- Benzene, toluene, ethylbenzene, and xylene are members of the aromatics hydrocarbon family group, often referred to as BTEX. These aromatic compounds are also belonged to the broader category of Hazardous Air Pollutants (HAPs) [2]. BTEX can be present in many natural gas streams and are partially absorbed by the solvent in glycol dehydration and amine (e.g., MDEA) sweetening units. It is of specific interest to note that the components: Benzene, and Ethylbenzene are known carcinogens, thus substantiating their removal be solubility techniques.
- In gas treating service, methyl diethanolamine (MDEA) will absorb limited quantities of BTEX from the gas. Based on literature data, predicted absorption levels for BTEX components vary from 5 to 30% [3]. Absorption is favored at lower temperatures, higher MDEA concentrations and circulation rates for normal operating Plant Unit Pressures 800 –1200 psia (56 – 84 bar). The bulk of absorbed BTEX is separated from the MDEA in the regeneration unit and leaves the system in the regenerator overhead stream which requires further treatment before being vented to atmosphere. The amount of absorption of the BTEX is required to be known to determine the proper treating method for the overhead acid gases leaving the regenerator.
- Correctly estimating the quantity of absorbed BTEX and understanding the factors that affect absorption levels is critical to ensure the proper mitigation methods are provided to meet the required emission limits.
- The GPA Midstream research report RR-242 [4], is an extension of several previous GPA Midstream research projects looking at the solubility of hydrocarbons in loaded and unloaded amine solutions. The previous research included research reports RR-180, 185, 195, and RR-220.
- Accurate hydrocarbon solubility data of RR-242 enables the development of new equation of state correlations that can be applied to the simulation of amine units (Bullin and Brown [3, 5]). The data can be used to optimize the design and operation of amine units in which these hydrocarbons are present in the feed gas. The data will provide a basis for accurately predicting the distribution of the heavier hydrocarbons between the treated gas, the amine flash gas, and the acid gas streams. The data will provide a basis for accurately predicting emissions of these hydrocarbons from the amine unit to aid in the design and operation of these units (Moshfeghian and Hubbard [6]).

Figure 1- Process flow diagram of MDEA acid gas recovery unit [3]

This tip will focus on the following design variables:

- Solubility of selected hydrocarbons in pure water, Equation 1, and Figure 2.
- GPA Midstream RR-242 Proposed Model
- Relative solubility of benzene, toluene, and ethylbenzene (EBenzene), Figure 3.
- Solubility of benzene, toluene, and EBenzene in 50 wt % MDEA solution, Figure 4, and Table 2.
- Multicomponent Hydrocarbons Phase

**Solubility of Selected Hydrocarbons in Pure Water:**

Solubility of selected hydrocarbons in pure water can be estimated using Equation 1 [4] or Figure 2.

(1)

Where T is the temperature in K and the correlation parameters, E, F and T_{min}, are shown in Table 1.

Table 1- Equation 1 parameters, E, F and T_{min} [3].

Figure 2 was generated using Equation 1 and its parameters in Table 1. The solubility of these selected hydrocarbons in pure water will be used to estimate their solubilities in amine solution in the proceeding sections.

Figure 2. Solubility of selected hydrocarbons in pure water [4].

**Estimation of solubility of hydrocarbons in amine solution by the GPA Midstream RR-242 Model [4]**

Equation 2 with its corresponding parameters will be used to estimate the solubility of selected hydrocarbons in unloaded and loaded amine solutions.

(2)

Where:

For simplicity and easiness of reading the figures, using the model (Equation 2) similar charts like Figures 3 and 4 or Table 2 were generated in Part – 1 [1].

*Figure 3 – Relative solubility of benzene (Fig 3), toluene (Fig 4), and Ethylbenzene (Fig 5) in loaded 50 wt % (13.1 mol-%) MDEA-Water [1]*

**Convert 50 wt% MDEA to mole % MDEA**

**Basis 100 kg of MDEA solution**

**Mass of MDEA = 50 kg MW of MDEA = 119.17 kg/kmol**

**Mass of water = 50 kg MW of water = 18 kg/kmol**

Figure 4 – Solubility of benzene, toluene, and ethyl benzene in unloaded 50 wt % MDEA solution [1]

Table 2 – Solubility (x0) of benzene, toluene, and ethylbenzene in unloaded 50 wt % MDEA solution [1]

**Example 1– Single Component Hydrocarbon **

This example and its solution on solubility of a single-component benzene in loaded 13.1 mol% (50 wt%) MDEA in water solution were presented in part 1 and shown in Appendix A of this tip.

**Multicomponent Hydrocarbons Phase: **GPA RR 242 [4] has presented the solubility measurements using a hydrocarbon phase consisting of equimolar amounts of Benzene, Toluene and Ethylbenzene. The acid gas used was CO2. The results are presented in Table 5. To evaluate the accuracy of Eq 2 **GPA RR-242 Model [4], **we estimated the solubility of Benzene, Toluene and Ethylbenzene into loaded MDEA (50 wt %) aqueous solution for the conditions listed in Table 5 – GPA RR 242. In addition, a step – by – step hand calculations are shown in Example 2, the yellow highlighted values are the corresponding measured values reported in the highlighted row of Table 5.

*Table 5 – Solubility of Benzene, Toluene and Ethylbenzene into loaded MDEA (50 mass-%) aqueous solution Sapphire Apparatus. Hydrocarbon phase consists of x**1**=0.3329, x**2**=0.3335, x**3**=0.3336 **[Table 5-GPA RR 242]*

a is loading mol acid gas/mol amine, T is temperature, P is Pressure, 𝑥̅ – average mole fraction, n – number of analyzed samples, σ – standard deviation

**Example 2 – Multicomponent Hydrocarbons Phase**

Determine the solubility of benzene, toluene, and ethylbenzene in loaded 13.1 mol% (50 wt%) MDEA in water solution in terms of scf of gas/gal of solvent (std m^{3} of gas/m^{3} of solvent) at 60 °C (140 °F), 333 K (600 °R).

The hydrocarbon phase consists of xB = 0.3329, xT = 0.3335, xEB = 0.3336. Rich amine solution acid gas loading, = 0.41 mol acid gases/ mole MDEA, MDEA MW =119.17

50 wt % MDEA solution density =1017.3 kg/m^{3} (8.49 lbm/gal)

**Solution**

From Fig 3 presented in Part 1 (July 2022 TOTM), for = 0.41 mol acid gases/ mole MDEA,

relative solubility solubilities are, (x/x_{0})_{B} = 0.52 (x/x_{0})_{T} = 0.46 (x/x_{0})_{EB} = 0.36

From Table 2 or Fig 4 presented in Part 1, for T =60 °C (140 °F),

the solubilities in unloaded MDEA are, (x_{0})_{B} = 0.00464 (x_{0})_{T} = 0.00216 (x_{0})_{EB} = 0.00084

Specified compositions (mole fractions) of hydrocarbon phase are, xB = 0.3329, xT = 0.3335, xEB = 0.3336

*Figure 3 – Relative solubility of benzene (Fig 3), toluene (Fig 4), and Ethylbenzene (Fig 5) in loaded 50 wt % (13.1 mol-%) MDEA-Water*

Table 2- Solubility of benzene, toluene, and ethyl benzene in unloaded 50 wt % MDEA solution

**Benzene:** (x/x_{0})_{B} = 0.52 (x_{0})_{B} = 0.00464

For xB = 1, x= x_{0}(x/x_{0}) = (0.00464) (0.52) = 0.00242 kmol Ben/kmol Sol

For xB = 0.3329, x= x_{0}(x/x_{0}) (xB) = (0.00464) (0.52) (0.3329) = 0.0008 (vs. 0.00093) kmol Ben/kmol Sol

The yellow highlighted values are the measured values in Table 5

x = (0.0008 kmol Ben/kmol Sol) (kmol Sol/0.131kmol MDEA) = 0.00611 kmol Ben/kmol MDEA

= (0.00611 kmol Ben/kmol MDEA) (23.64 std m^{3}/kmol Ben) (kmol MDEA/119.21 kg MDEA) = 0.0012 std m^{3} Ben/kg of MDEA

For each kg of MDEA we need 2 kg of sol (1 kg of MDEA + 1 kg of water)

x = (0.0012 std m^{3} Ben/kg of MDEA) (kg MDEA/2 kg Sol) (1017.3 kg Sol /m^{3} Sol)

= 0.62 std m^{3} of Ben per m^{3} of solution

**Or X = (770) [ (x _{0}) (x/x_{0}) (xB)] std m^{3} of Ben per m^{3} of sol**

**X = (770) [0.0008] = 0.62 std m ^{3} of Ben per m^{3} of solution**

**CF** = (kmol Sol/0.131kmol MDEA) (23.64 std m^{3} Ben/kmol Ben) (kmol MDEA/119.21 kg MDEA)*

(kg MDEA/2 kg Sol) (1017.3 kg Sol /m^{3} Sol) = (770 std m^{3} Ben/m^{3} Sol)(kmol Sol/kmol Ben)

The same color terms in the numerator and denominator cancel out.

**SI CF= ****(770 std m ^{3} Ben/m^{3} Sol) (kmol Sol/kmol Ben)**

**Toluene:** (x/x_{0})_{T} = 0.46 (x_{0})_{T} = 0.00216

For xT = 1, x= x_{0}(x/x_{0}) = (0.00216) (0.46) = 0.00099 kmol Tol/kmol MDEA Sol

For xT = 0.3335, x= x_{0}(x/x_{0}) = (0.00099) (0.3335) = 0.00033 vs. 0.00037 kmol Tol/kmol Sol

**X = (770) [0.00033] = 0.26 std m ^{3} of Tol per m^{3} of solution**

**Ethylbenzene (EB)**: (x/x_{0})_{EB} = 0.36 (x_{0})_{EB} = 0.00084

For xEB = 1, x= x_{0}(x/x_{0}) = (0.00084) (0.36) = 0.00030 kmol EB/kmol MDEA Sol

For xEB = 0.3336, x= x_{0}(x/x_{0}) = (0.00030) (0.3336) = 0.00010 vs. 0.000085 kmol EB/kmol Sol

** ****X = (770) [0.00010] = 0.08 std m ^{3} of EB per m^{3} of solution**

**Solution – FPS**

**Benzene: **(x/x_{0})_{B} = 0.52 (x_{0})_{B} = 0.00464

For xB = 1, x= x_{0}(x/x_{0}) = (0.00464) (0.52) = 0.00242 lbmol Ben/lbmol MDEA Sol

For xB = 0.3329, x= x_{0}(x/x_{0}) = (0.00464) (0.52) (0.3329) = 0.0008 (vs. 0.00093) lbmol Ben/lbmol Sol

The yellow highlighted values are the measured values in Table 5

x = (0.0008 lbmol Ben/lbmol Sol) (lbmol Sol/0.131lbmol MDEA) = 0.00611 lbmol Ben/lbmol MDEA

x = (0.00611 lbmol Ben/lbmol MDEA) (379.5 scf/lbmol Ben) (lbmol MDEA/119.21 lbm)

= 0.01945 scf Ben/lbm of MDEA

For each lbm of MDEA we need 2 lbm of sol (1 lbm of MDEA + 1 lbm of water)

x = (0.01945 scf Ben/lbm of MDEA) (lbm MDEA/2 lbm Sol) (8.49 lbm/gallon Sol)

= 0.083 scf of Ben/gallon solution

**Or** **X = (103) [(x _{0}) (x/x_{0}) (xB)] scf of Ben/gallon of solution**

**X = (103) [0.0008] = 0.082 scf of Ben/gallon of solution**

**CF** = (lbmol Sol/0.131lbmol MDEA) (379.5 scf Ben/lbmol Ben) (lbmol MDEA/119.21 lbm MDEA)*

(lbm MDEA/2 lbm Sol) (8.49 lbm Sol /gallon Sol) = (103 scf Ben/gallon Sol) (lbmol Sol/lbmol Ben)

The same color terms in the numerator and denominator cancel out.

**FPS CF ****= (103 scf Ben/gallon Sol) (lbmol Sol/lbmol Ben)**

**Toluene:** (x/x_{0})_{T} = 0.46 (x_{0})_{T} = 0.00216

For xT = 1, x= x_{0}(x/x_{0}) = (0.00216) (0.46) = 0.00099 kmol Tol/kmol Sol

For xT = 0.3335, x= x_{0}(x/x_{0}) = (0.00099) (0.3335) = 0.00033 vs. 0.00037 kmol Tol/kmol Sol

**Or** **X = (FPS CF) [(x _{0}) (x/x_{0}) (xT)] scf of Ben/gallon of solution**

**X = (103) [0.00033] = 0.034 scf of Ben/gallon of solution**

**Ethylbenzene (EB):** (x/x_{0})_{EB} = 0.36 (x_{0})_{EB} = 0.00084

For xEB = 1, x= x_{0}(x/x_{0}) = (0.00084) (0.36) = 0.00030 kmol EB/kmol MDEA Sol

For xEB = 0.3336, x= x_{0}(x/x_{0}) = (0.00030) (0.3336) = 0.00010 vs. 0.000085 kmol EB/kmol Sol

**Or** **X = (103) [(x _{0}) (x/x_{0}) (xEB)] scf of Ben/gallon of solution**

**X = (103) [0.00010] = 0.010 scf of Ben/gallon of solution**

The estimated soluble BTE in the MDEA solution for example 2 and two other cases are compared with the measured values in Table 5R. This table indicates that the APD (absolute percent difference between the measured and estimated values) for eight out of nine estimated solubilities are less than 17.2. Considering very small amount of solubility, the Model estimation values are good facilities calculations and troubleshooting.

Table 5R – Measured and estimated solubility of Benzene, Toluene and Ethylbenzene into loaded MDEA (50 wt %) aqueous solution. Hydrocarbon phase consists of xB=0.3329, xT=0.3335, xEB=0.3336

APD = Absolute percent deviation =100*ABS (Exp Avg x – Model x) / (Exp Avg x)

**Summary**

From the RR-242 developed model based on the experimental results; several conclusions can be drawn.

- Figures 3 and 4 or Table 2 present a simple tool for quick estimation of solubility of BETX compounds in 50 wt % MDEA gas treating process.
- Figures 3 and 4 or Table 2 are suitable for 50 wt % (13.1 mol-%) MDEA in the MDEA-Water solution, similar chart and tables can generated for other different amines and concentrations.
- For the examples considered in this tip and July TOTM, the estimated solubility for each of BETX compounds matched well with the experimental results.

To learn more about similar cases and how to minimize operational problems, we suggest attending our G4 (Gas Conditioning and Processing),G5 (Advanced Applications in Gas Processing)**, **http://www.jmcampbell.com/co2-surface-facilities-pf81.php and__PF49 (Troubleshooting Oil & Gas Processing Facilities)__,courses.

*By: Mahmood Moshfeghian, Ph.D.*

References:

1. Moshfeghian, M. and Snow–McGregor, K., www.petroskills.com/en/blog/entry/july2022-totm, PetroSkills July TOTM, 2022.

2. http://www.earthworksaction.org/BTEX.cfm, 2011.

3. Campbell, J. M. “Gas conditioning and processing, Volume 2: The Equipment Modules,” 9^{th} Edition, 2^{nd} Printing, Editors Hubbard, R. and Snow–McGregor, K., Campbell Petroleum Series, Norman, Oklahoma, 2014.

4. Uusi-Kyyny, P., Pakkanen, M., Richon, D., Ionita, S., Ogunrobo, E., Alopaeus, V., RR-242, “Solubility of Hydrocarbons in Amine Treating Solutions”, GPA Midstream Association, Tulsa, OK, 2019.

5. Bullin, J. A., Brown, W.G., Hydrocarbons and BTEX Pickup and Control from Amine Systems”, 83^{rd} Gas Processors Association Annual Convention, Mar. 2004.

6. Moshfeghian, M. and R.A. Hubbard, “Quick Estimation of Absorption of Aromatics Compounds (BTEX) in TEG Dehydration Process”, 3^{rd} International Gas Processing Symposium, March 5-7, Doha, Qatar, 2012.

**Appendix A**

**Example 1**

Determine the solubility of benzene in loaded 13.1 mol% (50 wt%) MDEA in water solution in terms of scf of gas/gal of solvent (std m^{3} of gas/m^{3} of solvent) at 60 °C (140 °F), 333 K (600 °R).

Rich amine solution acid gas loading, = 0.4 mol acid gases/ mole MDEA, MDEA MW =119.17

50 wt % MDEA solution density =1017.3 kg/m^{3} (8.49 lbm/gal)

**Solution**

From Fig 1, for = 0.4 mol acid gases/ mole MDEA, relative solubility, x/x_{0}= 0.53

Benzene solubility in un-loaded MDEA, x_{0} = 0.00464

*Figure 1 – Relative solubility of Benzene in 50 weight % (13.1 mol-%) MDEA-Water [Figure 16 of GPA RR 242].*

**Solution – SI**

X = x_{0}(x/x_{0}) = (0.00464) (0.53kmol Ben/kmol MDEA Sol) (kmol MDEA Sol/0.131kmol MDEA)

= (0.0187 kmol Ben/kmol MDEA) (23.64 std m^{3}/kmol Ben) (kmol MDEA/119.21 kg)

= (0.0037 std m^{3} Ben/kg of MDEA) (kg MDEA/2 kg MDEA + Water Sol) (1017.3 kg/m^{3} MDEA Sol)

= 1.88 std m^{3} of Ben/m^{3} of MDEA + water solution

**Or** **X = (770) (x _{0}) (x/x_{0}) std m^{3} of Ben/m^{3} of MDEA + water solution**

**Solution – FPS**

X = x_{0}(x/x_{0}) = (0.00464) (0.53 lbmol Ben/lbmol MDEA Sol) (lbmol MDEA Sol/0.131lbmol MDEA)

= (0.0187 lbmol Ben/lbmol MDEA) (379.5 scf/lbmol Ben) (lbmol MDEA/119.21 lbm)

= (0.0598 scf Ben/lbm of MDEA) (lbm MDEA/2 lbm MDEA + Water Sol) (8.49 lbm/gallon MDEA Sol)

= 0.25 scf of Ben/gallon of MDEA + water solution

**Or** **X = (103) (x _{0}) (x/x_{0}) scf of Ben/gallon of MDEA + water solution**

In gas treating service, methyl diethanolamine (MDEA) will absorb limited quantities of BTEX from the gas. Based on literature data, predicted absorption levels for BTEX components vary from 5 to 30% [2]. Absorption is favored at lower temperatures, higher MDEA concentrations and circulation rates. The bulk of absorbed BTEX is separated from the MDEA in the regeneration unit and leaves the system in the regenerator overhead stream which requires further treatment before being vented to atmosphere. The amount of adsorption of the BTEX is required to be known to determine the proper treating method for the overhead acid gases leaving the regenerator.

The emission of BTEX components from glycol dehydration is also regulated in most countries. In the U.S., benzene emissions are limited to 1 ton/year (900 kg/year). Mitigation of BTEX emissions is an important component in the design of a dehydration systems. Correctly estimating the quantity of absorbed BTEX and understanding the factors that affect absorption levels is critical to ensure the proper mitigation methods are provided to meet the required emission limits.

The GPA Midstream research report RR-242 [3], is an extension of several previous GPA Midstream research projects looking at the solubility of hydrocarbons in loaded and unloaded amine solutions. The previous research included research reports RR-180, 185, 195, and RR-220.

The previous projects have concentrated only on two amine systems, MDEA and DGA, both loaded and unloaded with several model hydrocarbons. RR-242 expands the current base of research data to other amines (including DEA, MEA, and a MDEA/piperazine blend), as well as measures the influence of CO_{2} and H_{2}S (so called loaded amines).

Accurate hydrocarbon solubility data of RR-242 enables the development of new equation of state correlations that can be applied to the simulation of amine units (Bullin and Brown [4]). The data can be used to optimize the design and operation of amine units in which these hydrocarbons are present in the feed gas. The data will provide a basis for accurately predicting the distribution of the heavier hydrocarbons between the treated gas, the amine flash gas, and the acid gas streams. The data will provide a basis for accurately predicting emissions of these hydrocarbons from the amine unit to aid in the design and operation of these units (Moshfeghian and Hubbard [5]).

Figure 1- Process flow diagram of MDEA acid gas recovery unit [2]

This tip will focus on the following design variables:

– Solubility of selected hydrocarbons in pure water, Equation 1, and Figure 2.

– GPA Midstream RR-242 Proposed Model

– Relative solubility of benzene, toluene, and ethyl benzene (EBenzene), Figures 3, 4, and 5.

– Relative solubility of benzene, toluene, and ethyl benzene (EBenzene), Figure 6.

– Solubility of benzene, toluene, and Ebenzene in 50 wt % MDEA solution, Figure 7, and Table 1.

**Solubility of selected hydrocarbons in pure water:**

Solubility of selected hydrocarbons in pure water can be estimated using Equation 1 [3] or Figure 2.

(1)

Where T is the temperature in K and the correlation parameters, E, F and T_{min}, are shown in Table 1.

Table 1- Equation 1 parameters, E, F and T_{min} [3].

Figure 2 was generated using Equation 1 and its parameters in Table 1. The solubility of these selected hydrocarbons in pure water will be used to estimate their solubilities in amine solution in the proceeding sections.

Figure 2. Solubility of selected hydrocarbons in pure water [3].

**Estimation of solubility of hydrocarbons in amine solution by GPA Midstream RR-242 Model [3]**

Equation 2 with its corresponding parameters will be used to estimate the solubility of selected hydrocarbons in unloaded and loaded amine solutions.

(2)

Where:

The experimental measurement data of relative solubility of benzene, toluene, and ethyl benzene (EBenzene) in 50 wt % MDEA solutions are shown in Figures 3, 4, and 5. In addition the estimated solubility data by Equation 2 is superimposed on these three figures.

*Figure 3 – Relative solubility of Benzene in 50 wt % (13.1 mol-%) MDEA-Water [Fig 16 of GPA RR 242].*

*Figure 4 – Relative solubility of Toluene in H _{2}S or CO_{2} loaded 50 wt % (13.1 mol-%) MDEA-Water [Fig 18 -GPA RR 242].*

*Figure 5 – Relative solubility of Ethylbenzene in CO _{2} loaded 50 wt % (13.1 mol-%) MDEA-Water [Fig 20-GPA RR 242].*

Tables 2 and 3 indicate that estimated solubility by the model agree well with the experimental measurements.

Table 2 – Solubility of Toluene in CO_{2}-loaded aqueous MDEA (13.13 mol-%)/water [3].

n – number of analyzed samples, x*–average, σ – standard deviation, x/x_{0} – soluble loaded/soluble. non-loaded

Table 3 – Solubility of Toluene in H_{2}S-loaded aqueous MDEA (13.13 mol-%)/water [3].

APD = Absolute percent deviation, AAPD = Average Absolute percent deviation,

**Example 1**

Determine the solubility of benzene in loaded 13.1 mol% (50 wt%) MDEA in water solution in terms of scf of gas/gal of solvent (std m^{3} of gas/m^{3} of solvent) at 60 °C (140 °F), 333 K (600 °R).

Rich amine solution acid gas loading, = 0.4 mol acid gases/ mole MDEA, MDEA MW =119.17

50 wt % MDEA solution density =1017.3 kg/m^{3} (8.49 lbm/gal)

**Solution**

From Fig3, for = 0.4 mol acid gases/ mole MDEA, relative solubility, x/x_{0}= 0.53

Benzene solubility in un-loaded MDEA, x_{0} = 0.00464

*Figure 3 – Relative solubility of Benzene in 50 wt % (13.1 mol-%) MDEA-Water [Fig 16 of GPA RR 242].*

**Solution – SI**

X = x_{0}(x/x_{0}) = (0.00464) (0.53kmol Ben/kmol MDEA Sol) (kmol MDEA Sol/0.131kmol MDEA)

= (0.0187 kmol Ben/kmol MDEA) (23.64 std m^{3}/kmol Ben) (kmol MDEA/119.21 kg)

= (0.0037 std m^{3} Ben/kg of MDEA) (kg MDEA/2 kg MDEA + Water Sol) (1017.3 kg/m^{3} MDEA Sol)

= 1.88 std m^{3} of Ben/m^{3} of MDEA + water solution

**Or** **X = (770) (x _{0}) (x/x_{0}) std m^{3} of Ben/m^{3} of MDEA + water solution**

**Solution – FPS**

X = x_{0}(x/x_{0}) = (0.00464) (0.53 lbmol Ben/lbmol MDEA Sol) (lbmol MDEA Sol/0.131lbmol MDEA)

= (0.0187 lbmol Ben/lbmol MDEA) (379.5 scf/lbmol Ben) (lbmol MDEA/119.21 lbm)

= (0.0598 scf Ben/lbm of MDEA) (lbm MDEA/2 lbm MDEA + Water Sol) (8.49 lbm/gallon MDEA Sol)

= 0.25 scf of Ben/gallon of MDEA + water solution

**Or** **X = (103) (x _{0}) (x/x_{0}) scf of Ben/gallon of MDEA + water solution**

For simplicity and easiness of reading the figures, using the model (Equation 2) similar charts like Figures 6 and 7 or Table 4 can be generated.

*Figure 6 – Relative solubility of benzene (Fig 3), toluene (Fig 4), and Ethylbenzene (Fig 5) in loaded 50 wt % (13.1 mol-%) MDEA-Water*

Figure 7- Solubility of benzene, toluene, and ethyl benzene in unloaded 50 wt % MDEA solution

Table 4- Solubility of benzene, toluene, and ethyl benzene in unloaded 50 wt % MDEA solution

Figure 8 shows the influence of amine solution concentration and acid gas loading on solubility of toluene in 50 wt% and 25 wt% MDEA solution at 100 °F (38 °C)

Figure 8- solubility of toluene in 50 wt% and 25 wt% MDEA solution at 100 °F (38 °C)

From the RR-242 developed model based on the experimental results; several conclusions can be drawn.

1. The solubility of the hydrocarbons depends strongly on the amine concentration in the solvent, with the solubility increasing exponentially with increasing molar concentration of the amine in the aqueous solution (Figure 8).

2. The solubility of the hydrocarbons increases with temperature (Figure 7 and Table 4).

3. The solubility of the hydrocarbons depends strongly on the acid gas loading (decreased solubility at higher loading, Figure 8.)

4. The solubility for CO_{2} loaded amines are found to be similar to the solubility for H_{2}S loaded amines.

5. Finally, the ratio of hydrocarbon solubility of the loaded solvent to the unloaded solvent is found to be similar at a given acid gas loading.

**Summary**

Figures 6 and 7 present a simple tool for quick estimation of solubility of BETX compounds in MDEA gas treating process. For the example considered in this tip, the estimated solubility for each of BETX compounds matched well with the experimental results.

To learn more about similar cases and how to minimize operational problems, we suggest attending our**G4 (**Gas Conditioning and Processing**)****,****G5 (**Advanced Applications inGas Processing**)****, **http://www.jmcampbell.com/co2-surface-facilities-pf81.php and__ PF49 (Troubleshooting Oil & Gas Processing Facilities)__,courses.

*By: Mahmood Moshfeghian, Ph.D.*

*and Kindra Snow-McGregor, P.E.*

**Reference:**

1. http://www.earthworksaction.org/BTEX.cfm, 2011.

2. Campbell, J. M. “Gas conditioning and processing, Volume 2: The Equipment Modules,” 9^{th} Edition, 2^{nd} Printing, Editors Hubbard, R. and Snow–McGregor, K., Campbell Petroleum Series, Norman, Oklahoma, 2014.

3. Uusi-Kyyny, P., Pakkanen, M., Richon, D., Ionita, S., Ogunrobo, E., Alopaeus, V., RR-242, “Solubility of Hydrocarbons in Amine Treating Solutions”, GPA Midstream Association, Tulsa, OK, 2019.

4. Bullin, J. A., Brown, W.G., Hydrocarbons and BTEX Pickup and Control from Amine Systems”, 83^{rd} Gas Processors Association Annual Convention, Mar. 2004.

5. Moshfeghian, M. and R.A. Hubbard, “Quick Estimation of Absorption of Aromatics Compounds (BTEX) in TEG Dehydration Process”, 3^{rd} International Gas Processing Symposium, March 5-7, Doha, Qatar, 2012.

Following on the previous two TOTMs [1, 2] on Nord Stream long distance pipeline for natural gas transmission from Russia to Europe, this TOTM discusses the application of various long distance gas transmission correlations/equations that are available to determine the maximum gas capacity of a long-distance pipeline. In addition, calculations can be done to estimate the line packed gas volume; demonstrating that a long-distance pipeline can be used as a gas storage facility as well.

**Case Study Data**

In the previous TOTMs, we discussed various parameters that are available in the public domain [3] and presented in Table 1. Nord Stream 1 has 2 parallel gas pipelines, each pipeline capable of transporting gas from Russia to Germany at a rate of 75.34 million Std m^{3}/day (2660.6 MMSCFD)

Table 1. Pipeline Specifications in SI and FPS Units

As the composition of the gas transported in the NS1 pipelines has not published, it was assumed for this study that the Norwegian gas, shown in Table 2, that is transported to the European Continental Shelf would be a good representation of the gas in the NS1 pipeline.

Table 2. Composition of the feed gas

Based on the above data, the physical and flow properties values were calculated and presented in Tables 3 and 4 in SI and FPS units, respectively.

Table 3. Calculated results for gas at a rate of 75.34 million Std m^{3}/day

Table 4. Calculated results for gas at a rate of 2660.6 MMSCFD

In this study, two standard equations derived from the basic gas flow equation reflecting the average (mean) conditions have been used to estimate the NS1 pipeline capacity. These relationships are the BASIC and AGA (American Gas Association) equations containing a friction factor “f”. These equations are [4]:

The AGA equation estimates the friction factor under two conditions, “partially turbulent” and “fully turbulent”. The “partially turbulent” correlation is the Colebrook-White equation for smooth pipe. The smooth pipe assumption is corrected using a drag factor, F_{f}, which accounts for several pipeline characteristics: pipe wall condition, welds, changes in the direction of gas flow, isolation valves, etc. In the “fully turbulent” region the friction factor is independent of Reynolds number and depends only on the dimensionless roughness of the pipe.

These equations are available in GCAP software [5] and the screenshot of GCAP results are presented in Figures A1 – A5 in Appendix A.

Table 5. Calculated results for gas at a rate of 75.34 million Std m^{3}/day

Table 6. Calculated results for gas at a rate of 2660.6 MMSCFD

The BASIC equation estimated gas flow of 84.07 million Std m^{3} (2969 MMscfd) of gas assuming 100 % efficiency. The BASIC equation estimated gas flow of 75.63 million Std m^{3} (2671 MMscfd) assuming 90 % efficiency.

The AGA equation estimated a gas flow of 84.59 million Std m^{3} of gas (2987 MMscfd) assuming 100% efficiency.

The published capacity of NS1 pipeline is 75.34 million Std m^{3} of gas [3].

A design flow rate check was also initiated by using PROMAX [6] that uses the single-phase regimes and single-phase basic equation applying Colebrook friction factor. This methodology gave a flow rate of 83.1 million Std m^{3} of gas.

The differences between the estimated and actual are 0.4% for 90% Basic, 11.6% for 100% BASIC, 12.30% for AGA and 10.3% with PROMAX. Considering that the gas composition is not known for NS1, these differences are reasonable.

**Pipe Wall Thickness**

NS1 pipeline is varying in operating pressure, thus varying pipeline thickness. Using Barlow’s formula, a check on the wall thickness was made. Barlow’s formula relates the internal pressure that a given pipe can withstand as a function of its dimensions and strength of its material.

Where:

t = pipe wall thickness, mm (in)

P = 1.1 x design pressure, MPag (psig)

S = allowable stress, 483 MPag (70,000 psi) for grade x70 steel

D = outside diameter, mm (in)

In the Barlow’s formula, there is no provision of corrosion allowance. If we include this in the Barlow’s formula and take 3 mm as corrosion allowance (ca), then

Using Barlow’s equation, the pipeline wall thickness for different segments were calculated and presented in Table 7.

Table 7. Estimated pipeline wall thickness for different segments

Table 7 shows calculated pipeline wall thickness (t) with a corrosion allowance, ca. This information reveals a good agreement with the published data is reached using Barlow’s formula.

**Line Packing**

The NS1 gas pipeline can also be used to store gas when not used for gas transport. The methodology to determine how many standard cubic meters of gas can be held is given below.

Inventory (V) of gas pipeline can be calculated with:

Taking the internal diameter of the pipeline as 1.153 m (3.78 ft) and pipeline length of 1 224 000 m (4 015 748 ft), the pipeline volume is 1 277 997 m^{3} (12 578 711 ft^{3}).

Then using the real gas law:

PV = nZRT

or molar volume

Where P is the average pressure between inlet (22000 kPa or 3190 psia) and outlet (10600 kPa or 1537 psia) pressures amounting to 16300 kPa (23663 psia), T is the average temperature in the pipeline (5 ⁰C=41°F or 278 K=500.4 °R), Z is the average compressibility of 0.75 and R is the universal gas constant (8.314 kPa.m^{3}/kmol. K or 10.732 psia.ft^{3}/lbmol-°R).

n = 12 017 147 kmol (26 497 809)

Now 1 kmol = 23.64 Std m^{3} and 1 lbmol = 379.5 scf

Then the amount of standard cubic meters of gas that can be line-packed is 284.1 million Std m^{3} (10.6×10^{9} scf).

This is the amount of gas that can be stored in the pipeline when it is not operating in the transportation phase.

**Concluding Remarks**

The methodology used above demonstrates how standard long distance pipeline flow correlations/equations (BASIC and AGA equations) can be used in evaluating the design flow rates of an installed or of an operating pipeline. It was noted that the Basic equation with 90%-line efficiency matched the published design capacity very closely.

Pipe wall thickness calculation methodology using Barlow’s formula also shows good agreement with that of published data.

In addition, using the real gas law, it can be demonstrated that considerable amount of gas can be line-packed when the pipeline is in non-transportation mode.

To learn more about similar cases and how to minimize operational problems, we suggest attending our **G4 (**Gas Conditioning and Processing**), P81 (**CO_{2} Surface Facilities**), and PF4 (**Oil Production and Processing Facilities**) **courses.

References:

1. Moshfeghian, M., Rajani, J., and Snow-McGregor, K., “Transportation of Natural Gas in Dense Phase – Nord Stream”, PetroSkills TIP OF THE MONTH, April 2022.

2. Langer, J.F, Snow-McGregor, K, and Rajani, J., “Part 2: Nord Stream Pipelines – Multiple Parallel Paths to Succes or Failure?”, PetroSkills TIP OF THE MONTH, April 2022.

3. Beaubouef, B., “Nord stream completes the world’s longest subsea pipeline,” Offshore, P30, December 2011.

4. Campbell, J.M., “Gas Conditioning and Processing, Volume 1: The Fundamentals,” 9^{th} Edition, 3^{rd} Printing, Editors Hubbard, R., and Snow–McGregor, K., Campbell Petroleum Series, Norman, Oklahoma, PetroSkills 2018

5. GCAP 10.2.1, Gas Conditioning and Processing, PetroSkills/Campbell, Tulsa, Oklahoma, 2022.

Appendix A: GCAP Results

Figure A1. Calorimetric Values

Figure A2. Average gas density by GCAP-Option 3C, SRK EOS

*Figure A3. Estimated design pipeline capacity by basic Equation with 90 % efficiency*

*Figure A4. Estimated design pipeline capacity by basic Equation with 100 % efficiency*

*Figure A5. Estimated design pipeline capacity by AGA Equation*

Part 1 of this Series on Gas Lift History and Basic Well Parameters focuses on the primary “state of affairs” of Gas Lift operations in the USA. A discussion was presented related to a candidate Gas Lift well’s completion design that included a typical Casing/Tubing sizing sequence. The function of the production tubing gas lift Mandrels in starting a “kick – off” procedure in a candidate well were discussed. Types of Mandrel Gas Lift Valves were discussed, along with a discussion of the Single Gas Lift Valve (with its appropriate orifice size) employed as the final receptor of the injected casing gas.

**II. Operational Fundamentals for the Performance of a Gas Lift Well, Related to Choke Flow, Single Phase Gas, and Multiphase Flowing Gradients**

Part 2 of this Series reviewed energy and mass balances as related to a candidate Gas Lift Well’s flowing gradient. Energy balance equations provided the proper data to simulate both the annular flow in a casing/tubing configuration, as well as for choke (orifice) performance. Data from Industry standards provided the injected Casing/Tubing/Liner dimensions to calculate Effective Areas, as well as Effective Diameters for flow of the injected casing gas to the Production Tubing Gas Lift Valve at a given depth. The Thornhill–Craver equation provided the choke (orifice) performance data for the Gradient curves presented in Appendix A and B. The Pressure versus Gas Rate curves apply to orifice sizing but are only an estimate for gas lift valves since the valve stem in the seat reduces flow area.

**Part 3** will review procedures for identifying, selecting, and optimizing technical as well as field operations for a gas lift well.** Section IIIA** reviews the gas lift well candidate related to gas content in the reservoir fluid and a choice of gas lift or pumping; **Section IIIB** discusses the well completion related to dimensional and clearance considerations and gas lift facility requirements; Section IIIC has guides for kicking off a well and avoiding erosion cutting of the unloading valves; Section IIID provides the procedure to optimize the well once it has kicked off and is operating in the production system.

**Section IIIA Gas Lift Well Candidates**

Reservoir conditions are primary drivers in choosing artificial lift. Gas content is key since gas lift supplements existing gas in the reservoir fluid and high content reduces the gas lift contribution. However, pumps are adversely affected by gas content in the reservoir fluid, leading to lower effectiveness and frequent failures. Production rate is a consideration that affects tubular size in gas lift, but changes pump choice with rod/beam pump for lower rates and electric submersible pump for higher rates. Finally, sand production from a sandstone reservoir or frac sand from a horizontal shale well have a detrimental effect on pump operation but a lesser effect on gas lift.

The fundamental relationship of gas lift and pumping with the reservoir is explained. Figure 1 shows a gas lift schematic on the left and the pressure‐rate behavior of flow from the reservoir (inflow) and up the tubing string (outflow) on the right. The gas lift well has gas entry through the tubing‐casing annulus to the operating valve or orifice, mixing with reservoir gas, oil, and water to reduce the composite density of the fluid, flowing to the wellhead and on to the separator. The chart at right shows the pressure versus rate for the inflow from the reservoir based on a PI = 1 bbl/d per psi and PR = 3000 psig. Each well is tested to obtain its productivity index (PI, related to IPR, Inflow Performance Relationship) and reservoir pressure (PR). This data is coupled with a nodal analysis program (PetroSkills uses SNAP from Tom Nations) to evaluate different tubing sizes and select the most appropriate. The other curves on the chart are multiphase flow results for 2 7/8” tubing outflow (called Vertical Lift Performance VLP, J‐Curve, Tubing Intake, Outflow) for natural flow and for gas lift. The intersection of the inflow curve and the outflow curve indicates a point of stable operation. The chart shows the natural flow curve (of higher density and pressure compared to gas lift) intersecting the inflow line at 400 stb/d whereas the gas lift curve (of lower density and lower bottomhole flowing pressure) intersecting at 1000 stb/d. The gas lift outflow curve is for a specific injection gas to liquid ratio (IGLR, scf/bbl) and although more injection gas would continue to decrease density, friction increase more than offsets the density reduction which is shown by the third curve in red, representing excessive IGLR that reduces production rate. IGLR plus formation gas to liquid ratio (FGLR) gives total gas to liquid ratio (TGLR). FGLR is a function of Solution Gas to Oil Ratio, Rs (scf/stb) and Oil Formation Volume Factor, Bo (bbl/stb). These two oil properties affect the quantity of “free flowing gas” which increases from the bottom of the bore to the wellhead as pressure and temperature reduce. Notice that all “outflow” curves decrease in bottomhole flowing pressure (negative slope) where density is the governing factor, and then increase (positive slope) as fluid velocity and friction become dominant.

**Figure 1 – Gas Lift schematic and chart of pressure‐rate behavior (1)**

Pumping is illustrated similarly to gas lift. Figure 2 shows a pump schematic on the left and on the right the pressure‐rate behavior of flow from the reservoir to the pump (inflow) and from the pump up the tubing string (outflow). A pumped well typically has no packer. Gas breaks out as reservoir fluids enter the casing and flows up the annular space to the wellhead where it is again mixed with produced fluids that are pumped up the tubing. The chart at right shows the pressure versus rate for the inflow from the reservoir based on a PI = 1 bbl/d per psi and PR = 3000 psig and represents flow into the pump suction. The other curve on the chart is multiphase outflow inside 2 7/8” tubing for natural flow and represents discharge from the pump. The chart shows the natural flow curve intersecting the inflow line at 400 stb/d, but to achieve 1000 stb/d with artificial lift, the fluid must be pumped from the intake pressure to the outflow pressure. The work energy put into the pump can be estimated from the pressure difference (Outflow pressure – Inflow Pressure), rate, and fluid density. Given more input power, a larger pump could continue to increase rate compared to gas lift, which is limited by friction.

**Figure 2 – Pump schematic and chart of pressure‐rate behavior (1)**

Nodal analysis simulation of gas lift and pumping is based on well testing to obtain reservoir inflow and to sample the reservoir fluids. This simulation permits evaluation of tubing sizes (and corresponding casing/liner sizes), changes in operation as reservoir conditions change, and the “best” amount of gas lift gas.

**Section IIIB Gas Lift Well Dimensional and Gas Facility Considerations**

Figure 3 is the gas lift well completion schematic used in Part 1 and 2. The arrangement of tubing, casing, and gas lift valves are shown, and distinction is made between unloading (kick off) valves and a bottom orifice for continuous injection.

**Figure 3 – Gas lift well schematic and surface facility (2)**

Prior to drilling, a tubing/casing size evaluation is conducted using exploration or prior well data as estimates for PI and reservoir pressure. If the reservoir has the rate capacity and engineering concurs that higher rates will not damage the reservoir rock nor preclude reserves recovery, then a larger size tubing and corresponding casing can be recommended. Once tubing/casing sizes are selected, a detailed dimensional analysis is required. The gas lift mandrels and associated valves are eccentric (both conventional tubing retrievable and side pocket with wireline retrievable valves) and clearance between the casing and tubing must be assured. The inside drift diameter of casing must be compared to tubing coupling outside diameter and to gas lift mandrel major diameter. Table 1 has tubing, casing, and gas lift mandrel dimensional data for a clearance check. The 9 5/8” casing string from Figure 3 has a drift diameter of 8.525”, much larger than the major outside diameter (OD) of a 2 7/8” gas lift mandrel (9 5/8” casing is usually paired with 3 1/2” or 4 ½” gas lift completions). The 7” liner has a drift diameter of 5.969” which will clear the 2 7/8” gas lift mandrel major OD of 5.5” for a side pocket or 4.835” for a tubing retrievable option. Downhole data confirms clearance, so attention can be turned to surface facilities.

**Table 1: Production Tubing, Casing, and Valve Mandrel Dimensions for Clearance [3,4,5]**

Gas compressors, dehydrators, and meters are the crucial complements to the wellbore, subsurface valves, and low pressure gathering/treating facilities of the gas lift system, Figure 4. All operations staff will tell you that gas lift success depends on near 100% run time from compressors, dehydrators, and gas lift gas meters. The rate and pressure available to each well must be adequate and steady. If compressors go down every few days due to poor maintenance or old equipment, then the gas lift system cannot stabilize. Wells are always in a startup (kick off) mode, not steady state operation. If dehydration is malfunctioning or the triethylene glycol (TEG) is so fouled that it cannot absorb water vapor from the gas stream, then hydrate at chokes, regulators, distribution piping, or fuel gas supply lines will cause individual wells, or portions of the field, or the entire field to go offline. Liquid accumulation over years due to condensing water vapor in the piping system can lead to corrosion, liquid slugging, and loss of gas transmission efficiency. Since most gas lift gas is dehydrated but unprocessed solution gas plus returning lift gas, it usually contains heavy hydrocarbon components which can condense and accumulate in the piping system causing problems.

**Figure 4 – Gas lift field schematic with well and surface facility (6)**

The critical quality of gas lift gas centers on water content in the gas at compressor discharge pressure and temperature. The value can be estimated from Figure 5. At compressor discharge downstream of the aftercooler, the pressure is 1400 psig and temperature is 120⁰F. The water content point on the chart is 80 lbs water vapor per million standard cubic feet (MMscf) gas. To prevent water condensation down to 40⁰F at 1400 psig, the water content must be reduced to 7 lbs water per MMscf and the TEG dehydrator must remove 73 lb/MMscf. Colder climes often require 1 lb/MMscf to achieve a dew point of ‐10⁰F, which requires 79 lb/MMscf water vapor removal. These estimates set the dehydration requirement to prevent water condensation in the piping which leads to hydrate, corrosion, and water accumulation.

When the dehydrator is out of service for an extended period, or if dehydration is not installed under the false assumption of no problem with hydrate, corrosion, or water accumulation in the injected gas piping system, then a chart is used to predict hydrate formation pressure and temperature based on the gas lift gas specific gravity (ranges from 0.65 to 0.8). Gas lift gas (0.7 specific gravity or relative density) at our example 1400 psig discharge pressure could form a hydrate at approximately 68⁰F, which during normal operation, could occur at pressure expansion (and cooling) locations at chokes, regulator valves, and piping low points where water accumulates. As weather cools many points, including the main pipeline or laterals, could be subject to hydrates. Methanol or ethylene glycol injection stations would be required at potential hydrate points to keep the gas lift operating.

**Figure 5 – Water content of hydrocarbon gas (7)**

**Figure 6 – Pressure‐temperature curves for predicting hydrate formation (7)**

**Section IIIC Gas Lift Well Unloading (Kick off) Guide**

An important first step is extracting the control (kill) fluid that is used by the completion/workover team to permit safe installation of the downhole equipment. Even though blowout preventers (BOP) are used, control (kill) fluid in the wellbore tubing and tubing‐casing annulus is the primary barrier to prevent reservoir fluid flow. With the well full of control (kill) fluid, the BOP is removed and replaced with the tree of valves and flanges are sealed. Now thevcritical unloading (kicking off) of the well can be slowly initiated to prevent erosion of valves/mandrels as thevcontrol (kill) fluid passes from the annulus to the tubing, where it flows up to the wellhead to be removed from the well.

Damage prevention to valves and mandrels requires actions prior to installing the downhole equipment and after tree installation. The following practices are applied during the workover to install the packer, tubing, mandrels, and valves:

a) Circulate the wellbore to remove any drilling mud before perforating, running other completion equipment, and installing the gas lift valves.

b) Use a casing scraper to remove debris that adheres to the casing wall and burrs created when packers were set; circulate the casing clean.

c) Use filtered completion and workover fluids and leave filtered fluid in the tubing‐casing annulus. Unfiltered fluids are often a source of solids that can either cut out or plug the gas lift valves.

Unloading the control (kill) fluid from the tubing and annulus is initiated after the well is secured to the production facility:

a) Displace with unloading rates not exceeding 1 barrel per minute (BPM) to prevent erosion of gas lift valves.

b) Start injection gas flow, control rate to attain a 50 psig casing pressure increase in 10 minute increments.

c) Continue this injection rate until the casing pressure reaches 400 psig.

d) Increase the injection gas rate to achieve a 100 psig increase in 10 minute increments.

e) Monitor for an injection gas pressure drop and the return of aerated fluid from the production tubing to indicate gas is injected through the top unloading valve.

f) Observe and record casing pressure (downstream of injection choke or regulator valve) to confirm casing pressure decline as injection point transfers to deeper valves.

g) Use acoustic fluid level tools in the casing annulus to confirm depth of injection.

h) Ensure that injection gas flow is continuous and avoids the occurrence of CRITICAL FLOW where the ratio (P2/P1) of the downstream choke pressure, P2, and the upstream pressure, P1, are in a range well above 0.60., i.e. 0.85 – 0.65.

The depth of injection is related to reservoir pressure (and corresponding tubing pressure) compared to the casing injection pressure. Early operating life may have gas lift injection at a mid‐point in the wellbore, but as reservoir pressure and tubing pressure decline with time, the injection point will automatically shift to a deeper valve where gas injection pressure is greater than tubing pressure. Testing after unloading coupled with nodal analysis simulation from each valve mandrel depth can indicate the point of operation, illustrated in Figure 7. This figure shows the well unloaded to the deep mandrel at 8000’ (Test 1), but a compressor outage caused a shift to the shallow mandrel at 4800’ (Test 2) (the well may not automatically return to the deep point of injection after the restart). Operators adjusted injection rate and another test indicated lift at the 7150’ mandrel (Test 3), and a subsequent test showed a return to the mandrel at 8000’ (Test 4). When the well is unloaded to the depth possible based on available injection pressure, and confirmed with acoustic fluid level and testing, then optimization testing can begin.

**Figure 7 – Production rate versus mandrel depth (1)**

**Section IIID Gas Lift Well Optimization**

Optimization based on well tests is an ongoing process since the reservoir inflow performance is continually changing and injection gas needs to be allocated to the best wells in a group supported by the same compressor station. However, confirmation of deep lift (related to available injection pressure) should be done first based on the prior section. The well tests, flowing gradient surveys, and measured flowing bottomhole pressure data from permanent sensors are used to build nodal analysis models that accurately describe the wells’ response to greater or lesser amounts of injection gas. The well performance curve, previously shown in Figure 7, is also called an “optimization” curve and charts gross production (oil and water) rate versus injection gas rate. Each well in the field is tested over a range of 80% to 120% of design injection rate; the results permit choice of operating point based on some criteria: maximum oil, best economic condition, flow stability to minimize slugging, water injection capacity, injection gas capacity. The group of wells in same facility can have injected gas allocated to achieve the “optimum” operating point for each well. Often, optimization is not attained.

When wells falter and optimum points cannot be achieved, troubleshooting techniques are applied to obtain data for problem resolution. Diagnostic techniques, solutions, and problems are addressed in the following table:

**Section III Summary**

This gas lift tip of the month (TOTM) provides information on gas lift well selection and its inflow relationship with the reservoir, on wellbore and facility parameters that must be addressed for operational success, on the critical stage of unloading control (kill) fluid that is in the wellbore following all interventions to install downhole equipment, and on the optimization procedure plus trouble shooting guides.

Section IIIA links gas lift choice to reservoir gas content since high available reservoir gas requires a lower supplement from gas lift. The effect is density reduction in the wellbore and nodal analysis graphs are used to indicate the difference between a lower natural flow rate and a higher gas lift rate that results from the lower pressure in the bottom of the bore. Nodal analysis with SNAP is used to evaluate interdependence of reservoir productivity, tubing size (with corresponding casing size), and gas lift injection pressure availability.

Section IIIB has an example that compares tubing, gas lift mandrel eccentricity, and casing drift diameters to assure the equipment can installed in the wellbore. Downhole evaluation is necessary, as is a review of surface facilities. Success with gas lift depends on high reliability compressors and dehydrators that provide steady gas capacity without hydrates or liquid accumulation.

Section IIIC provides guides to the crucial step of removing the control (kill) fluid without causing erosional cutting of valves/mandrels. Damage control involves actions prior to installing the wellbore hardware and precautions during the fluid extraction procedure. Displacement of control (kill) fluid is limited to 1 barrel per minute, deemed by testing to be the maximum rate where erosion will not occur.

Section IIID provides the multirate well test optimization procedure to obtain gross production rate versus injection gas rate varied over a range of 80% to 120% of design rate. This test phase begins after the well is confirmed to be lifting at a depth consistent with the available injection pressure. An “optimum” operating point is selected based on criteria such as maximum rate, or economic return, or flow stability, or capacity limits of

injection gas or injection water. When testing reveals a problem, then trouble shooting analysis begins using the guides in this section.

The Authors acknowledge and express our gratitude to Kindra Snow‐McGregor and to Mahmood Moshfeghian for their valuable review and feedback.

**REFERENCES**

1. PetroSkills Gas Lift (GLI) course manual

2. MEHDI ABBASZADEH SHAHRI, M.S. PhD Texas Tech – 2011

3. Renato Venom Technology and Inspection Services, LLC – 2022

4. Schlumberger Camco Gas Lift Catalog

5. Weatherford Gas Lift Catalog

6. API Gas Lift Handbook

7. Campbell, J.M., “Gas Conditioning and Processing, Volume 1: The Fundamentals,” 9th

Edition, 3rd Printing, Editors Hubbard, R. and Snow–McGregor, K., Campbell Petroleum Series, Norman, Oklahoma, PetroSkills 2018

In the Part 1 of this Series on Gas Lift History and Basic Well Parameters, an attempt was made to bring into focus the primary “state of affairs” of Gas Lift operations in the USA. A discussion was presented related to a candidate Gas Lift well’s completion design that included a typical Casing/Tubing sizing sequence. The function of the production tubing gas lift Mandrels and their function in starting a “kick – off” procedure in a candidate well were discussed. Types of Mandrel Gas Lift Valves were discussed, along with a discussion of the Single Gas Lift Valve employed as the final receptor of the injected casing gas.

**Part 2** will discuss basic Gas Lift well casing and tubing components, and their operational function, as well as Choke Flow relationships in Gas Lift wells.

In the First **Section II.A,** Energy and Mass Balance relationships will be used to compute flowing pressure gradients, (dP/dL) (psi/ft) for injected casing gas ((dP/dL)g), and for further documents addressing this subject, multiphase flow in the tubing ((dP/dL)mp).

**Section II.B **will address gas injected at surface into the annular space between production casing and tubing. The injection gas travels down the annular space on its way to either a “kickoff “gas-lift” valve located in a tubing MANDREL with an Injection Pressure Operated gas lift valve (IPO), or to the bottom Orifice GLV. This design was considered and included in the Part 1 discussion. The reader is referred to Part 1 for a description of the IPO. Figure 1 [1] illustrates a representative wellbore configuration for a gas lift well, and the flow paths of the fluids. There are multiple variations of oil well completions for Gas Lift operations that involve various Casing, Liner and Tubing sizes and configurations. As shown by Figure 1 [1], the Gas Lift well “active production” completion consists of an assumed 9 5/8” production casing set a given predetermined depth. There are additional larger casings set at shallower depths, but these are not active in the annular area available for injected casing gas flow. The injected casing gas first encounters the annular space between the 9 5/8” casing and the tubing (assumed to be either 2 3/8”, or 2 7/8” production tubing). In addition to the 9 5/8” casing, it is assumed that the well is equipped with two liners; a 7 inch liner, and a 5 inch liner. These compliment the assumed 9 5/8” set casing. As shown, the final operating (lowest) GLV is located in the region of the 7” liner. These Well completion configurations may vary from classical Csg/Tbg installations.

Calculations will be performed to determine injected gas annular flow vs. pressure loss related to the 9 5/8” casing and either the 2 3/8”, or 2 7/8” production tubing. The flow is then considered in the annular space between the 7” liner and either the 2 3/8’’, or 2 7/8’’ production tubing. Casing gas flow does not encounter the 5” liner. Physical dimensions for these selections will be addressed.

**Figure 1: Figure showing vertical section of typical tubing conditions for single phase gas casing/tubing annular flow (1), and two phase gas/liquid flow. [1]**

In this Section only Gas Flow is assumed, and flowing “Casing-Tubing” gas pressure gradients, (dP/dL)g (psi/ft) will be determined for the selected annular flow configurations.

The calculations will follow the Darcy friction loss correlation within a Bernoulli formulated analysis, along with the Fanning friction factor extracted from the Reynolds Number vs Moody Friction Factor graph (Re vs. f_{m}), The Fanning friction factor, f_{f}, is calculated as 25% of the Moody f_{m}.

Graphs will be presented showing the casing gas flowing gradient, (dP/dL)g (psi/ft) for variations of the injected casing gas rates, (Qg, SCF/D), within the dimensions cited for casing and tubing sizes. Median flowing conditions will be chosen to represent the flowing temperature, (°F), as well as fluid physical properties for gas gravity, γ_{g }, and the compressibility factor, Z. An 18.3 lb/lbmol molecular weight gas is assumed for all cases.

**Section II.C** presents the basic, single phase gas flow performance characterization related to CHOKE FLOW in the Gas Lift Valve. Once a valve has been fitted with a choke (orifice) size, the flow performance of a choke will follow the mass, and energy balance relationships related to isentropic gas expansion.

This flowing condition for the choke MUST be selected in its transitional, sub-critical flow region so that additional changes to injection gas flowrates may be made if called for. It is essential to design the final Orifice GLV so that operation near, or in the Critical Regime (Sonic Flow) is avoided.

As will be shown, the isentropic expansion of an orifice expanding gas is related to a specific pressure volume relationship at constant temperature: PV^{k }= C, where k is the specific heat ratio. SUBSONIC (transitional choke flow) will be addressed via the **Thornhill-Craver [2]** Equation (11). This relationship has been shown to match many choke flow measurements. Specific pressures, temperatures and physical properties will be shown.

** **

** II.A) Basic Mass and Energy Balances. Gas and Gas-Liquid Flow Pressure Gradients.**

The energy balance for gas/liquid flow in either a horizontal or vertical conduit is provided as Equation 1 in its Pressure Gradient form. Figure 1 provides a visual reference for the dimensional criteria for the injected casing gas, or gas/oil flow from the producing Horizon “Pay zone”.

**1 [3]**

Flowing Pressure Friction Head Momentum

Gradient Gradient Gradient Gradient

NOTE: With due consideration, the units selected for the Gas Lift written material will be in FPS units. Conversion factors will be included for assisting the reader. Values will be provided in convenient units to yield appropriate results.

Where:

dP/dL = Pressure gradient lbf/ft^{2}ft (psi/ft): (Pa/m)

ρ = Density of flowing phase: Single phase gas or two-phase gas/oil – water: lbm/ft^{3 }(kgm/m^{3})

v = Velocity of flowing phase: Single phase gas or two-phase gas/oil – water: ft/sec (m/sec)

d = Diameter of production tubing for gas/oil-water flow; Equivalent annular diameter for Casing-tubing annular flow: IDcsg – OD tbg: ft (m)

Ɵ = Well production string angle; (for vertical; Ɵ = 90° (Sine Ɵ = 1))

g_{c } = Gravitational mass – force constant: 32.2 lbm ft/sec^{2}lbf (1 kgm m/sec^{2}N)

g = Gravitational acceleration, 32.2 ft/sec^{2}

f_{f} = Fanning (Moody) friction factor from Reynolds Number, Re, taken from Moody Friction Factor Chart,

ρ = Density of the flowing Fluid: 1) Injected casing gas, 2) Production tubing Oil, Formation Gas (GOR)), and Injection Gas Oil Ratio IGOR, giving the total Gas Liquid Ratio or GLR (SCF/STB): lbm/ft^{3} (kg/m^{3})

The Reynolds Number, for use with the Moody Friction Factor Chart is defined as follows ** **

** **** 2 [3]**

Where: Terms are defined above.

The fluid viscosity, μ, is defined by the slope of the “Shear Stress” vs “Shear Rate” correlation. The units of viscosity are: **1 cp = .001 kg/m sec = 6.72 E-4 lbm/ftsec.**

All terms related to the pressure gradient are in an energy base of: lb_{f}/ft^{2}ft, or the SI equivalent per unit mass (N/m^{2}m). Proper conversions can be easily applied to convert the flowing gradient to typical units of: lbf/in^{2}ft: Pa/m. Notice the first term is the friction gradient, referred to as the Darcy Equation. The “f” parameter is the basic Fanning friction factor that is applicable to the Darcy friction loss term. If selected from the Moody Reynolds Number correlation, the Fanning f_{f }is the Moody value divided by 4 [3]. The “height” term is represented by the second gradient, which includes the Sine function to consider a non-vertical flow path while the last term is the momentum gradient.

Numerical computations have shown that the momentum component pressure loss does not play a large part in the gradient calculations both for single phase gas, or two phase gas/oil. Thus, the total pressure loss considered is designated by the Friction, and Head Gradients.

In terms of a flowing gradient: (dP/dL); psi/ft (kPa/m), the collected terms are dependent on the density, lbm/ft^{3} (kgm/m^{3}) of the gas or two-phase gas-liquid, as well as the actual flowing gas, or oil/gas velocity, and “wetted” diameter of the flowing scenario. The total pressure gradient may be determined from these considerations.

**II.B)** **The case of Casing/Tubing injected gas flow. An effective annular area must be**

** determined by:**

AREAeff (in^{2}) = Casing Inside Area (in^{2}) – Production Tubing Outside Area (in^{2}).

The fluid density term was taken from the standard equation for a gas, applying the following nominal range for the parameters as shown by Figures: A-2 – A-5.

**Nominal “Average” Data Range for Vertical Gas Flow in a Gas Lift Well: **

** ****T – ºF 100 – 180 ****°F**;** Z = .85 – .95**

** P – psia 500 – 2500 psia: Gas Viscosity – cp .012 – .018 **

** k (Cp/Cv) 1.23 – 1.24: MWg = 18.3 lb/lbmol**

** Table 1: Nominal parameters chosen for flow equations.**

The following data were selected from **Ref [4]** reporting the commonly used Casing/Tubing dimensions employed in a Gas Lift well completion design:

**1. ****Data: ** **ENPRO (OCTG); Casing and Tubing, (OCTG Pipe) [4]**

**Table 2: Production Tubing, and Casing design parameters [4]**

As discussed, the application of the flowing pressure gradient term requires an effective diameter and Area for tubing and casing. Flowing conditions also involve flow in the annulus between the casing and tubing. An “effective flow diameter” must be determined from the “effective area” exposed to the gas flow. Thus the effective annular areas, Aeff, and corresponding effective diameter, Deff, for the Casing–Tubing Configurations would be as follows:

Case 1: 9 5/8 in. Csg / 2 3/8 in. Tubing: Aeff_{1}= .785{(8.681)^{2} – (2.375)^{2}} = __54.76 in. ^{2}__

Effective Diameter 1: Deff 1 **= 8.35 in.**

Case 2: 9 5/8 in. Csg / 2 7/8 in. Tubing: Aeff_{1}= .785{(8.681)^{2} – (2.875)^{2}} = __52.70 in. ^{2 }__

Effective Diameter 2: Deff 2 **= 8.19 in.**

Case 3: 7 in. Csg / 2 3/8 in. Tubing : Aeff_{1}= .785{(6.094)^{2} – (2.375)^{2}} = __24.72 in. ^{2}__

Effective Diameter 3: Deff 3 **=** __5.91 in__.^{ }

Case 4: 7 in. Csg / 2 7/8 in. Tubing : Aeff_{2} = .785{(6.094)^{2} – (2.875)^{2}} = __22.66 in. ^{2}__

Effective Diameter 4: Deff 4 = __5.37 in.__

**Table 3: Casing – Tubing Configurations showing Effective Diameter and Area [4] **

The physical dimensions chosen for the well completion will impact the Casing Gas injection rate due to a reduced flow area. This area is specified as an “Effective Area”, “Aeff” in.^{2}. This reduced area will impact maximum flow in the casing/tubing annulus.

Excessive gas flow velocities are not recommended, as friction gradient increases rapidly, and impact optimal oil flow. As shown, flow from the surface to the final GLV would generally be a configuration of the above selections, depending on gas rates, and depth. All these conclusions are essentially based on the “assumptions” stated for the Casing / Tubing dimensions.

Equation 3 [3] indicates the “head” or hydrostatic term for a gas column, expressed in pressure terms, is given by:

ΔP_{gas} = ρ_{g}(g/gc)ΔH** 3 [3]**

When integrated over a differential height, the static gas pressure at the bottom of a vertical column Can be calculated as:

P_{2} = P_{1}e^{s } **4 [3]**

Where :

P_{2 } = Pressure at bottom of column – lbf/ft^{2}

P_{1} = Pressure at top of column – lbf/ft^{2 }

e = Naperian Log base : 2.718

s = Correlating function : ΔHγg/AT_{m}z_{m}

ΔH = Height differential – ft

γ_{g} = Gas gravity

T_{m} = mean absolute temperature – °R

Z_{m} = mean value for z.

Fortunately, the generalized equation for computing the total flowing gas gradient in a conduit at “median” conditions for all fluid dependent terms, including the vertical head term are available. We have defined a simple and direct approach via:

**5 [3]**

To further simplify the actual calculations, an assumption has been made to determine the Moody friction factor by a simplified equation for f, assuming turbulent flow. This equation is based on small pipes [3]. It has been sparingly used in gas flow “f” factors; however in most Gas Lift cases, the injected casing gas is in the turbulent flow range, and resulting f_{MOODY , }evaluated for small conduits (3” – 8”) is assumed to be applicable: For application of the flowing gradient equation, the Fanning friction factor f_{f} is applied. The Fanning friction, f_{f}, factor is the f_{MOODY} divided by 4.

** f _{MOODY} = 4 x 0.0239(Re^{– 0.134}) **

The calculation procedure will be based on the follow the sequences:

** II B.1) Calculation of flowing Gas gradients:**

Curves are presented in Appendix A showing the flowing casing gas annular flow pressure gradient, (dP/dH)csg in psi/ft for the following sequence of data :

Series 1: 9 5/8” Casing with 2 3/8” production tubing

Series 2: 9 5/8” Casing with 2 7/8” production tubing

Series 3: 7 ” Liner with 2 3/8” production tubing

Series 4: 7 “ Liner with 2 7/8” production tubing

The gradient data will be simplified for the casing/tubing gas flow indicated by the following input flowing physical properties, and conditions:

- Surface Injection Pressure = 500, 1000, 1500, 2000, 2500 psi
- Flowing temperature range = 100 – 180 °F
- Mean “ z” factor = 0.88
- Molecular Wt. Gas = 18.3 lb/lbmol
- Mean Gas Viscosity = .014 cp (9.4 E-6 lbm/ftsec) ; ( 1.4 E-5 kgm/msec)
- Aeff, Deff = Effective Casing-Tubing Flow Areas (in
^{2}), and Diameter, Deff, (in.) for annular flow yielding an equivalent effective “flow area” are taken from Table 3. - Selected Flow Range : 0.5 – 2.5 MMSCFD

As can be surmised, the gradient flowing parameters for pressure “gain” in the existing Casing/Tubing annulus must be known as this information yields the existing pressure at depth of the final (lowest) orifice Gas Lift Valve, shown in Figure 2.

**Figure 2: Bottom Hole Production Tubing Gas Lift Valve [6]**

Notice from the presented data, that a reasonable pressure gradient range is duly established by Figures [A.1] through [A.4], Appendix A. As shown by the Figures, the flowing gradients range discreetly between 0.01 and 0.06 psi/ft. For a set casing/liner size, (either 9 5/8” or 7”), the production tubing diameter, i.e. from 2 3/8” to 2 7/8” will impact flowing gradients. The shown “Effective Area, and Diameter” are seen to decrease discretely, showing a slight increase in the flowing gradient. It is interesting, and important to note that beyond a casing injection rate of 0.5 MMSCF/D, the flowing gradient shows to be essentially constant. This occurrence is due to the impact of the flowing gas density term which is included in the friction loss portion of the gradient with a negative sign, and also is part of the corresponding increase of the static gradient which is positive. The curves should be very applicable when estimating the Casing gas injection pressure as illustrated by the following example:

**Example 1: Gas Lift Well – Casing / Production Tubing Gas Injection:**

a) Depth of pay zone in candidate well: 8000 ft.

b) Csg/Tbg upper completion: 9 5/8” x 2/3/8”: Depth: 7000 ft.

c) Liner/Tbg. Lower completion: 7” x 2 3/8”: Depth: 8000 ft.

d) Injection Gas Rate : 1.5 MMSC/D

e) Well Head Injection Pressure, and Temperature: 1500 psia, : 140 °F

f) Mean Z factor : 0.85

g) Mean gas viscosity: 0.015 cp.

h) Mol. Wt. Gas : 18.3 lb/lbmol

1) Solution :

**a) **Gradient in 9 5/8” x 2/3/8”annulus : 0.035 psi/ft **(Figure A-1)**

b) Flowing Pressure at 7000 ft. : 1500 + (0.035)(7000) = 1745 psia

c) Gradient in 7”x 2 3/8” annulus: 0.038 psi/ft **(Figure A-3)**

d) Production Tubing Valve Injection Pressure: = 1745 +(0.038)(1000) = __1783 psia__

With these pressure vs depth data, and a knowledge of the well’s formation IPR, as well as the Solution Gas Oil Ratio (GOR – SCF/STB) of the formation fluid, the conditions are now set for a selection of the proper ORIFICE SIZE to be installed in the Production Tubing GLV.

**II C)** **Consideration of Basic Orifice Flow as applied to an operational Gas Lift Valve (GLV)**

To consider the fundamental conditions governing “orifice” flow, the basic energy balance is once again addressed. However, for the orifice flow case, the equation does not include the “friction loss” term, or the “head” term. The equation now considers the “pressure change” solely as a function of the momentum term:

**7 [3]**

For the specific case of an assumed adiabatic reversible (isentropic) expansion, pressure and specific volume V, (ft^{3}/lbm), and pressure (lbf/ft^{2}) are related by:

PV^{k }= Constant **8 [3]**

In Equation 8, the exponent, k, is the ratio of specific heats, Cp/Cv. With this assumption, the pressure loss across a restriction “choke”, could be fully recovered and downstream pressure would equal upstream pressure. In reality, some energy is lost to friction and the process is not reversible. Typically, this non-ideal behavior is resolved by assuming ideal behavior, then applying a correction factor to the result, which is the approach we will use here. The Thornhill – Craver relationship, Equation 11, applies this concept with the inclusion of the Cd factor. Alternatively, the exponent can be modified to better represent reality (such that “k” is not equal to Cp/Cv). In the latter case, the exponent is often determined experimentally, and is often referred to as the “polytropic” exponent. Either approach allows us to consider the case where the recovery of the upstream pressure is not reached due to some “polytropic” effect. The magnitude of the deviation is very dependent on the precise physical configuration of choke internals.

Notice in Figure 3, [5] depicting an orifice (choke) in a flowing condition, that the exchange of energy results in an increased “velocity”, and reduction of pressure for the fluid as it passes through the choke (orifice). The point of minimum pressure is termed the “Vena Contracta”. When the downstream area increases, the flow velocity decreases, and flowing pressure recovers; however due to the polytropic (i.e. non-ideal) conditions the recovering pressure does not reach the inlet value. This is the polytropic “energy loss”.

**Figure 3: Flow through an orifice (choke) for ploytropic conditions [5]**

Equation 9 now becomes:

**[3]**

This is the basis for most choke performance analyses, relationships, and working equations. This relationship yields the equations applied by Gilbert [6], Fortunati [7], and others. The fluid velocity, v, (ft/sec) can be related mathematically to the pressure differential, or pressure ratio across the choke.

The importance of all these solutions is the fact that a plot of downstream to upstream pressure ratios for choke flow: P_{2}/P_{1} yields the application for fluid flow deemed the “transient, subcritical” flow regime. As shown by Figure 4 [8], for a given upstream pressure, P_{1}, the flow increases across the orifice as downstream pressure, P_{2} is reduced, until further reduction of P_{2} will no longer increase flow. The reason for this behavior is that pressure disturbances are transmitted “upstream” at the speed of sound. Thus, when this velocity of the fluid at the vena contracts reaches the speed of sound, no additional flow is possible. This is referred to as CRITICAL flow. In this case, the “critical pressure ratio” is reported as 0.588, however this value is not a constant for typical natural gas flow through a choke. The critical pressure ratio varies from approximately 0.49 to 0.59.

**Figure 4: (P _{2}/P_{1}):**

**in an Orifice, or Choke [6]**

For the purpose of this document, the Thornhill-Craver [2] Choke flow relationship has been applied. This relationship addresses the non-ideal (non-reversible) behavior in part by applying a correction factor, in this case, C_{D}, the discharge coefficient which is derived experimentally.

In many Gas Lift instances, the calculated “choke capacity” has been well matched by this relationship. Equation 11 is the standard Thornhill-Carver giving a choke (orifice) capacity in SCF/d with all the parameters involved in the polytropic energy flow relationship. Appendix B presents the choke capacity results for various cases that coincide with the Flowing gradient curves with Appendix A. The selected data ranges are:

Upstream Pressures : 1000, 1500, 2000, 2500 psia

Choke Diameters : 0.125” (8/64ths”), 0.25” (16/64ths”), .375” (24/64ths”), .50” (32/64ths”)

Inlet Temperatures: 150, 175, 200, 225 °F

Gas Gravity : 0.63 (constant) – MW = 18.3 lb/lbmol

Z = .87 – .88 -.89 : k = 1.235 , 124 , 1.25 , 1.26

Equation 11, the Thornhill – Craver correlation will compute the specific choke capacity as a function of Pressure Ratios related to choke flow: P_{2}/P_{1}, downstream / upstream. The Figures in Appendix B show the flowing gas capacity as a function of the pressure ratio. All cases are seen to show the decrease in pressure ratio with increase in flow UNTIL the critical point is reached. This value is in the range of 0.55 – 0.48. Thus, once a bottom hole injection pressure has been determined, the choke must be selected to coincide in capacity (SCF/D) within its acceptable ** “sub critical”** flow regime.

Equation 11 [2] is the Thornhill-Craver for Choke Flow through an orifice.

**11 [2**]

**Where:**

Qg=gas-flow rate at standard conditions (14.7 psia and 60°F), Mscf/D,C=discharge coefficient (determined experimentally), dimensionless,_{d}A=area of orifice or choke open to gas flow, in.^{2},P_{1}=gas pressure upstream of an orifice or choke, psia,P_{2}=gas pressure downstream of an orifice or choke, psia,g=acceleration because of gravity, 32.2 ft/sec^{2},k=ratio of specific heats (C/_{p}C), dimensionless,_{v}T_{1}=upstream gas temperature, °R,F=pressure ratio, _{du}P_{2}/P_{1}, consistent absolute unitsThe correlations presented will allow the reader, and designer of a Gas-Lift well/system to choose a proper choke based on the flowing predictions for 8, 16, 24, and 32/64ths in chokes. The selected data will be displayed on the graphs. Rarely have choke performance curves been presented in this fashion, and their applicability is proven in that at the critical pressure ratio, at approaching sonic velocity, can be shown to exist. This critical pressure ratio has been shown to be expressed by: 12 [2]Where : = Critical Orifice pressure ratio: PF_{cf } _{2}(vena contracta) / P_{1 }(inlet)k = Specific heat ratio: Cp / Cv All assumed parameters have been chosen to represent actual Gas Lift wells in the field. Further, the parameters are extended so the impact of critical flow can be seen.to.If the previous example is revisited: Example 2: Gas Lift Well – Casing / Production Tubing Choke Capacity:a. Depth of pay zone in candidate well: 8000 ft. b. Csg/Tbg upper completion: 9 5/8” x 2/3/8”: Depth: 7000 ft. c. Liner/Tbg. lower completion: 7” x 2 3/8”: Depth: 8000 ft.d. Injection Gas Rate : 1.5 MMSC/De. Casing Injection Pressure = 1500 psia Solution: Flowing pressure at Production Tubing/ 7” Liner depth is found to be: 1873 psiaReferring to Appendix B, two (2) Choke Dimensions are seen to provide the desired solution for the correct flowing bottom hole liner/tubing capacity in the orifice valves shown as follows: As shown from the solution, both a 16/64 ths, or 24/64ths Choke will perform adequately. Perhaps the larger size, 24/64ths is the correct solution, as the remaining subcritical flow regime is greater: 0.96 – 0.5. This will allow for more casing gas to be injected, and provides leeway for corresponding increases, or reductions to the choke inlet pressure as flow conditions develop. Summary:In this Tip of The Month an analysis was performed in Section II A to review energy and mass balances as related to a candidate Gas Lift Well’s flowing gradients. Standard Energy balance equations provided the proper data to simulate both the annular flow in a casing/ tubing configuration, as well as for choke performance where energy change was related to momentum differential. In Section II B, Casing/Liner, and Tubing sizes were selected to perform the necessary flowing gradients for the injected casing gas. Equipment Data recompiled from Industry standards provided the necessary injected Casing/Tubing/Liner dimensions to calculate Effective Areas, as well as Effective Diameters for flow of the injected casing gas to the Production Tubing Gas Lift Valve at a given depth. Section II C reviewed the existing Industry standards for Gas Lift Choke flow. The Thornhill–Carver equation provided the choke performance data relating to the selected choke sizes. An example was presented to provide a flowing liner/tubing bottom hole pressure from the Gradient curves presented in Appendix A. The Choke performance curves in Appendix B were employed to “size” the proper choke diameter, and flowing conditions. The Appendix B curves apply to orifice sizing but are only an estimate for gas lift valves since the valve stem in the seat reduces flow area. To learn more about similar cases and how to minimize operational problems, we suggest attending the G-4 Gas Conditioning and Processing Course presented worldwide. In addition, our session in ALS (Artificial Lift Systems), GLI, Gas Lift, and Completion and Workover courses. By: Frank E. Ashford, Ph.D. Wes H. Wright The Authors would like to cite and appreciate the support received from Mr. John Martinez, PetroSkills Senior Advisor. Mr. Martinez is a known expert in Gas Lift applications. His excellent technical expertise, and proven field knowledge are reflected throughout this document. We also acknowledge and express our gratitude to Kindra Snow-McGregor for her valuable review and feedback. References:1. Simplified and Rapid Method For Determining Flow Characteristics of Gas Lift Valves (GLV); Mehdi Abbaszadeh Shahri: Texas Tech University, Aug. 2011 2. Cook, H. L. and Dotterweich, F.H. 1946 Report on Calibration of Positive Flow Beans manufactured by the Thornhill – Craver Company, Houston, Tx. 3. Gas Conditioning and Processing: The Basic Principles: (John M. Campbell): Vol 1 9 ^{th} Edition. Editors R.A. Hubbard, K.S. McGregor4. ENPRO (OCTG); Casing and Tubing, (OCTG Pipe) : (data and dimensions) 5. NEUTRIUM: Calculations of Flow through Nozzles and Orifices ; Feb. 11 , 2015 6. ELSEVIER: Flow Measurement and Instrumentation: Vol 76, Dec. 2020 – David A. Wood , et. Al. Appendix A : Casing – Production Tubing Flowing Gradients Figure A.1: Injected Gas Flowing Gradients in 9 5/8” Casing and 2 3/8” Production Tubing Figure A.2: Injected Gas Flowing Gradients in 9 5/8” Casing and 2 7/8” Production TubingFigure A.3: Injected Gas Flowing Gradients in 7 ” Liner and 2 3/8” Production TubingFigure A.4: Injected Gas Flowing Gradients in 7 ” Liner and 2 7/8” Production TubingFigure B.1: Gas Lift Choke Performance: .125 in. ( 8/64”) Choke DiameterFigure B.2: Gas Lift Choke Performance: .25 in. ( 16/64”) Choke DiameterFigure B.3: Gas Lift Choke Performance: .375 in. ( 24/64”) Choke DiameterFigure B.4: Gas Lift Choke Performance: .50 in. ( 32/64”) Choke Diameter |