bluuebunny/crossref_metadata_2025_split huggingface dataset:
Numerical Simulation of Transient Flow in a Gas Pipeline and Tank
Authors: Ling Kegang , Guo Boyun , Zhang He 
Published: March 2015

Summary
Gas transient flow in a gas pipeline and gas tank is critical in flow assurance. Not only does leak detection require a delicate model to simulate the complicated yet dramatically changed phenomena, but gas pipeline and gas tank design in metering, gathering, and transportation systems demands an accurate analysis of gas-transient flow, through which efficient, cost-effective operation can be achieved.
Traditionally, there are two types of approaches used to investigate gas-transient flow: one involves treating gas as ideal gas so that the ideal gas law can be applied and the other considers gas as real gas, allowing the gas compressibility factor to come into play. Needless to say, the former method can result in an analytical solution to gas transient flow with a deviation from the real-gas performance, which is very crucial in daily operation. The latter approach requires a numerical method to solve the governing equation, leading to instability issues with a more-accurate result. Our literature review indicated that no study considering the effect of changing gas viscosity on the transient flow was available; therefore, this effect was included in our study.
Our investigation showed that viscosity does have a significant influence on gas-transient flow in pipe- and tank-leakage evaluation. In this study, a comprehensive evaluation of all variables was performed to determine the most-important factors in the gas-transient flow. Several case studies were used to illustrate the significance of this study. Engineers can perform a more-reliable evaluation of gas transient flow by following the method we used in our study.
Oil and Gas Industry Megaprojects: Our Recent Track Record
Authors: Merrow Edward W. 
Published: March 2015

Summary
Projects throughout the process industries--oil and gas, chemicals, and minerals--have become significantly larger and more complex over the past decade or so. The underlying reasons for increasing project size and difficulty are understood--we are developing natural resources in progressively more difficult circumstances simply because we have to. Moreover, the choice of oil and gas developments is influenced by the decisions of some large resource-holding countries to restrict or delay the development of some more easily accessible reservoirs.
Eight years ago at the Offshore Technology Conference, the author reported on a distressing pattern that Independent Project Analysis (IPA) was seeing in offshore projects: Success, measured by how well we meet promises made at the time of the financial investment decision (FID), declines rapidly with project size (Merrow 2003). (Note: IPA benchmarks projects before FID and project systems in the oil and gas and other capital-intensive industrial sectors.) While projects in the USD 300- to USD 600-million range were largely successful, the success rate for the megaprojects--defined as exceeding USD 1 billion measured in constant start-of-2003 terms--was approximately 50%. Interestingly, megaprojects in other industrial sectors, such as downstream oil and gas, minerals, and chemicals, had approximately the same rates of success and failure.
In this updated analysis with a much larger sample of both oil and gas and other process industry megaprojects, our conclusion is quite different for oil and gas projects. While non-oil and gas development projects increased in size and difficulty, they maintained a success rate of approximately 50%. This rate of success is certainly not good, but at least it had not declined despite the much more difficult projects market. Meanwhile, the performance of oil and gas megaprojects collapsed; only 22% of these projects could reasonably be called successful. While the successful projects were spectacularly successful, the other 78% were equally unimpressive with 33% real cost overruns, cost indices that averaged 1.37, and execution schedule slip of 30%. More importantly, a disappointing 64% of these projects experienced serious and enduring production attainment problems in the first 2 years after first oil or gas. The issue this paper addresses is why the relative performance of oil and gas megaprojects dropped so precipitously in the first decade of the twenty-first century.
Experimental Study of 3% Cr Tubing Steel in CO2 and CO2H2S Corrosion Environment
Authors: Yan Wei , Deng Jingen , Dong Xingliang , Zhang Chunyang , Li Wenliang 
Published: March 2015

Summary
The corrosion behavior of 3% Cr steel is tested by a high-temperature/high-pressure autoclave. The corrosion environment is categorized into CO2-alone and CO2/H2S conditions. At 90°C, with the addition of H2S to the CO2, the surface corrosion condition improved greatly, and the corrosion rates declined compared with the CO2-alone condition. Under CO2/H2S condition, with an increasing CO2/H2S partial-pressure ratio, the corrosion rate reached a peak value at pCO2/pH2S = 100, and then declined. Through the analysis of the corrosion products of the samples in different conditions by scanning electron microscope (SEM), EDS, and X-ray-diffraction (XRD) methods, it was found that the inner film is finer and denser than the outer scale. The partial-pressure ratio of H2S corrosion regime should be between 10 and 100 and is not the previous 200.
Introduction Corrosion has wide-ranging implications for the integrity of materials used in the petroleum industry. The implication of CO2 corrosion can be viewed in terms of its effect on capital and operational expenditures and health, safety, and the environment (Kermani and Harrop 1996),which brings huge losses and poses security threats to the development of oil and gas (Minxu et al. 2002; Kinsella et al. 1998). Medium Cr-containing steels showed improved corrosion resistance compared with carbon steel and lower cost than 13% Cr steel (Ueda and Takabe 2002; Muraki et al. 2002; Nose et al. 2001). The effect of medium chromium-additions was attributed to the formation of chromium enriched corrosion products (e.g., observed on 3% Cr steel). Steels alloyed with 3% Cr or more were found to show improved corrosion performance over Cr-free steel by a factor of two or more (Nose et al. 2001). The corrosion becomes complicated when H2S is added into the CO2 corrosion system. The current research should focus on the formation mechanism of the corrosion product film, properties of corrosion product of different structures, and protection to the matrix. The corrosion experiment that has been carried out with 3% Cr tubular steel in pure CO2 and CO2/H2S environments. The results would be to supplement the CO2/H2S corrosion theory of 3% Cr steel and provide theoretical basis for the proper selection of the tubing and casing in oil and gas fields.
Acoustic-Induced-Vibration Case Study for WDDM Onshore Facilities
Authors: Moussa Atef Mahmoud 
Published: March 2015

Summary
In gas applications with high-pressure drops and/or high-velocity gas flow, acoustic-induced vibration (AIV) occurs when very high sound levels are propagated in piping. If the sound levels are high enough, they will excite the circumferential vibration modes of the pipe. This allows the pipe to vibrate in and out as the sound wave moves through the piping. Most often this occurs downstream of pressure-reducing valves or safety-relief valves, but AIV can occur at any location where the pressure drop or mass flow rate is sufficiently large. The level of pipe wall vibration is so high that it can induce fatigue cracking of the pipe and can potentially cause catastrophic pipe failure. The West Delta Deep Marine (WDDM) concession onshore of the slug catcher M9001 had a recent failure in the flare header as result of accumulating AIV effect. As a consequence of this failure Enppi/Burullus and Foster Wheeler have undertaken an engineering assessment study to investigate the risk of AIV for the plant and determine the corrective and engineering solutions to protect the plant from any failure that may occur as a result of AIV. This paper will present a case study as reference for gas-production facilities to consider the AIV application in regard to the design phase, and what might have prevented fatigue of pipes during the operation phase.
The Braess Paradox and Its Impact on Natural-Gas-Network Performance
Authors: Ayala Luis , Blumsack Seth 
Published: March 2015

Summary
Steady increases in natural gas transportation volumes have prompted operators to reevaluate the performance of the existing gas-pipeline infrastructure. Conventional wisdom dictates that adding an additional link or a pipe leg in a gas transportation network should enhance its ability to transport gas. Several decades ago, however, Dietrich Braess challenged this traditional understanding for traffic networks. Braess demonstrated that adding extra capacity could actually lead to reduced network efficiency, congestion, and increased travel times for all drivers in the network (the so-called "Braess paradox"). The study of such counterintuitive effects, and the quantification of their impact, becomes a significant priority when a comprehensive optimization of the transportation capacity of operating gas-network infrastructures is undertaken. Corroborating the existence of paradoxical effects in gas networks could lead to a significant shift in how network capacity enhancements are approached, challenging the conventional view that improving network performance is a matter of increasing network capacity. In this study, we examine the occurrence of Braess' Paradox in natural-gas-transportation networks, its impact, and potential consequences. We show that paradoxical effects do exist in natural-gas-transportation networks and derive conditions where it can be expected. We discuss scenarios that can mask the effect and provide analytical developments that may guide the identification of paradoxical effects in larger-scale networks.
Optimal Design and Operation of Egyptian Gas-Transmission Pipelines
Authors: Elshiekh T. M. , A. Khalil S. , El Mawgoud Hussien A. 
Published: March 2015

Summary
Natural gas is increasingly being used as an energy source. Natural gas transmission pipelines transport large quantities of natural gas across long distances. They operate at high pressures and use a series of compressor stations at frequent intervals along the pipeline (more than 60 miles) to move the gas over long distances.
The objective function is given by a nonlinear function of flow rates and pressures. The optimization problem has been solved with a number of decision variables and the number of constraints to find the optimal design variables and operations of transmission pipelines over flat terrain. The objective function includes installation cost of pipelines, compressor stations, fuel consumption in compressor stations, maintenance, labor, and supervision. The software computer program LINGO (LINDO 1997) is used to obtain the solution procedure for optimal design and operation of gas-transmission pipelines.
Choice of Development Concept--Platform or Subsea Solution?
Authors: Osmundsen Petter 
Published: March 2015

Summary
A real choice exists today on a number of discoveries between platform-basedor subsea development solutions. Statistics from the Norwegian continentalshelf (NCS) show that fields developed with fixed platforms have asubstantially higher recovery factor. The potential for a later commitment toimproved oil recovery (IOR) is determined largely by the original developmentsolution. Through the use of cases and examples, this paper discussesprinciples for valuation of the enhanced flexibility offered by platform-baseddevelopment solutions and sequential subsea solutions. It illustrates thatvaluing the various types of flexibility is difficult, which leads to thefollowing question: Are development solutions being selected without takingsufficient account of option values?
Treating and Releasing Produced Water at the Ultradeepwater Seabed
Authors: Prescott Neal , Daigle Timothy P. , Hantz Savanna N. , Janjua Rafique , Zhang Jeff 
Published: March 2015

Summary
Tomorrow's energy needs are driving the industry to pursue the concept of "no oil left behind." But this goal comes at a cost as the pressures in remote deepwater reservoir pockets are depleted and the water cuts increase. Existing technology is evolving to meet the challenges to automate water separation and purification in deepwater for environmentally safe discharge at the seabed.
To solve these problems, the objectives must be defined; the best available solutions must be selected, and the technology gaps must be identified and closed. Environmental protection is a priority, and the translation of the existing statutory regulations regarding discharged water quality is the starting point. Safety and reliability will follow along with the flexibility to tailor the system to match the reservoir's changing needs and incorporate the best, newest, and fastest-developing technology. Equipment relocation may also prove commercially attractive.
Major challenges will include remote process train control and monitoring, and the ability to perform routine maintenance while the wells still flow. Some of this technology could have immediate benefits to surface processes that would in turn provide ideal proving grounds before the technology ventures into deepwater.
Analysis of Decline Curves on the Basis of Beta-Derivative
Authors: Shahamat M.S.. S. , Mattar L.. , Aguilera R.. 
Published: March 2015

Summary
This paper presents a new simplified method for forecasting oil and gas production during transient and boundary-dominated flow (BDF), which does not require the use of complex analytical or numerical modeling tools. The method is based on the behavior of the beta-derivative (β), where two approximate straight lines are obtained during transient flow and BDF with slopes mt and mb, respectively.
The method is applicable not only to vertical wells in conventional reservoirs producing during BDF but also to hydraulically fractured vertical/multifractured horizontal wells in unconventional reservoirs with prevailing transient (linear) flow. Upon selection of an appropriate βBDF—which mainly depends on the type of flow regime (i.e., radial or linear)—and using the proposed equations, type curves can be generated that provide a convenient method for obtaining the slopes of beta-derivatives for transient flow (mt) and BDF (mb) through a type-curve matching process. The method is validated by comparing results against oil and gas numerical simulations of vertical and hydraulically fractured vertical wells.
The developed method is not biased toward any flow regime or presence of skin. Flow regime and skin effects are embedded in the βBDF and mt parameters. Transient flow and BDF are accounted for through the slopes mt and mb, respectively. Corroborated with the use of numerical simulation and field data from the Western Canada Sedimentary Basin and Mexico, the proposed method provides reliable production-rate forecasting while staying away from the complexities of analytical or numerical modeling.
Analysis of Windows of Opportunity for Weather-Sensitive Operations
Authors: Foo Yu Poh , Gan Kenneth , Giudice Dario , De Masi Giulia 
Published: March 2015

Summary
This paper presents an approach to the statistical analysis of weather windows of opportunity, which are defined as the time span over which the stringent, multiparametric conditions required by weather-sensitive marine operations (such as heavy lift, topside float over, pipeline tie in) are met. For this paper, the topside float over has been used as a case study and application of the statistical analysis. The basic data for the analysis are the numerically generated long-time-series wind, wave, and sea currents, which are becoming increasingly available from weather-forecasting models, global reanalysis studies, and project-specific metocean assessment. These long time series allow identification of climatically significant weather windows at the seasonal, and often at the monthly, time scale. Appropriate statistical distributions to fit the weather windows are required to interpolate within and extrapolate from windows durations, smooth the sample data, and obtain objective assessment of weather-window statistics. For this task, two possible distributions are proposed - the Johnson set of transformations (Johnson 1949) and the Kappa distribution (Hosking 1994) – that, although well-documented in the statistical literature, have seldom, if ever, been applied in offshore analysis. Fits on sample data are performed with the L-moment method (Hosking 1990, 1996, 2000) for the Kappa distribution and with both moment (Draper 1952; Hill et al. 1976) and quantile (Wheeler 1980) methods for the Johnson distribution. The entire procedure (definition of limit conditions, identification of weather windows, and statistical analysis of weather windows) is exemplified with reference to a hypothetical float-over operation in the Andaman Sea (Myanmar). The simulation carried out indicates that the use of statistical distributions can enhance the reliability of the weather-window analysis significantly because of smoother description of weather-window durations, improved interpolation and extrapolation capabilities, and higher discriminating power of alternative design solutions. Both the Johnson distribution and the Kappa distribution provide an overall good performance in fitting the sample data, either when subjectively assessed by visual inspection and in terms of the objective analyses of the resulting mean-square errors; hence, they are suggested as promising candidates for routine analysis of weather windows.
Pneumatic Controllers in Upstream Oil and Gas
Authors: Simpson David 
Published: March 2015

Summary
Process-control engineering is a fairly narrow field of study that has used inconsistent terminology among practitioners. Natural-gas-actuated pneumatic-control equipment has recently become a focus area for regulators trying to reduce the quantity of actual pollutants and greenhouse gases released to the atmosphere. The historical use of inconsistent key terms by experts has led to regulations that are at odds with the realities of existing equipment. The intention of this paper is to begin development of a rigorous set of terms and operational classifications that can help create a framework of knowledge consistent with how this equipment functions. Standardization of terminology has benefits for operators, manufacturers, and regulators alike.
Fast Production Recovery of a Typhoon-Damaged Oil Field in the South China Sea
Authors: Jiayou Mao 
Published: March 2015

Summary
The Huizhou oil field is located at the Pearl River mouth in the continental-shelf region of the South China Sea, with an average water depth of approximately 117 m. The oil field's main facilities include eight fixed-jacket platforms, two subsea-production wellheads (HZ32-5 and HZ26-1N), and one floating production, storage, and offloading (FPSO) vessel (Nanhai Faxian). Fig. 1 illustrates the general layout of the field. The peak daily oil production is approximately 70,000 BOPD. In September 2009, after a strong typhoon (Koppu) passed over this oil field, the FPSO vessel's permanent mooring system was seriously damaged. All production risers connected to the FPSO vessel's turret were ruptured, and production was forced to shut down. To resume production in a fast-track manner, several engineering cases were studied. Finally, the concept of using a dynamic-positioning (DP) FPSO vessel to temporarily resume production was selected. Detailed design and operability analysis was performed by the owner of the DP-FPSO vessel, and various flexible pipes and other materials were sourced quickly in local and international markets. The offshore installation took place throughout the harsh winter monsoonal season from November 2009 to February 2010. Finally, the field was brought back into production after 5.5 months of production stoppage. The DP-DPSO system operated for more than 18 months and proved safe and effective. This was world record time for an FPSO vessel operated in DP mode.
Impact of Well Features on CT Reach
Authors: Kelleher Patrick , Newman Ken , Galvan Irma , Opel Steve 
Published: March 2015

Abstract
Coiled tubing (CT) is frequently used in horizontal wells to mill out hydraulic fracturing plugs before bringing new completions online. However, the maximum depth CT may reach while milling plugs can be a major limiting factor for final completion depths. CT reach limits are normally attributed to friction lockup during these milling operations and can reduce effective pay zone penetration if not considered during the well design. In these cases, several common well features typically contribute to the majority of the low force transfer factors leading to insufficient set-down force and helical lockup.
This paper will discuss key parameter variations found from a case study of several horizontal well designs, and analyze their impacts on typical coiled tubing reach capabilities using a tubing forces model. Features analyzed include: kick-off build rate, vertical sections and simple deviations down to the heel, trajectory changes in the horizontal section, well completion geometry, and required weight on bit (WOB).
Rapid Deployment of Best in Class Snubbing Unit for a Remote Location Reabandonment
Authors: Pittman Iain , Kirchner Silke 
Published: March 2015

Abstract
This paper will outline the snubbing operations conducted to carry out a complex reabandonment in a remote jungle location.
The abandonment called for the fullbore removal of the existing cement plugs with suspected poor integrity and with uncertain pressures below. The challenge was compounded by a restricted ID in the surface equipment which was installed due to unforeseen bubbles in the 13-3/8″ casing after wellhead removal during the original abandonment. The pressures observed required the use of live well intervention techniques and equipment
Several vendors for the supply of the snubbing unit were considered with focus on their stand alone capability and the availability of suitable interlock safety systems.
Due to the nature/condition of the well a number of concepts were considered to initially mill a pilot hole through the surface plug to establish communication with any pressure below the plug. As the intervention was considered urgent the primary plan was to utilise coiled tubing for this (available in country), however due to the cement plugs being inside the 13-3/8″ casing it was decided to hang off a 3-1/2″ conduit string from a slip ram assembly down to the surface plug to contain any CT “walk”.
Following the milling of a pilot hole, a new cement plug was to be set to act as a barrier to allow surface equipment reconfiguration to a 13-5/8″ snubbing stack.
Prior to the CT being mobilised to location and whilst the snubbing unit was in transit from The Netherlands the pressure trend changed from a building trend to a stabilised pressure. As such a judgement call based on the safest and greatest chance of success was made to use the snubbing unit for all operations upon its arrival. The snubbing unit was mobilised and rigged up on to the tree to perform the initial phase of the operation of re-establishing communication to the well through a pilot hole thus allowing reconfiguration of the surface equipment. Following the reconfiguration of the surface equipment the snubbing unit was re-rigged in fullbore 13-5/8″ snubbing stack mode, whereupon the reabandonment operations were conducted based on an assured programme which was amended through management of change during operations due to the wells behaviour.
The remoteness of the location required that all downhole scenarios had to be planned and equipment for all had to be prepared, tested and shipped to location. Meticulous planning was essential for this.
Post job it is evident that utilising the latest interlock systems and modular tower paid dividends in providing a safe conclusion to an uncomfortable situation.