- Mehtab Shaikh, Managing Director, UPCEM Engineering & Consultancy Pvt Ltd
-V K Gajinkar, Head - Process & Commissioning, UPCEM Engineering & Consultancy Pvt Ltd
-Amjad Khan,Process & Commissioning Engineer UPCEM Engineering & Consultancy Pvt Ltd
-Melwin Raj, Process & Commissioning Engineer UPCEM Engineering & Consultancy Pvt Ltd

Acid gas sweetening units are used to remove the Hydrogen Sulphide (H2S) and Carbon Dioxide (CO2) which comes with associated gases obtained from offshore oil & gas field. Acid Gas Removal Unit (AGRU) uses 30-35 percent concentration of Methyldiethanol Amine (MDEA) solution for absorption of H2S and also CO2 till certain limit. Indian offshore is having sour field in Heera-Panna Bassien block of Bombay offshore, about 60-90 km towards west coast of Mumbai. These fields are of marginal nature having high H2S & moderate CO2 content. Due to unavailability of sour gas treatment facilities at offshore, it was not possible to exploit these sour fields (as transportation of sour gases is economically not feasible and also not recommended considering HSE factors). As the concentration of H2S is high (upto 28000 volppm) in associated gas, it is also not possible to release such high concentrated acid gas in atmosphere which separates during regeneration of amine. To overcome such a problem, Acid Gas Disposal Unit (AGDU) is used in offshore platforms to incinerate H2S gas converting into SO2, which is then scrubbed in seawater scrubber (with constant caustic dosing) to avoid emission of toxic gases in the atmosphere. The Gas Sweetening Unit (GSU) unit with above specification was successfully commissioned for the first time in Indian offshore by our team. Being first system of this kind, many problems occurred during commissioning and start-up. In this present paper, we are also going to discuss the problems faced during commissioning phase with their solutions. Also safe commissioning guidelines are mentioned.

Recent years have demonstrated that for an increasing number of countries it may be difficult to meet their future local gas demand and gas export commitments[1]. India is the 13th largest consumer of natural gas in the world and domestic demand is increasing due to increasing population, higher living standards and development of new energy intensive industries such as Petrochemical, Metal Smelters etc. Additionally gas injection is applied more frequently to boost the life time of oil producing fields. In order to fulfill the future gas demands , resource owners are forced to develop more complex gas fields like sour gas fields which were previously regarded as economically unattractive. Figure 1.1 shows the increase in gas demand and supply over past few years.

The development of a sour gas field has many challenges, not only Health , Safety and Environmental (HSE) aspects, which need to be reflected in the design of the surface facilities, but also challenges related to the continuous drive to minimise the environmental footprint from the surface facilities.

This results in stringent Sulfur Dioxide (SO2) emission targets and corresponding ultra-high Sulphur Recovery Efficiency (SRE) requirements. In order to meet these requirements, sophisticated technologies need to be applied to develop sour gas fields[3]. These challenges are combined with high availability targets, large uncertainties in feed gas compositions, fluctuating and limited availability of skilled labour for construction.

A key aspect of sour gas field development is the selection of the disposal method for sulphur containing molecules. From a cost perspective, reinjection of sour gas molecules back into a field can be an attractive option. This is typically only acceptable when empty and disconnected fields are available in close surroundings. This removes the risk of field contamination which needs to be avoided to meet the sour gas field life time. For this reason, sour gas reinjection is not widely applied in the industry [3].

India has sour gas fields at Mumbai offshore Bassein region, called as B series marginal fields. These fields are of marginal nature, with high H2S and moderate CO2 content. ONGC Ltd has recently implemented sour gas treatment facilities in this region so as to utilise these sour fields, this is India's first offshore facility to have sour gas treatment unit along with an acid gas disposal unit. This facility was commissioned in June 2014, which is taken as a case study in this paper. Increasing energy costs and growing demand for natural gas have driven the development of sour gas fields around the world. About 40 per cent of the world's natural gas reserves are in the form of sour gas where H2S and CO2 compositions exceed 10 per cent volumetric of the raw produced acid gas. In some cases, the acid gas composition in these reserves is very high and economics of producing pipe line quality gas are marginal .

Sour Gas Treatment (Acid Gas Removal Process)
There are many treating processes available. However, no single process is ideal for all applications. The initial selection of a particular process may be based on feed parameters such as composition, pressure, temperature, and the nature of the impurities, as well as product specifications. The second selection of a particular process may be based on acid/sour gas percent in the feed, whether all CO2, all H2S, or mixed and in what proportion, if CO2 is significant and reduction of amine unit regeneration duty[4].

Final selection is ultimately based on process economics, reliability, versatility, and environmental constraints. Clearly, the selection procedure is not a trivial matter and any tools that provides are liable mechanism for process design is highly desirable[4].

Available gas sweetening processes[9]:
  • Chemisorption with regenerative solvent (using amines, glycol amines, K2CO3 etc)
  • Non-regenerative chemical process (scavenger process)
  • Molecular sieves
  • Dry sweetening process (Iron Sponge:Iron Oxide)
Chemisorption with regenerative solvent is most widely used process for sweetening of sour gas in refineries as well as offshore facilities. Chemical solvents react with the acid gas components to form loosely -bonded chemical complexes. On heating at reduced pressure, these complexes dissociate and release the acid gas from the solvent.The choice of solvent is based on the gas composition, expected sweet gas specifications, requirements of the acid gas processing unit, etc. Figure 2.1 shows a typical chemisorption type sour gas sweetening process.

The most widely used chemical solvents for the removal of acid gases from natural gas streams are alkanolamines (referred to generally as amine solvents), employed as aqueous solutions. These chemical solvent processes are particularly applicable when acid gas partial pressures are low and/or low levels of acid gas are desired in the residue gas. Because of the low hydrocarbon solubility in the aqueous solution, these processes are particularly effective for treating gases rich in heavier hydrocarbons. Some alkanolamines can be used to selectively remove H2S in the presence of CO2.

The basic chemical reactions involved in this process are as follows:

Where R denotes an alkanol group and R’ and R’’ can be alkyl or alkanol groups, hydrogen, or a mixture of the two depending on whether the amine is primary, secondary or tertiary. H2S & CO2 are termed as acid gases .

Acid Gas Processing/Disposal Methods
Acid gas leaving from gas sweetening unit (Figure 2.1) contains very high concentration of H2S and CO2 gases which are very harmful for environment and human health. This waste gas can be sent for further processing to recover elemental sulfur, to produce some other useful industrial products such as sulphuric acid or it can be sent to a disposal unit.

Below are the processes which can be used depending upon the requirement and economic factors:
3.1 Sulphur Recovery Unit (SRU)
3.2 Wet Sulphuric Acid Process (WSA)
3.3 Reinjection in Wells
3.4 Acid Gas Disposal Unit (AGDU)/ Seawater Scrubbing process

3.1 Sulfur Recovery Unit (Claus Process):
The Claus process is the most significant gas desulphurising process, recovering elemental sulphur from gaseous hydrogen sulphide. H2S removed in the gas sweetening process is sent to the sulphur recovery unit (SRU) as acid gas. SRU recovers H2S as elemental sulphur through the Claus reaction.

Offshore sulphur recovery was considered as an alternative for acid gas handling. After preliminary review of the option, it was determined that it was not economically feasible due to the size of the platform required for the process and the logistics of handling the sulphur product.

3.2 Wet Sulphuric Acid Process (WSA):
The wet sulphuric acid process (WSA process) is one of the key gas desulphurization processes on the market today. Since the Danish catalyst company Haldor Topsoe introduced and patented this technology in the late 1980s, it has been recognised as an efficient process for recovering sulphur from acid gas in the form of commercial quality Sulphuric Acid (H2SO4), with simultaneous production of high pressure steam. Figure 3.2.1 shows basic flow of a WSA process.
Again this method is not economically feasible for offshore facilities due to the size of platform required. Also health and safety concerns are very high due to handling and transportation of acid. WSA process is most suitable for refineries and onshore facilities only.

3.3 Reinjection in Wells:
One other approach to avoid acid gas emission to atmosphere is by injecting it to an empty field which is nearby. Acid gas re-injection is attracting much attention as an environmentally-sound and cost -effectiveapproach that can avoid the cost of traditional H2S processing and the problems of handling theelemental sulphur product, particularly for very sour natural gas streams. In this process, the acid gases separated are compressed and injected into the disposal reservoir through a special well, in amanner similar to the disposal of produced water. The disposal zone can be either ahydrocarbon reservoir or a saline aquifer[2].

By far this method is considered best for disposal of acid gas as it reduces chance of emission of toxics in environment but this method is economically not feasible (as it cannot be applied to facilities with high amount of acid gas and also it is not suitable for long time operation) andit also has some other limitations such as, we must have an empty or disconnected field nearby to avoid contamination in field, high risk & safety factors as we are dealing with high pressure acid gas . Hence this method is not widely used in most of the industries.

3.4 Acid Gas Disposal Unit (AGDU)/Seawater Scrubbing Process :
Acid gas disposal unit or seawater scrubbing process is quite similar to that of wet sulphuric acid process; in this process acid gas from regenerative solvent type gas sweetening unit, is sent to an incinerator operating at temperature 760-830°C, to convert it to a mixture of SO2, H2O (vap) & SO3 in presence excess of air.

The flue gas flows downward through a refractory lined nozzle with a Venturi shaped quencher (evaporative cooler). The gas expands and flows past a high pressure spray into the quencher where it encounters further liquid contact to be cooled to its dew point. The flue gas is saturated with water vapor which causes it to cool down to its adiabatic saturation temperature. Saturated flue gas from the quench venturi is next ducted to the seawater SO2 scrubber. SO2 scrubber consists of two different sections (seawater scrubber & caustic scrubber) to ensure complete absorption of toxic gases viz. SO2, SO3, H2S & CO2. Lower section is called seawater scrubber where flue gas is brought in contact counter-currently with seawater, this section removes upto 95 per cent of toxic gases. Upper section of SO2 scrubber is called caustic scrubber where aqueous solution of NaOH is dosed to absorb remaining toxic gases exiting from seawater scrubber section, this ensure 98 per cent removal of toxic gases from flue gas.The cleaned flue gas passes through a demister pad and is ducted to the atmosphere through an extended portion of ducting. The stack is mounted directly above the caustic scrubber. NaOH also helps to neutralise the acids formed in absorption process.

Reaction taking place in SO2 scrubber:
Effluent discharge from scrubber bottom majorly contains acids and sodium salts. Approximate pH turns out to be around 2-3 which exceeds allowable limits of effluent discharge. To overcome this problem an Effluent neutralisation unit (ENU) is installed. ENU consists of a static mixer where effluent discharge stream is diluted with large quantity of seawater to maintain the pH up-to allowable limit and then it is discharge to sea. Figure 3.4.1 shows basic block diagram of seawater scrubbing process.

Process Advantages: This process has many advantages over other conventional acid gas processing & disposal techniques for offshore facilities.
  • This is a very simple process.
  • The plant is highly reliable because of its simplicity.
  • SO2 is washed out of the flue gas in a once-through operation, i.e., there will not be any clogging problems.
  • This is very compact unit, so platform size is not an issue.
  • There are no critical levels or other process parameters to control .
  • No expensive chemicals are required.
  • The process uses only seawater and air, hence operating costs is low .
  • No land disposal is needed.
  • The absorbed SO2 is converted to sulphates, a natural constituent of seawater. This is considered safe for aquatic life.
  • It is a safe choice.
Economical Impact
In India, supply and demand gap of oil & gas are gradually increasing every year, which results increase in market value of this commodities.India’s demand for oil and gas has been increasing significantly in recent years boosted by its rapid economic growth. By 2013, India had become the world’s fourth largest oil consumer, consuming 3.7 million barrels a day (mb/d). It is forecast to reach 4.4 mb/dby 2018, when it will overtake Japan as the third largest consumer of oil. This growthin oil demand has also made India the fourth largest oil importer since 2011, importingaround 3.5 mb/d of crude. India’s limited oil production has been slowly declining andis expected to continue declining, thereby increasing its dependence on imports andallaying its concerns over energy security[15]. One of the solutions to overcome this declining behavior is to exploit the sour fields present in offshore locations.

Nearly 40 per cent of the world's gas reserves contain sour gas that poses obstacles to development. Overcoming those obstacles is a key challenge for oil companies. B & S region of Mumbai offshore is having many sour fields; these fields are of marginal nature with high H2S and moderate CO2 concentration. Due to unavailability of sour gas treatment facilities at offshore, it was not possible to exploit these sour fields (as transportation of sour gases is economically not feasible and also not recommended considering HSE factors). First Indian offshore facility with sour gas treatment and acid gas disposal (AGDU) units was commissioned at Mumbai offshore in 2014 by us; giving an opportunity to ONGC to exploit these sour fields. It has a great impact on economics and it helps us reducing supply and demand gap.

India's first platform with sour gas treatment units is designed to handle 25000 BOPD and 1.1 MMSCMD natural gases; it’s in operation from last 18 months. Considering 70 per cent capacity of operation below is a workout to show the impact on economics:

Oil production/day on 60% capacity = 0.7*25000
= 17500 BOPD

Total production in 18 months = 17500*18*30
= 9.45*106 Barrels

Gas production/day on 60% capacity = 0.7*1.1
= 0.77 MMSCMD

Total Gas production in 18 months = 0.77*18*30
= 415.8 MMSCM

Thus, using this technology it was possible to achieve above mentioned production of oil & gas. And there is more potential in these fields.

The following case study is used to demonstrate the effectiveness of sour gas treatment units at offshore facilities.

The case study is taken of India’s very first offshore platform with gas sweetening unit and acid gas disposal unit (AGDU); it has regenerative solvent type sour gas sweetening process and SO2 seawater scrubbing process for acid gas disposal. This offshore platform is located in B & S region of Mumbai offshore which belongs to ONGC Ltd.; this field is having 28000 ppm of H2S concentration and 7-8 vol% of CO2.

This offshore platform was commissioned by UPCEM Engineering & Consultancy Pvt Ltd in 2014. With addition of sour gas processing units this platform became more complicated than normal offshore platforms. Commissioning of this platform was a challenging job because of sour environment and non -awareness of acid gas disposal unit in Indian offshore.

Below mentioned are the problems faced during commissioning of acid gas disposal unit (AGDU):

• Air Fuel Ratio Adjustment in Incinerator: Maintaining air to fuel ratio in incinerator was quite a difficult task which ultimately affects the temperature of incinerator and can cause process shutdown. Calorific value of H2S gas is very high hence it plays important role sudden rise of incinerator temperature, thus control philosophy allows more quench air into incinerator. Also there was no moisture monitoring or removal unit for combustion air; it also has an impact on incinerator temperature which ultimately disturbs air/fuel ratio (as air/fuel ratio was controlled by temperature in control philosophy).

Damages in Expansion Bellow: Thermal shock across the quench venturi is very high and to avoid any kind of expansion in metallic part a fabric expansion bellow is installed. This bellow helps compensate all kind of expansions and contractions taking place inside the system. Due to improper design of this expansion bellow it was unable to withstand such high a thermal shock and got damaged; which was a very risky situation. Better designed quality expansion bellow was then installed to overcome this problem.

Equipment Failure: Many equipment failures occurred due to non-awareness of such kind of system at Indian offshore, such as burner, blowers, high flow submersible pumps, expansion bellow etc. But with expertise knowledge and extended commissioning experience of UPCEM, these problems were rectified and tackled easily.

Non-availability of pH Control: Effluent discharge from acid gas disposal unit (AGDU) contains very high amount of sulphates, and according to environmental norms effluent discharge should be of pH 7-8. But there was no online pH monitoring system was available for continuous monitoring of effluent quality. This modification needs to be implemented to avoid any acidic effluent release to the sea which can be very dangerous to aquatic life as well as it can cause corrosion on platform legs.

Health & Safety Guidelines during Commissioning
Hydrogen Sulphide or acid gas (H2S) is a flammable, colorless gas that is toxic at extremely low concentrations. It is heavier than air, and may accumulate in low-lying areas. It smells like ‘rotten eggs’ at low concentrations and causes you to quickly lose your sense of smell. Many areas where the gas is found have been identified, but pockets of the gas can occur anywhere.

Commissioning is a complex and sophisticated technical specialty, which may be considered as a specific and independent engineering discipline, as important as the more traditional ones; it requires sharp skills, vast knowledge and good experience. Commissioning of a sour gas handling platform can be a difficult task because it involves very high risk of Health Safety and Environment (HSE). Many accidents takes place during commissioning phase due lack of knowledge and non-seriousness of the situation, but due to UPCEM’s extensive experience in commissioning field, India’s very first sour gas handling platform was commissioned with zero accident rate.

Below are some guidelines which are to be strictly followed for safe commissioning of a sour gas field:

  • Skilled Manpower: It is absolutely necessary to have skilled manpower for sour field jobs and every individual should have awareness about H2S gas hazard and they must go through H2S safety training.
  • Personal Protective Equipment (PPE): Every personnel entering H2S zone must wear personal protective equipment such as self-contained breathing apparatus, safety goggles, safety gloves, safety shoes, safety helmet etc. all the time.
  • Detectors: Every individual must carry a H2S detector with him while working in H2S areas. And also H2S detectors need to be installed at different locations on platform with F & G system.
  • PTW: Special permits needs to be taken to work in H2S zone where a safety officer should analyze all the risk. These type of permits fall under confined space permit category.
  • Medical Emergency Team: Emergency medical team should always be there with the team working in H2S.
  • Evacuation Plan: Evacuation plan should be ready in case of H2S leak and every member should be informed about the plan.
  • H2S Muster Area at Elevation: Muster station for H2S leakage should be defined and as H2S is heavier than air, muster station has to be on an elevation.
  • Daily toolbox meeting to be carried out.
  • Induction training about H2S safety needs to be conducted periodically.
  • Standard Procedure to be followed for particular task.
  • Risk Assessment/Hazard Analysis report to be made before starting the task.
  • All personnel should be aware of the H2S safe shelters available on platform.
Case study of India’s first offshore platform with sour gas treatment facility has demonstrated that the challenging opportunity was accepted and successfully commissioned. This technique helps us reducing the supply & demand gap by utilizing sour fields. It has also given exposure to Indian people about this technology thus increasing individual competency in international market. Therefore, this technique should be implemented in other sour fields as we have experienced many advantages on economy, personnel development, environment etc. As this technology is new in Indian offshore, further improvements are also in process.