bluuebunny/crossref_metadata_2025_split huggingface dataset:
Artificial Neural Networks for Corrosion Rate Prediction in Gas Pipelines
Authors: Supriyatman Deden , Sumarni Sumarni , Sidarto Kuntjoro Adji , Suratman Rochim 
Published: October 2012

Abstract
Artificial Neural Network (ANN) is adopted from the human neural network systems and is among many tools to understand complex model including corrosion. Such predictive model can be developed through corrosion rate. By ANN application, one may update its model iteratively, hence it will be adaptable for all decisions. It can be learned from the previous data and recognize patterns of data always changing and dynamic, like the ones in oil and gas fields.
Based on the characteristics of ANN methods, corrosion rate model will update iteratively during the training phase leading to the best (more accurate) model target. Using a number of data input and output characteristics of the fluid, the result of corrosion rate model will be able to predict the corrosion rate in the range of the entered input data. With models that are adaptive and can adjust to changes in the dynamic data, one will be able to obtain predictions with a great degree of accuracy.
Research methodology on the subject using crude oil was developed by Hernandez and Nesic (2005). Some crude oil characteristic associated with the corrosion rate are, among others, sulfur, vanadium, nickel contents, total acid number and API. A correlation analysis between the crude oil characteristics vs corrosion rate, then a regression model of percentage of inhibiton which is a function of characteristics of crude oil were obtained. Percentage of inhibition in this regard is the number of ratio between the corrosion rate of the fluid-carrying pipe and corrosion rate in the blank pipe.
This paper will describe ANN that creates a program to determine the corrosion rates of the carbon-steel materials containing flowing fluid (gas). The characteristics evaluated are gas composition, temperature and pressure then regression equation of inhibition percentage will be made in the characteristics function of earlier inputs. Only data having a high level of significance will be used, and the ones of very low level of significances will be excluded in the equation. The next step is building models with ANN for which significant data based on the regression test will be used as input data to the corrosion prediction program in gas pipelines.
The deliverable of this study is getting the prediction program of gas pipeline corrosion of carbon steel using MATLAB software. The program accuracy of the program is compared with the actual data.
Impairment of Gas Well Productivity by Salt Plugging: A Review of Mechanisms, Modeling, Monitoring Methods, and Remediation Techniques
Authors: Aquilina Peter 
Published: October 2012

Abstract
Well productivity decline in mature gas fields, often attributed to liquid loading, may actually be due to salt deposition, which can produce identical symptoms. Salt plugging in gas wells has been well documented in Germany and the USA and is increasingly becoming an issue in the North Sea. There is an increasing awareness amongst North Sea operators of the issue of salt precipitation in gas wells, however, a recent literature search on the subject revealed a limited body of work suitable for use as an introduction to the subject. This paper reviews the mechanisms of salt precipitation, and looks at some modelling and monitoring methods and reviews the available remediation techniques
Salt problems occur over a very limited range of producing conditions and are generally seen in mature, depleted gas fields, explaining perhaps the recent increasing interest in the issue amongst North Sea operators (UK and Netherlands). Salt solubility in water decreases with both reducing pressure and temperature, such as in a producing gas well, so that salt can precipitates as saturated produced water flows up the wellbore. The solubility effects are small but are exacerbated, or exceeded, by dehydration effects as produced water enters the wellbore. Salt may precipitate and adhere to the completion walls and produce a salt bridge. Salt can plug perforation tunnels and even form within the reservoir itself. It is not solely a downhole problem, salt precipitation can occur inside surface equipment such as compressors.
For production operations, early detection or prediction of salt precipitation is vital, yet it has proved difficult as the issue depends on individual well conditions. The paper discusses how diagnostic modelling may help if certain data are available: produced water salinity, operating conditions along the wellbore and reliable WGR history.
Finally, the paper describes current remediation techniques to restore gas well productivity.
Correlation to Predict and Validate the Maximum Retrograde Condensation in Gas Condensate Reservoirs
Authors: Paredes J. E. , Pérez R. , Larez C. J. 
Published: October 2012

Abstract
An important aspect for the exploitation of gas condensate reservoirs is the knowledge of the maximum retrograde condensation, due to the volume of liquid that can be trapped if the pressure reaches the zone where this phenomenon occurs because hardly reaches critical fluid saturation as so it can move toward wells.
This work proposes a correlation that can be used to predict or validate this property, based on the relationship between the maximum retrograde condensation, the molecular weight (MW) of the original composition and its gas oil ratio. A real case analysis is presented which corrects the maximum retrograde condensation measured in the laboratory, reproducing the full curve of this property, without changing the thermodynamic conditions of the fluid.
Also, a conceptual numerical simulation model was built to quantify the behavior and effects if is not corrected the retrograde condensation property in a PVT study.
The Use of a Transient Multiphase Simulator to Predict and Suppress Flow Instabilities in a Horizontal Shale Oil Well
Authors: Norris H. Lee 
Published: October 2012

Abstract
Due to its limited drainage radius, the sand face pressure in a hydraulically fractured, horizontal shale oil well will fall rapidly with cumulative production. Once the sand face pressure falls below the bubble point, flow instabilities will increase dramatically. The onset of instability can be predicted using a transient multiphase simulator such as OLGA1, and techniques to minimize instabilities can be quantitatively investigated through simulation. This paper describes flow instabilities in a typical horizontal shale oil well and demonstrates both causes and remedies for fluctuating production rates in the intermediate and latter stages of well life. Through the suppression of production instability, the ultimate recovery of reserves may be significantly increased.
Experimental Study on Natural Gas Hydrate Slurry Flow
Authors: Lv X. F. , Gong* J. , Li W. Q. , Shi B. H. , Yu D. , Wu H. H. 
Published: October 2012

Abstract
To better understand hydrate slurry flow, a series of experiments have been performed, including water, natural gas and diesel oil, under 4MPa (system pressure), 40Hz (initial pump speed). The experiments have been conducted in a high-pressure hydrate flow loop newly constructed in China University of Petroleum (Beijing), and dedicated to flow assurance studies. A Focused Beam Reflectance Measurement (FBRM) is installed in this flow loop, which provides a quantitative chord length distribution (CLD) of the particles/droplets in the system. Firstly, the influence of flow rate on the hydrate slurry flow was discussed. Then we have studied the factors such as water-cut and additive dosage on the hydrate induction period and the CLD before/after hydrate formation. Finally, we have fitted a new correlation between the dimensionless rheological index, n′, and water-cut as well as additive dosage, according to these experimental results. And a laminar flow pressure model of quasi-single phase hydrate slurry has been established in this paper.
New Upscaling Scheme for Capillary Dominant Displacement
Authors: Behzadi S. H. , Alvarado V. 
Published: October 2012

Abstract
A procedure for upscaling CO2 buoyancy-driven upward migration in finite-difference simulation models is presented in this work. This upscaling procedure allows accounting for effects of capillary and buoyancy forces to enable CO2 upward migration modeling in coarser grids while preserving approximately dominant fine-scaled geological effects. The method has been used in 2D domain simulations with no-flow boundary conditions. The conceptual geological models are built by utilizing sequential Gaussian simulation for different correlation lengths and high level of heterogeneity, Dykstra-Parsons coefficient of 0.7.
Multiphase flow upscaling (MPF) has been improved by accounting for spatial connectivity (percolation), which enabled us to obtain more realistic rock-fluid pseudo-functions and capture effects of local capillary trapping at the fine scale (meso-scale trapping). In contrast with other MPF, e.g. Ekrann (1999) and van Duijn et al. (2002), calculation of rock-fluid functions of each cell has been conditioned by accessibility. Therefore, configuration of coinciding fine-scale cells in a coarse cell affects calculation of upscaled rock-fluid functions. In addition, the effective porous medium properties were estimated using mean field theory (the Maxwell approximation), which considers continuity and isolation of geological facies, responsible for macroscopic residual saturation. The upscaling method and estimation of rock-fluid functions were numerically tested and compared with currently accepted single- and multiphase-flow upscaling methods.
Our results show that single-phase flow upscaling and Maxwell approximation fail to adequately predict mobility and residual saturation. Those upscaling approximations predict gas travel time 7 fold faster. Therefore multiphase flow upscaling should be employed. Significant improvement in gas travel time (representative of mobility) and trapped CO2 saturation (representative of trapped saturation) are observed when spatial connectivity (percolation) is included. Implementation of percolation, improves prediction of gas travel time and residual saturation 21% and 50% respectively.
The developed upscaling scheme lowers simulation execution time 17 fold through upscaling and noticeably enhances the prediction of phases mobilities and macroscopic trapped saturation. This speedup will enable simulating 3D CO2 sequestration simulation scenarios. The scheme can also serve to scale up other subsurface multiphase flow displacement where capillary force is dominant one.
Laboratory Study of Sand Production in Unconsolidated Reservoir
Authors: Luo Weiguo , Xu Suxin , Torabi* Farshid 
Published: October 2012

Abstract
Sand production is a major operational and economical concern in the oil industry due to the potential risk of well failure, limited productivity, erosion of facilities, and increased operating expense. Experimental studies play an important role in understanding the behavior of sand production under different conditions. However, the existing traditional sand production experiments such as thick-walled, cylinder approach or perforation collapse test are only able to predict the onset of sanding and cannot be used to analyze sand production performance over time. In this work, preliminary empirical sanding prediction was performed based on well log data and the formation mechanical properties. The steady-state core flooding tests and core swelling tests were applied to simulate and investigate how the volumetric sand production changes with different flow rates, water saturations and the salinity of injected water. The cores and crude oil samples from an unconsolidated sandstone reservoir in China were used in the tests. The sand flow rate, accumulative sand volume and relative permeability were measured during the sand production process.
The experimental results indicated that the sand production rose at the beginning and declined with the increase of flow rate. During the early water-free production stage, the skeleton sand was not destroyed under realistic reservoir/well flow conditions so that the oil production with sanding was preferred. However, as water saturations increased from 20% to 80%, the permeability decreased by 80% accompanied by dramatic increase in sand production. This is due to the high content of Kaolinite, Illite and Montmorillonite with weak cement in the core which swells significantly and blocks the porosity once it is subjected to the water influx. Therefore, sand control should be considered when water saturation is over 20%. The change of sand production rate demonstrated that both the transient and continuous sand production could be involved in this reservoir. In addition, it is expected that the lower salinity of injected water aggravates the sand production.
Integrated Approach to Unconventional Reservoir Characterization: Key for Understanding Hydrocarbon Production Challenges in Kerogen and Tight-Fractured Deep Carbonate Complex in Kuwait
Authors: Acharya Mihira N. , Kabir Mir R. , Al-Ajmi Saad H. , Al-Maia Noura A. , Kumar Ashok , Pradhan San P. , Al-anzi Ealian H. 
Published: October 2012

Abstract
The unique Kimmeridgian-Oxfordian complex of unconventional and fractured carbonates has been tested to be prolific producer of gas, condensate and light oil in different wells discovered in various North Kuwait fields. The challenge is to characterize the complex reservoir flow system where critical reservoir parameters such as reservoir type, porosity and permeability characteristics, and production and pressure data can vary substantially.
The relationship between the natural fractures and the tight matrix in controlling effective system conductivity in reservoir flow units are the key features which dictate the nature of inflow mechanisms thus the production performance. The paper deals with developing an effective methodology which integrates the variations in critical reservoir properties of the low porosity yet naturally-fractured carbonate reservoir.
The drill stem test (DST) results in some wells were successful without stimulation, while in other wells the DSTs were unsuccessful in spite of advance and repeated stimulations, thus categorizing these plays as geologically-complex, tight gas condensate reservoirs where out of ordinary stimulation techniques may be needed to activate the fractured matrix. Pressure transient analyses and flow regime interpretation of the successfully-tested wells confirm the dual porosity flow-system and the fractured nature of the reservoir.
In this paper, the authors will discuss a new integrated approach for understanding the production and pressure behavior in light of the unique unconventional reservoir characteristics along with the fractured reservoir properties. Dual-layer and dual poro-perm models for pressure transient analysis have been applied extending the previous study of relationship developed between the productivity index (PI) and the total organic carbon (TOC). The proposed integrated methodology can significantly improve the current approach to production optimization, reservoir management strategy, completion, and stimulation design in fractured tight gas condensate reservoirs in Kuwait as well as in other regions.
Channel Characterization for Acoustic Downhole Communication Systems
Authors: Farraj Abdallah K. , Miller Scott L. , Qaraqe Khalid A. 
Published: October 2012

Abstract
The ability to communicate between downhole and surface instruments became a critical need as well operators monitor flow rate, temperature, and pressure data to facilitate well performance optimization and maintenance. The use of wire lines for communication between downhole and surface is common, but these installations present cost, maintenance, and reliability issues. Wireless communications technology using acoustic waves is an interesting alternative to these wired systems. While the acoustic technology offers great benefits, a clear understanding of its propagation aspects inside the wells is lacking.
A testbed was built to investigate the propagation of acoustic signals over production pipes. The testbed comprises an acoustic tool that transmits data to the well surface without cables, an internally-developed receiver unit, and five segments of 7 inch production tubing that form a pipe string. Acoustic waves propagate in this setup by vibrating the pipes’ body, without interfering with the surrounding medium. Moreover, to study the effect of cemented pipes on wave propagation, the third pipe segment was encased in concrete. An impulse signal was fed to the acoustic tool, and channel impulse response readings were taken along the pipe string. The measurements were analyzed to understand the propagation aspects of acoustic waves.
This work shows that acoustic waves experience dispersion and frequency-dependent attenuation over the pipe string; the pipe string appears as a frequency selective channel. The concrete segment filters out a considerable amount of energy in the higher frequency band and introduces further attenuation and dispersion. Signal processing algorithms are proposed to reduce the distortion and dispersion introduced by the pipe string channel on the acoustic waves.
Technical contributions include: finding the impulse response of the channel along the pipe string, investigating the power delay profile, power spectral density, and signal-to-noise ratio measures, and studying the channel dispersion parameters.
Solving Swelling Clay Issues: Modeling Effort/Concentric Reamer Saves Operator Over Seven Days Rig Time vs Plan, UK North Sea
Authors: Snowie Mike , Alexander Gregg , Duncan Roy , Alemi Hassan , Jolly Iain , Barlow Adam 
Published: October 2012

Abstract
The operator requires a 12¼" tangent borehole through interbedded shale, chalk/sandstone that contains hydratable montmorillonite clay, Auk North field, UK North Sea. The swelling clay and long open-hole section have proven troublesome creating hole cleaning issues, frequent wiper trips and stuck pipe events.
A comprehensive modeling project was initiated with the aim of reducing vibration whilst improving rate of penetration (ROP) by selecting the best drive system, bottom hole assembly (BHA) configuration and combination of operating parameters. A rock strength program was run and indicated unconfined compressive strength (UCS) of the Oligocene/Eocene formations at 2-10kpsi. Analogous formation samples were selected from the rock library and laboratory tests were conducted to replicate actual drilling conditions. The resulting data was then entered into the finite element analysis (FEA) based modeling system. A 12¼" × 14" concentric reamer equipped with three polycrystalline diamond compact (PDC) triple row cutter blocks, a pilot PDC bit and a rotary steerable system (RSS) were selected for the investigation. Dynamic simulations were preformed with various operating parameters to observe how changes influenced BHA performance.
The analysis provided valuable insight when the bit and reamer are drilling non-homogeneous formations. The weight-on- tool fluctuation creates BHA instability which can be mitigated by managing parameters. A driller's roadmap was produced showing optimum weight on bit (WOB)/revolutions per minute (RPM) combinations that would produce stable drilling for different formation scenarios.
The integrated BHA was run with the recommended parameters and drilled 5889ft in three runs at an average ROP of 77ft/hr. The BHA met all directional objectives with low lateral vibration and medium stick-slip levels. All cutting structures used showed minimal wear. The successful run enabled the operator to complete the section seven days ahead of authority for expenditure (AFE) plan.
The Use of Two Phase Compressibility Factors in Predicting Gas Condensate Performance
Authors: Arukhe Inese Ntuk , Mason W. E. 
Published: October 2012

Abstract
Gas condensate reserves are typically underestimated when single phase compressibility factors are applied to two-phase systems. The effect is worse in rich gas condensate system with adverse implications for gas initially in place (GIIP) estimation, gas reserves, petroleum accounting, and pipeline designs. Accurate prediction of GIIP early in the life of a reservoir is therefore crucial in reaching development decisions and contractual agreements.
Underestimation of reserves often results from approximations based on single phase (Standing and Katz) compressibility factors that do not consider two-phase regions that retrograde condensate reservoirs exhibit at pressures below the dew point. During isothermal pressure reduction below the dew point phase changes occur leading to liquid and gaseous phase separation in the reservoir. Consequently, there is need to introduce a two phase Z factor in material balance calculations to account for the phase changes in the reservoir.
Ideally, Z-factors for gas reservoirs are determined from constant volume depletion (CVD) tests that simulate compositional changes during reservoir depletion. Sometimes the CVD test reports are not readily available or plans are non-existent for PVT data acquisition campaign. A methodology that employs a suitable correlation developed using fluid molar composition or gas gravity of reservoir fluid to obtain two-phase Z-factors (Z2p) is described. This compares quite well with actual data for retrograde condensate systems.
This paper describes a correlational research design with two-phase Z-factor derived from the real gas law equation and single phase Z factor from Rayes et al (1992) to determine GIIP for gas condensate reservoirs. Z-factors were also determined from Dranchuk Abu-Kassem (1975) correlations using pseudo-reduced properties presented by Sutton (1985) and Kay (1936) mixing rules. The paper compares Z2p, Z-factors, GIIP values obtained from the CVD test and correlations and establishes that the two-phase Z-factor should be used for more precise estimation of GIIP in gas condensate reservoirs.