Hydrogen transportation by pipelines

I.A. Gondal , in Compendium of Hydrogen Energy, 2016

12.3.1 Pipeline components

A natural gas transportation system is made up of compressor stations, pipelines, city gate stations, and storage facilities. The compressor station serves as the heart of the transmission system as it supplies the energy required to ensure that the gas continues to flow at a prescribed flow rate and pressure. The onshore and/or offshore pipelines have three types: trunk or gathering, transmission, and transportation and distribution pipelines. Figure 12.3 shows the different types of pipelines according to their function.

Figure 12.3. How natural gas gets from the well to the consumer (Pipeline and Hazardous Materials Safety Administration, 2013).

Natural gas pipelines primarily serve as a means of moving gas from the field to consumers. Inter- and intrastate pipelines are used for the transportation of natural gas produced from gas fields, either onshore or offshore facilities through gathering systems to commercial, residential, industrial, and utility companies. The pipelines are usually constructed of carbon steel and varying in size from 2  inches (51   mm) to 56   inches (1400   mm) in diameter, depending on the type of pipeline. Pipeline infrastructure originating from the resource field comes from two main networks:

•

High-pressure grid-transport network

•

Low-pressure grid-distribution network

High-pressure lines are characterized by larger diameter and strong piping with compression stations after regular distance intervals. Low-pressure or distribution networks are identified by pressure reduction stations and a relatively small diameter piping network. The function of the pipeline network is twofold. It serves to supply energy to the consumer in the required quantity, and at the same time, it also provides storage for the fuel gas in a considerable quantity depending upon the dimensional capacity of pipeline and the demand–supply gap. When supply surpasses the consumer demand, the excess gas is "packed" in the pipeline, which is hence called the "linepack."

Transport pipelines are mainly made out of steel because of the high pressures used. Distribution pipelines are made out of cast iron, fibrous cement, PVC-enriched polyethylene (PE), or steel. Currently, mostly PE pipelines are used.

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Desulfurization for Fuel Cells

Santosh K. Gangwal , in Fuel Cells: Technologies for Fuel Processing, 2011

11.3.1.1 Background

Pipeline natural gas, as opposed to wellhead natural gas, is an ideal fuel for large and small fuel cells because of its very low regulated sulfur content and its ready availability for industrial and residential use through an extensive production and distribution infrastructure. The primary fuel constituent of natural gas is methane. As received from the wellhead, it also contains smaller quantities of C2-C4 alkanes and impurities including H2S, methyl mercaptan, mercury, and inerts (CO2, nitrogen and water vapor). Wellhead natural gas undergoes extensive processing to meet pipeline specifications including operations such as CO2 and H2S absorption, pressure-swing or glycol-based dehydration, mercury adsorption, cryogenic or adsorption-based nitrogen separation, and fractionation of natural gas liquids (C2-C4 alkanes) [25,26]. The amine absorption-based acid gas removal process for nearly complete desulfurization of sour natural gas at the wellhead to the pipeline specification of <4 ppmv is well established.

Liquefied Petroleum Gas (LPG), like pipeline natural gas, enjoys a large distribution network, and is a desirable low sulfur fuel for the development of a fuel cell system with a potential to serve a niche market. It is a versatile fuel that is used widely in decentralized residential and industrial applications requiring heat. It consists of predominantly propane and butane in various combinations. They are byproducts of both pipeline natural gas production plants as well as petroleum refineries. Unlike pipeline natural gas (CH4), LPG becomes a liquid under modest pressure. This property of LPG makes it easier than natural gas to store and transport in vessels and cylinders.

As required by law for safety reasons, sulfur bearing odorants are intentionally added to both cleaned natural gas and LPG prior to their distribution and sale. Typical sulfur containing compounds present naturally and added as odorants are listed in Table 11.1. The typical odorants used are mercaptans, sulfides, and tetrahydrothiophene (THT) [39]. THT is commonly used to odorize natural gas in Europe while tert-butyl mercaptan (TBM) and sulfides, such as dimethyl sulfide (CH3SCH3) are commonly used in the USA. [40]. LPG is most often odorized with ethyl mercaptan (C2H5SH). The total sulfur in pipeline natural gas including odorants is typically in the 2–20 ppmv range [39] while it could be as high as 120 ppmv in LPG [40]. In addition to a widely available supply infrastructure, the low sulfur concentrations also make these fuels highly desirable for compact fuel cell systems.

TABLE 11.1. Typical Sulfur Compounds and Odorants in Natural Gas and LPG

Name Formula Structure Boiling point (°C)
Hydrogen sulfide H2S
–60
Carbonyl sulfide COS
–50
Methyl mercaptan CH3SH
6
Ethyl mercaptan C2H5SH
36
Dimethyl sulfide C2H6S
38
t-Butyl mercaptan C4H10SH
64
Tetrahydrothiophene C4H8S
120

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Current Status and Perspective in the Use of Natural Gas for Electricity Generation in the North America Region

Jorge Morales Pedraza , in Conventional Energy in North America, 2019

Natural Gas Pipelines in the United States

The US natural gas pipeline system is a complex structure that is used to carry natural gas nationwide. "The US has more than 217.000 miles of interstate natural gas pipelines to deliver natural gas from producing regions to end users" ( Estimated Natural Gas Pipelines Mileage in the Lower 48 States, 2008). The system is also used to import and export this type of energy source for its use by millions of people daily to satisfy their consumer and commercial needs (Natural Gas Pipeline System in the United States, 2018). "Across the country, the US natural gas pipeline network has about three million miles of mainline and other pipelines that link natural gas production areas and storage facilities with consumers. This natural gas transportation network delivered more than 25 trillion cubic feet of natural gas in 2016 to about 74 million customers" (Natural Gas Pipelines, 2017) (Fig. 3.18). 13

Figure 3.18. Natural gas pipelines in the US.

Of the lower 48 US states, those with the most natural gas pipelines running through them are, according to the EIA source, Texas (58.588 miles), Louisiana (18.900 miles), Oklahoma (18.539 miles), Kansas (15.386 miles), Illinois (11.900 miles), and California (11.770 miles). The states with the least natural gas pipelines running through them are Vermont and New Hampshire (Natural Gas Pipeline System in the United States, 2018).

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Hydrate formation prediction during discharge of trapped natural gas in a network. Case study

V. Esfahanian , ... M. Samadian , in Proceedings of the 3rd Gas Processing Symposium, 2012

1 Introduction

Tehran city natural gas pipeline network is designed to transmit natural gas from city gas stations (CGS) to industrial and domestic customers. The high pressure sub-network of Tehran gas pipeline network is divided into two sub-networks, namely the north and south super blocks and these super blocks are separated by a number of vales. In a natural disaster (such as earthquake) these valves, the valves between the high-pressure and medium-pressure sub-networks and the CGS valves are closed to isolate each super-block and then the trapped natural gas in sub-network is discharged to the atmosphere through some discharge stacks. Hydrates formation is one of problems facing the production, processing and transportation of natural gas [1]. During the discharge of the high-pressure trapped natural gas in a network, hydrate formation issue needs a careful attention in some pipes of the network due to temperature drop.

In the present, work for hydrate formation prediction a well known numerical simulation software (Pipeline Studio-TGNET) is employed [2]. In addition, to calibrate the model, the results of an experiment carried out in a part of Tehran gas network are used. Some research works related to hydrate formation and numerical simulation of natural gas flow in a network can be found in [3–6].

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The Role of Fuel Cells and Hydrogen in Stationary Applications

Kathrin Volkart , ... Brian Cox , in Europe's Energy Transition, 2017

Blending of Hydrogen in Natural Gas Pipelines

Blending of hydrogen in natural gas pipelines is expected to require only small modifications of the gas grid (see sub-chapter on hydrogen transport in Section 23.1). Nevertheless, the hydrogen concentration and gas ratio must be controlled to avoid damage to the equipment running on the gas mixture. Compared with the other considered hydrogen transmission and distribution options, hydrogen blending in natural gas pipelines (up to 15% by volume) has high public acceptability, high regulatory coverage, and low costs. The major barrier is the medium maturity (TRL 7 in 2020–30), which can be improved by further R&D on the impact of the gas mixture on the gas grid and applications.

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Optimization in Natural Gas Network Planning

Maryam Hamedi , ... Gholamreza Esmaeilian , in Logistics Operations and Management, 2011

Steady State or Nonsteady State

The state of natural gas pipeline networks in different models is presented with two main categories: steady state and transient state. These states are determined through considering or not considering a partial differential equation involving derivation with respect to time [4]. In other words, this classification is dependent on how the gas flow changes in relation to time.

Steady state: In a large number of previous researches with optimization problems in the field of natural gas network, the operation of systems is assumed in steady states because in the previous decades there was no need to quick responses to variability of demands and conditions and problems were simplified by converting to subproblems in steady states [18].

In a steady-state system, the flow of gas is determined with some values which are independent from the time and constraints of the system, especially the ones describing the pipelines gas flow are described by algebraic nonlinear equations [6]. In the steady-state assumptions, it is possible to work out the partial differential equation and reduce to a nonlinear equation with no derivatives, which from the optimization view makes the problem more tractable [4].

Because loads and supplies are not a function of time in steady-state problems, the structure of the network—including the number of sources, compressor stations, valves and regulators, and the optimal parameters of operations including pressures and flows—are determined once [9]. General equations for steady-state flows in natural gas networks have been collected in Coelho and Pinho [19].

Nonsteady (transient) state: When load variations in a system are high, steady-state operations of that system are not desirable or even possible to consider such as when factors like deregulation and peak shaving are being considered. Therefore, efficient and responsive operations in dynamic statuses are essentially required to respond rapid variations in demands and conditions [18]. In a transient state system, the system variables such as mass flow rates through the pipelines and gas pressure levels at each node are defined as the functions of the time dynamically. Usually, descriptive models are used to analyze transient states because of their intractable from the optimization point of view [7].

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Pipeline Economics

E. Shashi Menon , in Transmission Pipeline Calculations and Simulations Manual, 2015

10 Problems

1.

A natural gas pipeline transports 120 MMSCFD at a load factor of 95%. The capital cost is estimated at $70  million and the annual operating cost is $6   million. Amortizing the capital at 8% for a project life of 20 years, calculate the cost of service and transportation tariff for this pipeline.

2.

A new pipeline is being constructed to transport natural gas from a processing plant to a power plant 150   miles away. An initial phase and an expansion phase are contemplated. During the initial phase lasting 10   years, the amount of gas shipped is expected to be a constant volume of 100 MMSCFD at 95% load factor. A pipe size of NPS 18, 0.250-in wall thickness is required to handle the volumes with two compressor stations of 5000   HP total. The total pipeline cost may be estimated at $750,000 per mile and compressor station cost at $2000 per HP installed. The annual operating costs are estimated at $6   million. The construction project will be financed by borrowing 75% of the required capital at an interest rate of 6%. The Regulatory ROR allowed on equity is 13%. Consider a project life of 25 years and overall tax rate of 36%.

a.

Calculate the annual cost of service for this pipeline and the transportation tariff in $/MCF.

b.

The second phase lasting the next 10   years is projected to increase throughput to 150 MMSCFD. Calculate the transportation tariff for the expansion phase considering the capital cost to increase by $30   million and the annual cost increases by $4   million, with the same load factor as before.

3.

A gas pipeline is to be constructed to transport 200 MMSCFD of natural gas from Jackson to Columbus, 180   miles away. Consider three pipe sizes—NPS 18, NPS 20, and NPS 24—all constructed of API 5L-X52 pipe with suitable wall thickness for a maximum operating pressure of 1400   psig. Determine the most economical pipe diameter taking into account the pipe material cost, cost of compressor stations, and fuel costs. The selection of pipe size may be based on a 30-year project life and a PV of discounted cash flow at 6% per year. Use $750 per ton for pipe material and $2000 per installed HP for compressor station cost. Fuel gas may be estimated at $3 per MCF.

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Sales Gas Transmission

Saeid Mokhatab , ... John Y. Mak , in Handbook of Natural Gas Transmission and Processing (Fourth Edition), 2019

15.4 Transient Flow in Gas Transmission Pipelines

Transients occur in natural gas pipelines during filling and line pressurization, emergency shutdown, gas blowdown, and line depressurization processes. Transient flow can also occur in the gas pipeline during normal operation due to variations in demand, inlet and outlet flow changes, compressor start and stop, pipe leak, and/or rupture.

There are some reasons for applying transient analysis during design phase of gas transmission pipelines. The first reason is related to the large investment required by such projects, which includes pipeline and compression stations. The designed system must be able to operate under predicted different scenarios; otherwise the transmission company would face penalties for not delivering the contracted gas volumes and will probably have to make additional unpredicted capital investment on the system, dramatically affecting its cash flow. The second reason is related to the operation behavior of some end user such as gas-fired power plant with different gas demand profile that may interrupt gas consumption up to zero for a certain period of time on a weekly basis. These scenarios must be taken into account because they directly affect pipeline capacity management and transmission costs and also affect the assembling schedule of compression stations and compressor units causing cyclic operation, shutting units on and off. Transient analysis is used to help selecting turbo compressors that best fit system requirements arranged in series (few units and bigger machines) or parallel (more units and smaller machines). It is also necessary to run failure analysis for a single compressor unit or even for a complete station and predict system response in terms of remaining capacity versus time. Transient analysis is important to establish maintenance strategy and define whether standby unit will be installed to enhance system availability. Transient analysis will also be very useful along the negotiation process of ship-or-pay contracts that normally starts well before the design phase. Additional uses of transient analysis are related to the operation of the pipeline in control rooms, training operation personnel, and commercial planning (Santos, 1997; Santos and Mokhatab, 2008).

Accurate predictions of the gas flow rate, temperature, and pressure profiles along the pipelines under transient conditions, which are vital to the adequate operation of gas transmission pipelines, indicate the need for appropriate mathematical models to do a detailed analysis. When modeling pipelines, however, it is sometimes convenient to make the simplifying assumption that flow is isothermal and steady state as long as we incorporate a load or swing factor contingent to a latter transient design checking to prevent inadequate pipeline sizing with potential detrimental impact on the feasibility of pipeline projects (Santos, 1997). Steady-state models are widely used to design pipelines and to estimate flow and line pack. However, there are many situations where an assumption of steady state flow and its attendant ramifications produce unacceptable engineering results. Note should be made that the flowing gas temperature in transmission pipeline does not remain constant over the length of the pipeline. Therefore, complete temperature profiles along pipeline length are required to adequately design the pipeline for operation under varying environmental conditions.

The unsteady nonisothermal flow of gas in transmission pipelines can be described by a one-dimensional approach and by using an equation of state and a set of partial differential equations expressing mass, momentum, and energy conservation laws (Osiadacz and Chaczykowski, 2010). In practice, the form of the mathematical relationships depends on the assumptions made based on the operating conditions of the pipelines. For the case of slow transient flows due to fluctuations in demand, it is assumed that the gas in the line has sufficient time to reach thermal equilibrium with its constant-temperature surroundings. Similarly, for the case of rapid transient flows, it is assumed that the pressure changes occur instantaneously, allowing no time for heat transfer between the gas in the pipeline and the surroundings. However, for this case, heat conduction effects cannot be neglected.

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Underground Sensing Strategies for the Health Assessment of Buried Pipelines

Sean M. O'Connor , ... W. Jason Weiss , in Underground Sensing, 2018

8.1 Introduction

Lifelines infrastructure includes natural gas and oil pipelines, water and sewage lines, gas and oil storage facilities, tunnels, power and communication lines, among others (Ariman and Muleski, 1981), which are vital to modern society and urbanization. As the scale of urbanization increases and societal reliance on modern infrastructure grows, the negative impacts stemming from a lifeline failure also grow. Damage to critical infrastructure lifelines, such as buried pipelines, can have potentially extreme consequences including loss of water pressure, energy supply and communication as well as secondary effects such as widespread disease due to contaminated drinking water and hindered response efforts due to lack of lifeline resources (e.g., water supply for firefighting). Among of the most serious hazards to buried pipelines are seismic and landslide events, resulting in wave propagation and permanent ground displacement (PGD). PGD hazards are typically considered to be much more severe (R. Eguchi, 1983; O'Rourke, 2005) than wave propagation. PGD can be localized to a small section of the pipeline, such as the case for surface faulting, or widespread, such as the case for large scale lateral spreading during liquefaction. Widespread PGD can result in many damage locations throughout the lateral spreading area while localized PGD can result in few damage locations but with potentially much more severe damage. Pipeline damage estimations based on wave motion and PGD metrics have been developed. Eguchi (1983) correlated pipe-break rate with modified Mercalli intensity (MMI). O'Rourke and Ayala (1993) presented wave propagation damage rate versus peak ground velocity for various pipe types and materials. Several researchers developed empirical wave propagation damage relations for various pipe types and situations (Eidinger et al., 1995; Honegger, 1995; O'Rourke and Jeon, 1991). Empirical damage relations for PGD have also been developed (Heubach, 1995; Eidinger et al., 1995; Porter et al., 1991). The current methodologies for post-PGD pipeline assessment are predominately visual inspection from the ground level. Specifically, inconsistencies at the ground level may indicate pipeline displacement below. Above ground sensing methods can also be used such as infrared thermography (IT) and ground penetrating radar (GPR). IR thermography and GPR methods are convenient for providing images that may indicate pipe leaks or discontinuities occurring at the subsurface level (Birken and Oristaglio, 2014). However, these imaging methods can be costly, slow to deploy and operate, and require skilled technicians to operate. Imaging methods may also not provide the level of resolution required for damage localization. In-pipe methods have also been deployed, such as sending small remote devices ("smart pigs") through the inside of a pipeline to detect pipe damage. While empirical PGD-to-damage models and subsurface imaging technologies exist, better decisions could be made on subsurface pipelines after PGD if in situ sensing and monitoring is adopted.

Due to the importance of buried lifelines, it is critical that damage be located and diagnosed quickly so that risks to humans and property can be minimized and repairs made that minimize service outages. Monitoring systems are an obvious approach, allowing for quick assessment of damage severity and location for fast repair. However, two challenges exist for monitoring buried pipelines. First, pipelines often run for tens to hundreds of miles requiring a judicious approach to selecting where sensors are installed. Second, their subsurface location hinders the acquisition of data from installed sensors. To date, most in situ pipeline monitoring systems have been tethered (including traditional wired and fiber-optic sensors) with wiring installed alongside the pipeline to communicate data to a data acquisition system (Glisic, 2014). Such methods can be expensive due to the invasive installation requirements.

The primary goal of this chapter is to illustrate experimental sensing methods that can serve as the basis of future pipeline monitoring systems. Traditional and novel sensing devices are explored in addition to the use of wireless telemetry as a strategy for data acquisition from buried sensors. Specifically, the chapter focuses its attention on customization of a sensing strategy for buried segmented concrete pipelines subjected to PGD. Segmented pipelines, and concrete segmented pipelines in particular, are common buried lifeline systems used to transport waste and storm water. They exhibit dramatic damage when exposed to large PGD events. Depending on the orientation of the pipeline with respect to the fault plane and the direction of faulting, the pipeline may experience axial forces resulting in tension or compression, as well as shear and bending. The principal failure modes in continuous pipelines are tensile rupture and local buckling (O'Rourke, 2003). Segmented pipelines failure is primarily observed as joint distress (O'Rourke, 2003). Axial forces in segmented pipelines can lead to joint pullout or bell and spigot crushing (i.e., telescoping). The sensing technologies presented will be specific to monitoring the motion of pipeline segments and to directly detect damage at the pipeline joints during PGD. Towards this end, the chapter describes the full-scale testing of buried segmented concrete pipelines at the Network for Earthquake Engineering Simulation (NEES) Lifeline Experimental and Testing Facilities at Cornell University. The tests provide an ideal venue to not only validate the performance of buried sensors for pipeline health monitoring, but the tests also advance the understanding of the evolution of damage in segmented concrete pipelines under PGD. Tasks include construction of a full-scale segmented concrete pipeline, design and installation of a sensing system for damage detection and localization, testing and validation of buried wireless communications, observation of soil–pipeline interaction during PGD, and analysis of damage evolution.

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Biogas and Syngas Upgrading

L. Yang , X. Ge , in Advances in Bioenergy, 2016

3.1 Natural Gas

Injecting purified biogas into natural gas pipeline has become a common practice. According to the US pipeline specifications, natural gas pipeline injection typically contains CO 2, water vapour, H2S and O2 at less than 3%, 112   mg/m3, 350   mg/m3 and 1   ppm, respectively. Low concentration of water vapour and H2S is essential to avoid condensation and corrosion. Under certain conditions, long distance pipelines have to be heated, or the gas which is to be transported has to be preheated. Otherwise the temperature would fall below the dew point, because the gas temperature drops in the pipeline and corrosive condensate would develop. In the United States and Canada, interstate pipelines are the "highways" of natural gas transmission. Natural gas that is transported through interstate pipelines travels at high pressure in the pipeline, at pressures anywhere from 200 to 1500   psi or equal to1.4–10.4   MPa. Pressure level is reduced when natural gas is delivered to end consumers.

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