Tuesday, December 19, 2017

Typical Gas Well flow control.

Typical Gas Well flow control.




Since the Automation has been increased in upstream industry of oil and gas in last 2 decades, Now Control schemes on the automated choke valves are also getting sophisticated. Automation certainly have tremendous advantage over manual operation but have to be careful for operation and control strategy adopted for the same.
I was doing the research on gas well control and I thought to give a synopsis for the same.Typical gas Control valve Control Scheme may be look like below: 


I would like to give you a quick and easy to remember Summary of various Controllers / Constraint on the gas Line Choke valve.

1. Demand From the master load controller (Asking For how much gas the plant can handle to process in the separator)
2. High Pressure Controller: CONTROL The Pressure before the HIPPS valve activated for safeguarding of flow line.
3. High Flow Controller: Flow should not be more than the pipeline can handle even though the terminal asking for more.
4. Low Flow Controller: To avoid Liquid Loading the Well tubing
5. High Erosion velocity Controller: To Avoid Erosion in Well Tubing / Annulus
6. Low pressure Controller: To avoid Reverse Flow from other wells and In case of tube rupture etc.
The above control or constraints to flow are super set and applicable constraints to be chosen as per the applicability to your system.

Saturday, December 16, 2017

What is Process Simuation in Process Design

What is Process Simulation for Process Design?

General Concept and Typical Simulator Steps:-

Simulation is nothing but computer assistance for solving the equation which we study during our course of engineering e.g. gas equations for calculating the properties of gas, heat and mass balance equations, Chemical rate equations etc. –All combined together

So basically Computer reduce our efforts to do the calculation and it’s called simulation (Good for making impression on somebody else – “Ya, I am doing Simulation, you know “)

So like any other calculation, Computer (Simulator program) also needs to be told about each and everything you wanted him to do for you.

You can ask simulation to do the calculation and get the results called “Design Mode” Or give them the results and ask him to check weather this is satisfying the criteria (Rating mode).

Simulation is like a baby without his own brain so it needs to be tell exactly how to do the calculation, what’s your assumption, what to consider what to note otherwise it will be like
Garbage in = Garbage Out.

Steps :
1. You have start first by defining the number of Components.
2. How you would like to calculate the properties of the system (Equation of state)
3. Now Enter Simulation Mode and start putting the equipment and flow line/ Energy Lines.
a. For Stream; Give either of two specifications between, temperature, pressure and vapor fraction and then define composition of streams.

4. Than Start Defining the specification of the equipment’s or their duty ( what you want the equipment to do e.g. I put a valve so that I can reduce the pressure than give the valve of How much pressure you wanted to reduce from this particular valve. Another example, you want to heat the fluid and putted a heater so now tell simulation up to what temperature you want this fluid to be heated.
This the basic building block of all simulation models, the more you know, the more you can go into the details of each step. Let me know if you have any specific Question
Don’t forget to enjoy the day.

Friday, December 8, 2017

Corrosion by Naphthenic Acids in oil and gas

Corrosion by Naphthenic Acids in oil and gas.

Corrosion Has Many Sources and Naphthenic acids are just one source of the corrosive properties of crude or crude fractions.
Other naturally found crude components that can contribute to corrosion in the refining process are mineral acids, phenols, hydrogen sulfide, mercaptans, and carbon dioxide.

So exactly what are Naphthenic Acids?

          General term for all organic acids found naturally in crude oils.
         General structure is believed to be


1.      What Makes Them Special?

          Naphthenic acid corrosion is very serious as Iron Naphthenate is soluble in oil. 
          These effects can be seen even in highly alloyed metallurgies which are normally resistant to corrosive attack from sulfidic species.

2.      How is Naphthenic Acid Concentration related to TAN (Total Acid Number)?

          There is no direct correlation.  TAN is a measurement of all acidic species present in the crude.
          Many types of Crude with high TAN numbers can have a low naphthenic acid content, and vice-versa.  

3.      How is Naphthenic Acid Concentration Related to Corrosive Potential

          The corrosive potential from naphthenic acids is a function not only of concentration, but also of temperature, flow regime, velocity and metallurgy.
          Boiling points of the naphthenic acids.
And this means…..?
          Naphthenic acid concentration may be a serious source of corrosion for one process and have relatively benign effects for another. 
          The density and viscosity of the liquid and the vapor in the pipe, the degree of vaporization in the pipe, and the pipe diameter are all factors affecting the corrosive activity of naphthenic acids.
CDU Furnace Tubes, Transfer Lines and Side Stream Piping
          Higher temperature increases likelihood. (kerosine/diesel, long resid)
          Two phase flow favors organic corrosion.
          Turbulence increases potential for organic corrosion.
Vacuum Column System
          Nap. acids are vaporized and condensed.  This increases the TAN of the condensed material.
          Relatively low velocity.  This means that corrosion is almost all in the liquid phase at the point of condensation.
          LVGO and HVGO are boiling ranges where nap acids are more prevalent and active.
And this Means?
          There is not a one-size-fits-all rule of thumb for how naphthenic acids will affect a given metallurgy in a given process.
          Depending on process conditions and metallurgy, small amounts of naphthenic acid can accelerate corrosion in specific areas of the refinery.
Summary
          Naphthenic acids are responsible for a specific type of corrosion in specific areas of the refining process.
          Naphthenic acid concentration is not necessarily a function of TAN magnitude.

Naphthenic Acid Analysis

  1. TAN-  ASTM D664.  Correlations not that great.
  2. UOP 565 and 587.  Sulfur compounds are removed prior to potentiometric or color-indicator titration.  Not very sensitive, and is not very specific to naphthenic acids.
  3. Mobil Method- LC extraction and IR quantification
  4. Fast Atom Bombardment –Mass Spec: This is very specific to naphthenic acids, and provides a very good profile of the MW distribution of the species that are present. (Energy and Fuels, 1991, Vol 5, pp371-375) although it’s also not a very easy technique and the amount of instrumentation is significant.
  5. Negative-Ion Micro-electrospray High-Field Fourier Transform Ion Cyclotron Resonance Mass Spectroscopy: - Very solid technique, but not widely available (Energy and Fuels 2001, Vol. 15, pp.1505-1511).
  6. Electrospray Ionization High-Field Asymmetric Waveform Ion Mobility Spectrometry-Mass Spectrometry:- Very little sample prep/No loss of volatile components such as formic or acetic acid (http://www.osern.rr.ualberta.ca/Downloads/conradsymp03/fedorak.pdf).
  7. SPE cartridge Extraction/Esterification/Mass Spec: - Provides a very solid analysis of C10+ naphthenic acids. Lighter acids can be lost in the esterification step (Analytical Chem., 2001, Vol. 73, pp 703-707).
So we can keep in mind that :

TAN is not an indication of corrosion potential of naphthenic acids in any given crude.
While more High Acid Crudes are being seen in the market place, Testing of Naphthenic Acid content in high TAN crude is essential to understanding corrosion potential of that crude.

Reference: - HIGH TAN CRUDE CONFERENCE held in Singapore on May 10, 2005

Friday, November 17, 2017

Fired Heaters Performance Checking-Sample calculation

Fired Heaters Performance Checking-Sample calculation

From My Previous Post of Fired Heater Performance check Equation, In this Post lets do a sample calculation :

The Equation Is :

Say Heater Duty is 25 MW, Temperature in and Out is 250 °C and 375 °C, Excess Air is 20%  and Radiant Av Flux is 35000 W/h.m2

VC Heater. Single side fired. 2 pass-6 " NB tubes. Exit Gas Approach to inlet fluid temperature is 100 °C
C
Stack Gas Temperature will be = Fluid Out Temperature + Approach = 250 + 100 =350 °C.

Thermal Efficiency fro Chart 1 below :( for 350 °C tem and 20 % Excess air , its coming 83.5 %)

Let say 1.5% is further loss in casing so efficiency is 82 %.

Assume radiant duty is 65% of total.

Radiant inlet temperature = 294°C


Average radiant fluid temperature = (294+375)/2 = 334°C


Tube metal temperature, take 50°C above = 384°C


Radiant gas temperature, read from chart -2 = 940°C


Radiant section thermal efficiency, from chart -1 again = 53%


Deduct 1.0% firebox casing loss, net efficiency = 52%


Radiant section duty = 52/82 = 63.4% Vs 65% assumed = 15.85 kW


If you want to size this heater,


Radiant heat transfer area = 15.85 e6/35,000 = 453 m
2

Radiant coil length = 453/(π*6.625*0.0254) = 856 m

Take 60 tubes, 30 per pass,


even number; top inlet / top outlet

Each tube, effective length = 14.3 m


Credit for 180° bend, tube weld to weld = 13.8 m


Tube Circle Diameter 60 tubes on 12” pitch on circle


= 60*12*0.0254/ π = 5.8 m


L/D ratio = 2.5


Chart -1



Chart-2
Reference : Energy Environment Engineers

Fired Heaters Performance Checking

Fired Heaters Performance Checking

You might have know about the use of Fired Heaters use in Oil n Gas industry. I would like to write and easily understood post to check the Performance of your Fired Heaters. these methods are developed by :

1. Wilson, Lobo & Hottel (1932)
2. Hottel (1938)
3. Mekler (1938)
4. Lobo & Evans (1939) and others


The Equition is  :   Qr = σ Aeffectiveεeffective (Tg4 – Tt4) + hcAo(Tg4 – Tt4)

Where:

Qr = Radiant Section Heat Absorbed

σ = Stefan Boltzmann constant


A
effective = Effective tube heat absorption area

ε
effective = Effective emissivity based on source & sink

T
g = Radiating gas cloud temperature

T
t = Absorbing tube metal temperature

h
c = Convective heat transfer coefficient gas to tube

A
o = Radiant tubes outer surface area

Aeffective and εeffective are decided by excess air level, tube-spacing, fire box geometry etc, involving a trial & error method employing multiple equations and/or charts to get
the solution.


Lobo - Evans method is based on 85 tests on 19 different furnaces with excess air ranging from 6 to 170%, heat transfer rates or flux ranging from 9.5 to 170.3 kW/h.m
(3,000 to 54,000 Btu/h.ft2) with re radiating refractory surface 0.45 to 6.65 times the effective tube area. 

It is reported to have an error of 5-16%. This methods attempt to relate fired duty including air-preheat against unit heat transfer rate or flux.
The fired duty can easily be determined separately by the thermal efficiency chart for the fuel fired and excess air levels, as shown here. Modern compact furnaces have a narrow range in design
and operation, for instance excess air from 5 to 40% and refractory area 0.5 to 1 times effective tube area.

Please see next post for Sample calculation :

Thursday, August 31, 2017

HAZARDOUS AREA CLASSIFICATIONS Part 5 - last Part with definatations

HAZARDOUS AREA CLASSIFICATIONS  Part 5 -  last Part with definatations

You might have heard IP-55 or IP-56 for your New Mobile phone specification , here is the explanation.

 INGRESS PROTECTION: IP Ratings


• Two digits are used to denote the level of ingress protection for a piece of apparatus.

• 1st digit for the protection against solid objects & 2nd for the protection against liquids.

• Provides basis for suitability for a product depending on environmental condition the product.

First Number
Second Number
Protection against Solid Objects
Protection against liquids
0
No Protection
0
No Protection
1
> 50 mm e.g. hands
1
Vertically dripping water
2
> 12 mm e.g. fingers
2
Angled dripping water i.e.15°
3
> 2.5 mm e.g. tools
3
Sprayed water i.e.60°
4
> 1 mm e.g. wires
4
Splashed water from all directions
5
Dust protected
 (No harmful deposits)
5
Water jets from all directions
6
Dust tight (Total protection)
6
Strong water jets from all directions


7
Immersion upto 1 mtr. & 15 cm


8
Indefinite Immersion
 

CENELEC Marking information:      




ATEX Directive: Atmospheriques Explosives 

          After 1st July 2003, ATEX Directive comes into force throughout Europe. 

          ATEX is continuum  of CENELEC standards & addressing to Dust hazardous.

          To remove trade barrier within Europe.

          Two specific Directives 95a(100a) aimed at manufacturers of equipment intended for use in Hazardous area; 137(118a) aimed at personal safety where sites embrace hazardous areas.

Product Certification Standards:

          CSA: Canadian Standard Association. Canada & U.S.
          FM: Factory Mutual. Aus., Canada, China, European countries.
          UL: Underwriters Laboratories. U.S., U.K., India, HK, Japan.
Statutory Approvals in India:
          Testing Authority – CMRS Dhanbad
          Approving Authority – CCOE Nagpur ; DGFASLI
          Licensing Authority – BIS.

Glossary of Terms used: -

        CENELEC: European committee for Electro-technical Standardization.
        IEC: International Electro-technical Commission.
       Euronorm: Standard developed by CENELEC applying to apparatus for use in hazardous locations. e.g. EN 50018.
      BASEEFA: British Approvals Service for Electrical Equipment in Flammable Atmospheres.
    ATEX Directive: It's an continuum to Cenelec standards and taken care of Dust hazards. To remove trade barriers within EU.
       CE Mark: It's an official marking required in Europe for all electric & electronic equipment that will be sold or put into service for the 1st time.

HAZARDOUS AREA CLASSIFICATIONS Part 4 - METHOD OF PROTECTION

STANDARDS FOR METHOD OF PROTECTION  IN HAZARDOUS AREA


Different techniques are used to prevent electrical equipment from igniting explosive atmospheres. There are certain restrictions on where these different types of equipment can be used.

1. Ex ‘d’ – EN 50018 Flameproof Enclosure Protection :

  • The potentially incendive components are contained within an enclosure into which the flammable atmosphere can enter but which will contain any resultant explosion and prevent its transmission outside the enclosure. Typically used for Switch devices, small breakers, control enclosures, SOV’s etc.
  • Explosion Proof Vs. Flameproof – Americans refer to Explosion proof while UK & IEC refer to ‘flameproof’. IEC defines Ex d equipment which contain an internal explosion but no flames escape from the enclosure to ignite any external flammable gases present outside. Hence ‘flameproof’.
  • Suitable for Zone 1 & 2.

Advantages :


  • Users are familiar.
  • Sturdy housing provides protection to internal components, so used in hazardous areas.
  • Ex proof housing is usually WP also.

Disadvantages :


  • Circuits must be De-energized before housing cover opening.
  • Opening of housing in Hazardous areas voids all protection.
  • Armoured cable required, Type MI. Threaded fittings must be rigid.
  • Conduit seals required within 18" of field Instrument to maintain Ex-proof rating and reduce the pressure piling effect on the housing. 

2.Ex ‘e’ – EN 50019 Increased Safety:

  • Normally sparking components are excluded.
  • Equipments designed so as to eliminate sparks & hot surfaces capable of igniting an explosive atmosphere.
  • Reducing the probability of contamination by dirt and moisture ingress
  • Reducing & controlling working temperatures, ensuring electrical connections are reliable, increasing insulation effectiveness.
  • Suitable for Zone 1,2. Normally Junction Boxes, Terminal Boxes, Motor Control Boxes are Ex’e’.

3. Ex ‘i’ – EN 50020 Intrinsic Safety:


  • An electrical equipment under normal or abnormal conditions is incapable of releasing sufficient electrical or thermal energy to cause ignition of hazardous atmospheric mixture in its most easily ignitable concentration.
  • The circuit parameters are reliably controlled to reduce potential spark energy to below that which will ignite the specific gas mixture.
  • This includes occurrence of one (ib) or two (ia) components faults in the apparatus.
  • Electrical apparatus may be used in hazardous area without certification provided that , they do not generate or store > 1.2 V,0.1A, and 25 mW.
  • Ex ia – Explosion Protection maintained up to 2 components or other faults. IS apparatus may be located in, and associated apparatus may be connected into Zone 0,1 and 2 Hazardous areas.
  • Ex ib - Explosion Protection maintained up to 1 component or other faults. IS apparatus may be located in, and associated apparatus may be connected into Zone 1 and 2 Hazardous areas.
  • This method does not protect entirely against the local over heating of damaged connections or conductors and these should be kept sound suitably enclosed against damage.

Advantages :


  • Lower cost, No armoured cable for Field wiring of Instruments.
  • Greater flexibility. RTD, T/Cs SW’s are used with certification but with appropriate barriers.
  • Easy of maintaince & repair in the field. No need to remove power supply.
  • System is safe if Instrument is damaged because energy level is too low to ignite.

Disadvantages :


  • Requires I.S. Barriers to limit current & voltage between Haz. & Safe areas.
  • High energy consumption applications are not applicable for this technique.
  • Limited for low energy applications as DC Ckts, E/P Positioners.

4. Ex ‘p’ – EN 50016 Pressurized Apparatus Protection:

  • These are system methods.
  • One maintains a positive pressure inside the apparatus and the other a continuous flow of air or inert gas to neutralize or carry away any flammable mixture entering or being formed within the enclosure.
  • Monitoring systems and Purging schedules are required to ensure their reliability.
  • Suitable for Zone 2.

5. Ex ‘o’ – EN 50015 Oil Immersion Protection:

  • This is an old technique used for switchgears.
  • The spark is formed under oil, and venting is controlled.
  • The use of Hydrocarbon oil has disadvantages and the method of protection is confined to remotely hazardous area.
  • Suitable for Zone 2.

6. Ex ‘q’ – EN 50017 Powder Filling Protection:

  • This involves the mounting of potentially incentive components in an enclosure filled with sand or similar inert powder and having a vent.
  • It is primarily of use where the incendive action is the abnormal release of electrical energy by the rupture of fuses or failure of components such as capacitors.
  • Normally it is used for the components inside Ex’e’ or Ex’N’ apparatus & for Heavy duty traction barriers.
  • Suitable for Zone 2. 

    Ex ‘m’ – EN 50028 Encapsulation Protection:

  • Potentially incendive components are encapsulated by a method which excludes the flammable atmosphere and controls the surface temp. under normal and fault conditions.

  • Suitable for Zone 1,2.

7. Ex ‘s’ – BASEEFA SFA 3009 Special Protection:

  • BASEEFA – British Approvals Service for Electrical Equipment in Flammable Atmospheres.
  • No definite rules for this protection systems.
  • It is any method which can be shown to be safe in use.
  • Much of the apparatus having ‘s’ protection was designed with encapsulation & this has been superseded by EN 50028.
  • In addition ‘s’ coding is used when apparatus has been assessed to one of the individual parts of the CENELEC series but does not comply with it.
  • Special protection is likely to emerge is some apparatus which will be certified in accordance with ATEX Directive.
  • Suitable for Zone 0,1,2.

8. Ex ‘n’ – EN 50021 Non Sparking Protection:

  • This is the ‘restricted breathing enclosure’ technique.
  • Precautions are taken with connections and wiring to increase reliability, but not as high as Ex’e’. Where internal surfaces are hotter than desired T rating they can be tightly enclosed to prevent ready access of a flammable atmosphere into internal parts.
  • Its use also means that high ingress protection ratings of IP 65 and above are built into the design.
  • These methods are developed to use in remotely hazardous area as Zone 2.

HAZARDOUS AREA CLASSIFICATIONS Part 3 - TEMPERATURE CLASSIFICATIONS

HAZARDOUS AREA CLASSIFICATIONS  Part 3 - TEMPERATURE CLASSIFICATIONS


In Continuation of my previous Post  Area Classification ,   



we continue in  TEMPERATURE CLASSIFICATIONS

• Hot surfaces can ignite explosive atmospheres. To guard against this, all electrical equipment intended to use in a potentially explosive atmospheres is classified according to max. surface temp. it will reach in service.

• This temp. is normally based on a surrounding ambient temp. of 40 deg C (102 deg F).

• This temp. is compared to the ignition temp. of the gases which may come in contact with the equipment & checked for the suitability.

 

IEC 79-8 / EN 50014
NEC Table 5003 (d)
Max. Surface Temp.  (Deg C)
T1
T1
450
T2
T2
T2A/T2B/T2C/T2D
300
280/260/230/215
T3
T3
T3A/T3B/T3C
200
180/165/160
T4
T4
T4A
135
120
T5
T5
100
T6
T6
85