Pipeline Dewatering Liquid Velocity

[Stuuus]

Hello,

I am putting together a calcs spreadsheet for general pipeline services operations and have run across a problem.

In the case of bulk dewatering, i.e. pigging the water out of the line with nitrogen, I need to calculate the back pressures of the MEG/MeOH slugs and also the water infront of the pig train. The gas flowrate is known in scfm, however this gives an unrealistically high liquid velocity, so I have tried converting the gas flowrate to actual volumetric flowrate as opposed to at standard conditions. This still gives unrealistically large liquid velocities. I'm assuming I'm missing something fairly obvious.

Any help appreciated.

Pipeline Services Engineer in the Oil & Gas Sector

 

[LittleInch]

And we're expected to know some how from that description?

Give us some data to work with here so we can see tour calculation and assumptions.

Remember - More details = better answers
Also: If you get a response it's polite to respond to it.

 

[Stuuus]

Okay.

For the sake of argument, let's say the following:

Pipelay = Horizontal (for simplicity)
Location = Subsea
Pipeline on Seabed at Depth = 105.5 m
Pipeline Length = 23,184.3 m
Pipe ID = 196.9
Pipeline Free Volume = 705.953 m3 (24,927.2 scf)
Pipeline Fill Volume (N2 at 23.3 barG) =
Absolute Roughness = 0.046 mm

Pumping with Nitrogen Gas
Pipeline initially filled with seawater (3.5% Salinity)
Temperature = 7 DEGC (UKCNS average subsea)

Desired Pigging Velocity = 0.5 - 1 m/s (calculated from gas flowrate)
Therefore Qs = 1200 scfm

Pigs : Batch (believe they were foam pigs but don't have the details to hand) - PIG DP = ~0.4 barG
MEG Slug 1 = 4 m3 between Pig1 and Pig2
MEG Slug 2 = 4 m3 between Pig2 and Pig3
MEG Slug 3 = 3.5 m3 between Pig3 and Pig4


Data from the actual job as performed (Pump on Platform, Pipeline outlet - Subsea PR):
N2 Convertor P = 23.33 barG @ Q = 1200 scfm and Vpumped = 728,540 scf
N2 Convertor P = 23.36 barG @ Q = 1200 scfm and Vpumped = 748,401 scf


Calculations for gas flow from Menon - Gas Pipeline Hydraulics Textbook
Where gas velocity is calculated as:
v (m/s) = 14.7349 * Qs (Sm3/day) / (D*1000)^2 * Ps / Ts * Z / Tsys / P
All other units are SI.
Calculating Qs using the general gas equation with churchill friction factors and
thermophysical properties: PREOS for gas , Tumlirz for water and UTE for MEG.


So I can get the gas velocity easily enough, what I'm needing is the liquid velocity within the pipeline (potentially of up to 10 sections, with varying dimensions).

Pipeline Services Engineer in the Oil & Gas Sector

 

[LittleInch]

That's a lot better.

A couple of things before I address the numerical data.

It is a little surprising to note that you initially used standard conditions for a pressurized supply - that's a fairly basic issue right there. Remember to always use absolute pressure in any compression calculation.

It's always best to use one set of units, chopping and changing makes for errors when you forget to convert or get the conversion wrong.

Clearing a liquid pipeline with gas is a transient event with constantly changing flows, pressures and issues. Unless the pipeline is very long (>50km) I would normally ignore the frictional losses in the gas phase ( and hence and pressure difference from injection point to the pig) as being almost negligible compared to the vastly more viscous and dense liquid phase.

Essentially you need to look at the pressures and heads every 5 or 10% of the overall pig journey. Then re-calculate based on elevation of the pig, end pressure, length, frictional resistance etc. The exit flowrate is much better if it is controlled to a set flow as the driving force and frictional element are in constant change as the pig moves along the pipeline.

Your numbers look Ok,
1m/sec = 30.43 m3/hr = 65.5 ft3/min

Converting that liquid volume flow to standard gas flow depends on the pressure you use, which for 1200 scfm you quote is about 18 bar.

Mass flow in the liquid phase will be the same wherever you have liquid so just need internal diameter to get velocity if the ID changes.

I really don't know what that second last paragraph is doing or means.

As I said above, you can't spreadsheet this other than a snap shot at a particular distance along the pipeline with a particular pressure, because it all keeps changing as the pig moves down the pipeline pushing the liquid out of the exit point ( subsea?). Hence the frictional losses will keep going down as the length of liquid column is constantly reducing.

Normally what you're trying to do is use the smallest amount of expensive Nitrogen as you can so that you arrive with barely enough pressure behind the pig to keep it moving and flow the liquid out of the end. however each line clearance is different and what happens afterwards will affect the issue, but control over the liquid flow is usually required to prevent excessive pig velocity either at the end or part way through the operation.



Remember - More details = better answers
Also: If you get a response it's polite to respond to it.

 

[Stuuus]

Thanks for the response.

We always use scfm for any gas flow, I had assumed that was just standard convention as it is rare we see anything else, so the SoW can be quoted regardless of back pressures calculated in detailed engineering.

Regarding the units, procedurally we generally use gauge pressures just to make it easier on the field guys who will be reading off a gauge and inputting into a dewatering report which can do the conversions for them. My calcs spreadsheet has all calculations in SI units with conversions from selected units in the inputs automatically converted.

I perhaps could have been more clear, my spreadsheet currently has 78* 'scenarios' which specify the location of a chemical slug, and calculate for that particular scenario and then cycle thru each of the 78 using VBA. An example of a scenario: Slug 1 has entered section 2, or slug 4 has entered the downline, or the pigging medium only. The spreadsheet is not specific to dewatering (or gas for that matter) so has to be fairly adaptable to accommodate any different operation type we generally perform. (*78 because 10 pipeline sections, 1 downline and up to 7 chemical slugs, plus one for only the propelling medium).

The solution is iterative, in order to more accurately determine thermophysical properties, i.e. I first calculate at NTP in order to get an initial estimate of the pressure profile, then use that pressure to determine new values for compressibility, density etc, re-calculate, get new pressures and thermophysical properties and iterate to a solution.

So, I believe what you are saying is if I convert the standard volumetric flowrate (gas) into a mass flowrate (Gas) by:
mdot = (Q (std) * rho (gas))
then from this mass flowrate to determine the liquid vol. flowrate by:
Q(liq) = mdot / rho(liquid)

Then this should give the liquid flowrate and thus liquid velocity from Q = Av

 

[LittleInch]

The issue with pigging is that the gas pressure can go up and down and hence density and mass flow goes up and down as the pig moves along the line. Hence it's not easy to directly equate a compressible fluid flow with an incompressible fluid flow.

The best way by far is simply to control the liquid outflow flow rate measured by a flow meter.

You can't always control the gas pressure fast enough to stop the liquid flow rate going up and down rapidly which is normally not a good thing. I appreciate the gas vendors like to have a fixed gas standard volume / mass flow being pumped in, but the pressure that occurs at will be going up and down and that will impact the liquid velocities.

I would be very careful to separate the calculations for liquid lines and blowing liquid lines with gas - different beasts with different inputs.

Remember - More details = better answers
Also: If you get a response it's polite to respond to it.

 

[Stuuus]

Okay, thanks for your help. Appreciate it.

Pipeline Services Engineer in the Oil & Gas Sector

 

[LittleInch]

No problem.

Line clearances are usually quite fun and out of the ordinary - I've done a few and always enjoyed them, but it is always a moving feast. It's worse onshore when you go up and down over hills and the pig speeds up and slows down hugely if you're not careful.

Remember - More details = better answers
Also: If you get a response it's polite to respond to it.

 

[Stuuus]

Aye, we have the same problem offshore on longer lines, over sand banks, up risers or from offshore to the beach.
Got a job in the Med next year where the lowest points are at 1600-1700m, platforms at 80m depth and then onshore. Going to be interesting

Pipeline Services Engineer in the Oil & Gas Sector