Natural Gas: Operations and Transport: A Handbook for Students of the Natural Gas Industry

By Harald Osel

 Natural Gas: Operations and Transport is the second volume in a series of textbooks following Natural Gas: Exploration and Properties (first volume). This series is continued with Natural Gas: Customers and Consuming Industries (third volume) and Natural Gas: Economics and Environment (fourth volume). Th

• Language: English
• Publisher: Aurora House
• Release date: Jan 3, 2017
• ISBN: 9780994634238

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8

Chemical Gas Composition

This Volume 2 continues with Chapter 8, while Chapters 1–7 were referred to already in Volume 1, which focused on natural gas extraction.

Following successful well testing and fluid sampling (see Volume 1, Chapter7) field development activities could commence, which target bringing the reservoir on stream and to produce from its wells. The fluid mixture produced consists primarily of three types of reservoir fluids: oil, gas and water. Depending on whether it is a gas- or oil reservoir determines the degree of gas or hydrocarbon fluids present in the fluid-mix. The amount of water present in the fluidmix depends on the presence of an aquifer below the reservoir and the stage of production.

The hydrocarbon fluid mix (excluding water) occurring naturally in the reservoir is also referred to as petroleum. (Petroleum is a term used mainly to refer to hydrocarbon fluids. Occasionally non-hydrocarbon contaminants such as nitrogen, carbon dioxide and hydrogen sulfide – produced together with oil and gas – are included in the definition of petroleum.) Some organizations – such as the Measurement Coordination Department of API – otherwise prefer to use the term petroleum only in connection with crude oil and refined petroleum products. Knowledge of the exact composition of petroleum and the composition of the reservoir fluids produced from the reservoir (including all impurities) is of great significance, not only for marketing purposes but also for the design of the production facilities.

The emphasis in this section is on describing the reservoir fluid composition in connection with gas reservoirs, which includes raw gas produced from the reservoir, as well as gas contaminants.

8.1.

Gas Composition: Determination

By analyzing the fluid sample – retrieved during formation testing – data concerning the composition of reservoir fluids could be gained. The instrument most commonly used for the quantitative evaluation of the individual components of raw gas is the gas chromatograph.

The hydrocarbon gases contained within raw natural gas are mainly methane (C1), ethane (C2), propane (C3) and butane (C4), while pentane (C5) or higher alkanes (C5+) are often present as well. These hydrocarbons belong to the chemical group of the alkanes, which are also known as paraffins or paraffinic hydrocarbons.

The impurities contained in raw gas are otherwise mainly carbon dioxide (CO2), hydrogen sulfide (H2S) and nitrogen (N) although traces of other substances could as well be present.

Hydrogen atoms (H) are present in most of the chemical compounds prevailing in a gas reservoir, while free hydrogen is otherwise never present as a constituent of raw gas.

8.1.1.

Hydrocarbon Gases: Alkanes

Hydrocarbons are chemical compounds of organic origin with a varying molecular structure and consist of the two elements: carbon, C, and hydrogen, H. Hydrocarbons with a low molecular weight, which corresponds to a low number of carbon atoms (e.g. C1, C2, C3 or C4) and a short molecular chain, are hydrocarbon gases. Paraffinic hydrocarbons with a very high molecular weight are solids, while liquid hydrocarbons form in a range between C5+ and ~C25.

Hydrocarbon gases occurring naturally in a reservoir belong to the group of the paraffinic hydrocarbons also known as alkanes. These hydrocarbons exhibit some inertia to react with other substances, which translates in Latin to parum affinis or insufficiently reactive. Alkanes are often referred to synonymously as paraffins. Occasionally, highly viscous hydrocarbon solids (~C30) are called paraffin as well, but should be referred to as paraffin wax.

The classification of a substance as an alkane is highlighted by the suffix -ane, whereas the first part of an alkane’s name comes from classic Greek language (e.g. penta = 5). The chemical characteristic of an alkane is based on the general formula: CnH2n+2.

Hydrocarbon gases could consequently be described as:

C1H4 … methane

C2H6 … ethane

C3H8 … propane

C4H10 … butane

C5H12 … pentane

For easier reference, acronyms are often used to refer to hydrocarbon gases, i.e.:

C1 … methane

C2 … ethane

C3 … propane

C4 … butane

C5 … pentane

C5+ … pentane and alkanes with longer hydrocarbon chains

The number of carbon atoms determines the length of the hydrocarbon chain. Higher hydrocarbons are those with longer chains and more carbon atoms.

C1, C2 and C3 all have one straight chain of carbon atoms (linear alkanes) around which the H-atoms are grouped. C4 could have, in addition to a straight chain (called n-butane), a differently grouped carbon chain with one carbon atom on top, in which case it is referred to as isobutene. C5, pentane, exhibiting one additional carbon atom appears in three different groupings around the carbon chain, which are n-pentane, ­isopentane and neopentane. The differences between these types of pentane could be visualized in the molecular diagram of the carbon chains below.

The carbon chain consist in all cases of five carbon atoms (C5) around which the twelve hydrocarbon atoms are arranged via a bond (− or l) with carbon. Even though the molecular structure appears quite differently, the chemical formula is in all cases the same, i.e.: C5H12.

The different groupings of a substance with the same chemical formula are referred to as isomers. With an increase in the number of carbon atoms – i.e. with increasing molecular weight – the number of isomers increases exponentially.

According to the nomenclature used by the International Union of Pure and Applied Chemistry (IUPAC), the n-pentane isomer is simply referred to as pentane while isopentane is known as 2-methylbutan and neopentane as 2,2-dimethylpropane. When opting for this nomenclature, additional information on the length of the main carbon chain (with C4 being butane and C3 propane) as well as the number of methyl groups, could further be provided. (A methyl group consists of one carbon atom, which is bonded to three H-atoms, i.e.: −CH3.)

The following ball-and-stick models could provide a more detailed understanding of the actual molecular model, with respect to the C5-isomers referred to in the molecular diagram above. In the case of n-pentane (also normal pentane or unbranched pentane), the model could be visualized as below, while black balls refer to carbon- and white balls to hydrogen atoms.

(Source: Ben Mills and Jynto)

The following ball-and-stick models refer to isopentane (below left) and neopentane (below right).

(Source: Ben Mills)

Although the chemical formula and molecular weight of each isomer of the same alkane (e.g. C5) is identical they otherwise differ with respect to properties, such as boiling- or critical points, densities, heating values, octane numbers etc. (The boiling point of n-­pentane, for example, is 36.1°C whereas it is 27.7°C for isopentane and 9.5°C for neopentane.)

Isomers occur naturally but not in sufficient quantities to satisfy demand. In petroleum refining isomerization processes – involving thermal cracking at temperatures of about 100−200°C are carried out with the support of a usually platinum-based catalysts to change the grouping of the alkane’s atoms. Isomerization typically aims at achieving a transformation from straight-chain to branch-chain hydrocarbons (e.g. from n-pentane to isopentane). Isomerization targets especially at increasing octane numbers to improve fuel quality.

Traces of hydrocarbons with a molecular chain consisting of more than five carbon atoms – such as hexane, C6H14, heptane, C7H16 and C8+ alkanes are regularly present in raw gas. Together with pentane (C5), these alkanes are often referred to as C5+ or condensate.

The name condensate indicates that a phase change takes place from a vapor phase – at pressure and temperature conditions in the reservoir – to the liquid phase, when C5+ condenses out as liquid on surface. (Under special circumstances associated with retrograde condensation, liquid C5+ could condense out already in the reservoir at conditions below the dew point.)

When handled on surface, condensate (C5+) is also called natural gas liquid, NGL. It needs though to be kept in mind that the notion of NGL refers as well to liquefied C3 and C4, which is known as liquefied petroleum gas or LPG. Occasionally, reference is made to NGL not only with respect to condensate (C5+) and LPG (C3, C4) but in connection with liquefied ethane (C2). Ethane (and occasionally also C3 and C4) usually forms part of natural gas when in a vapor state and part of NGL when liquefied. Small quantities of ethane could also be present in liquefied natural gas, LNG.

Propane (C3) and butane (C4) – once separated on surface from raw gas – could be liquefied under pressure and kept as LPG (liquefied petroleum gas) in pressurized holding tanks (e.g. bottled gas). The following image shows such a (butane) gas bottle.

The amount of C3 and C4 in LPG varies from consisting exclusively of C3 or C4 to comprising a mixture of both. For industrial applications, LGP could be stored on site in much larger containments than LPG bottles, such as spherical containers.

The main constituent of raw, natural gas – when produced from a gas reservoir – is methane (C1), while fractions of C2, C3, C4 and C5+ form part of it as well. Raw gas from a dry gas reservoir mainly consists of methane, while wet gas contains a much larger portion of C2 to C5 components. Impurities of non-hydrocarbon origin form further part of the raw, natural gas flowing from the reservoir to surface. The sum of all these individual components determines the gas composition. Following processing in a gas treatment plant, natural gas can be shipped via a transmission pipeline over large distances. During gas treatment C2 to C5 components get largely removed, while the remaining pipeline natural gas consists mainly of methane.

The following diagram provides an overview of the different categories associated with natural gas.

The composition of raw gas produced from a well serves as basis for differentiating associated gas, wet gas and dry gas.

Tab.1 (below) further provides an idea of the composition of raw gas produced from a reservoir (excluding gas contaminants)¹.

Contaminants present in raw gas have not been included in the figures in Tab.1, which represent an estimate of 100% of all hydrocarbon reservoir fluids remaining after gas treatment. Contaminants – especially carbon dioxide (CO2), nitrogen (N2) or hydrogen sulfide (H2S) – need to be considered forming part of most reservoir fluids.

Pure gas reservoirs exhibit a tendency to hold a higher amount of contaminants than reservoirs holding gas associated with liquids, e.g. in an oil reservoir. Oil reservoirs could be classified in connection with the API-gravity of the crude oil contained within. Heavy, black oil reservoirs usually contain less contaminants, but also less methane. A light hydrocarbon gas such as methane is a constituent of the associated gas (produced together with oil) and is in higher concentrations present in the fluids of light, rather than heavy, oil reservoirs. A relatively low content of methane in the associated gas (e.g. ~30%) consequently corresponds to a heavy oil reservoir, while for gas associated with light crude production the methane fraction could be up to 70%. (This is especially valid in case of a reservoir containing crude oil at near-critical conditions.)

The notion of associated gas was used above to refer to gas produced in tandem with oil. This terminology is common industry praxis, although it is not entirely accurate. More precisely, a further distinction could be made between associated free gas and casinghead gas.

Associated free gas is gas originating from the gas cap and is produced only at the end of field life.

Casinghead gas (or dissolved gas) is gas coming out of solution with oil in the reservoir once reservoir pressure has dropped below the bubble point after an initial production period. With a view to the pattern for gas composition (as in Tab.1), associated free gas could be considered being a dry to wet gas, whereas the composition of casinghead gas should correspond to that of associated gas in Tab.1.

Gas produced from a gas reservoir is referred to as non-associated gas. Reference to low- and high-pressure, non-associated gas roughly coincides with the wet- and dry gas categories, as introduced earlier. Since wet gas tends to be found in shallower, less pressurized horizons it is regarded to be low pressure gas, whereas dry gas, found in deeper horizons, is regularly exposed to higher pressures and is consequently referred to as a high pressure gas. As can be seen from Tab.1, non-associated gas mainly consists of methane, C1, whereas associated gas exhibits a much higher percentage of C2 to C5+ fractions.

It needs to be kept in mind that reservoir fluids change in composition in tandem with the degree of depletion of the reservoir. This is not so much the case for a dry gas reservoir but remains valid for condensate- and oil reservoirs (especially those with a solution gas- or gas cap drive).

Hydrocarbon gases produced from a gas reservoir are generally paraffins, which are also called alkanes. Non-associated gas reservoirs – especially in case of thermogenic gas – occasionally hold not only straight-chained paraffinic hydrocarbons but also small quantities of ring structured cycloparaffins or traces of aromatic hydrocarbons.

8.1.2.

Non-Hydrocarbon Gases: Natural Gas Contaminants

In addition to paraffinic, hydrocarbon gases, which are the main constituents of natural gas, non-hydrocarbon gases are also present in raw gas. These gases could be classified as diluentsor contaminants and are together referred to as impurities. Non-combustible gases such as carbon dioxide (CO2), nitrogen (N2) or steam (H2O-vapor) could be identified as diluents. Gases containing sulfur compounds (which are combustible) – especially hydrogen sulfide (H2S) – could otherwise be referred to as contaminants. The difference between diluents and contaminants is not generally drawn, while these types of non-hydrocarbon gases are often simply referred to as impurities or contaminants of raw gas.

In addition to these impurities (CO2, H2S, N2), noble gases such as helium or argon could also be present in raw gas. Water vapor forms another part of the raw gas produced, which adds to the requirements for gas treatment.

H2S could be present in the reservoir fluids as well – often together with CO2 – but appears rarely in concentrations of more than 10%. Nitrogen- and CO2 components (without H2S) are in comparison found in raw gas more often. Raw gas containing e.g. 2.5% nitrogen and 5% CO2 could be considered a standard case. In exceptional cases, nitrogen concentrations could be as high as 25% (e.g. in the Uch field in Pakistan) or CO2 concentrations as high as 70% (such as in the Natuna field offshore Indonesia). The absence of impurities, or their presence in very low concentrations, should be considered to be an exceptional case.

Raw gas produced from natural gas reservoirs corresponds to a wide range of gas compositions. The Groningen field (offshore the Netherlands) produces for example gas with a nitrogen content of about 15%. Kapuni in New Zealand has otherwise produced gas with roughly 45% CO2. Gas from Lacq – a naturally fractured reservoir near Pau in southwest France – has consisted of 15% H2S. Reservoir fluids from Lac could further serve as an example for all major contaminants – nitrogen (1.5%), hydrogen sulfide (15%) and carbon dioxide (9%) – being present.² Gas from the Uch field otherwise contains 46% CO2as well as 25% nitrogen and only 27% methane.

A more recent example could be provided with ADNOC’s announcement in 2010 to go ahead with the development of the Shah sour gas project by appointing the US company Flour Daniel as the project management services contractor (PMSC), since Flour has already carried out the FEED for this project. The Shah Gas Field is located onshore (about 180 km southwest of Abu Dhabi) and contains about 30% H2S. Following gas treatment the natural gas produced from Shah is destined for shipment to the local grid. After its completion in 2014 Shah is producing about 1 BCF per day of raw gas, from which roughly 530 MMCF of natural gas and 10,000 tonnes of sulfur could be gained. Sulfur granulation plants have been designed to form part of the Shah-gas project, including a railway link for transporting sulfur to the port of Ruwais. The entire Shah sour gas development was reported to require an investment of about 10 billion US Dollars. Following the withdrawal of ConocoPhillips from this project, Occidential Petroleum (OXY) signed a partnership agreement in 2011 with ADNOC (Abu Dhabi National Oil Company) for the development of this field.

Raw gas containing sulfur H2S is known as sour gas. (It should be noted that H2S could be produced together with the associated gas of an oil reservoir.) Sweet gas – in contrast to sour gas – contains no H2S but might still contain CO2.

H2S and CO2 are also called acid gases. Hydrogen sulfide (H2S) and carbon dioxide (CO2) are both acid gases since they form an acid (sulfuric- and carbonic acid, respectively) in the presence of water. Acid gases are toxic (especially H2S), damaging to the environment, highly corrosive and of little economic value. The materials used when handling acid gases are usually coated steel pipes, while inhibitors remain to be injected into the flowing gas. Alternatively, fiberglass-reinforced pipe could be used instead of coated steel pipe. In a more difficult high temperature and pressure environment with high levels of sour gas, special corrosion resistant alloys (CRA) could be employed.³

8.1.2.1.

Water Vapor (H2O)

The chemical component most commonly present in the raw gas (other than hydrocarbon gases) is water vapor. H2O-vapor is produced from almost every reservoir although at varying levels of concentration. Due to its widespread occurrence, H2O is usually not considered to be a gas contaminant but rather a constituent part of most reservoir fluids. The presence of water requires a treatment process that achieves the separation of oil, gas and water. H2O remains an unwanted byproduct of oil and gas production since H2Onot only creates corrosion problems (especially in the presence of H2S or CO2), but is also pivotal for the formation of gas hydrates (see section 2.3.3).

Water produced from a reservoir is usually brine, which contains salt. On the surface, in the presence of oxygen, salt creates serious corrosion problems to steel pipes. At present, no efficient inhibitors are available to reduce fluid salinity. Diluting salt levels by adding fresh water to brine otherwise remains possible. Corrosion problems due to the salinity of water could originate as well from the use of seawater during water injection into an offshore reservoir (for pressure maintenance). These corrosion problems could be mitigated by removing oxygen from the water. Prior to water-injection, seawater can be shipped to a vacuum tower where oxygen could come out of solution with water at vacuum conditions (created by a vacuum pump).

Droplets of water condensing out of the gas stream could create severe damage to machinery and facilities. The blades of a gas turbine for example, when hit by water droplets, would suffer severe damage that could be costly to repair.

In addition, H2O has no heating value, while its presence decreases the market value of natural gas. Dehydration (see section 9.3.2.1.) needs consequently to form part of gas treatment that leads to an acceptably low water dew-point of the processed natural gas.

8.1.2.2.

Sulfur Components – Hydrogen sulfide (H2S)

Hydrogen sulfide, H2S, is a highly poisonous gas with a molecular mass of 34 (kg/kmol) and a boiling point of (minus) −60°C. The molecular mass (i.e. the mass of one molecule) of air (at standard conditions) is in comparison 29 (kg/kmol). H2S is consequently heavier than air, which causes it to remain on the ground when released to the atmosphere. In high concentrations, a H2S-air mix further creates an explosive mixture. H2S has otherwise a heating value (GHV) of 672 BTU per SCF while the gross heating value of hydrogen alone is 325 BTU per SCF. In the presence of oxygen, hydrogen sulfide burns with a blue flame.

The combustion of H2S further produces sulfuric oxides, SOx (essentially SO2). Sulfur dioxide, SO2, is a substance that is highly damaging when released to the environment, although it could be used during the manufacture of gypsum.

Sulfuric oxides remain to be toxic, but to a considerably lower degree than hydrogen sulfide. Combusting H2S in the presence of oxygen yields:

2 H2S + 3 O2 → 2 SO2 + 2 H2O

H2S-combustion (as above) is an oxidation reaction that also forms part of a Claus ­process, which converts H2S to sulfur, S.

Raw gas containing H2S and other sulfur components is also referred to as sour gas. Thermogenic gas (which is usually found in deeper, high-temperature horizons) shows a higher tendency towards H2S-formation than biogenic gas. Gas containing H2S consists in most cases of carbon dioxide (CO2) as well.

The primary constituent of sour gas is H2S, which is a highly poisonous and potentially corrosive substance. The handling of H2S during gas production causes additional investment costs associated with H2S treatment facilities. H2S detectors need to be installed during exploration drilling, as well as during the subsequent field development and gas production. These detectors prevent the environment from H2S leaks remaining unnoticed.

Another sour gas component that could be present in raw gas is carbonyl sulfide (COS), which needs to be removed via an absorption process using an appropriate solvent. Other sulfur components such as carbonyl disulfide (CS2) or thiophene (C4H4S) could further be present in raw gas.

Most sour gases contain mercaptans– especially methyl mercaptan or methanethiol (CH3SH). They are typically removed by applying the same processes as used for gas sweetening in general (see section 9.3.3.).

Sulfides, mercaptans or sulfuric acids, could be removed by bringing these substances into contact with sodium hydroxide, NaOH (caustic soda), creating a solution containing these sulfuric substances. By passing that solution through a caustic treater – a vessel holding caustic soda (or other alkalis) – sulfur removal could be achieved.

It might be worthwhile to note that sour gas produced on surface could not only contain sulfuric substances but also elemental sulfur (S). Although pure, elemental sulfur is not present in the reservoir, it could form during gas production and treatment through the oxidation of H2S, i.e.:

H2S + ½ O2 → H2O + S

At ambient conditions, this reaction (also occurring during volcanic eruptions) is relatively slow but could be enhanced by providing a high-temperature environment and the use of an appropriate catalyst. Iron, and nickel, as well as triethylene glycol (TEG) could be employed here as catalysts. (When using TEG for dehydration in uncoated iron pipes an oxidation reaction with H2S would consequently be enhanced.)

The presence of pyrite, FeS2, could also contribute to the formation of elemental sulfur by causing hydrogen sulfide to disassociate. This disassociation

H2S → H2 + S

is based on a catalytic reaction with pyrite.

Catalytically enhanced oxidation of H2S forms the starting point of the Claus process, which produces elemental sulfur from H2S. The first step of this process involves an oxidation reaction in the presence of H2S, producing sulfur dioxide, SO2, and water-vapor since

2 H2S + 3 O2 → 2 SO2 + 2 H2O

Elemental sulfur, S, is produced in a further reaction of H2S with sulfur dioxide, SO2, i.e.:

2 H2S + SO2 → 3 S + 2 H2O

When using a Claus process hydrogen sulfide, H2S could ultimately be chemically transformed into relatively harmless substances, in particular, water-vapor and sulfur.

The threat H2S constitutes to the human body can be linked to the H2S-concentration.⁴ Up to a concentration of 10 ppm, no toxic effects should be noticed by the human body. At relatively low concentrations of H2S in the order of >10−150 ppm, a first reaction such as burning and irritated eyes occurs. When exposed to higher concentrations of up to 300 ppm for a time span of less than 30 minutes, negative health effects remain to be reversible. At concentrations of >300−500 ppm of H2S in air – ­corresponding to >0.03−0.05% of air volume – H2S starts to create an imminent health risk. Exposure to H2S-levels of 800−1000 ppm for about 30 minutes could be fatal, while higher concentrations lead to instant death.

In lower concentrations, H2S smells like rotten eggs due to its sulfur content. At about 100−200 ppm the ability to smell H2S ceases, which allows for H2S to remain undetected by the human body. That inability to smell H2S in tandem with the characteristic of H2S to be heavier than air (causing H2S to remain on the ground) add to the dangers associated with the presence of hydrogen sulfide in raw gas. In order to prevent H2S-related accidents, H2S monitoring facilities and detectors need to be installed.⁵ (It needs to be kept in mind that H2S detectors could produce a false alarm when exposed to moisture, H2O.)

A special source of H2S is the decomposition of petroleum in the reservoir, caused by bacteria introduced to the reservoir via the well bore by drilling mud or injection fluids. In combination with sulfate reducing bacteria (respectively bacteria-forming slime that is rich in oxygen) H2S corrosion problems could be created in addition.

During earlier stages of the gas industry, H2S (and other sulfur components of raw gas) have simply been combusted and released to the atmosphere in form of sulfur oxides, SOx. The flaring of H2S, nevertheless, creates substantial environmental problems. This environmental burden could be reduced by converting H2S instead to sulfur (on the basis of a Claus process). Sulfur extraction units – including tail-gas treatment and clean up facilities – have been designed for the removal of sulfur from H2S. That additional investment into sulfur extraction facilities needs to be further evaluated vis-à-vis revenues generated from sulfur sales. Especially in case of raw gas with a low H2S-content, the construction of sulfur extraction units needs to be justifiable on environmental grounds although it could not be economic.

In addition, H2S and other sulfuric components of sour gas create metal corrosion by forming an acidic solution in the presence of water. (When comparing oil and water, H2S goes into solution with water at a much lower rate than it into a solution with oil.) The corrosion product of ferrous metals resulting from an acidic solution of H2S with water is, FeS, iron sulfide. The presence of oxygen further aggravates H2S corrosion, since oxidation of H2S ultimately produces water and elemental sulfur. Water wet sulfur subsequently causes severe corrosion problems to steel.

Sour gases rich in H2S create a great potential for causing sulfide stress cracking (SSC). SSC is a source of material failure due to fracturing, which could occur below the yield strength of the metal. It could be noted that the cracking of the material is actually caused by the hydrogen atoms of H2S. Consequently, SSC needs to be considered as a specific case of hydrogen stress cracking, HSC (also known as hydrogen embrittlement). SSC and HSC could occur at an internal location of the metal. Stress corrosion cracking (SCC) commences with metal fracturing on surface. Normal corrosion processes need an extended period of exposure to cause material failure. Sulfide stress cracking (SSC) is a form of corrosion where material failure could occur within a short period of a few hours, or even minutes.

H2S, when transported in carbon steel pipelines, reacts with the steel and forms iron sulfide (FeS), creating a FeS-film that coats the line. In fact, the formation of FeS forms part of the corrosion process of iron and steel in the presence of H2S. FeS-formation further continues until a critical thickness is reached at which the FeS-film starts cracking again, and loses its bond with the pipeline wall. Inhibitors can be used to support the formation of a stable FeS-film, which remains attached to the metal surface. These inhibitors are imidazolines such as carboxyethylimidazoline,⁶ while the inhibition effect is based on the adsorption properties of the inhibitor. Imidazolines and their salts are nitrogen-based organic inhibitors that could be employed in an H2S-CO2 environment. These organic inhibitors could also be employed instead of arsenic inhibitors when using hydrochloric acid for the acidizing of wells in the presence of H2S.

Another potential source of material failure in the presence of H2S could be the acidizing of wells, which involves the pumping of acids down the wellbore. Acidizing typically aims at improving flow by removing skin and cleaning up the well. When hydrochloric (HCl) acid or a combination of HCl and hydrofluoric (HFl) acid are used for this purpose, acetylenic alcohols need to be inhibited simultaneously to prevent creating corrosion problems. Acidizing in tandem with inhibition could be carried out only over a relatively short period, otherwise material failure due to corrosion should be expected. In the presence of H2S, corrosion rates are drastically increased when acidizing with HCl. Interestingly enough even high quality, corrosion resistant alloys (CRAs) react in such an environment rather sensitive to acidizing with HCl. Consequently, special inhibitors for HCl-acidizing through CRA-tubular needs to be brought into service. Alternatively, organic acids could be employed instead of HCl. Another option could be using an expandable work-string that runs within CRA-tubular in order to protect the tubular from chloride SCC.

During the exploration phase and in order to prevent H2S from entering the wellbore, sour-gas wells have often been drilled overbalanced (to protect the drillstring from exposure to H2S), even though this procedure could create skin. Using pipe for the drillstring, consisting of grade E-75 or X-95, could further reduce the risk of material failure due to H2S-exposure. The use of OBM (oil-based mud) could contribute to controlling corrosion in an H2S environment.

Once sour gas is produced, following successful exploration and field development, sour components inevitably enter the wellbore when flowing up the tubing to surface, together with raw gas. During production operations, H2S could further come in touch with casing through the annulus. As a result steel pipes used in a sour gas environment need to be SSC-resistant. During manufacturing this type of pipe has to undergo quenching, in order to achieve a high degree of martensite, and needs to be tempered to the highest possible temperature at which mechanical strength could still be maintained. Medium to high-pressure sour gas production requires high quality alloys (such as chromium-molybdenum steel alloys) to be used, which corresponds to pipe of grade C-90 or T-95. (For sour-oil production in a relatively low-pressure environment, pipe of Grade J-55, K-55 or L-80 might be sufficient.) The same high quality alloys have to be used for all flow lines leading to the sour gas removal facility and should provide resistance against corrosion (including SCC and SSC), as well as pitting by chlorides. Plastic coating of the interior pipe could further be considered to avoid exposing uncoated steel alloys to sour gas flow (while injecting inhibitors simultaneously). At moderate operating conditions (with respect to temperature and pressure) fiberglass pipe could be of great use when handling sour gas. It needs though to be considered that at high temperature (=190°C) and pressure – in tandem with high H2S-concentrations – only special alloys provide an acceptable degree of corrosion resistance. These corrosion resistant alloys (CRA) consist of metals such as chromium, nickel or molybdenum and could be associated with stainless steels, titanium alloys or nickel-based alloys, while cobalt-based alloys are used as well.

An effective method of transporting H2S-contaminated fluids is shipping them through a concentric pipeline (or pipe-in-pipe), as shown in the following illustration:

In the annulus of this line, nitrogen flows with a high pressure P1 while the H2S contaminated fluid flows through the center of the line with a lower pressure P2. In case of leakage of the inner line, nitrogen (kept under high pressure in the annulus) prevents H2S from being released from the inner line. When transporting H2S contaminated fluids offshore, these fluids are regularly shipped in concentric lines (especially in the North Sea).

8.1.2.3.

Carbon dioxide (CO2)

Carbon dioxide, CO2 or O=C=O, is a gas that is heavier than air, with a molecular weight of 44 (kg/kmol) corresponding to one mole of CO2 = 44.0 g (CO2 = 12 g + 32 g = 44 g). Carbon dioxide has no boiling point asCO2 could not be liquefied at any temperature, given atmospheric pressure. CO2sublimes instead at −78.5°C (i.e. it transits directly from solid to gas without passing through an intermediate liquid phase). The critical point of CO2 is otherwise at 31.1°C and 73.8 bar. Below the critical temperature, CO2 could be liquefied at elevated pressures. At room temperature, a pressure of about 60 bar would be required for the liquefaction of CO2. Above the critical point, CO2 remains in a supercritical state. Supercritical fluids in general exhibit features of gases as well as liquids (such as filling a container like a gas but with the density of a liquid) and adopt ­properties of both phases. Supercritical carbon dioxide is used as an industrial solvent (e.g. for decaffeination), chemical reagent (such as for the production of hydraulic cement or various foams) or as a refrigerant (especially for domestic heat pumps). The oil industry uses supercritical carbon dioxide for enhanced oil recovery.

Oxygen, O, is part of a reservoir fluid mainly as a constituent of carbon dioxide. CO2 is a chemical compound with two oxygen atoms in a covalent bond (O=C=O) with a carbon atom. Elemental oxygen, O2 (such as in air), is otherwise no natural constituent of a reservoir fluid.

Oxygen is otherwise the most abundant element within the earth’s mass (e.g. in silica SiO2) as well as on the surface of the earth (especially in H2O) and in the atmosphere (in air and ozone). Stable, free oxygen, O, exists on the other hand only under extreme conditions in the universe (such as in its vacuum zones or stellar atmospheres). Oxygen is by mass the third most abundant element in the universe after hydrogen and helium. (The universe’s forth most abundant element is carbon, C.)

CO2 is an almost odorless gas. It is heavier than air and rests on the ground once released to the atmosphere. Small concentrations of CO2 are harmless to the human body, releasing itself with exhaled air about 4% CO2. With CO2-concentrations in air above 15%, carbon dioxide starts causing damage to the human system due to a lack of oxygen.

Carbon dioxide (CO2) has no heating value, while the heating value of carbon monoxide (CO) is 68 BTU per SCF. A heating value of zero (GHV=NHV=0) is not only attributable to CO2 but to nitrogen (N) as well. Both gases are consequently non-combustible and cannot be burned. It needs to be kept in mind that even though carbon dioxide is a non-inflammable gas, it is not chemically inert,⁷ as is the case with nitrogen.⁸ The presence of carbon dioxide (CO2) and nitrogen (N) in gas reservoirs is relatively common. Since their heating value is zero their presence in a gas reservoir reduces the calorific value of raw gas. (In certain cases CO2 might not be present in a gas reservoir right from the beginning but forms, in low quantities, during well stimulation, especially when acidizing the well.)

Carbon dioxide (as well as hydrogen sulfide) can also be damaging to the rheology of water-based mud (WBM). In case adequate mud additives could not solve this problem oil-based drilling fluids could serve as an alternative to WBM. It needs though to be considered that when drilling through gas bearing formations, water-based mud is usually preferred since a gas-kick is more difficult to detect with oil-based mud (OBM) than in the case of a water-based drilling fluid. This is especially valid once gas would go in solution with OBM and comes out of solution only at ambient pressure and temperature on surface.

Although the presence of CO2 in raw gas requires natural gas purification and CO2 removal (up to a threshold limit value of e.g. <1%), some industrial customers could purchase gas containing substantial amounts of CO2. Especially power plants using gas turbines to create shaft power could tolerate a fuel gas with a limited CO2 content (below 20%). On the other side, some processes such as the desulfurization of hydrocarbon gases could hardly tolerate the presence of CO2 because of the extraordinary heat generated in the presence of steam.

The solubility of CO2 in water is with 1700 mg/l (at standard conditions) relatively high, which makes it a suitable candidate for CO2 sequestration in an aquifer. (In comparison, the solubility of oxygen is just 9 mg/l, while it is 20 mg/l for nitrogen and 35 mg/l for methane.) When carbon dioxide dissolves in water, the resulting solution contains small quantities of carbonic acid, H2CO3. Occasionally, the solution of CO2 in water itself ­(carbonic acid solution) is referred to as carbonic acid. (The salts of this acid are the various carbonates.) Even though H2CO3 is a weak acid it remains to be a corrosive acid and its continued presence in a pipeline system – in tandem with its ability to react with other substances – requires measures to be taken (such as the inhibition of chemical agents) to prevent corrosion. In the presence of high amounts of CO2 (where inhibition alone might be insufficient) high quality steel alloys need to be used during the manufacture of tubular, and are installed in the well or as flow-lines. Chromium, Cr, steel alloys are often used to provide the material resistance required in connection with CO2-corrosion. In a sour gas environment, in the presence of H2S, chromium alloys could otherwise not offer sufficient protection against sulfide stress cracking (SSC), and other alloys have to be alternatively considered. The internal coating of lines could provide an additional level of protection. High-quality flow lines (produced from steel alloys and internally coated) create a substantial additional cost factor. Since CO2 removal close to the wellhead is often not practicable (especially offshore), high-quality flow lines need to be constructed for the shipment of CO2 contaminated gas over longer distances.

Additional costs associated with CO2-corrosion resistant flow lines and the installation of CO2-removal facilities further add to the economic burden associated with the presence of CO2 in raw gas. CO2 generates, in addition, no economic value when present in natural gas since it has no heating value. The environmental burden associated with CO2 requires further gas treatment, adding to costs linked to CO2 removal and sequestration. It needs to be