Hydrogen Sulphide

Abstract

Hydrogen sulphide (H₂S), a highly toxic and corrosive molecule, is typically found in hydrocarbon reservoirs, sewers and in the waste industry. It can be extremely problematic during drilling, production and processing. This chapter offers a synopsis of H₂S, which is sulphur in its most reduced form of all its numerous oxidation states. It delves briefly into H₂S’s history on planet earth before there was life all through to its diminishment during the latter Proterozoic era to present day. It also investigates its various forms of generation and production, and its effect and impact especially as an occupation-based hazard. Its utilisation in enhanced oil recovery (EOR) as a standalone or together with carbon dioxide (CO₂) and its role in geosequestration together with CO₂ is explored.

1. Introduction

Hydrogen sulphide (Figure 1) is a colourless, rotten egg smelling gas that poses problems in many industries and occupations, especially in oil and gas and the waste industries due to the anaerobic nature of its production. Chemically, even though H₂S is a chalcogenide (a molecule composed of hydrogen and a group 16 element) just like water, it does not have the strong hydrogen bonds of water due to the oxygen atom in water’s strong electronegativity, thus inducing the polarity in water that is missing in H₂S.

Figure 1.

H₂S molecule with white representing the two hydrogen atoms and yellow sulphur.

It usually occurs naturally in low-lying areas where there is a tendency for oxygen to be absent. The increase in exploitation of sour reservoirs [1] means that issues with H₂S will be ongoing, especially in deep carbonate reservoirs [2, 3] for the foreseeable future. It is toxic and corrosive and is immediately dangerous to life or health (IDLH) at just a 100 ppm. This therefore complicates any mix or environment H₂S is present in. Exposure to H₂S is largely occupational and not widespread, usually confined to energy sources from the subsurface such as oil and gas fields and others such as crude oil and natural gas refineries. Atmospheric H₂S usually is released through leaks from hydrocarbon field equipment including wellheads, sometimes through blowouts, and abandoned reservoirs. These reservoirs can contain sulphate-reducing bacteria (SRB), microorganisms (SRMs) or prokaryotes (SRPs). In the sewage industry, generation of H₂S could occur when the waste remains stationary for long periods of time, giving rise and conditions ripe enough for SRB, SRMs and SRPs to infest and become active. The primary function of the SRB, SRPs and SRMs is to break down (reduce) sulphur-bearing compounds into H₂S throughout the course of metabolism. Sulphur dioxide (SO₂), the subject of this book, is related to H₂S as a product through a limited combustive oxidation reaction (and more importantly as the first reaction in the two-stage Claus desulphurisation process);

$$2H_2{S}_{\left(g\right)}+3O_{2\left(g\right)}\to 2{\mathit{SO}}_{2\left(g\right)}+2H_2{O}_{\left(l\right)}$$E1

2. A brief palaeohistory

Before the first life on earth developed in the late Eoarchaean-early Paleoarchaean eras nearly 4 billion years ago (4 Ga), H₂S was present, due to an abundance of sulphur, and anoxygenic photosynthesis was occurring between H₂S and CO₂ [4]. Although the process’ time of evolution may be debated [5], oxygenic photosynthesis, aided by cyanobacteria also involving both acid gases, is believed to have commenced during the Archaean expansion of about 3.2–2.8 Ga ago (tail end of the Paleoarchaean all through to the very end of the Mesoarchaean era) [6], even though there was practically very little oxygen [7]. Some of these early life cyanobacteria, through their activities in the formation of stromatolites, can still be found in the Pilbara Craton’s Strelley pool chert [8] and Warrawoona group of fossils [9], Cervantes’ Lake Thetis [10] and Shark Bay [11], all in Western Australia. The great oxidation event (GOE), which occurred around the generally accepted ∼2.4–2.1 Ga ago (middle Siderian through all the Rhyacian period) is hypothesised to have marked the enduring presence and spread of atmospheric oxygen from the oceans through cyanobacterial activity. These cyanobacteria used water as fuel to conduct photosynthesis by oxidising it into oxygen, and this produced oxygen filled out the atmosphere so fast in a ∼ 300 million year period, threatening the very existence of the same oxygen-producing cyanobacteria. It also has been theorised that this event coincided with a substantial growth in oceanic sulphates [12]. But atmospheric anaerobiosis (life without free, molecular oxygen) shrunk and this affected the H₂S-producing cyanobacteria, driving them into low-lying spaces that were still anoxic. A focused study of the Proterozoic aeon indicates that in the periods that followed the GOE in the Paleoproterozoic era (Orosirian and Statherian), the oceans remained sulphidic, and by extension anoxic, due to production of sulphates from sulphur oxidation possibly aided by SRB, which was eventually swept out to the oceans [13]. The Mesoproterozoic era (starting 1.6 Ga ago) is remarkable for the increase in oceanic oxygen [14] and the development of multicellular eukaryotes over prokaryotes [15]. Note that prokaryotes are the basis for SRPs hence their diminution would mean a reduction in available sulphur and its other forms including H₂S. The rise of eukaryotes is also presented as evidence of the existence of atmospheric oxygen in this time period [16], even though the presence of H₂S in the atmosphere is proposed to have been responsible for the delay in eukaryotic development in this aeon [17]. Much of the atmospheric H₂S disappeared during the latter deglaciation years of the Proterozoic aeon in the Neoproterozoic era, and specifically in the early parts of the Ediacaran period. This was after the waning thaw of the Cryogenian period after both the Sturtian and Marinoan snowball earth glaciation—between ∼720 and 630 Ma ago [18]—when an influx of oxygen engulfed the atmosphere [4]. This is a little surprising considering even the GOE which essentially served as a bridge between the Archaean and Proterozoic eons and initiated multicellular life forms when free oxygen appeared in the atmosphere in voluminous amounts was not as successful in removing much of the H₂S present, and the GOE had a lot more oxygen. More perplexing still is that the GOE occurred simultaneously with the peak period in euxinic conditions, where oceans and water bodies had high H₂S content [19] and had little or no oxygen content except for at the surface [20]. In the current Phanerozoic eon, the Cambrian explosion of fossil biodiversity has been partly attributed to the cessation of euxinic oceanic conditions [21]. Mass extinctions earlier in in this eon at the tail end of the Permian period have been attributed in part to the accumulation of noxious H₂S in both the oceans and the atmosphere as well as CO₂-inducing hypercarbia [22]. An oxygen isotope study theorises that sulphates were probably lower in the early part of this Cenozoic period [23], hence lowered presence of H₂S to oxidate and/or not enough sulphates to reduce. Another study posits an oceanic sulphate fluctuation in the current period, with a 10 million year decrease starting 65 Ma ago, an increase for 10 Ma thereafter, then steady for the interval in between till the last 2 million years when it has been uniformly decreasing [24]. Present day, less than 1% of all ocean floors are covered by H₂S [25].

3. Generation

Microorganisms that reduce sulphates into H₂S (SRMs, SRPs, SRB) are found in every ecosystem on earth, from water bodies to soils and even in human and animal guts [26]. But most recent H₂S occurrence results from the production and processing of sour fluids in oil field operations. Sour fluids are defined in the oil and gas industry as any natural gas or petroleum fluids that contain more than 4 ppm of H₂S [27] at standard temperature and pressure (STP) conditions of 0°C (273.15 K) and 1 bar respectively. Whilst hydrogen sulphide (H₂S) formation/generation is complex and all processes involved are not entirely understood [28], it is known that H₂S can be formed either naturally or by industry production operations, especially during secondary and enhanced phases of recovery. A common denominator for each is the requirement of the absence of oxygen (anoxic or anaerobic conditions). As hydrocarbons also form in the absence of oxygen, then these hydrocarbon reservoirs serve as excellent media for in situ generation of H₂S. The process by which H₂S forms in reservoirs in the absence of oxygen, but in the presence of oxidising agents (oxidants) and/or nutrients together with hydrocarbons, is referred to as reservoir souring. Marriott et al. [29] explained three mechanisms for the generation of H₂S in the petroleum industries. These are through the breakdown of reservoir biomass or aquathermolysis, the breakdown and reduction of sulphate-bearing minerals through microbes, microbial sulphate reduction (MSR), and also through heat, or thermochemical sulphate reduction (TSR). They further stress that some operations in the oil and gas industry can affect H₂S production either by contributing towards its increased production or delaying its emergence. For instance, sea water injected into reservoirs to enhance recovery has also been shown to introduce microbes and initiate H₂S generation. Higher rates of H₂S generation result when cold sea water is pumped into oil zone but lower rates when cold water is injected near the water zone below oil zone [30]. This H₂S generation has been attributed to large quantities of sulphate being imparted by the sea water which is then worked on and reduced by SRPs in the reservoir [31]. These electron donor-oxidising prokaryotes, which take in sulphates and generate sulphides [32] are not restricted to just the reservoir but they can also sour production pipework and well tubing and offshore topside facilities [33]. The technologies used in unconventional oil and gas resources during the exploitation and development such as hydraulic fracturing and steam-assisted gravity drainage (SAGD) could possibly add more H₂S to the reservoir or turn existing sulphur in the reservoir to H₂S, Marriott et al’s study appends [29]. Another research showed that the chemical reaction in crude petroleum between sulphoether and sulphur-alcohol may be responsible for the generation of H₂S, in addition to the thermochemical reactions of sulphate-containing minerals [34]. Anthropogenically-induced H₂S generation, especially in reservoirs that were initially sweet, usually occurs through production activities such as waterflooding. Ma et al. [35] conducted experiments based on superheat degree during thermal enhanced oil recovery (EOR) processes. They found that at a constant reservoir temperature, H₂S generation was more likely to occur at a greater superheat temperature, with a superheat temperature of 62.19°C recording H₂S formation of 0.178 mL/g whereas a superheat temperature of 89.42°C reported an H₂S generation of 0.345 mL/g. They also established an inverse relation between the increase in H₂S and the dwindling of sulphur-generating sources such as sulphides and sulphates, and typically non-sulphur generating sources such as methylene, carboxyl and carbonyl groups. H₂S is linked to CO₂ in that the first method of H₂S generation (through reservoir biomass) occurs when carbon-essential organic matter decomposes to form H₂S. This is often a by-product of the decomposition of the same organic matter to usually form aliphatic hydrocarbons (alkanes, alkenes and alkynes). The organic matter may include dead and rotting vegetation, coral reefs, plankton, and even animals. In fact, H₂S generation may even be in direct competition to hydrocarbon generation (a heterotrophic relationship) as methanogenesis (the generation of methane CH₄, the foundational aliphatic hydrocarbon) from peat bog sources may be delayed due to the effect of these sulphate-reducing microorganisms (SRMs) [36]. A sample study from the Santanghu Basin found that the ³⁴S isotopologue contributed up to a fifth of the sulphur in the areal H₂S and concluded that TSR and/or the thermal decomposition of sulphur (TDS) was/were the key generation mechanism(s) [37] and listed a TSR formation equation as thus [38]:

$$\mathit{\text{sulphate}}+\mathit{\text{petroleum}}\to \mathit{\text{calcite}}+H_{2}S\pm H_{2}O\pm {\mathit{CO}}_2\pm S\pm \mathit{\text{altered petroleum}}$$E2

The methionine-to-serine amino acid metabolic transsulphuration pathway occurs when sulphur is transplanted to the amino acid l-cysteine from l-homocysteine and the process eventually culminates in the generation of H₂S [39]. Cysteines and the uptake of the sulphur-containing cystine are particularly important in oncogenesis, when previously healthy cells start becoming carcinogenic [40]. The sulphur in persulphides (RSSH) can also be reduced to the endogenous signalling biomolecule H₂S, which plays a paramount role in some mammalian physiology [41]. A simplified reaction is as follows:

$$R-\mathit{SSH}+R-\mathit{SH}\to R-\mathit{SS}-R+H_{2}S$$E3

Simply put, a cysteine persulphilde is reduced by the organosulphur thiol to produce the disulphide cystine and H₂S [42] where R is a functional alkyl or organic substituent.

The presence of humic acid in dissolved organic matter (DOM) in sediments and soils could also serve as a key driver in H₂S generation [43] and can also be responsible for the multiplication of microorganisms in sediments and soils [44] which is favourable for both H₂S and hydrocarbon generation. Humic acid can also hasten or hinder hydrocarbon generation through control over biodegradation solubilisation and limiting cell adhesion [45] but petroleum hydrocarbons (PHs)—made up of straight chain aliphatic hydrocarbons (AHs) and polycyclic aromatic hydrocarbons (PAHs)—can also have their phytodegradation amplified by the humic acid [46]. In soils and sediments, humic matter—humic acids, fulvic acids and humin—are classified as the key ingredients in organic composition when animals and plants wither and decay through the biological and chemical agents and actions of microorganisms [47]. In the sulphur cycle, fulvic acids may also act as sinks (geological storage or reservoir) in deep groundwater for when H₂S deliquesces in water [48].

Generation of H₂S in other industries is also well documented though in scale and size, is dwarfed by generation in hydrocarbon reservoirs. In the waste and sewage industry, Zhiqiang et al. [49] relate factors that affect H₂S generation including isolating the manhole septic tank as a major hotspot, the effects of temperature and flow turbulence, water quality and how heavy rains hinder H₂S production because of sheer moving velocity. In thermal springs or geothermal fields, sulphur-bearing minerals deep in the earth oxidise to form H₂S which in turn dissolves in the hot water. As this hot water rises to the surface and the water gets colder, the H₂S evolves from the water giving the spring the rotten egg smell. These types of springs are called sulphurous thermal waters (STW). Industries as diverse as tanneries, piggeries, pulp and paper manufacturing, metallurgical and thermal coal plants, textile production especially rayon, landfills and manure storage pits have also been known to produce H₂S. With coal, H₂S is usually generated or ‘sorbed’ out during high-pressure but below calcination temperature gasification by limestone in the form of calcium carbonate [50] whilst SO_x is a/are direct product(s) when combustion takes place instead [51]. Biomass—in the form of biofuels, bioliquids, biogas, etc.—a source of renewable energy touted as one of the potential fossil fuel substitutes, also releases amounts of H₂S during the processing into energy form [52]. Whilst most the generation is through SRMs and chemolithotrophs (organisms that derive chemical energy and sustenance through the oxidation of inorganic sources such as rocks), the influence of temperature (thermochemical and thermobiological) is also felt as even under anaerobiosis, the sulphate-reducing bacteria (SRB) thrive under warm conditions. Underwater thermal vents, volcanoes, stagnant waters and polluted waters can also produce H₂S [53]. Stoichiometry-wise; one of the primary SRB reactions to produce H₂S is:

$${{\mathit{SO}}_4}^{2-}+10H^{-}+8e^{-}\stackrel{\mathit{SRB}}{\to }{H}_{2}S+4H_{2}O$$E4

And two others that convert the intermediate monosaccharide metabolite glyceraldehyde;

$$2{\mathit{SO}}_2+C_3{H}_6{O}_3\stackrel{\mathit{SRB}}{\to }2H_{2}S+3{\mathit{CO}}_2+H_{2}O$$E5

$$3{{\mathit{SO}}_4}^{2-}+2C_3{H}_6{O}_3\stackrel{\mathit{SRB}}{\to }3H_{2}S+6{{\mathit{HCO}}_3}^{-}$$E6

In wastewater systems, abundance of sulphate ions results in their reduction to an intermediate sulphur ion and then conversion to H₂S thus;

$${{\mathit{SO}}_4}^{2-}+\mathit{\text{organic matter}}\stackrel{\mathit{SRB}}{\to }{S}^{2-}+H_{2}O+{\mathit{CO}}_2$$E7

$$S^{2-}+2H^{+}\stackrel{\mathit{SRB}}{\to }{H}_{2}S$$E8

All the above-listed equations occur anaerobiotically, that is, the microorganisms perform them without the benefit of free, molecular oxygen. Outside of SRB equations, hydrogen gas and elemental sulphur can also react to form H₂S;

$$H_{2\left(g\right)}+S_{\left(s\right)}\to H_2{S}_{\left(g\right)}$$E9

The reaction between aluminium sulphide and water also achieves that purpose;

$${\mathit{Al}}_2{S}_{3\left(s\right)}+6H_2{O}_{\left(l\right)}\to 2\mathit{Al}{\left(\mathit{OH}\right)}_{3\left(s\right)}+3H_2{S}_{\left(g\right)}$$E10

And another equation between ferrous sulphide and hydrochloric acid usually in a Kipp’s apparatus in a fume hood also produces H₂S;

$${\mathit{FeS}}_{\left(s\right)}+2{\mathit{HCl}}_{\left(\mathit{aq}\right)}\to {\mathit{\text{FeCl}}}_{2\left(s\right)}+H_2{S}_{\left(g\right)}$$E11

Solid thioacetamide decomposes in hot water to form acetate and ammonium ions (acetamide or ammonium acetate) and is most importantly a precursor for H₂S production;

$${\mathit{CH}}_3{\mathit{\text{CSNH}}}_{2\left(s\right)}+2H_2{O}_{\left(l\right)}\stackrel{\mathit{\text{heat}}}{\to }{\mathit{CH}}_3{{\mathit{COO}}^{-}}_{\left(\mathit{aq}\right)}+{{\mathit{NH}}_4^{+}}_{\left(\mathit{aq}\right)}+H_2{S}_{\left(g\right)}$$E12

The above listed are by no means exhaustive. H₂S can be produced several different ways synthetically in the lab but these are the major means by which H₂S is generated. Approximately 90% of H₂S found in the environment occurs naturally [54].

4. Effects and impact

In the petroleum field, H₂S can make oil and gas reservoirs harder to develop and can hinder hydrocarbon extraction from formation reservoirs as they are classified as contaminants in natural gas which consists of mainly methane and ethane and thus the natural gas has to be “sweetened” [55] to remove these impurities. Oil and gas workers may also be exposed to the potentially fatal H₂S that may be present in drilling fluids as the gas may be brought up to the surface when drilling mud goes through its cycle. H₂S is corrosive and can make both concrete and steel equipment in the upstream flowlines and tubing brittle [56]. It also has a similar corrosive effect on iron, copper and brass [57], and its presence leads to increased corrosion rates [56].

In waste water and sewerage treatment plants, biogas plants, industrial and manufacturing processes, chemical, petrochemical and oil refining processes, during production, storage and transportation, H₂S is known to be highly toxic even at low concentrations. It has been proven to cause cognitive impairment [58] and has also been linked to neurological symptoms and health effects on the central nervous system and respiratory functions [59]. In a study of nearly 150 wastewater workers, for whom H₂S is frequently an occupational health and safety hazard, an inflammation was found, albeit low but pervasive, symptomatic of the effect on lung capacity through exposure to workaday strength H₂S [60]. H₂S is usually the unwanted end-product of the hydrodesulphurisation of coal and hydrocarbons and may interrupt normal physiological functions and cause ailments such as asthma, sepsis, neurodegenerative disease, cirrhosis and diabetes [54]. Elevated concentrations of H₂S in the gut can be detrimental to the intestinal and bowel regions because it reduces pH and can induce toxicity [61].

Studies have shown that some prokaryotes (primarily archaea) and bacteria utilise sulphur compounds through their oxidation or reduction to aid and invigorate both cellular and chemolithotrophic growth [62].

5. Mitigation

Large-scale H₂S produced from hydrocarbon reservoirs usually undergo a hydrodesulphurisation Claus process where in the presence of a catalyst it is converted into elemental sulphur. This has been the established choice for at least the last few decades. Because H₂S produced in the waste and sewage is localised in nature, it is easier to fashion containment strategies, especially through chemical dosing using nitrates and biocides [63] for prevention and remediation purposes. But these biocides may require more space and more importantly their effluvia can possibly be carcinogenic hence a nitrate-based solution whereby SRB are inhibited by the growth and enrichment of the less-unpleasant nitrate-reducing bacteria (NRB) [33]. A free ammonia based method wherein urine is dosed in the sewage system was found to greatly reduce H₂S production by the genus Desulfobulbus [64]. A free nitrous acid (FNA) dosing was also observed to substantially lower operational costs and leave a much lower carbon footprint [65]. The growth of the twin sulphide oxidisers Rhizobiaceae and Xanthomonadaceae was reinvigorated by nitrates [66]. A study [67] found that nitrate-reducing, sulphide-oxidising bacterium (NR-SOB) consisting of the culture Thiomicrospira sp. strain CVO dosed in an SRB environment rife with Desulfovibrio sp. strain Lac6 and the NR-SOB obstructed the growth of the SRB. In the presence of high level of the NR-SOB, complete oxidation of the sulphide took place, totally eliminating any remaining H₂S, the study adds [67]. The nitrate-reducing bacteria work by competing directly with SRB and heterotrophically beating it for available organic matter to biodegrade [31]. They also oxidise H₂S already produced [68]. Sulphidogenesis, the process of sulphide generation, has also been controlled with (per)chlorates by energising two known chlorate respirers Pseudoalteromonadaceae and Pseudomonadaceae through biologically competitive exclusionary means [66]. Other measures of control include the use of bacteriophages, inorganic chemicals, sonication, filtration and disinfecting with UV rays [69]. Scavengers such as zinc oxide (ZnO), copper(II) nitrate trihydrate (Cu(NO₃)₂·3H₂O) and potassium permanganate (KMnO₄) of varying mass concentrations in drilling mud have been used historically to reduce the threat posed by H₂S in drilling fluids when they are cycled during oil and gas drilling operations [70]. Further, it has been established that in sewer pipes, the combination of conductive concrete containing magnetite, and the presence of electricity-producing bacteria reduces the concentration of H₂S [71].

Together, however, and in much larger volumes than found at waste sites, the hydrocarbon reservoir-produced acid gases (primarily CO₂ and H₂S) can be used in Enhanced Oil Recovery (EOR) [72]. This is whereby they are reinjected into formations to usually boost tertiary production of hydrocarbons after the natural pressures in the reservoir significantly reduce over time during primary production. This specific EOR, known as flue gas flooding, is on the ascendancy because components such as CO₂, H₂S, CO, N₂, NO_x and SO₂ are all part of the mix that is injected. These flooding operations contribute towards reducing greenhouse emissions. The presence of H₂S is known to increase the sweep efficiency of the residual oil due to its greater density and being more soluble in the residual oil compared to other acid gases [73]. The rise in acid gas flooding is also attributable to its inexpensive nature and the ease of access [74]. The acid gas mix can also be used as part of a combination flooding strategy (together with water flooding and surfactants) where their combined effects may serve to improve the displacement efficiency of the unswept oil region [75]. Bolstering the case even further for their joint use is research that shows that an acid gas mixture containing over four-fifths CO₂ concentration—which is usually the case except in very sour reservoirs—is almost azeotropic in nature [76]. This makes it difficult to separate the mixture through binary distillation and the alternative process may be energy-intensive and solvents may be required to proceed with separation (for which m-xylene was discovered to be the best amongst four studied) [76]. This phenomenon is analogous to why ethanol cannot be absolutely distilled to 100% purity because of the non-ideal azeotropic behaviour; at a certain ethanol concentration—usually just under a 100%—the vapour phase concentration of both alcohol and water becomes equivalent to the liquid phase’s concentration of both, hence any extra distillation produces both water and ethanol and not the required ethanol, resulting merely in a waste of energy.

6. Role in geosequestration

Utilising or geosequestering both acid gases together make sense in many ways especially if they are produced together. Economically, disposing of both together saves costs compared with storing them individually. They can be both used in enhanced oil recovery (EOR) operations and their injection could be used to maintain reservoir pressures [77]. Additionally, and perhaps significantly, research has shown that the EOR injection of the acid gas mixture has a delayed breakthrough at the producing well compared to a CO₂ EOR injection alone [78]. Furthermore, there can be another case made for the sequestration of these gases especially for H₂S, as the alternative, the desulphurisation process that ends in the reduction of the produced H₂S into sulphur [79] is proving to be financially unfeasible [80] mainly due to a reduced global appetite for elemental sulphur.

In CO₂ and H₂S sequestration and storage projects, an important concern is to ensure that the gases will be securely contained for the long term in the given geological formation. According to International Energy Agency Greenhouse Gas Research and Development Programme (IEAGHG), ‘long term’ is classified as a period anywhere from several hundred to thousands of years [81].

From a storage efficiency (minimum leakage) perspective, reservoirs (storage sites) may be considered based on their ability to trap the fluids injected, and the formation fluids (oil and water) will be more dense than the injected fluids [82]. Theoretically and practically, injected fluids are prevented from escaping to the surface by four trapping mechanisms: structural trapping, residual trapping, dissolution trapping and mineral trapping [83].

For multiple phase conditions, surface wetting in a hydrocarbon reservoir, analyses of the behaviour of the supercritical acid gas, and its eventual fate in the reservoir after sequestration, requires an in–depth knowledge of the processes, molecular reactions and interactions between mineral and fluid phases to create larger–scale simulation models [84]. For a safe and efficient CO₂, H₂S or acid gas storage project, the accurate prediction of reservoir molecular interactions is very important.

In 1989, Chevron injected acid gas containing 85% CO₂ by volume and 15% H₂S in Acheson, Alberta, Canada [85] in what is perhaps the first of its kind. Whilst acid gas injection (AGI) operations may not be as common as carbon capture and storage (CCS), many projects have been investigated, with over 80 acid gas sequestration operations in the world over a decade ago, especially in Canada [86], Poland [87] and Algeria [88]. The geosequestration processing of acid gases is generally classified into two main actions: the surface operational exercises which involves the capture, transport and injection of the gas, and the in situ processes which relate to the storage functions within the geological media [89]. Large-scale H₂S capture is usually from sour oil and gas reservoirs unlike CO₂ which in addition to being captured from hydrocarbon reservoirs can also be directly captured from the atmosphere.

In the oil and gas industry, produced fluids containing significant amounts of H₂S and CO₂ are typically passed through a processing and refinery plant that contains two essential components: an absorption column and a regeneration tower. The former, also called an amine gas treatment column, usually uses an aqueous alkanolamine variant such as;

• diethanolamine (DEA),

• triethanolamine (TEA),

• diglycolamine (DGA),

• diisopropanolamine (DIPA),

• monoethanolamine (MEA),

• methyldiethanolamine (MDEA),

• aminomethyl propanol (AMP),

Sometimes a hybrid mixture is used to absorb the acid gases out of the produced gas stream, hence generating a hydrocarbon phase devoid of or containing low amounts of acid gas (sweet gas or crude). The stream containing the acid gas and the amine is then passed through the regeneration column where the acid gas is separated from the amine and the amine can be reused in the absorption column for future separation.

Separated acid gases are usually compressed and temporarily stored, transported and injected in a supercritical state where they are neither liquids nor gases but enjoy the distinct benefit of being very diffusive, like gases, but nearly as dense as liquids.

For simplicity and economic reasons, wellhead injection temperatures and pressures are usually aligned with that of the compressed gas’s transportation conditions [90] although temperatures can range between 30°C all through to 200°C and pressures from 1 to 30 MPa, with both temperature and pressure ceiling usually determined by the reservoir’s state [91], and the acid gas injection strategy delineated to take advantage of system thermodynamics, including importantly, use of the phase envelope [92]. Storage is usually implemented in deep saline aquifers, depleted oil and gas reservoirs, clastic and basaltic formations, unmineable coal seams [93], and unconventional oil and gas reservoirs [94]. The temperatures are non-trivial during injection, as they affect the reservoir fluids and rock thermodynamically, chemically, hydrologically and mechanically, wherein the Joule-Thomson cooling effect may occur due to advection and expansion of injected fluids [90]. This disruption to a system previously in equilibrium can lead to continued effects on the reservoir and cap rock as it may cause stress/strain on them, opening up old fissures and faults or creating new fractures hence affecting long term containment security and safe storage [95].

Factors that go into selecting a geological disposal media are broadly framed under physical, hydrodynamic, regulatory, geological, social, thermodynamic, economic and technical [96]. They include the minimisation of geomechanical risks, site selection, retention and optimising injectivity [97] containment security and reservoir capacity. An expansive and exhaustive list laid out by Raza et al. [98] include common benchmarks such as permeability, density, depth, porosity, trapping mechanisms, injectivity, minerals present, residual hydrocarbon saturation, rock type, sealing potential, well type, wettability, subsurface type, etc. Studies have shown that deep saline aquifers have larger storage capacities compared to depleted oil and gas reservoirs [99] with the former having a range anywhere between 1000 and 10,000 Gt compared to a maximum of 900 Gt of storage [100] as original reservoir pressures during oil/gas producing life should not be superseded lest overlying cap rocks may be impaired and may give rise to leakages and storage integrity compromised [101]. Economically, a low capital outlay on operational frameworks (infrastructure) and an ability to sequester buoyant fluids safely in geological media and time are some of the reasons that make depleted oil and gas reservoirs appealing [99, 102]. Added to that is the fact that they have two other advantages: they once were producing reservoirs so they’ll have been studied immensely through their geology, core and well logs and production logs so they will have rich historical data, and secondly, because they have a history of trapping oil and gas prior, they therefore make good candidates to trap fluids being injected [103]. Depleted gas reservoirs are also understood to be a more secure outlet for injection than other geological receptacles [102] since saline aquifers may be subject to a buildup of pressure over a region due to water’s mobility [104].

There is more risk attached to the in situ geosequestration phase as it comes with a greater degree of uncertainty [89], which is why a rigorous study of the interface (interfacial tension, thickness, etc) is important to reduce the risks involved in the process. This is especially imperative considering the recent problems both the seminal Sleipner and Snøhvit CO₂ injection operations in Norway have run into. Sleipner has had CO₂ migrate from the formation fluid and ‘hover’ just underneath the caprock whilst Snøhvit has had its original 18 year storage capacity reduced to less than 2 years [105]. The Borzęcin sequestration project in Poland is unique in that it injects the acid gas into the water zone overlain by a producing gas cap and not as an enhanced gas recovery (EGR) technique but as an ongoing study of the effects of the acid gas on the formation water, and once formation water reaches critical saturation and the injected gas starts buoyantly moving upwards, the effects on the producing gas cap [106]. Some of the injected acid gas will be soluble in the formation water. In that case what will be the implications for newly formed weak acidic fluid, the interactions within the new fluid and its relationship with the reservoir rock? A weak acid will still lower the pH of the formation fluid and thereby increase solubility of the injected fluid. Both acid gases are diprotic, that is, they undergo two ionisation reactions when they dissociate to release H⁺ or H₃O⁺ ions, with H₂S shown thus;

$$H_2{S}_{\left(\mathit{aq}\right)}\rightleftharpoons {H^{+}}_{\left(\mathit{aq}\right)}+{{\mathit{HS}}^{-}}_{\left(\mathit{aq}\right)}$$E13

$${{\mathit{HS}}^{-}}_{\left(\mathit{aq}\right)}\rightleftharpoons {H^{+}}_{\left(\mathit{aq}\right)}+{S^{2-}}_{\left(\mathit{aq}\right)}$$E14

CO₂ in water presents as weak carbonic acid, which is very important in the carbon cycle as it is responsible for the storage of CO₂ in carbonate rocks during weathering [107], and the two dissociation steps written thus;

$$H_2{\mathit{CO}}_{3\left(\mathit{aq}\right)}\rightleftharpoons {H^{+}}_{\left(\mathit{aq}\right)}+{{{\mathit{HCO}}_3}^{-}}_{\left(\mathit{aq}\right)}$$E15

$${{{\mathit{HCO}}_3}^{-}}_{\left(\mathit{aq}\right)}\rightleftharpoons {H^{+}}_{\left(\mathit{aq}\right)}+{{{\mathit{CO}}_3}^{2-}}_{\left(\mathit{aq}\right)}$$E16

However, the two ionisation reactions for both CO₂ and H₂S typically have very low equilibrium constants, K. Since K is several orders lower than 1 (order usually between 10⁻⁷ and 10⁻¹⁹), then both acid gases will exist in the formation water in their molecular form (CO₂ and H₂S) compared to in their dissociative states (HCO₃⁻, CO₃²⁻ and HS⁻, S²⁻ respectively) as equilibrium would overwhelmingly favour the reactants. This very likely will be temporary until geochemical reactions between injected fluids, in situ fluids and reservoir rock commence. Some research suggests the new fluid will dissolve some of the reservoir rock minerals which in turn may create secondary reactions and new products hence the need to study thermodynamic, geochemical, structural and physical properties [108]. A lot of research has been done, especially for deep saline aquifers and the fluid-fluid-rock environment [109, 110, 111, 112]. Our group’s work on both injected H₂S [113] and acid gas (CO₂/H₂S) [114] using molecular dynamics (MD) simulation showed that geosequestration in depleted oil and gas reservoirs is ideal at low pressures and higher temperatures as more of the injected fluid is absorbed into the formation water under these conditions. Higher absorption rates reduce the risk of the injected fluid buoyantly escaping the subsurface environment. However, these conditions are also very germane for the generation of clathrate hydrates, with H₂S in particular singled out as the most amenable ‘guest’ molecule for hydrate formation [92], so a balance needs to be struck.

Research on H₂S-water and acid gas-water systems lags behind CO₂-water due to the difficult reservoir conditions and the toxic and corrosive nature of H₂S. Most research has been on enhanced oil recovery (EOR) [72, 115]. Bachu and co-workers [116, 117, 118] have done extensive work in Canada on CO₂ and acid gases during geosequestration using analytical models to approximate behaviour of injection plumes. Isothermal cracking experiments have also been performed on heavy oil samples to resolve the H₂S generation mechanism and it demonstrated that increasing the cracking temperature invariably increased the H₂S yield [119]. H₂S has also been injected in small rates in hydrothermal reservoirs in Iceland as a pilot, with prospects for later expansion [120]. Metal-organic frameworks (MOFs) have been recognised for their adsorbency in gas separation and storage due to their high selectivity of the corrosive H₂S [121, 122]. Koschel and co-workers [123, 124] have also performed considerable research and reviewed enthalpy and solubility data for H₂S under geological storage conditions. Chapoy et al. [125] developed a vapour-liquid equilibrium (VLE) model for the H₂S-water system at conditions (temperatures between 25 and 65°C, and pressures up to 4 MPa) below typical reservoir conditions. Possibly the widest range of temperatures and pressures parametrised for the H₂S-water binary system and the acid gas-water ternary system was by Springer et al. [126] who developed VLEs for these systems by reviewing several different data points in the literature. A considerable number of diagenetic, hydrogeological, mineralogical and stratigraphic appraisals have been performed [127] for acid gas injection and geosequestration. In all these works however, they have not necessarily looked at the intermolecular interactions, but at more specific properties and macroscopic scale behaviours. The work of Ng et al’s [128], stressed the need for proper property calculations, especially density, near the critical point of the acid gas mixture as this is at injection conditions and properties are functionally very dependent on pressure and temperature.

7. Conclusion

Hydrogen sulphide (H₂S) is a molecule that presents mostly in oil and gas reservoirs and processing operations. Due to its acutely toxic and corrosive nature, it represents a specific complication during operations. This chapter attempts to highlight some of the issues. It also briefly traced its presence on earth before the genesis of life in the Archaean all through to its role in different timelines to the present Cenozoic era. Generation and production mechanisms have also been discussed, with emphasis on natural production which accounts for the majority of H₂S on the planet. Its effects as mainly an occupational health and safety risk, together with mitigation strategies are also deliberated upon. Finally, its topical and relevant position as a constituent acid gas injected for geosequestration is also briefly examined.

Conflict of interest

The author declares no conflict of interest.