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

A Novel Method to Mitigate the Top-of-the-Line Corrosion in Wet Gas Pipelines by Corrosion Inhibitor within a Foam Matrix

CORROSION ◽  
10.5006/0617 ◽  
2013 ◽  
Vol 69 (2) ◽  
pp. 186-192 ◽  
Author(s):  
I. Jevremović ◽  
M. Singer ◽  
M. Achour ◽  
D. Blumer ◽  
T. Baugh ◽  
...  
Keyword(s):  
Corrosion Inhibitor ◽  
Gas Pipelines ◽  
Wet Gas ◽  
Novel Method

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.

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.

A long history of wet gas pipelines in Victoria

2015 ◽  
Vol 55 (2) ◽  
pp. 415
Author(s):  
Steve Henzell
Keyword(s):  
Oil And Gas ◽  
Gas Pipelines ◽  
Gas Field ◽  
Initial Development ◽  
The North ◽  
Wet Gas ◽  
Industry Practice ◽  
Offshore Oil And Gas ◽  
The 1960S ◽  
Marginal Field

Australia's relative isolation and the harsh environment in Bass Strait have led to many innovations in offshore oil and gas developments. The initial developers were moving into frontier territory when Bass Strait was developed, with the harsh sea state and the water depths presenting major challenges. The original development of Bass Strait in the 1960s was tied to a wet gas pipeline philosophy, which was a novel step-out from normal industry practice. For example, the North Sea developments, which started shortly after Bass Strait, adopted dry gas export pipelines and required substantially larger platforms to process the gas for export. The cold waters of Bass Strait require an active hydrate management strategy and the success of hydrate inhibitors has been a key element in using wet gas pipelines. The initial development relied on methanol for hydrate inhibition, but this changed to a glycol-based hydrate inhibitor within 10 years of production start-up, due to challenges in the onshore production facilities. The use of mono-ethylene glycol for management of wet gas pipelines was demonstrated in Bass Strait. The success of the initial developments has given operators the confidence to pursue marginal field developments that rely on wet gas transport to the beach. The Minerva, Casino, Thylacine and Longtom gas field developments in Bass Strait have all adopted the same strategy, in part because of the confidence provided from operating the initial developments for many years.

GRE Lined OCTG as a Cost-Effective Solution for Water Disposal Wells

2021 ◽  
Author(s):  
Gervasio Pimenta ◽  
Mohamad Hussain Ahmad ◽  
Akio Mizukami ◽  
Bogdan Andres
Keyword(s):  
Life Cycle ◽  
Corrosion Inhibitor ◽  
Life Cycle Cost ◽  
Produced Water ◽  
Water Injection ◽  
Cost Effective ◽  
Effective Solution ◽  
Oxygen Scavenger ◽  
Water Disposal ◽  
Monitoring Activities

Abstract Glass Reinforced Epoxy (GRE), lining systems for API 5CT tubing have gained prominence in O&G industry, essentially due to the fact that GRE constitutes a physical barrier protecting the OCTG pipe from corrosive environment, and minimizing issues with scale deposition. ADNOC group companies have been building experience on the implementation of GRE Lined L-80 tubing by successfully using it in produced water disposal wells. Produced water is a highly corrosive medium due to dissolved CO2, H2S high to very high chloride content, high TDS, eventually containing bacteria. The corrosiveness of the fluid increases as the temperature increase from temperatures in the range of 30 – 50 degC at surface to reservoir temperature. The aggressiveness of this medium towards API 5CT L-80 or 13Cr / modified 13Cr increases with its contamination with oxygen. Dissolved oxygen is a strong depolarizer leading to high pitting rates if dissolved O2 content in the water is above 10 or 20ppb. Conventional completion of WDW in ADNOC Onshore is based on API 5CT L-80, and short life of the completion strings has been attributed to deficient water treatment (lack of oxygen scavenger, corrosion inhibitor unsuitable for downhole conditions. A life cycle cost analysis suggests that GRE lined OCTG could be a cost-effective solution for water injection. For this life cycle cost assessment, CAPEX (cost of L-80 completion string, combo corrosion inhibitor & oxygen scavenger skid and OPEX: cost of Combo chemical and monitoring activities for design life were considered, while achieving the required level of well integrity and lower operational safety risks (e.g. handling hazardous chemicals, monitoring activities)

Liquid Holdup in Wet-Gas Pipelines

1987 ◽  
Vol 2 (01) ◽  
pp. 36-44 ◽  
Author(s):  
K. Minami ◽  
J.P. Brill
Keyword(s):  
Gas Pipelines ◽  
Liquid Holdup ◽  
Wet Gas

scholarly journals Effect of Organic Oxygen Scavenger on Performance of Pyrrole as Corrosion Inhibitor

2018 ◽  
Vol 358 ◽  
pp. 012045
Author(s):  
E S Mohd Kassim ◽  
I M Ibrahim ◽  
J Jai ◽  
M S So’aib ◽  
N Ahmad Zamanhuri ◽  
...  
Keyword(s):  
Corrosion Inhibitor ◽  
Oxygen Scavenger

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

Development of MEG Regeneration Unit Compatible Corrosion Inhibitor for Wet Gas Systems

2012 ◽  
Author(s):  
Chaitanya Bikkina ◽  
Narayanan Radhakrishnan ◽  
Sumit Jaiswal ◽  
Ryan Harrington ◽  
Mark Charlesworth
Keyword(s):  
Corrosion Inhibitor ◽  
Wet Gas ◽  
Regeneration Unit
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