Reservoir souring occurs when the concentrations of hydrogen sulphide H2S in production fluids are increased. This corrosive and foul smelling ‘ sour gas’ is dangerous to life and likely to cause pitting and cracking of susceptible steels. The source of H2S has generally been associated with secondary recovery. Without secondary recovery during the production life of a reservoir, the reservoir pressure would decrease continuously, which would result in decline in the production rate. In order to maintain production, water (seawater) is generally injected in the reservoir to maintain the pressure and to sweep hydrocarbon through the reservoir to maximize the recovery. Hydrogen sulphide (H2S) is generated if the bacterial activity associated with water injection is not controlled, which will ultimately ‘sour’ the reservoir and the hydrocarbons to be produced. Hydrogen sulfide is extremely corrosive and toxic and the level of H2S in the sales gas should be less than 4ppm. The phenomenon of unexpected increase in the concentrations of hydrogen sulphide in produced fluids has been observed in many fields throughout the world. Recently, at least two major oil fields in North Sea have been observed with higher concentrations of hydrogen sulphide in produced fluids after the breakthrough of seawater occurred. Conversely there are still several fields with mature water floods that have suffered few souring problems. The corrosivity of water produced along with oil/gas from the reservoir can vary throughout its lifetime. This is predominantly seen in fields which are considered sweet initially, but produce more concentration of H2S in later life, and in some cases at concentrations of up to thousands of parts per million by volume in the gas phase. Though CO2 can cause very severe corrosion and pitting of steels, H2S corrosion is more localized, and can cause Hydrogen Induced Cracking (HIC), Hydrogen Embrittlement (HE), and Sulphide Stress Corrosion Cracking (SSCC). Hence, increasing H2S concentration will not necessarily cause an increase in corrosion rate, but also cause catastrophic failure of susceptible materials. Reservoir souring also causes many economical problems like it can reduce the value of the oil and gas asset, increase operational costs and, in the worst case scenario; result in shut-in of the well due to incompatibility of the materials. Sweet reservoirs can be soured by the activity of sulphate-reducing bacteria present in the reservoir, or introduced through the injection water (such as sea water).
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Mechanisms of souring
Sulphate Reducing Bacteria
Sulfate reducing bacteria (SRB) can be traced back to 3. 5 billion years ago and are considered to be among the oldest forms of microorganisms, having contributed to the sulfur cycle soon after life emerged on Earth. These organisms ” breathe” sulfate rather than oxygen, in a form of anaerobic respiration. SRBs are widely distributed in oil production facilities and in seawater, which makes their introduction into water-flooded reservoirs. It has a wide range of metabolic mechanisms which allows sulphate reduction to proceed under many different environmental conditions at the expense of a range of electron donors and carbon sources. Under optimal conditions, it has been estimated that a sphere of porous rock approximately 7 meters in radius could support an SRB population capable of producing the 400 kg of H2S per day observed for badly soured wells. Under favorable conditions SRB’s will convert SO4- sources to H2S. In general, SRB, obtain energy for growth and reproduction from the oxidation of a range of organic materials which also serve as sources of carbon. Since SRB grow in the absence of oxygen, the oxidation of organics, such as acetic acid, is linked to the reduction of sulphate:
CH3COO- + SO42- → 2HCO3 + HS-
SRB’s utilise suitable carbon and energy sources in oxidizing an organic substrate. It donates an electron, along an electron transport chain. Sulphate acts as the electron acceptor, being reduced to sulphide. Some SRB’s are able to use hydrogen (via hydrogenise enzymes) rather than organic compounds as electron donors.
4H2 + SO42- + H+ → 4H2O + HS-
In this case, the requirement for carbon is satisfied by organic compounds or from the fixation of carbon dioxide. This consumption of hydrogen is one way in which SRB is implicated in corrosion events in the oil industry.
Reduction of SRB Protection by Bisulphite Chemicals
To protect process and well completion of equipment against excessive corrosion, oxygen levels in sea water need to be reduced prior to injection. Mechanical means, gas counter current stripping or vacuum deaerators, are used. These achieve reductions to around 100 50 parts per billion (ppb). It is usual to add, continuously, small amounts of ammonium bisulphite or sodium sulphite to chemically scavenge further oxygen. Some operations, NH4HSO3 are often only used during maintenance shut downs of the mechanical units. Such method can cause sulphite scavengers to react with the residual chlorine used as the primary biocide, thereby reducing protection against SRB’s. Then a direct reaction of bisulphite/sulphite with the steel process equipment and tubing can also occur. The nature of the reduction reaction has been investigated, on both NH4HSO3 and Na2SO3. Several qualitative tests have been performed, using mild steel coupons in deaerated 3. 5% NaCl solutions, with pH adjusted to 5 or 6 with NaOH/HCl at ambient temperature. Bisulphite concentrations from 0. 3 g/l to 12. 5 g/l have been used, and the presence of sulphide is the confirmed. Reactions Type that are suggested:
HSO3- + 7H+ + 3Fe2+ → 3Fe2+ + H2S + 3H2O
HSO3- + 5H+ + 3Fe2+ → 2Fe2+ + FeS + 3H2O
The electrochemical nature of the reaction has been further investigated by potentiodynamic polarization scans using a gold rotating disc electrode (RDE). Scan rates of 1 mv/sec and rotation rates of 10 Hz are used. The curves show a reduction reaction occurring at a potential of about 0. 6 V (SCE) which is concentration dependent (in respect of reaction rate and the equilibrium potential) and substantially under diffusion control. The reaction has been identified as the formation of dithionite
S2O42- + 2H2O → 2SO32- + 4H+ 2e-
Eo = 0. 416 0. 1182 pH + 0. 0295 log (SO32-) 2 / (S2O42-)
This reaction was confirmed by polarization of a platinum electrode to 0. 70 V in a solution of NaCl/Na2SO3 followed by positive identification of dithionite by spectroscopic analysis.
Thermal Sulphate Reduction
Thermal Sulphate Reduction chemical is the direct reduction of sulphate by hydrocarbons in order to produce hydrogen sulphide. Whether the kinetics of these types of reactions are such that they may contribute to reservoir ‘souring’ is open to debate, although evidence for this has been growing in recent years. At temperatures in the range 250 325°C, and modest pressures, many organic compounds are rapidly oxidized with high product yields. A requirement for this reaction is the presence of sulphur species in a lower valance state to initiate the reaction. Any S species of valance less than +6 will initiate, though H2S appears most successful. The mechanisms proposed by Toland initially involve the protonation of the sulphate ion: Rsequation1. PNGWithout initiation the reaction cannot proceed. However, in the presence of H2S: Rsequation2. PNGThe thiosulphate formed is unstable and decomposes, in acidic conditions, to elemental sulphur and sulphate. Rsequation3. PNGReactive elemental sulphur is then available for the oxidation of various organic species. The sulphite formed can undergo further disproportionation reactions, oxidizing more organic substrate and re generating H2S to initiate further reaction.
Zinc and iron based absorbers are cheap and react quickly, but can cause downstream oil/water separation problems. Aldehydes are cheap but slow reacting; a key point when this must take place between wellhead and separators. Strong oxidisers, like chlorine dioxide, have found preference since they are both quick in reaction and cause little production upsets. However, they are corrosive and require special metallurgies. New organic scavengers have been developed with some success but still requiring further improvements. Currently, triazine scavengers offer the highest efficiency and are building some track record of cost and performance.
Biocide treatments of injection wells have been tried to treat reservoir souring with little success. The problem with biocide is that it cannot penetrate sufficiently deep into the reservoir. Chlorine (> 10ppm) has been observed to limit bacterial activity in sand packs close to the inlet, but this can also cause severe corrosion in injection wells.
In nitrate treatments, bacterial population can be altered by encouraging the nitrate reducing bacteria to consume all the available electron donors, thereby preventing SRB from using them.
Sulphate Removal from Injection Water
Reverse Osmosis phenomenon is used to decrease sulphate levels in seawater used for injection purposes. Reverse Osmosis plants built to control scale problems, can be used to treat potential reservoir souring problem. No work has been undertaken so far, to set up whether such technology, that has high initial capital costs, could be effective in reducing the availability of the prime sources of SRB energy to limit reservoir souring.