Process Optimization Strategies for Associated Gas Utilization and Flaring Minimization in Onshore Oil and Gas processing Facilities

 

Process Optimization Strategies for Associated Gas Utilization and Flaring Minimization in Onshore Oil and Gas processing Facilities

Brahmaiah Binginapalli, Rani Bora Borthakur, P V Kherodkar, B Harish Krishna

Surface Facilities and Process Engineering Department, Institute of Production Engineering and Ocean Technology, ONGC, Panvel, India

Nagaraju Sandaka

Facility Engineering Group, Rajahmundry Asset, ONGC, Rajahmundry, India

Abstract – An oil and gas field produces about 300 m³/day of crude oil and 50,000 SCMD of associated gas with liquid production supported by gas lift using high pressure gas from a nearby well. Currently, the associated gas is being flared due to the lack of gas evacuation infrastructure. To reduce flare and monetize this gas, a 32 km pipeline connecting to the local gas grid is under construction.

This study identified optimal infrastructure and processing facilities to ensure the sales gas meets regulatory specifications while minimizing gas shrinkage and off gas generationConceptualized facilities include a compression unit, solvent-based Gas Dehydration Unit (GDU), and refrigerant based Dew Point Depression Unit (DPDU). Process simulations were performed using Aspen HYSYS software for compressor discharge pressures of 70 and 100 kg/cm²g. For each case, the sales gas, lift gas, and off-gas quantities were estimated for two lift gas withdrawal locations: downstream of the GDU and downstream of the DPDU

Simulation results showed limiting lift gas diversion at the downstream of GDU and operating DPDU only on the throttled sales gas stream reduces off-gas generation and maximum sales gas availability. The optimized configuration meets water and hydrocarbon dew point standards at both supply and delivery points which is at 32 Km away. The otimized configuration also minimizes overall energy usage. The study also underscores the importance of off-gas recovery and utilization scheme to reduce flaring effectively.

KeywordsAssociated gas; Flaring reduction ; Gas Dehydration; Aspen HYSYS: Optimized process configuration;

1. INTRODUCTION

   Associated gas is the natural gas produced along with crude oil from reservoir. In many crude oil producing fields, particularly in remote or infrastructure deficient areas, this gas has historically been flared. Non emergency flaring and venting occurs in oil and gas installations when the operators opt to burn the associated gas that accompanies oil production with no availability of sales arrangement with consumers [2]. While flaring of associated gas ensures operational safety, it results in significant loss of this high calorific value energy resource and increased greenhouse gas emissions. Tackling these emissions is one of the most viable and low cost options to reduce GHG emissions .

   There are different methods or strategies available for monetization of associated gas. Typical monetization strategies are explained in the following sub sections.

2. STRATEGIES FOR MONETIZATION OF ASSOCIATED GAS
   1. Pipeline Evacuation for Market Delivery

      Building dedicated pipelines to connect oil fields to regional gas grids is a first and effective method to be evaluated for monetizing associated gas. This infrastructure enables the continuous evacuation of surplus gas from the field, ensuring a steady supply to downstream markets. By linking to a regional gas network, the associated gas once processed to meet required specifications can be sold to industrial, commercial, or residential customers, generating consistent and reliable revenue streams over time. However, building dedicated pipelines requires significant upfront capital investment and long-term planning. Challenges include securing regulatory approvals, negotiating land access, demand and price reasonability. Due to these complexities and costs, pipeline infrastructure development should be prioritized early in project planning and evaluated as the primary monetization option, compared to other smaller scale or technically complex solutions such as LNG, CNG, or GTL technologies for associated gas listed below.

   2. Gas Reinjection

      Re-injecting associated gas into reservoirs to enhance oil recovery and maintain reservoir pressure is a common method although it does not directly generate revenue, but it will certainly increase oil production. Careful analysis and identification suitable reservoirs and the depth of injection are to be identified for success of this strategy.

   3. Power Generation

      When there is limitation to pipeline connectivity or market access, associated gas can be used as a fuel for onsite power generation or be supplied to nearby grids, providing economic value especially in remote locations. Small to medium gas engines can be used for onsite power supply and dependency on grid power can be reduced. This option can be used in remote fields. Gas Turbines offer a highly efficient power generation option for larger gas volumes and centralized facilities. Now a days Micro turbines are also being used where gas flow rates are low. They provide flexible, modular solutions that can be deployed near wellheads or processing units to generate electricity close to the source and reduce flaring.

   4. Compressed Natural Gas (CNG)

      The monetization of associated gas through Compressed Natural Gas (CNG) option involves gas treatment and compressing the gas so that it is more economical to transport and distribute where pipeline infrastructure is lacking. CNG is transported in high pressure cylinders on trucks or trailers to offsite customers such as industrial plants, power generation facilities, or local gas distribution networks which are at far away. Collaboration among operators to combine gas volumes can make CNG monetization economically viable by sharing compression and transport infrastructure costs.

   5. Liquefied Natural Gas (LNG)

      Monetizing associated gas through Liquefied Natural Gas (LNG) involves purifying the gas and cooling it to about 160°C to convert it into liquid form. Before liquefaction, the gas is treated to remove CO, HS, water, heavy hydrocarbons, mercury, and other impurities. The purified gas is then liquefied using refrigerant systems. The resulting LNG is transported in specialized road tankers for distribution to industries and domestic gas supply networks.

   6. Gas-to-Liquids (GTL)

      Monetizing associated gas through Gas-to-Liquids (GTL) involves converting natural gas into synthetic liquid fuels such as diesel, naphtha, and lubricants. The process first reforms the gas to produce synthesis gas (a mixture of hydrogen and carbon monoxide). This syngas is then converted into longer-chain hydrocarbons using the Fischer Tropsch process. The resulting synthetic liquids are refined to meet fuel specifications. GTL products are easily transported and can directly replace conventional petroleum fuels in industrial, transport, and other applications.

3. BACKGROUND AND PROBLEM STATEMENT

   An oil and gas field is currently producing about 300m³/d of crude oil and 50,000 SCMD of associated gas. Liquid production is supported by gas lift, utilizing high-pressure gas from well. At present, there are no gas evacuation facilities at the production installation, resulting in flaring of associated gas. For monetization of the associated gas, a dedicated pipeline was planned following a detaied feasibility analysis and has recently been laid from the processing installation to the nearest gas terminal, located approximately 32 km away.

   To meet the required pressure and sales gas quality specifications, this study was undertaken to identify the necessary facilities at the processing installation. Its objective is to establish the most effective gas processing scheme to satisfy both lift gas and sales gas quality requirements.

4. INPUT DATA & BASIS OF STUDY

   Following input data is considered for this study

   1. Formation Gas quantity: 50,000 SCMD
   2. Gas grid trunk line pressure is considered as 50 Kg/cm2(g) which is at 32 Km from processing installation
   3. As the lift gas pressure requirement was not yet finalized during the study, two cases of compressor outlet pressure are considered: Case1: 70 Kg/cm2(g), Case 2: 100 Kg/cm2(g)
   4. Feed Gas Composition is shown in the following table 4.1

   Table 4.1: Feed Gas Composition
   Component	Mole %
   Methane	56.58
   Ethane	16.64
   Propane	12.87
   i-butane	1.83
   n-butane	4.11
   i-pentane	0.87
   n-pentane	1.00
   n-hexane	0.49
   n-heptane	0.245
   n-octane	0.245
   CO2	4.11
   Nitrogen	0.70
   He	0.01

5. CONCEPTUALIZATION OF PROCESSING FACILITIES

   To monetize natural gas, sales gas must meet regulatory specifications while maximizing sales and lift gas availability, minimizing shrinkage, and reducing off-gas generation. The table 5.1 below lists required sales gas quality parameters.

   Table 5.1: Regulatory Specifications for quality of pipeline gas
   Parameters	Limit
   Hydrocarbon Dew Point (max)*	00C
   Water Dew Point (max)*	00C
   H2S (max)	5 ppm (wt.)
   Total Sulphur (max)	10 ppm (wt.)
   CO2 (max)	6 % ( mole)
   Total inerts	8 % (mole)
   Temperature	550C
   Oxygen (max)	0.2% (mole)

   Considering the feed gas composition and outlet pressure requirement, the following processing facilities are required to meet the sales gas quality requirement.

   1. Compression facilities to meet lift gas and sales gas pressure requirement
   2. Gas Dehydration facilities to lower the water dew point below 00C
   3. Hydrocarbon Dew Point depression facilities to maintain HCDP below 00C.
   4. Condensate handling facilities.
   1. 1. Compression facilities

         At present, the associated gas is being flared after separation of crude oil in a vertical separator which is being operated at about 2-3 Kg/cm2(g). Now, Compression facilities are required to boost natural gas pressure from a low suction pressure of approximately 2 kg/cm²(g) to a high delivery pressure of 70 kg/cm²(g)/ 100 Kg/cm2(g). The compression facilities are required to handle expected variations in gas flow, suction pressure, and composition while maintaining stable operation.

         Reciprocating compressors are well suited for moderate flow rates combined with high pressure ratios and operational flexibility over a wide range of operating conditions. Centrifugal compressors are generally not preferred for this application of high compression ratio and relatively low flow rate. Considering the low suction pressure and high discharge pressure, a multi-stage reciprocating compressor is the most suitable compression system for this application. In this case, three compression stages with inter-stage cooling are considered. Inter-stage separators are installed downstream of each cooler to remove condensed water and heavy hydrocarbons, thereby preventing liquid carryover to subsequent compressor stages.

         Also, a suction scrubber is provided upstream of the first compression stage to remove free liquids, solids, and slugs from the incoming gas stream. This is critical given the low suction pressure and potential for upstream condensation. Following the final compression stage, an after cooler is installed to cool the gas to meet downstream pipeline or injection system temperature specifications prior to delivery at 70 kg/cm² (g)/ 100 Kg/cm2(g). Simulation of compression system is carried out in Aspen HYSYS process simulator and the model is shown in Fig 5.1.

         Fig 5.1: Modelling and simulation of compression system

         For minimum total work in a multi-stage compressor, the pressure ratios in all stages are equal and are given by the following equation [3]. Though compression ratios up to 4.0 can be considered in the basic engineering stage, discharge temperatures are also be kept in check to attain better cooling in coolers.

         is the overall pressure (absolute) ratio

         r is the single stage pressure ratio with n number of stages

      2. Details of compression system

         The compression system is simulated and major operating parameters are shown in Table 5.2

         Table 5.2: Details of compression system
         	Case 1	Case 2
         Suction Pressure, Kg/cm2g	2.0	2.0
         Discharge Pressure, Kg/cm2g	70.0	100.0
         No.of Stages	3	3
         Compression ratio	2.84	3.20
         Power required (KW)	584	715

         Auxiliary systems such as a lubrication oil system, pulsation control equipment, and vibration monitoring are considered. A comprehensive instrumentation and control system is also considered for performance monitoring, capacity control and protection. Safety systems such as pressure relief valves, emergency shutdown (ESD) systems and gas detection are incorporated in compliance with applicable industry codes and standards.

      3. Gas Dehydration Facilities

         During natural gas processing, gas dehydration is more often accomplished by either of the following processes.

         1. Glycol based dehydration systems
         2. Molecular sieve based solid desiccant adsorbent systems.

         Molecular sieve based adsorbent systems are generally used when the gas pressure is low or also when very water dew points are to require for the treated gas. These adsorption-based systems are costlier compared to the glycol- based systems. Hence, in this case, Glycol based gas dehydration facilities are considered.

         1. Glycol based gas dehydration systems

            In this process, gas is first passed through a scrubber to remove the carried over liquid, if any. The gas then enters the absorption column i.e. contactor, where it comes in contact with the lean glycol which flows counter-currenly. The dehydrated gas exits from top of the absorber after exchanging heat with the lean glycol and routed to the outlet gas KOD. After absorbing moisture from gas, rich glycol is sent to the flash drum to remove the dissolved hydrocarbons, if any. The rich glycol will be passed through series of filters and then routed to heat exchangers where the hot lean glycol from the regeneration column will transfer heat to the rich glycol. Thus, the preheated rich glycol will be routed to the regenerated column where the absorbed moisture in the glycol will be vaporised through reboiler system. The liberated water vapour is released from the top of the regeneration column. Hot lean glycol from the regeneration column exchanges heats as briefed before with the incoming rich glycol and is pumped back into the contactor. The process flow diagram (PFD) of glycol based dehydration process is shown in Figure 5.2

            Fig: 5.2 Triethylene glycol (TEG) based gas dehydration process.[4]

      4. Hydrocarbon Dew Point Depression (HC DPD) Unit

         Once the moisture is removed from the gas as per pipeline specification, is required to be routed to the hydrocarbon dew point depression unit. Following are technically proven and commercially available cryogenic methods for hydrocarbon dew point depression:

         1. Joule Thomson expansion & Compression system
         2. Refrigerant based dew point control systems

         In a JouleThomson expansion system, hydrocarbon condensation is achieved by isenthalpic expansion of the gas across a throttling valve followed by separation of condensed liquids and subsequent recompression of the treated gas to pipeline pressure. While this technology is widely used, JT expansion with recompression is not considered

         suitable for the present application due to its relatively high capital cost and energy requirement, particularly for low to moderate gas throughputs. The need for additional compression facilities to recover pipeline pressure significantly increases both CAPEX and OPEX, making the process economically unattractive for the current gas flow rate.

         1. Refrigerant based HC DPD

   Refrigerant based hydrocarbon dew point control systems on the other hand achieve dew point depression by externally cooling the gas stream using a closed-loop refrigeration cycle allowing controlled condensation and removal of heavier hydrocarbons. These systems offer better energy efficiency, improved operating flexibility, and lower overall capital cost for the given throughput range, and are therefore considered more suitable for this application.

   Accordingly, refrigerant-based dew point control is selected as the preferred technology for hydrocarbon dew point depression in this case. Schematic diagram of this process is shown below in Fig 5.3

   Fig 5.3 : Refrigerant based Hydrocarbon Dew point control unit

6. SIMULATION STUDIES

   The calculated Sales gas pressure at processing installation is 55 Kg/cm2g considering the gas grid line pressure of 50 kg/cm2g. The schematic of the pipeline and facilities are shown below in Fig 6.1.

   Processing Installation

   Gas Trunk line

   High Pressure Dehydrated Gas

   Fig 6.1: Schematic of Pipeline connecting Processing Installation to gas grid

   Processing facilities are simulated for two different compressor discharge pressures of 70 Kg/cm2(g) and 100 Kg/cm2(g). The details of the simulation and results are explained in the following sections.

   1. Case 1: Compressor Discharge pressure of 70 Kg/cm2g
      1. Lift gas is diverted after DPD

         In this scenario, a gas compressor is considered in the downstream of the group separator, followed by a Gas Dehydration and Dew Point Depression (GDU & DPD) units both operating at about pressure of 70 kg/cm²g. The lift gas stream is taken at the DPD outlet, maintaining a pressure of 70 kg/cm²g. Further in the sales gas stream pressure is reduced to 55 Kgcm2g through a throttling valve. The schematic diagram of the processing facilities is shown below in Fig 6.2.

         Fig 6.2: Schematic of processing facilities at production installation

         Further Modelling and Simulation is carried out in Aspen HYSYS (shown in Fig 6.3). Flow rates, Temperature, Pressure and dew Points of the streams are given in the tables below from Table 6.1 to 6.4

         Fig 6.3: Modelling and Simulation of processing facilities in Aspen HYSYS

         If the hydrocarbon dew point is maintained as 0.0 °C at 70 kg/cm², it increases to approximately 1.05 °C at 55 kg/cm² due to the presence of the Cricondentherm on the hydrocarbon dew point (HCDP) envelope between these two operating pressures.

         Table 6.1: Dew Points Estimation for 70 KSC Discharge
         HCDP at 70 KSC	HCDP at 55 KSC	HCDP at 50 KSC
         00C	1.050C	0.650C
         -20C	-0.80C	-1.10C
         -50C	-3.59	-3.87

         In this case, we need to maintain minimum dew point of -20C at 70 KSC to maintain negative dew points at gas grid terminal. Initial simulations started with 50,000 m3/d of feed flow, and then by re-circulating the lift gas to the feed gas, the stabilized flow rate results are given below. The stabilized feed gas flow of 68,530 m3/d includes the return gas from gas lift wells.

         Table 6.2: Simulation Results Flow rates
         Stream	Flow rate, m3/d	Pressure, Kg/cm2g
         Feed Gas	68,530	2.0
         Sales Gas	18,530	55.0
         Lift Gas	18,530	70.0

         In this case, off gas quantity is obtained from the simulation which is about 31,030 m3/d and condensate generated is about 8.13 m3/d (at 1 atm., 30 Deg C)

         Table 6.3 : Simulation Results- Dew Points
         At Source/ Processing		At sales point (32 Km away)
         WDP, Deg C	HCDP, Deg C	WDP, Deg C	HCDP, Deg C
         -7.5	-0.8	-8.3	-1.1
         -7.5	-3.6	-8.3	-3.9
         -7.5	-5.0	-8.3	-5.2

         As per PNGRB norms, at sales location/ custody transfer point we need to maintain water and hydrocarbon dew point of 00C. Hence for a trunk line pressure of 50 Kg/cm2g, it is required to maintain Hydrocarbon dew point of minimum -10C. However, to ensure consistent compliance and avoid any positive dew point excursions under transient operating conditions, the system shall be conservatively designed for a hydrocarbon dew point of 5 °C at the specified reference conditions. Hence to maintain the negative dew points, it is required to cool the gas up to – 50C in DPD and accordingly, refrigeration system is considered.

         Table 6.4: Gas Composition details of different gas streams from simulation
         	Feed Gas	Sales Gas/p>	Off gas	Condensate
         Methane	0.5659	0.7333	0.3933	0.0017
         Ethane	0.1664	0.1334	0.2162	0.0236
         Propane	0.1287	0.0592	0.2133	0.1488
         i-Butane	0.0183	0.0052	0.0314	0.0669
         n-Butane	0.0411	0.0093	0.0689	0.2187
         i-Pentane	0.0087	0.0011	0.0119	0.1042
         n-Pentane	0.0100	0.0010	0.0122	0.1475
         n-Hexane	0.0049	0.0002	0.0030	0.1251
         CO2	0.0440	0.0464	0.0438	0.0011
         Nitrogen	0.0070	0.0108	0.0028	0.0000
         Helium	0.0001	0.0002	0.0000	0.0000
         H2O	0.0000	0.0001	0.0024	0.0001
         n-Heptane	0.0025	0.0000	0.0006	0.0780
         n-Octane	0.0025	0.0000	0.0002	0.0842

      2. Lift gas is diverted after GDU

         In this scenario, a gas compressor is installed downstream of the group separator followed by GDU operating at 70 Kg/cm2(g). The lift gas stream is extracted at the GDU outlet, maintaining a pressure of 70 kg/cm²g. Subsequently, an expansion (throttle) valve reduces the pressure, resulting in outlet pressures of 55 kg/cm²g, which is also the operating pressure range for the DPD. A schematic diagram of the processing facilities is provided below fig 6.4.

         Fig 6.4: Schematic of upcoming facilities at Processing Installation

         Further Modelling and Simulation is carried out in Aspen HYSYS. Flow rates, temperature, pressure and dew points of the streams are given in the table 6.5 below. To avoid the Dew points inversion, DPD has to be operated below 59 Kg/cm2(g). If we operate the DPD below 59 Kg/cm2(g) then maintaining HC dew point of 00C or less would ensure the compliance of PNGRB guidelines. Simulation results are presented in the following table 6.5 and

         6.6 with DPD operating at 55 KSC and 00 C.

         Table 6.5: Simulation Results Flow rates and Dew Points
         Stream	Flow rate, m3/d	Pressure, Kg/cm2g	At Installation		At Sales point (32 Km away)
         			WDP, 0C	HCDP, 0C	WDP, 0C	HCDP, 0C
         Feed Gas	94,890	2.0	40.0	29.60	–	–
         Sales Gas	30,440	57.0	-6.28	-0.01	-7.74	-0.56
         Lift Gas	44,920	70.0	-6.31	50.1	–	–

         In this case, Off gas quantity is obtained from the simulation which is about 18,710 m3/d and the condensate generated is about 5.2 m3/d (1 atm, 300 C)

         Table 6.6: Gas Compositions results from simulation
         	Feed Gas	Sales Gas	Off gas	Condensate
         Methane	0.5659	0.7193	0.3325	0.0013
         Ethane	0.1664	0.1426	0.2352	0.0261
         Propane	0.1287	0.0634	0.2535	0.1857
         i-Butane	0.0183	0.0053	0.0354	0.0799
         n-Butane	0.0411	0.0093	0.0738	0.2497
         i-Pentane	0.0087	0.0010	0.0107	0.0998
         n-Pentane	0.0100	0.0009	0.0102	0.1328
         n-Hexane	0.0049	0.0002	0.0021	0.0962
         CO2	0.0440	0.0479	0.0420	0.0010
         Nitrogen	0.0070	0.0099	0.0020	0.0000
         Helium	0.0001	0.0001	0.0000	0.0000
         H2O	0.0000	0.0001	0.0021	0.0001
         n-Heptane	0.0025	0.0000	0.0004	0.0596
         n-Octane	0.0025	0.0000	0.0001	0.0676

   2. Case 2: Compressor Discharge Pressure 100 Kg/cm2(g)
      1. Lift Gas is Diverted after DPD

         In this scenario, a gas compressor is installed downstream of the group separator, followed by a Gas Dehydration and Dew Point Depression (GDU & DPD) units both operating at a pressure of 100 kg/cm²(g). The schematic diagram of the processing facilities is shown below in Fig 6.5. The lift gas stream is taken out at the DPD outlet maintaining a pressure of 100 kg/cm²(g). After Lift gas stream is taken out, sales gas goes through expansion/ throttle valve with despatch pressure of 55 Kg/cm2(g).

         Fig 6.5: Schematic of upcoming facilities at Processing Installation

         Further Modelling and Simulation is carried out in Aspen HYSYS. In this process configuration, if the gas is cooled to -50C or 00C entire quantity of gas is condensing and there will be no sales gas or life gas. Snapshot of Aspen HYSYS flow sheet is given below Fig 6.6.

         Fig 6.6: DPD outlet Stream summary from simulation

         Fig 6.7: Snapshot of Aspen HYSYS Flow sheet and simulation

         Phase Diagram and reason for total condensation:

         The compressor outlet stream which is inlet to DPD unit is at a pressure and temperature of 100 Kg/cm2(g) and 500 C respectively. Phase Diagram of DPD inlet gas stream is given below.

         Fig 6.8: Phase Diagram of DPD Inlet Stream at 100 Kg/cm2g

         In the above Phase diagram, blue line indicates dew points and red line indicates bubble points at different pressure. The dew point at 100 Kg/cm2(g) is about 450C. If we cool this gas at constant pressure in heat exchanger, it is entering two phases (mix of liquid and vapour) below 450C and the entire stream becomes liquid at about 10C.

         Vapour fractions at different temperatures are given in the following table.

         Table 5.7: Vapour fractions at DP temp
         Temperature (0C)	Vapour Fraction
         47	1.00
         35	0.83
         10	0.31
         1.0	0.00

         Further parametric study of DPD outlet temperature is carried out with following two objectives

         • Sales gas has to be maintained with dew points below 00C
         • Maximum sales gas and lift gas quantities are desired

         Table 5.8: Simulation results Flow rates and Dew Points
         DPD Outlet T (0C)	Sales Gas, m3/d	Lift Gas, m3/d	Off gas, m3/d	Condens ate, m3/d	Sales gas at Installation		Sales gas at Custody
         					WDP (0C)	HCDP (0C)	WDP (0C)	HCDP (0C)
         20	15470	18540	33850	4.29	-7.01	2.45	-7.77	1.96
         15	11290	13460	38300	3.25	-7.35	-2.75	-7.94	-3.08

         Optimum DPD gas outlet temperature is to be at 150C in this process configuration. However this design configuration leads to significant off gas generation adversely impacting hydrocarbon recovery and overall process efficiency. Hence this option is not recommended for facility design.

      2. Lift Gas is diverted after GDU

         In this scenario, a gas compressor is installed downstream of the group separator followed by a gas dehydration unit (GDU) operating at 100 Kg/cm2(g). The lift gas stream is extracted at the GDU outlet, maintaining a pressure of 100 kg/cm²(g). Subsequently an expansion (throttle) valve reduces the pressure resulting in outlet pressures of 55 kg/cm²(g) which is also the operating pressure range for the DPD. A schematic diagram of the processing facilities is provided below.

         Fig 6.9: Schematic of upcoming facilities at Processing Installation

         Further Modelling and Simulation is carried out in Aspen HYSYS. Flow rates, temperature, pressure and dew points of the streams are given in the table below.

         Table 5.9: Simulation Results- Flow rates and Dew Points
         Stream	Flow rate, m3/d	Pressure, Kg/cm2g	At Installation		At Sales Custody (32 Km away)
         			WDP, (0C)	HCDP, (0C)	WDP, (0C)	HCDP, (0C)
         Feed Gas	98,950	2.0	–	–	–	–
         Sales Gas	29,550	56.0	-7.19	-5.0	-7.74	-5.21
         Lift Gas	48,950	100.0	-6.21	45.0	–	–

         In this case, off gas quantity is obtained from the simulation which is about 20,001 m3/d and the condensate generated is 3.43 m3/d (1 atm., 300 C )

7. CONCLUSIONS:
8. Higher off-gas and condensate generation is observed when lift gas is withdrawn downstream of the DPD unit for both lift gas pressure scenarios. To minimize off-gas generation, it is recommended to withdraw lift gas upstream of the DPD unit.
9. It is recommended to divert lift gas downstream of the GDU and operate the DPD unit exclusively for sales gas at 55 kg/cm² (g). This configuration results in significantly lower off-gas generation compared to alternative configurations.
10. It is prudent to design Hydrocarbon Dew Point Depression system for 5.0°C at the processing installation under the final configuration to ensure that negative dew point margins are consistently maintained at the sales delivery point, located 32 km downstream of the installation.

ACKNOWLEDGEMENT

The author is heartily obliged to ONGC for providing the opportunity as well as requisite administrative support for the fruitful completion of the study. This study was carried out under able guidance and support of various experts of the ONGC and concerned persons from production site whose excellent expertise and experience as well as invaluable suggestions immensely helped the author in improving the knowledge and skills. The views expressed in this paper are of author and not necessarily those of ONGC.

REFERENCES

[1]. Emissions from Oil and Gas Operations in Net Zero Transitions, IEA, Revised Version, June-2023 [2]. World Energy Outlook Special report, IEA, 2025

[3]. Narayanan, K.V, Chemical Engineering Thermodynamics, Prentice-Hall India, 2004

[4]. L. Micucci, Siirtec nigi, The natural gas dehydration process, Gas Processing & LNG, Nov-2020,

[5]. Abeer M. Shoaib, Ahmed A. Bhran, Mostafa E. Awad, Nadia A. El-Sayed, Tamer Fathy, Optimum operating conditions for improving natural gas dew point and condensate throughput, Journal of Natural Gas Science and Engineering, Jan- 2018, 49, 324-330