API 676 MULTIPHASE PUMP MOC & NPSH

[kalizzy]

Hi there,

I'm strugling with the selection for a MPP pump for an onshore oil field(located in the rainforest), the plan is to pump a gas, liquid and oil mixture (about 60%GVF), as you can see i m a jr. engineer and i m having a lot of doubts. The physical-chemical production water test says that there is about 18 ppm H2S(g) and 10% CO2 (g) and the first question is about moc, the type of pump will be twin screw but in some part the API 676 says that if there is any % of H2S, the construction materials shall be suitable with NACE MR0175, but how can i know if the quantity of H2S is the amount enough for this kind of materials. To complete my confusion, i already receive two quotations, one from Bornemann and othrer from leistritz, the first one offers a NACE MR0175 design with reduced hardened materials, but the second only offers CS materials for internal parts as indicates that " materials will be confirmed once the fluid chemical properties are confirmed too". Thanks in advanve.

Similar, the API 676 says that NPSH test is not requerided for MPP, and also the quotations do not show any value for min NPSHr, so the question is ¿Does NPSH is a critical point for design in MPP pumps? ¿Why thes manufacturers do not indicate the amount of NPSHr? Is there any reference to check? because i already search a lot in the internet but i cant find this information. The second type of pump in case twin screw is not suitable, is PCP.

Total flow is about 30 300 bepd and water production flow is apprx. 4500 bwpd.

 

[Snickster]

Looks like you just have H2S in the liquid phase in 18 PPM concentrations. NACE will give recommendations on materials for different H2S concentrations. CO2 is extremely corrosive due to formation of carbonic acid in water. 10% CO2 of gas phase is an extreme amount and I believe you would not be able to use Carbon Steel normally although it may be that the oil phase coats the metal and hinders the corrosion. There are a lot of reports and studies of corrosion in the oil and gas industries due to CO2 and H2S including by NACE. Here is one that provides recommended corrosion resistant materials based on concentrations of CO2 and H2S. I believe in your case you would use charts based on both CO2 and H2S but with H2s at very low concentration if there is very little in the gas phase. The diagrams provide the maximum operating allowed temperature with different concentrations of H2S and CO2 for different CRA materials.

Usually an experience vendor will assist in material selection. You seem to have some pretty bad stuff there.

 

[Snickster]

Here is another reference on corrosion in Oil and Gas Industry.

 

[georgeverghese]

Disappointment and chaos waiting in the wings in this rainforest - screw type MPP with solids in the feed. Good luck to your project managers.

 

[Snickster]

Here is a very old Exxon spec for multiphase twin rotor PD pumps which has a little information on materials and other info that may be helpful.

 

[LittleInch]

It's been a while since I looked at MPPs but in my experience they were all built pretty strong to cope with the changing conditions, densities etc.

For materials you really need to find a materials engineer if you're going to question the vendor or just tell them what the fluid conditions are (pressure, temperature, composition, etc.) and let them decide.

You don't need to know NPSH for multi phase pumps as it's only for liquid.

What sort of inlet pressure and delivery pressure are you talking about? 60% gas volume doesn't mean a lot without pressure.

 

[SB1976]

Hi,

(1) As per NACE MR0175, if the partial pressure of H2S is 15 psi or more, then it calls for applying the NACE requirements. In essence, this calls for including impact strength tests. Hence, along with suction/discharge pressure for the MPP, you need to indicate the percentage of H2S in fluid stream.

(2) Being a positive displacement machine, the correct terminology is NPIP, but you see MPP sometimes behaves as pump when Gas/Liquid Ratio (GLR) =0 and as a compressor when GLR=100%/. Vendor for MPP should consider including a priming vessel to take care of the above. Nevertheless, the good thing about Screw pump is that it can suck vacuum. Yes, u got that right! They can operate with suction conditions at vacuum conditions.

(3) The three technologies available in the market for multi-phase pumping solutions are : (a) Twin Screw, (2) Progressive cavity and (3) Helico-Axial Centrifugal pump. Each has its own merits and demerits to be considered while pump selection.

 

[kalizzy]

Thanks everybody for your kindly answers, somethings to add:
1. 18 ppm H2S(g) and 10% CO2 (g) was found as "disolved gas" in the production water
2. the analysis for the gas phase shows 0% for H2S and CO2, so i thought there is no gas phase for H2S and CO2, isn't it?
3. inlet pressure is min 80 - max 100 psig and discharge pressure shall be 430 psig
4. MOC analysis is important because i should deliver an specification and API 676 DS for this pump, so i shall indicate the materials i recommend for internal pressure parts, so i m not sure if NACE MR0175 design shall be recommended in this situation or not.
5. i already calculate de partial pressure for H2S (1.56kPa or 0.23 psi), my calculation as follows:
C is for H2S concentration (18 ppm or 0.00053 mol/L) , R is for ideal gas constant (0.082 L·atm/mol·K )and T is for fluid temperature (178°F or 354 K) and PH is 6.9
So, 0.23 psi < 15 psi, in this case is not critical use of materials according to NACE MR0175? I found this diagram at Nace part 2 section 7.2.1.2, does it apply? :

6. is primming vessel the same as "recirculation systems"? As the information i received from vendor, in some cases the pump have " external recirculation systems (gas boot)" and in others " internal recirculation systems", does it function as primming vessels?
7. Im not sure if sometimes there is gonna be 100% gas or 100% liquid, but i understood the answer about NPIP!

Thanks in advance!, i'm very gratefull for your guidance!

 

[Snickster]

I think the issue when there is no H2S in gas phase but only in the liquid phase is that you have to calculate an effective equivalent partial pressure that existed in the gas phase to get that concentration in the liquid phase, since NACE only quantifies sour service by partial pressure in gas phase of H2S. I believe this would just be a Henry's law type equation since for a given partial pressure in the gas phase Henry's law predicts the concentration in PPM dissolved in the liquid phase. With a known 18 ppm in liquid phase you should be able to calculate an equivalent partial pressure in the gas phase correlated to 18 ppm in liquid phase.

For the CO2 concentration the term 10% CO2 is confusing as to what is meant by this amount in the liquid as it also should be a PPM dissolved in the liquid.

The following NACE publication appears to provide clarification on how the H2S gas and liquid concentration limits were historically derived and how partial pressure in gas phase relates to amount of dissolved gas in the liquid phase (and visa-versa) and should clarify things.

https://onepetro.org/NACECORR/proceedings-abstract/CORR21/2-CORR21/D021S006R011/464146