3.Gas calculations

The presence of free gas at the pump intake and in the discharge tubing makes the process of equipment selection much more complicated and voluminous. As the fluid (liquid and gas mixture) flows through the pump stages from intake to the discharge and through the discharge tubing, the pressure and consequently, fluid properties (such as volume, density, etc.) continuously go on changing. Also, the presence of free gas in the discharge tubing may create significant “gas-lift” effect and considerably reduce the required discharge pressure. The performance of a centrifugal pump is also considerably affected by the gas. As long as the gas remains in solution, the pump behaves normally as if pumping a liquid of low density. However, the pump starts producing lower than normal head as the gas-to-liquid ratio (at pumping conditions) increases beyond a certain “critical” value (usually about 10 - 15%). It is mainly due to separation of the liquid and gas phases in the pump stage and due to a slippage between these two phases. This phenomenon has not been well studied and there is no general correlation describing the effect of free gas on pump performance. A submersible pump is usually selected by assuming no slippage between the two phases or by correcting stage performance based on actual field test data and past experience. Ideally, a well would be produced with a submergence pressure above the bubble point pressure to keep any gases in solution at the pump intake. This is typically not possible, so the gases must be separated from the other fluids prior to the pump intake to achieve maximum system efficiency.There are numerous combinations of equipment configurations and wellbore completions which are available for enhancing the performance of ESP's in gassy applications. Many of these are identified in the "Gas Handling Guideline". ESP market offers several optional components used for separating gas from the fluid going to the pump intake. These are listed acccording to increasing efficiency. The first is a reverse flow intake, which uses the natural buoyancy of the fluids for separation. The second is a vortex type intake, which uses the fluid velocity to set-up a rotational flow to induce radial separation of the gas. The last is a rotary gas separator intake, which utilizes a mechanical,rotating chamber to impart a high, centrifugal force on the fluid to separate the gas.It is essential to determine the effect of the gas on the fluid volume in order to select the proper pump and separator. The following calculations yield the percent free gas by volume.

_{"Natural separation efficiency defines the amount of free gas that naturally flows}_{up the casing annulus and therefore does not enter the pump. 100% natural}_{gas separation will mean that no free gas will enter the pump and 0% means}_{that all the free gas enters the pump. If the pump is below an unvented packer}_{then 0% should be entered, and no rotary separator should be selected.}

_{Mechanical Gas Separation Efficiency refers to the amount of free gas separated from the fluid before entering the first pump stage, versus the total amount of free gas in solution. Separation efficiency decreases with increase in flow rate."}

If the solution gas/oil ratio (Rs),

the gas volume factor (Bg),

and the formation volume factor(Bo)

are not available from reservoir data, they must be calculated, and there are a number of multi-phase correlations to select from. The correlation you select will affect your design, so select the one that best matches your conditions. The following are Standing 3 correlations for solution gas/oil ratio, and formation volume

Gas Volume Fraction (GVF)

Measure of gas produced as % of total solution volume including water, oil, & solids. Since GVF encompasses GOR it is now used in most AL advertising.

Now that we have a grasp on our basic formulas, we can use them to derive some more advanced (and useful)relationships

Advanced Calculations: Considering dual separation (Natural and forced)

Gas to Liquid Ratio (GLR)

Measure of gas produced as a ratio of the Oil and Water production.

What is Turpin's Ratio?

Turpin's correlation is a measure that combines the relative amount of gas (VLR or GVF) and Pump Intake Pressure to determine whether gas interference is likely in a centrifugal pump.

Turpin's Correlation

Two phase flow -When the Pump Intake Pressure(PIP) < Pb(Bubble Point Pressure)

Gas and Liquid Co-exit together in the well & ESP Stages

a)Stagnant bubbles

b)Gas Pockets

1.Bubble Flow Regime: If the PIP < Pb-gas comes out (Bubbles)

2.Agglomerated Bubble: Increasing GVF allows accumulation of gas bubbles at Impeller blade( Head Degradation)

3.Gas Pocket Regime: If the Gas Content (GVF) continues to increase, gas bubbles merge together to form gas pockets (Gas Blocking to Surging)

4.Intermittent Gas Regime: After the Gas Pocket Regime and Gas Content continues to rise, we get (Gas Locking)

Contour surface of 30% gas void fraction corresponding to 10% GVF

1.Free Gas Content (ᾳ): Free Gas flow rate divided by Total Volume rate Qg/(Qg+ Ql)-or GVF @ Insitu. This is the Void Fraction

2.Free Gas into Pump(FGIP): Free Gas flow rate into pump divided by Total Volume Rate into the pump after Natural Separation Qgp/Ql+ Qg-@ Insitu

3.Head Degradation: Reduction of Pump head from Ideal conditions of water

4.Gas Blocking: After the accumulation of the Gas Bubbles, they start to block the Impeller Eye( fluid path)

5.Surging/Heading: Worsened by Gas Blocking. A cyclic fluctuation of the systems pressure . “Pressure Instability” is also used to reference this phenomenon

6.Specific Speed: Just a number to gauge which family the Pump belongs to (Next Slide)

Two phase flow bad Impact towards Pump

Head Degradation: Loss of Production

Surging/Instability

Gas Locking: The walk to Gas Locking

Motor Performance

Unstable load on motor affects Motor

Poor cooling of the Motor as the specific heat capacity of gas is very low

During Surging/ Gas locking stops the liquid and the motor cannot be cooled so Winding Temperature spikes up and this could damage the Motor

Cavitation: A big problem for Centrifugal pumps in general.

This happens when small vapour bubbles collapses as they are taken by the flowing liquid to places at higher pressure Damages: Mechanical destruction & Erosion of the metal partsPumping efficiency reduced when eroded

Gas to Oil Ratio (GOR)

Measure of gas produced as a ratio of the Oil production only.

Solution Gas Ratio (Rs):

Where:

Rs = solution gas – oil ratio (scf/sbo)

API = oil API gravity

SGg = gas specific gravity (relative to air)

PIPa = ambient pressure (psia)

T = ambient temperature (°F)

Step 1 PIPa = ambient pressure (psia)

Step 2 T = ambient temperature (°F)

Step 3 API = oil API gravity

Step 4 SGg = gas specific gravity

NOTE: Pump Intake Pressure (PIP) should be substituted for Bubble Point Pressure when calculating intake conditions.

Oil formation Volume Factor

The formation volume factor Bo, represents the increased volume a barrel of oil occupies in the formation as compared to a stock barrel.

Where:

Bo = oil formation volume factor

Rs = solution gas – oil ratio (scf/sbo)

SGg = gas specific gravity (relative to air)

SGo = oil specific gravity (relative to water)

T = ambient temperature (°F)

Step 1 Solution Gas Ratio (Rs)

Step 2 SGg = gas specific gravity Step 3

SGo = oil specific gravity Step 4

T = ambient temperature (°F)

Gas Formation Volume Factor (Bg)

Bg is the ratio of the volume occupied in the reservoir by gas to by a volume of gas measured at standard conditions

Where:

Bg = gas formation volume factor (bbl/mscf)

Z = gas compressibility factor

PIP = pump intake pressure (psi)

T = ambient temperature (°F)

Step 1 T = ambient temperature (°F)

Step 2 SGg = gas specific gravity

Step 3 PIP = ambient pressure (psia)

Water Formation Volume Factor (Bw)

Bw is the ratio of volume occupied in the reservoir to a volume of water measured at standard conditions. Water is very incompressible compared to oil and gas will not readily dissolve in it, Bw is usually assumed to be 1.

Total Volume of Fluids

When these three variables, Rs, Bo ,Bg & Bw are known, the volumes of oil, water, and free gas can be determined and percentages of each calculated. The total volume of gas ( both free and in solution ) can be determined as follows:

The gas in solution at submergence pressure ca be determined as follows:

Determining free gas at intake conditions

The Free Gas equals the Total Gas minus the Solution Gas.

Surface Conditions Low Pressure & Low Temperature

Downhole Conditions High Pressure & High Temperature

Conversion Factors Surface to Downhole

Vw=Bw x BWPD

Vo= Bo x BOPD

Vg= Bg x Free Gas

Calculate surface volumes

Total Fluid at Intake

Vt = Vo + Vg + Vw

Free Gas at Intake

%free gas= Vg/Vt

Vapour to Liquid Ratio

Total Liquid rate at intake = Vl = Vo+Vw@sc

Vapour to Liquid ratio = VLR = Vg/Vl

VLR can be used to determine the pump intake requirements. Grey zone indicates that gas interference may occur. The zone below the straight line indicates there is gas interference & a rotary gas separator is needed.

Eg: Liquid Flowrate at intake = 3849 BPD

2 Stage Separator is 74% efficient at removing gas, 26% gas remains