FORM 2
THE PATENTS ACT, 1970
(39 OF 1970)
THE PATENTS RULES, 2003
Provisional/ Complete specification
[See section 10 and rule 13]
1. Title of invention:
"Energy Integration In Amine Based Gas Sweetening Process".
2. Applicant(s):
Name Nationality Address
Oil and Natural Gas India IOGPT, Phase -II, Panvel -
Corporation Ltd. 410221, Navi Mumbai,
Maharashtra, India.
3. Preamble to the description:
The following specification particularly describes the invention and the manner in which it is to be performed.

ENERGY INTEGRATION IN AMINE BASED GAS SWEETENING PROCESS
BACKGROUND OF THE INVENTION
1. FIELD OF THE INVENTION:
The present invention relates to a new energy efficient process for preventing hydrocarbon condensation occurring in a Gas Sweetening Unit (GSU) of onshore oil and gas treating facilities.
2. DESCRIPTION OF THE PRIOR ART:
2.1. Problem:
Sour gas from slug catchers in an onshore gas treating facility is routed to gas sweetening unit (GSU) for removal of H2S & C02. The off gases from Crude Stabilization Unit (CSU) and Condensate Fractionation Unit (CFU) are also processed in GSU. A schematic diagram of Gas Sweetening Unit is provided in Fig.1. There are two identical trains of GSU with each train processing around 5.75 MMSCMD of gas during normal operation. The sour gas first enters in to inlet knockout drums (KODs) to knock out any liquid from the gas. Gas from inlet KODs is sent to the absorber column where acid gases like H2S and C02 are removed by counter-current contact with lean amine solution.
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It has been reported from field that the liquid condensation occurs at the upstream of KODs, which is more severe during winter. The condensation is occurring during winter even at normal flow and sometimes causes the choking of draining lines resulting in operational problems. The problem In extreme case of the operational problem, the liquid level may build-up in KOD vessel causing the liquid carryover and

process upset conditions in the absorber column which may result in the shut-down of the facility.
2.2. Present Practice:
The GSU trains remove acid gases (C02, H2S etc.) from associated and other gases from offshore & satellite fields and off-gases from Crude Stabilization Unit (CSU) & Condensate Fractionating Unit (CFU).
Two identical GSU trains were originally designed to treat 5.275 MMSm3/D each of feed gas containing 4.0% (mol) C02 and 450 ppm (mol) H2S to specifications of less than 50 ppm (mol) of C02 and less than 4 ppm (mol) of H2S. The GSU designs are based on a Sulfinol-D solvent. GSU trains were subsequently re-rated to a capacity of 5.75 MMSm3/D (combined 11.5 MMSm3/D) of feed gas without any equipment modifications.
In the GSU, the feed gas from the battery limit is fed to the inlet gas knockout drum, where entrained liquid gets separated. Then the gas is fed to the absorber column. The acid gases like C02 and H2S in the feed gas are removed in absorber column by the counter-current contact with the lean Sulfinol-D solution (lean solution) to meet the feed specification of gas to LPG and Ethane Propane Recovery Unit (EPRU). The treated gas from Absorber is sent to the LPG Plants.
The rich Sulfinol-D solution from the absorber bottom is flashed into Flash Scrubber. Flashed vapour is routed to re-contactor where it is scrubbed counter currently by small quantity of lean solution to remove H2S. This treated flashed gas is used as low pressure fuel gas after eliminating the entrainment through flashed fuel knockout drum.
The flashed rich liquid solution is then fed to the regenerator after getting heated from the hot lean solution through the lean/rich exchanger. In the regenerator, medium pressure steam is used as heat

source. The stripped C02 and H2S with steam are routed to overhead condenser of regenerator and sent to the reflux drum to separate acid gas and condensed water.
The separated acid gas is vented to atmosphere and water is used as reflux to regenerator. The regenerator solution is cooled to ambient temperature by cooling water through lean solution coolers and sent to the solution tank from where it is fed to absorber column. The make-up solution and water are pumped in the solution tank based on the requirement.
2.3. Design Basis:
The average compositional analysis and other parameters of gas for GSU considered as design basis are as given below:

Table 1: GSU Feed Gas Parameters
Pressure, kg/cm2 51
Temp, deg C Max-38/Min-14
Composition, Vol (%)
C1 82.39
C2 7.19
C3 5.12
i-C4 1.06
n-C4 1.35
i-C5 0.31
n-C5 0.27
C6+ 0.10
C02 1.83
N2 0.38
H2S 60ppm
The maximum and minimum feeds for the present study are 5.75 and 2.875 MMSCMD respectively.Understandanbadly adequacy

has to be checked for maximum feed. To take in to account for variation in feed, a 20% margin on maximum feed has been considered. Hence the maximum feed for the study has been taken as 6.90 MMSCMD.
Design parameters and size details considered for this study has been taken from the data sheets of inlet knockout drum of GSU are as indicated below:

Table 2: Equipment details of KOD
S. No. Parameter Unit Value
1. Vessel Type - Vertical
2. Vessel Diameter mm 2900
3. Vessel Height, T/T mm 3800
4. Demister Yes/No Yes
5. Gas inlet nozzle Inch 18
6. Gas outlet nozzle Inch 18
7. Liquid outlet nozzle Inch 1.5
The ambient temperature range adopted for this study is as follows:
• Maximum - 38 deg C
• Minimum -14 deg C
However, to have the adequate design margin, the effect of ambient temperature has been investigated up to 5 deg C.
2.4, Reasons of Condensation:
Field observations at GSU indicate that liquid condensation occurs in the feed line of inlet KOD. The problem of condensation is more pertinent in winter season. Since the gases from CFU and CSU Off-gas compression plant are also fed to GSU, any upset in these plants

results in the more rich gas going to GSU which may further increase the chance of condensation in the inlet KOD of GSU.
To find out the reasons of condensation in gas line, a steady state simulation study was carried out on 'HYSYS' package for one train of GSU (with feed rate of 5.75 MMSCMD). Since both the trains of GSU are identical, the results will be same for other train of GSU. Based on simulation studies, it was observed that there is no liquid condensation at present operating conditions.
To investigate the effect of ambient temperature on the feed stream of inlet KOD and the possibility of hydrocarbon condensation, the simulation model was run for gradually reduced temperature values in the range of 38 to 5 deg C. Table 3 summarizes the effect of ambient temperature on condensation for operating pressure of 51 kg/cm2.

Tabh S.No. 3 3: Effect Temp deg C of temperature o
Condensate quantity, m3/hr n condensation

Remarks
1. 38 Nil -
2. 20 0.138 Water (100%)
3. 15 0.159 Water (100%)
4. 14 0.164 Water (100%)
5. 10 0.177 Water (100%)
6. 9 0.68 2.16 Water (61%) Water (30%)
7. 8

8. 7 3.75 Water (20%)
9. 6 5.43 Water (15%)
10. 5 7.18 Water (12%)
As evident from the above table, there is no liquid condensation at normal operating conditions of 51 kg/cm2 and 38 deg C. At the specified lowest temperature of 14 deg C and at 51 kg/cm2g, the liquid condensation (mainly water) has been observed. However, when the temperature is lowered below 10 deg C, the condensation of

hydrocarbon liquid also occurs and the hydrocarbon quantity in condensed liquid further increases with decrease in temperature.
The above observation pertains to the composition of the gas during normal operating conditions. In case there is any operational exigency in the CSU off-gas compression plant or in CFU, the gas at the upstream of inlet KOD will be richer in terms of heavier hydrocarbons. In that case, the condensate formation will be more and relatively at higher temperatures.
Hence it may be concluded that the liquid condensation is mainly attributed to the temperature drop during winter season when the ambient temperature drops significantly.
The rich gases from CSU off gas compressors and CFU, as discussed earlier, also contribute to condensation if there is process upset in these plants.
It has been established by field observations and simulation studies that liquid is condensed at the inlet of feed knock out drum of GSU. Though the condensation occurs at the inlet of KOD, it should not result in abnormal conditions because the vessel has been designed to knock out the liquid.
3. DETAILED DESCRIPTION OF THE INVENTION 3.1. Heater System at the Met of KOD:
This option has been considered in view of the field observations of condensation in winter conditions. Putting a heat exchanger at the upstream of inlet KOD's of each GSU train will avoid the condensate formation and thus will minimize the operational problems. It has been established by simulation studies that heating the inlet sour gas to around 25 deg C will suffice the purpose of condensate vaporization.

Accordingly a heater arrangement has been conceptualized as solution to the problem which has been designed to heat the inlet stream from 5 deg C to 25 deg C.
Before entering to inlet KOD's, the sour gas shall be routed to the heater system (One each for individual GSU train) where it shall be heated to a temperature of 25 deg C. For design purpose, the inlet gas temperature of 5 deg C is considered.
3.2. Source of Heat
The source of heating in these heat exchangers may be steam or any other conventional hot stream. The estimated heat duty of the heating system is about 2.82 MMkcal / hr per train of GSU which will require around 10 Tons/hr of LP steam for both the trains. Since the steam is costly and the steam generation facilities were not available in spare at the plant site, the possibility of some other heat source was explored.
For this purpose, detailed study was done and the analysis of each stream of GSU was carried out with an objective of optimizing the heat recovery by effective energy integration. After analysis of the existing streams, it was found that hot lean amine solution from regenerator column is first utilized to heat the rich amine solution in rich-lean exchanger. Thereafter the hot lean solution is further cooled to ambient temperature by water in the lean solution coolers before sending to solution tank. The field parameters of this solution at the inlet of lean solution cooler are reproduced below:
√ Average hot lean solution circulation rate: 200m3/hr. √ Temperature: 64 deg C (Max 71 deg C). √ Pressure: 4.42 kg/cm2 g.

This stream was analyzed for utilizing in the new heater system and it was observed that the same is sufficient to heat the inlet sour gas up to desired temperature of 25 deg C. Hence the same is considered as heating source.
3.3. The Scheme:
An integrated diagram of GSU along with the new heater system has been provided in Figure 2. The hot lean amine solution, before entering in to the lean solution cooler, is diverted to the new heating system to heat the feed gas. The lean solution from this new heating system is re-routed to the lean solution cooler. This will also result in optimizing the operating cost in GSU by saving in cooling water requirement. Provision has also been given to bypass the hot solution partly or fully when the temperature of heater outlet gas rises beyond 25 deg Celsius. Also, these heaters can be kept in bypass mode when not required in operation.
The specifications of Heat Exchangers are given below:

Table 4: Specifications of Heaters
S.No. Parameter Tube Side Shell Side

Inlet Outlet Inlet Outlet
1. n Fluid Handled Sour Gas Hot lean Amine solution
2. Flow Rate, kg/hr 207500 184500
3. Pressure, kg/cm2g , 51 50.5 4.42 3.92
4. Temperature, degC 05 25 64 45.2
5. Number of heater required Two (One for each train of GSU)
6. Heat Duty, MMkcal/hr 2.82
7. LMTD, degC 39.6

4 SUMMARY OF THE INVENTION:
Onshore oil and gas treating facilities predominantly faces the problem of condensation of liquid from the gas (especially during winter) at the upstream of inlet KOD of GSU. The problem of condensation can be removed by putting a heater arrangement at the upstream of inlet KOD of GSU which will hot lean solution from regenerator column which will heat the inlet sour gas. Heating of the hot lean solution will also assist in reducing the cooling water circulation rate thereby saving the makeup water.

BRIEF DESCRIPTION OF DRAWINGS
The above and other objects, features and other advantages of the present invention will be more clearly understood from the following detailed description taken in conjunction with the accompanying drawings, in which:
1) Fig-1 is a schematic diagram of conventional Gas Sweetening Unit."
2) Fig-2 is a diagram of Gas Sweetening Unit with integrated scheme of heater system.

We claim:
1. Heating of GSU feed gas at the upstream of inlet knock out drums will avoid hydrocarbon condensation.
2. Utilizing hot lean amine solution as heat source will reduce the cooling water circulation rate in Gas Sweetening Unit by around 300 m3/hr per train and will result in saving of make-up water.