Haldun , Raul Vishal V. 
Published: October 2016

Abstract
A new downhole optical Venturi flowmeter (OVFM) was developed that makes use of world's first optical differential pressure sensor (ODPS) and an optical pressure/temperature gauge. The use of Venturi flowmeters for downhole applications is not common because of the short life span of the associated electronics in the challenging downhole environment. The OVFM may therefore represent a more reliable solution for downhole applications when compared to its electronic versions.
The heart of the OVFM, the ODPS sensor, was developed between 2007 and 2014 as a part of a downhole multiphase flowmeter program that required differential pressure (ΔP) measurements. The ODPS measures the true ΔP with low uncertainty and is, therefore, superior to using two independent static pressure sensors with higher measurement uncertainties at the high pressures in a typical downhole environment. The performance of the OVFM was recently demonstrated in a multiphase flow loop test as a by-product of the aforementioned multiphase test program. The 100-bar test pressure represented a realistic downhole condition and the data from the single-phase test points and from one-phase dominant two-phase test points (i.e., liquid-rich/gas, gas-rich/liquid, and wet-gas flows) were analyzed to evaluate the performance of the OVFM with the ODPS sensor. In the process, modeling equations for Venturi discharge coefficient were also developed based on the multiphase flow data.
The results showed that the OVFM is in excellent agreement with the reference flow rates for single-phase, wet-gas, gas-rich/liquid, and liquid-rich/gas flows. By dynamically adjusting the density and viscosity of the fluid at the measured pressure and temperature (P and T) for the single-phase and one-phase dominant flows, and by using the ΔP measurements from the ODPS, the total-flow rates were successfully calculated. Because the ΔP measurement across the Venturi tube is fundamentally a static measurement, the OVFM is orientation-free and can be installed in any angle. Furthermore, this type of measurement is equally applicable to turbulent and laminar flows and, as a result, is a viable candidate for nonturbulent heavy oil applications. This paper provides a detailed discussion of performance results of the OVFM from the multiphase flow loop tests.
The OVFM represents a novel technology because the ODPS sensor is the first and only optical ΔP sensor for downhole applications. The optical nature of the sensor prevents any significant drift in the signal, and its true ΔP measurement capability provides increased accuracy in the flow measurement.
Transient Temperature Effect on Well Test Interpretation of HPHT Gas Wells
Authors: Wei Pang , Hanxiu Peng , Zuqing He , Qian Hou 
Published: October 2016

Abstract
Yuanba Gas Field is one of the most difficult fields categorized as super-deep and HPHT reservoirs to develop in China. It’s buried in vertical depth (TVD) of more than 6700 m, and with pressure up to nearly 70MPa while temperature above 150oC, meanwhile, the average concentration of hydrogen sulfide and carbon dioxide are 5.14% and 7.5%. Well testing interpretations are hard for wells in this field because of phase segregation, and temperature effect on sour gas PVT especially if the wells are wellhead shut-in.
In this paper, the first horizontal well in Yuanba gas field is reviewed. The backflow pressure test and pressure buildup test were conducted in order to quantify the wells’ AOF and optimized daily rate. The test lasts for one week and one AOF of more than 6 million cubic meters is interpreted. However, severe temperature effect in wellbore is induced because the well is wellhead shut-in and the pressure & temperature gauge are located in wellhead. The testing was conducted in late autumn and the atmosphere temperature difference is as large as 20°C between day and night which caused severe pressure dilation. One well test interpretation model is built by taking atmosphere temperature dependent pressure dilation into consideration.
Results show that both the log-log plot of pressure & pressure derivative and the history match plot have good agreement with measured data after that the models convert the wellhead pressure into downhole pressure and implementing the ability of considering the pressure dilation caused by transient temperature. Without considering the temperature effect for super-deep wells, the wellhead pressure recording cannot truly converted into downhole pressure, which can not reflect the formation information and interpretation results are not believable. Using the new method, the weird well testing data for well-head shut-in wells can be interpreted.
The research is helpful for super-deep HPHT sour gas wells for wells and formation appraisal especially when the pressure and temperature gauge cannot be installed down into target layer. It can also be used to compare the commercial software models used for downhole pressure data.
Damage Appraisal of Massive Hydraulic Fracture Stimulation in Unconventional Oil and Gas Reservoirs
Authors: Bo Cai , Guoqiang Bi , jiangwen Xu , Chunming He , yuebin Gao , jin Chen , ning Cheng , jia wang 
Published: October 2016

Abstract
Over the past decade, multi-stage fractured horizontal wells have been widely applied to develop tight oil and gas reservoirs. Therefore, it has become a standard practice to pump more and more numbers of treatment proppants and fluids with higher and higher pumping rate during hydraulic fracturing treatment in China, but things always did not get the expected results, field test application has displayed that not all wells production have positive correlation with increasingly treatment scales but rather lead to high costs. To investigate this problem, we established a new fracture face damage skin (FFDS) mathematical model based on the classical model of Perkins-Kern-Nordgren(PKN) and Khristianovic-Geertsma-Daneshy(KGD) using fracture mechanics and fluid coupling method. Furthormore, a new evaluation experiment by computed tomography (CT) scanning and rock mechanics and some key factors were revealed. Compared with original model the influence of FFDS on productivity was increase from 5% to 51% using new model when the permeability is 0.1mD. The results indicated the lower of permeability and the greater of impact for a specific low permeability reservoir. A case study was put forward with four different volume of proppants and fluids while different pumping ratel located in the same stratum with a same pay thickness in X tight oil reservoir. The reason was studied that some large-scale fractured well not produce that expected much oil and some small-scale fractured wells even perform better than massive treated ones owing to the fracture face damage skin. What's more, a comprehensive low FFDS treatment was put forward as following: Firstly, utilizing the low damage fracturing fluids such as slick water, low concentration and low molecular weight fluid, etc.; Secondly, optimizing the viscosity value of fracturing fluid with corresponding pumping rate for a certain permeability reservoir;Thirdly, optimizing combination between fracturing fluid and proppant types according new mathematical model; Fourthly, using such as acid-fracturing to minimize fracture face damage skin for an optimized fracture profile.
These new observations have significant implications for field development stratedies and hydraulic fracturing design. More than 45 wells have been put into field application using new technology. The performance of post-fracturing is remarkable and it has a great significance in unconventional oil and gas development in China.
Robust Chemical EOR Modelling from Coreflood to Full Field Scale in a Brown Field, Offshore
Authors: Ghadami Nader , Zakaria Nur Atiqah , Manap Arif Azhan , Wahid M Izad 
Published: October 2016

Abstract
Chemical flooding is one of the challenging EOR methods to improve the oil recovery. The objective of this work is to examine a systematic approach for upscaling Alkaline Surfactant Polymer (ASP) coreflood data to field scale and design the single well chemical tracer (SWCT) test. Appropriate upscaling can help to determine the effect of crucial parameters on process mechanisms and oil recovery. Besides, uncertainty assessment should be conducted thoroughly to evaluate the impact of key parameters.
In this paper, a robust approach for modeling the ASP flood from core to reservoir scale including the data uncertainty would be presented. Experimental work was aimed to screen and select the suitable chemicals for implementation in the field. Coreflood tests include ASP flood with and without polymer chase with the objective to evaluate the effectiveness of chemical flood and sweep efficiency. Sensitivity analysis by response surface methodology (RSM) would help to find the crucial parameters during the history matching of coreflood tests and reservoir modeling for ASP implementation.
Coreflood modeling was performed to represent the flow behavior of lab tests and investigate the mechanisms through the experimental efforts. Assisted history matching of the coreflood test was carried out to incorporate waterflood and chemical flood processes. Some variables such as relative permeability characteristics, trapping number, adsorption, and residual resistance factor were included as matching parameters. The next step was to upscale the model from core scale to reservoir scale by an appropriate method. Velocity and pressure were preserved during the scaling procedure. The parameters obtained from scaling exercise were used for SWCT design and full field model. Thus, radial models were used to describe and improve the design of SWCT tests for candidate wells. The next step was to evaluate the ASP flood on reservoir model. Sensitivity analysis was conducted on key parameters e.g. adsorption, injector-producer spacing, residual oil reduction by chemical, and ASP slug size to identify the impact of these parameters on oil recovery. RSM was applied to develop a suitable proxy model based on the results of sensitivity study. The proxy model can be used to find the optimum well spacing and slug size for field implementation.
Appropriate technique of chemical flood modeling is presented in this work. Moreover, upscaling of lab data to reservoir scale for pilot design and evaluation of ASP flood on reservoir scale by considering how to address risks and uncertainties are other outcomes of this work.
Subsea Multiphase Flowmeter: Performance Tests in Multiphase Flow Loop
Authors: Ünalmis Ö. Haldun , Raul Vishal V. , Ramakrishnan Vijay 
Published: October 2016

Abstract
Performance of a new three-phase (3-P) flow measurement system is presented using multiphase flow loop data. The system consists of two currently available products: an optics-based flowmeter and a near-infrared (NIR) water-cut meter. The measurement capability and performance of a combined system comprising two robust and field-proven technologies under realistic flow conditions is demonstrated for the first time. The new 3-P flow measurement system represents a viable alternative for subsea multiphase flow measurement and can also be used on offshore platforms, onshore as well as downhole, in single-zone or multizone applications.
The flowmeter system relies on three main measurements: bulk velocity and sound speed measured by the optics-based flowmeter, and water-cut measured by the water-cut meter. The velocity measurement is a robust measurement based on turbulent flow and is not affected by upstream flow conditions. The water-cut measurement is based on NIR absorption of water and oil molecules, and therefore, is immune to water salinity and the presence of gas (such as free gas, gas in solution, and oil foaming). Total flow rate is calculated using the bulk velocity measurement; liquid holdup and density of the mixture are obtained by introducing the mixture sound speed and the water-cut measurements into a flow model.
The results of the multiphase flow loop test demonstrated that the new flow measurement system is capable of resolving total volumetric flow rates as well as phase volumetric flow rates in a broad gas-volume-fraction (GVF) band. Furthermore, mixture density can be successfully calculated from the flow model and, as a result, the mass flow rates can also be determined. The test data also confirm that the water-cut measurement is not affected by foaming issues and associated density variations. The test results are discussed in detail in the paper.
The new flow measurement system offers several advantages. The flowmeter can be installed in any orientation and does not require recalibration. Its nonintrusive and fullbore features mean no permanent pressure loss, and high resilience to erosion and corrosion. The nonnuclear water-cut meter measures water cut in the broad GVF spectrum and is not affected by challenging flow conditions, such as slug flow. Installed inside a wellbore, an optics-based flowmeter can provide reliable flow measurement for the life of that well with no significant drift in signal.
Application of Liquid CO2 Fracturing in Tight Oil Reservoir
Authors: Wang Feng , Wang Yucai , Zhu Yongzhi , Duan Yongwei , Chen Shi , Wang Cuicui , Zhao Wei 
Published: October 2016

Abstract
The low control reserve of a single well and the difficult on energy supplement in the reservoir are two key problems in tight oil reservoir development. It is testified that non-liquid CO2 fracturing not only efficiently increases the reservoir energy but also intensifies the reservoir transformation through the field test in Jinlin oil field.
The transformation volume of non-liquid CO2 fracturing is confirmed, through micro-seismic data monitor in the borehole during fracturing, that it is 2.5 times of that of normal hydraulic fracturing with the same liquid volume usage, which can remarkably increase the complexity of the fracture. Through the laboratory experiments and the oil sampling analysis after fracturing, CO2 is verified that it can reduce the oil viscosity efficiently, therefore, it can make oil miscible and enhance the flooding efficiency by non-liquid fracturing implementation. The results of reservoir static pressure test after fracturing prove that reservoir pressure remarkably increases compared with that before fracturing and has the effects of advanced energy storage.
Five tight oil wells fracturing have been successful in Jilin oil field until now. Oil production after fracturing increases obviously compared with that before fracturing. The average oil production increase per well is 2.31 ton. According to the research, the stimulation effects of non-liquid CO2 fracturing are seriously underestimated and there is wide prospect in the application of the technique during the tight oil reservoir development.
Experimental And Discrete Particle Modelling Of Solid Particle Transportation And Deposition In Pipelines
Authors: Wong C. Y. , Boulanger J. , Feng Y. , Wu B. 
Published: October 2016

Abstract
Transport of solid particles in oil and gas pipelines is a common occurrence in the oil-gas industry. Solid particle transport occurs at various phases of an oil-gas development project: transport of drill cuttings during exploration and completion, and transport of sand particle during production. Current research and development in this space focusses on the physical and numerical modelling of the phenomenon. The concentration of sand within a pipeline will determine the type of modelling required. The literature provides a suite of empirical models to study flows with sand concentration greater than 1% by volume, especially during wet drilling operations. Although suspended sand concentration in production pipelines is nominally much less than 1% when adequate sand control is deployed downhole, there are flow velocities below which result in sand deposition, accumulation and blockage in a pipeline. There are presently limited models to simulate sand transport and deposition in the dilute sand concentration regime as it applies to the production phase. This paper will present some preliminary results using Discrete Particle Modelling to predict the transport and deposition characteristics of low concentration solid particles flowing in a liquid medium. Simulations are also supplemented by physical experiments conducted in a 2″ pipeline systems with water as the carrier fluid.
Regaining Oil Production by Overcoming Emulsion Problems After Artificial Lift Installation
Authors: Uetani Takaaki , Furuichi Naoto , Yorozu Hirokazu , Sasaya Kazuyo , Shibuya Takehiro , Kiminami Narihito , Yonebayashi Hideharu 
Published: October 2016

Abstract
An oil well, referred to in this paper as Well B, experienced a serious emulsion problem soon after the introduction of artificial lift using a hydraulic jet pump. This forced the operator to reduce the production rate to meet sales oil specifications. During its natural flow production period, this well experienced relatively emulsion-free operation. Consequently, the operator continued to use the same demulsifier, after the jet pump production began.
This paper presents results of a number of field trials that took place over 1.5-year period to control emulsions and to improve oil production. Initially, the operator raised the separator temperature but this was not effective. Next, the operator injected xylene into the formation. Although this was reasonably successful, the effect was short-term. It became necessary to open the separator dump valve to drain the emulsions, and reduce the basic sediment and water (BS&W). This expensive operation was only undertaken to maintain production. The operator then explored changing the demulsifier dosage rate and changing the location of the demulsifier injection port, but neither measure was effective. Finally, a series of bottle tests were conducted to find a better demulsifier to replace the original chemical, which was no longer effective. Soon after injection of the new demulsifier, the emulsions disappeared, and the operator regained the production rate.
Based on the field observations and the preliminary laboratory investigations, the emulsions that affected Well B over a period of 1.5 years were most likely caused by the introduction of artificial lift augmented by the continued used of the original demulsifier chemical, the increased production rate, and the presence of asphaltene and clay particles. An important lesson learned from this project was that emulsion treatment programs should be reviewed periodically, especially when operating conditions change.
Integration of Wireline Formation Tester Pressures with Advanced Formation Evaluation and Image Logs in Fractured Marine Slope Carbonates
Authors: Roche Jeff , Harfoushian Jack , Datey Ashish , Lewis Dale , Advent Francis 
Published: October 2016

Abstract
Fractured slope to deepwater carbonates in Papua New Guinea present significant challenges from the perspective of calculating hydrocarbons in place and assessing reservoir productivity. Given the heterogeneous nature of the carbonates, significant difficulties arise when attempting to determine productive intervals using only petrophysical evaluations and borehole image logs. This paper discusses how productive intervals are identified by integrating mobility from formation pressure testers.
To determine the role exerted by diagenetic processes (mainly cementation and compaction) on the fluid storage and migration pathways within the slope to deepwater carbonates, permeability structures had to be appraised. Over the past several decades, wireline formation testers have proved to be an efficient method of assessing mobility and inferred productivity, in addition to gathering representative fluid samples for accurate pressure, volume, and temperature (PVT) analysis. Recent advancements have further improved the efficiency of wireline testers in such environments by combining the benefits of straddle packer systems with enhanced probes.
In this paper, in-depth analysis is presented on the integration of a comprehensive pressure and productivity data set acquired using the latest-generation wireline tools with advanced formation evaluation and image logs. The revolutionary advances provided by a new multifrequency dielectric tool were also used to provide an Archie mn exponent log from continuous in-situ measurement of rock texture.