pH-stabilisation, a Reliable Method for Corrosion Control of Wet Gas Pipelines

2004 ◽  
Author(s):  
Arne Dugstad ◽  
Marion Seiersten
Keyword(s):  
Reliable Method ◽  
Corrosion Control ◽  
Gas Pipelines ◽  
Wet Gas

Top-of-Line Corrosion Control in Large Diameter Wet Gas Pipelines

2009 ◽  
Author(s):  
Dylan Pugh ◽  
Stefanie Asher ◽  
Nader Berchane ◽  
Jiyong Cai ◽  
William J. Sisak ◽  
...  
Keyword(s):  
Large Diameter ◽  
Corrosion Control ◽  
Gas Pipelines ◽  
Wet Gas

Top-of-Line Corrosion Control in Large Diameter Wet Gas Pipelines

2009 ◽  
Author(s):  
Dylan Pugh ◽  
Stefanie Asher ◽  
Nader Berchane ◽  
Jiyong Cai ◽  
William J. Sisak ◽  
...  
Keyword(s):  
Large Diameter ◽  
Corrosion Control ◽  
Gas Pipelines ◽  
Wet Gas

Top-of-Line Corrosion Control in Large Diameter Wet Gas Pipelines

2009 ◽  
Author(s):  
D.V. Pugh ◽  
S.L. Asher ◽  
N. Berchane ◽  
J. Cai ◽  
W.J. Sisak ◽  
...  
Keyword(s):  
Large Diameter ◽  
Corrosion Control ◽  
Gas Pipelines ◽  
Wet Gas

scholarly journals FLOW ASSURANCE IN KUMUJE WET-GAS PIPELINE: ANALYSIS OF PIGGING SOLUTION TO LIQUID ACCUMULATION

2018 ◽  
Vol 9 (9) ◽  
pp. 380-386
Author(s):  
Sarah Akintola ◽  
Emmanuel Folorunsho ◽  
Oluwakunle Ogunsakin
Keyword(s):  
Pressure Loss ◽  
Gas Pipeline ◽  
Gas Condensate ◽  
Flow Assurance ◽  
Gas Pipelines ◽  
Wet Gas ◽  
Highly Sensitive ◽  
Temperature And Pressure ◽  
Pipeline Corrosion ◽  
Assurance Problem

Liquid condensation in gas-condensate pipelines in a pronounced phenomenon in long transporting lines because of the composition of the gas which is highly sensitive to variations in temperature and pressure along the length of the pipeline. Hence, there is a resultant liquid accumulation in onshore wet-gas pipelines because of the pipeline profile. This accumulation which is a flow assurance problem can result to pressure loss, slugging and accelerated pipeline corrosion if not properly handled.

scholarly journals Coatings & linings for oil & gas pipelines – the most effective method of corrosion protection for aged pipelines

2020 ◽  
Vol 305 ◽  
pp. 00016
Author(s):  
Ion Antonio Tache ◽  
Carmen Tache
Keyword(s):  
Corrosion Protection ◽  
Oil And Gas ◽  
Control Program ◽  
Corrosion Control ◽  
Gas Pipelines ◽  
Internal Corrosion ◽  
Below Ground ◽  
Infrastructure Failure ◽  
Water Gas

Pipelines around the world are in danger due to ageing, deposits and corrosion. Leaky fittings and cracks are an environmental hazard and cause the loss of valuable resources such as drinking water, gas, or oil. The pipelines may get corroded internally due to the nature of the fluid flowing inside and due to various other factors. The environmental and societal impact of infrastructure failure is a primary consideration for today’s pipeline operators. Without implementing safety measures and having a corrosion control program, corrosion makes transporting hazardous material unsafe. There are many methods NACE (National Association of Corrosion Engineers) recommends as part of a successful corrosion control program to protect oil and gas pipelines. Coatings and linings applied to pipelines whether above or below ground and often used in combination with cathodic protection. Different linings may be used for internal corrosion protection, provided the lining material does not degrade following long-term exposure to the transported fluid, at the pipeline pressure and temperature conditions.

Corrosion Inhibitor and Oxygen Scavenger for use as MEG Additives in the Inhibition of Wet Gas Pipelines

2014 ◽  
Author(s):  
MN Lehmann ◽  
A Lamm ◽  
HM Nguyen ◽  
CW Bowman ◽  
WY Mok ◽  
...  
Keyword(s):  
Corrosion Inhibitor ◽  
Gas Pipelines ◽  
Oxygen Scavenger ◽  
Wet Gas

Flow Assurance of Wet Gas Pipelines From a Corrosion Viewpoint

2002 ◽  
Author(s):  
Rolf Nyborg ◽  
Arne Dugstad
Keyword(s):  
Carbon Steel ◽  
Oil And Gas ◽  
Prediction Models ◽  
Process Equipment ◽  
Corrosion Control ◽  
Internal Corrosion ◽  
Application Range ◽  
Wet Gas ◽  
Offshore Oil And Gas ◽  
Stabilization Technique

In many offshore oil and gas projects under development, the pipeline costs are a considerable part of the investment and can become prohibitively high if the corrosivity of the fluid necessitates the use of corrosion resistant alloys instead of carbon steel. Development of more robust and reliable methods for internal corrosion control can increase the application range of carbon steel and therefore have a large economic impact. Corrosion control of carbon steel pipelines has traditionally often been managed by the use of corrosion inhibitors. The pH stabilization technique has been successfully used for corrosion control of several large wet gas condensate pipelines in the last few years. Precipitation of scale and salts in the pipeline and process equipment creates further challenges when formation water is produced. Different corrosion prediction models are used in the industry to assess the corrosivity of the transported fluid. An overview of the present models is given together with a link to fluid flow modeling.

Sizing Wet-Gas Pipelines and Slug Catchers With Steady-State Multiphase Flow Simulations

1998 ◽  
Vol 120 (2) ◽  
pp. 106-110 ◽  
Author(s):  
J. J. Xiao ◽  
G. Shoup
Keyword(s):  
Steady State ◽  
Multiphase Flow ◽  
Simulation Models ◽  
Gas Pipelines ◽  
Flow Simulations ◽  
Wet Gas ◽  
Starting Point ◽  
Operational Information ◽  
Exit Speed ◽  
Steady State Simulation

The design of wet-gas pipelines and slug catchers requires multiphase flow simulations, both steady-state and transient. However, steady-state simulation is often inadequately conducted and its potential not fully utilized. This paper shows how mechanistic steady-state simulation models can be used to obtain not only pressure drop, liquid holdup and flow regime, but also to extract important operational information such as pig transit time, pig exit speed, liquid buildup rate behind the pig, and the time for the pipeline to return to a steady-state after pigging. A well-designed set of steady-state simulations helps to determine pipeline size, slug catcher size, and pigging frequency. It also serves as a starting point for subsequent transient multiphase flow simulations.

PREDICTION OF CONDENSATE FLOW RATES IN LARGE DIAMETER HIGH PRESSURE WET GAS PIPELINES

1978 ◽  
Vol 18 (1) ◽  
pp. 171 ◽  
Author(s):  
R. S. Cunliffe
Keyword(s):  
High Pressure ◽  
Residence Time ◽  
Flow Rate ◽  
Large Diameter ◽  
Operating Pressure ◽  
Gas Pipelines ◽  
Liquid Holdup ◽  
Wet Gas ◽  
Exploration And Production ◽  
Demand Changes

Esso Australia Ltd. operates two offshore gas platforms for Esso Exploration and Production Australia Inc. and Hematite Petroleum Pty. Ltd. in the Gippsland Basin. Gas and condensate from the Marlin platform flow to the gas plant near Sale, Victoria through a 67 mile, 20 inch pipeline. Gas and condensate from the Barracouta platform flow to the plant through a 30 mile, 18 inch pipeline. Average flowing pressure is 1300 psig. Condensate: gas ratios are 65 bbl/MMscf for Marlin and 15 bbl/MMscf for Barracouta.As these platforms are the only source of supply for the city of Melbourne, gas rates are changed to match gas demand. Changes in gas rate are accompanied by changes in condensate flow. From consideration of liquid holdup and liquid residence time, a method of predicting the condensate flow rate resulting from gas rate change was developed.A controlled run was made to test the prediction. After holding the Marlin gas rate steady at 150 MMscfd for 50 hours to reach equilibrium holdup conditions, the rate was increased to 250 MMscfd and held at this rate for 26 hours to reach equilibrium conditions again. The condensate flow rate out of the pipeline was monitored continually.The Marlin pipeline test demonstrated that changes in condensate flow rate resulting from changes in gas rate in high pressure wet gas pipelines can be predicted within 15 per cent of actual rates using liquid holdup and liquid residence time as input data. In the absence of holdup data from pipeline pigging, Eaton's correlation will provide good values for holdup for wet gas pipelines with operating pressure up to 1500 psig and which traverse relatively flat topography.This work has application in the sizing of liquid surge capacity required to receive condensate from high pressure wet gas pipelines. In many cases, investment in slug catcher facilities can be greatly reduced without risk of overfilling with liquid.

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