Chapter 3 (b)

Production Engineering II

By :

Dinesh Kanesan([email protected])

Tel No : 05 368 7295Internal

Oil and Gas Production Processes

Gas Treating Systems - Introduction• The gas that is separated must be compressed and treated for sales.

Compression is typically done by engine-driven reciprocating compressors,• Usually, the separated gas is saturated with water vapor and must be

dehydrated to an acceptable level (normally less than 7 Ib/MMscf). Usually this is done in a glycol dehydrator.• In some locations it may be necessary to remove the heavier hydrocarbons to

lower the hydrocarbon dew point. Contaminants such as H2S and CO2 may be present at levels higher than those acceptable to the gas purchaser. If this is the case, then additional equipment will be necessary to "sweeten" the gas.• Figure 15 is a block diagram of a production facility that is primarily designed

to handle gas wells.

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Gas Treating Systems

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Compressor

Stabilization

H.P Separation

Gas Treating

Cooling

Dehydration Gas Sales

Figure 15. Gas Field Facility Block Diagram

WELLS

Heating

Introduction• Some well flow stream may require heating prior to initial

separation.• Choke – gas expands and temperature decreases.• At low temperatures, hydrates start forming which leads to

plugging. • Typically in a gas facility, there is an initial separation at high

pressure, enabling the reservoir energy to move the gas through the process to sales. • Depending on the number of stages, the gas flashes in the lower

pressure separator can be compressed and combined with the gas from the high-pressure separator.

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• Purchasers require that impurities be removed from the gas they purchase. • Consequently, contracts for the sale of gas to transmission companies

always contain provisions regarding the quality of the gas that is delivered to them, and periodic tests are made.• Impurities commonly found in Natural Gas which has to be removed

are :a) Hydrogen Sulfide

Very corrosive Causes hydrogen embrittlement of steel Extremely toxic at low concentration Normal specification of 4ppm by volume

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b) Carbon Dioxide Very corrosive (forms carbonic acid with the precence of water)Normal specification of 2-4 volume %

c) Nitrogen No calorific value – lowers the heating value of gas. Gas purchasers may set a minimum limit of heating value (normally

approximately 950 Btu/scf)

• Natural gas produced from a well is usually saturated with water vapor. • The liquid or solid phase of water that may occur when the gas is compressed

or cooled is very troublesome.

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• Problems due to presence of water vapor :

(a) Liquid water accelerates corrosion of pipelines and other equipment.(b) Solid hydrates that can form when liquid water is present in plug valves,

fittings or the pipelines itself(c) Liquid water accumulates at low points of pipeline, reducing the capacity

of the lines.

• Removal of water vapor by dehydration eliminates these possible difficulties and is normally required by gas sales agreement. •Water vapor concentrations of 2-4 lb/MMscf are common.

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Gas Treating • This section discusses the different processes that are commonly used in field gas

treating of acid gases and method that can be used to select from among the various processes.• Numerous processes have been developed for gas sweetening based on a variety

of chemical and physical principles. • These processes can be categorized by the principles used in the process to

separate the acid gas and the natural gases as follows:

(a) Solid Bed Absorption(b) Chemical Solvents(c) Physical Solvents(d) Direct Conversion of H2S to Sulfur(e) Sulfide Scavenger(f) Distillation(g) Gas Permeation

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(a) Solid Bed Absorption• A fixed bed of solid particles can be used to remove acid gases

either through chemical reactions or ionic bonding. • Typically, in solid bed absorption processes the gas stream

must flow through a fixed bed of solid particles that remove the acid gases and hold them in the bed. •When the bed is saturated with acid gases, the vessel must be

removed from service and the bed regenerated or replaced. • There are three commonly used processes under this category:

(a) Iron oxide process (b) Zinc oxide process(c) Molecular sieve process,

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(b) Chemical Solvents• Chemical solvent processes use an aqueous solution of a weak base

to chemically react with and absorb the acid gases in the natural gas stream.• The absorption occurs as a result of the driving force of the partial

pressure from the gas to the liquid. • The reactions involved are reversible by changing the system

temperature or pressure, or both. • The majority of chemical solvent processes use either an amine or

carbonate solution.

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(c) Physical Solvents• These processes are based on the solubility of the H2S and CO2

within the solvent.• Various organic solvents are used to absorb the acid gases. • Physical solvent processes have a high affinity for heavy

hydrocarbons. • If a stream is rich in C3+ hydrocarbons, the use of physical solvent

process may result in a significant loss of heavier molecular weight hydrocarbons. • These hydrocarbons are lost because they are released from the

solvent with the acid gases and cannot be economically recovered.

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(c) Physical Solvents [con’t]• Under the following circumstances physical solvent processes

should be considered for gas sweetening:(a) The partial pressure of the acid gases in the feed is 50 psi or

higher.(b) The concentration of heavy hydrocarbons in the feed is low. (the

gas stream is lean in propane-plus)(c) Only bulk removal of acid gases is required.(d) Selective H2S removal is required.• A physical solvent process is shown in Figure 7-6

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(d) Direct Conversion of H2S to Sulfur• The chemical and solvent processes previously discussed remove acid gases

from the gas stream but result in a release of H2S and CO2 when the solvent is regenerated. • The release of H2S to the atmosphere is limited by environmental regulations. • The acid gases could be routed to an incinerator or flare (H2S converted to

SO2)• Direct conversion processes use chemical reactions to oxidize H2S and produce

elemental sulfur. • These processes are generally based either on the reaction of H2S and O2 or

H2S and SO2. Both reactions yield water and elemental sulfur. • Where large flow rates are encountered, it is more common to contact the

produced gas stream with a chemical or physical solvent and use a direct conversion process on the acid gas liberated in the regeneration step.

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(e) Sulfide Scavengers• Sour gas sweetening may also be carried out continuously in the flowline by

continuous injection of H2S scavengers.• The most common H2S scavenger used are the amine-aldehyde condensates. • Contact time between the scavenger and the sour gas is the most critical

factor in the design of the scavenger treatment process.• The amine-aldehyde condensates process is best suited for wet gas streams of

0.5-15 MMscfd containing less than 100 ppm H2S. • The advantages of amine aldehyde condensates are water soluble reaction

products, lower operating temperatures, low corrosiveness to steel, and no reactivity with hydrocarbons.

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(f) Distillation• The Ryan-Holmes distillation process uses cryogenic

distillation to remove acid gases from a gas stream. • This process is applied to remove CO2 for LPG separation or

where it is desired to produce CO2 at high pressure for reservoir injection.• This complicated process is beyond the scope of this

module.

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(g) Gas Permeation• Gas permeation is based on the mass transfer principles of gas

diffusion through a permeable membrane.• In its most basic form, a membrane separation system consists of a

vessel divided by a single flat membrane into a high- and a low-pressure section.• Feed entering the high-pressure side selectively loses the fast-

permeating components to the low-pressure side.• The driving force for the separation is differential pressure. CO2 tends

to diffuse quickly through membranes and thus can be removed from the bulk gas stream. • It is difficult to remove H2S to pipeline quality with a membrane

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(g) Gas Permeation [con’t]•Membrane systems have effectively been used as a first step to

remove the CO2 and most of the H2S. (iron sponge or other H2S treating process is then used to remove the remainder of the H2S)•Membranes will also remove some of the water vapor. Depending

upon the stream properties, a membrane designed to treat CO2 to pipeline specifications may also reduce water vapor to less than 7 Ib/MMscf.• Often, however, it is necessary to dehydrate the gas downstream of

the membrane to attain final pipeline water vapor requirements.

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Process Selection• Each of the previous treating processes has advantages relative to the others

for certain applications; therefore, in selection of the appropriate process, the following facts should be considered:

(a) The type of acid contaminants present in the gas stream.(b) The concentrations of each contaminant and degree of removal desired.(c) The volume of gas to be treated and temperature and pressure at which

the gas is available.(d) The feasibility of recovering sulfur.(e) The desirability of selectively removing one or more of the contaminants

without removing the others.(f) The presence and amount of heavy hydrocarbons and aromatics in the gas.

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Gas Dehydration• Gas dehydration is the process of removing water vapor from a gas stream to

lower the temperature at which water will condense from the stream. • This temperature is called the "dew point" of the gas. • Dehydration to dew points below the temperature to which the gas will be

subjected will prevent hydrate formation and corrosion from condensed water. • This chapter discusses the design of liquid glycol and solid bed dehydration

systems that are the most common methods of dehydration used for natural gas.• In producing operations gas is most often dehydrated by contact with

triethylene glycol. • Solid bed adsorption units are used where very low dew points are required,

such as on the inlet stream to a cryogenic gas plant where water contents of less than 0.05 Ib/MMscf may be necessary)

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Glycol Dehydration• By far the most common process for dehydrating natural gas is to

contact the gas with a hygroscopic liquid such as one of the glycols.• This is an absorption process, where the water vapor in the gas

stream becomes dissolved in a relatively pure glycol liquid solvent stream. • Glycol dehydration is relatively inexpensive, as the water can be

easily "boiled" out of the glycol by the addition of heat. • This step is called "regeneration" or "reconcentration" and enables

the glycol to be recovered for reuse inabsorbing additional water with minimal loss of glycol.

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Glycol Dehydration [con’t]• Figure 16 shows a typical trayed contactor in which

the gas and liquid are in counter-current flow. • The wet gas enters the bottom of the contactor and

contacts the "richest" glycol (glycol containing water in solution) just before the glycol leaves the column. • The gas encounters leaner and leaner glycol (that is,

giycol containing less and less water in solution),as it rises through the contactor. • At each successive tray the leaner glycol is able to

absorb additional amounts of water vapor from the gas. • The counter-current flow in the contactor makes it

possible for the gas to transfer a significant amount of water to the glycol and still approach equilibrium with the leanest glycol concentration.Internal

Figure 16. Typical glycol contactor in which gas and liquid are in counter-current flow.

Gas Processing• The term "gas processing" is used to refer to the removing of ethane,

propane, butane, and heavier components from a gas stream. • They may be fractionated and sold as "pure" components, or they

may be combined and sold as a natural gas liquids mix, or NGL.• The first step in a gas processing plant is to separate the components

that are to be recovered from the gas into an NGL stream. • It may then be desirable to fractionate the NGL stream into various

liquefied petroleum gas (LPG) components of ethane, propane, iso-butane, or normal-butane.• NGL is made up principally of pentanes and heavier hydrocarbons

although it may contain some butanes and very small amounts of propane.

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Gas Processing [con’t]• Gas Processing Plants are installed because it is more economical to extract

and sell the liquid products even though this lowers the heating value of gas.• The value of the increased volume of liquids sales may be significantly higher

than the loss in gas sales revenue because of a decrease in heating value of the gas.• Another objective of gas processing is to lower the Btu content of the gas by

extracting heavier components to meet a maximum allowable heating limit set by a gas sales contract. • The three basic method used to separate LPG and NGL liquids from the gas

and to fractionate them into their various components are :a) Absorption / Lean Oil Plantb) Refrigeration Plantc) Cryogenic Plant

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Choice of ProcessType of Process Absorption/Lean Oil Refrigeration Cryogenic Plant

Liquid Recovery C3 ≈ 80%C4 ≈ 90%C5+ ≈ 98%

C3 ≈ 85%C4 ≈ 94%C5+ ≈ 98%

C2 > 60%C3 > 90%C4+ ≈ 100%

Ease of Operation Hard to Operate Moderate Ease Simple to operate

Cost Expensive Reasonable Expensive

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Thank You

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Q & A Session

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