Reservoir Souring: a potential problem in the Gulf of Guinea’s Deep Offshore Oilfields?
The attractiveness of the oil from the Gulf of Guinea (GoG) oilfields is related to its high quality measured by its sweetness and lightness. Sweet oils, unlike sour oils, have low sulfur content and light oils are abundantly enriched in low-molecular weight hydrocarbons. This attributes makes such oils easier and cheaper to refine. Sulfur in oil may be present as hydrogen sulfide, thiopenes, mercaptans, disulfides and as elemental sulfur. It can be assumed that a bulk of the oils from GoG reservoirs naturally has low level of such compounds. However, the fact that higher proportion of oil are expected to be produced from recently discovered deep and ultra-deep offshore reservoirs in GoG suggests that souring of oil and gas in GoG oilfields could be a problem in the near future. This assumption is supported by experience from deep offshore fields elsewhere. The fact that some oilfields in the North Sea (e.g. Ekofisk, Skjold) that harbor oil with low sulfur-content are turning sour especially after produced water re-injection (PWRI) indicates that souring is a potential problem in offshore reservoirs notwithstanding the low level of sulfur in the oils. The question is why is this so?
There are several possible mechanisms of souring. This can be divided into two classes: (i) abiotic and (ii) biotic mechanisms. Abiotic mechanisms include:
- Thermochemical reduction of sulfate (TRS) to sulfide by hydrocarbons in reservoirs close to anhydrite, which is an in-situ source of sulfate. Though potentially possible, the minimum temperature requirement of the process has been controversial. It is reported to occur at temperature as low as 80 °C, and it has been argued to occur only at temperature above 200 °C. Several attempts to demonstrate the process at room temperature or even at 300 °C is reported to have failed. Pre-existing hydrogen sulfide is known to drive the process at temperature between 77 – 121 °C.
- Thermal decomposition of organic sulfur compounds present in crude oils leading to the generation of hydrogen sulfide. The drawback of this process is its requirement for much higher temperature.
- Dissolution of pyritic mineral resulting in oxidation of pyrite. This is a very slow process requiring powerful oxidant at high potential. Therefore it is unlikely to occur in a reducing environment like oil reservoirs.
- Redox reaction of oxygen scavenging bisulfate has been considered by oil companies because these compounds contain sulfite. They are often thought to stimulate the growth of sulfate-reducing-bacteria (SRB). For the fact that relatively low concentrations of the compound are used, their role in souring could be limited to catalytic conversion of some sulfur compounds.
Biotic mechanism of souring involves biological reduction of sulfate by sulfate-reducing bacteria (SRB) that are resident in oil reservoirs. In this process, hydrogen, and dissolved organic compounds or even crude oil components are used as electron donor for microbial reduction of sulfate leading to the production of sulfide. This process is widely reported to occur in reservoirs receiving injection water that is used to support reservoir pressure during secondary recovery of oil. While it occurs in onshore reservoirs that are injected with sulfate-containing make-up water, however, it is more pronounced in offshore reservoirs that are injected with seawater. Unlike in fresh-water, concentration of sulfate in sea water could be as high as 30 mM (as reported for the North Sea) and it is this abundant source of electron acceptor that makes souring a potential problem in offshore reservoirs since this environments has abundant sources of highly reduced inorganic and organic electron donors.
- Bacterial reduction of sulfate coupled to oxidation of oil organics and production of sulfide and carbon dioxide
Production of sulfide in high-temperature reservoirs (> 70 °C) as in the North Sea is often reported to be limited to injection well-bore zones as well as in reservoir zones within the thermal viability shell that is created in area slightly farther from the injection well-bore after the introduction of low-temperature sea water. The mixing of low-temperature sea-water with formation water reduces the temperature around the injection well-bore. Other problems that could result from reservoir souring include corrosion of oilfield installations, reduced injectivity and production due to the formation of metal sulfides, and the potential health hazards to oilfield personnel.
Reservoir conditions in the oilfields in the GoG are more conducive for microbial metabolism. This suggests that oil reservoirs in GoG would likely turn sour following injection of seawater to support reservoir pressure. For example, conditions in the main reservoir of the Bonga oilfield off the coast of southern Nigeria is reported to be conducive for microbial souring with: temperature in the thermophilic range (63 °C) that is capable of tolerating field-wide biogenic production of sulfide; moderately saline formation water; absence of sulfide-scavenging siderite; abundant source of easily degradable organic volatile fatty acids. Because sea water was injected to maintain reservoir pressure from the beginning of oil production in the Bonga field, models predicts that souring of the reservoir was likely. The strategy in this field is to prevent microbial souring by injection of nitrate in combination with biocide from day one. Nitrate acts by serving as electron acceptor for more competitive heterotrophic nitrate-reducing bacteria (hNRB) that out-competes SRB for electron donors thus arresting sulfide production. It is also an electron acceptor for a special group of bacteria (the nitrate-reducing sulfide-oxidizers, NR-SOB) that are required to eliminate sulfide. In addition to this, nitrite, a side-product of nitrate-reducing bacteria can inhibit some SRB and it can also react chemically by oxidizing sulfide. However, not all these processes are feasible in one field that is treated with nitrate. For example, the mechanism of action of nitrate to control souring in high temperature reservoirs is often attributed to the side reaction of nitrite with sulfide.
- hNRB out-competes SRB for oil organics, and nitrite, a side-product cause inhibition of some SRB or reacts chemically with sulfide. Thicker arrow line for hNRB-mediated oxidation of oil organics indicates faster reaction than SRB-mediated oxidation of oil organics indicated by broken arrow line. Nitrite inhibits SRB or it may react chemically with sulfide.
- NR-SOB directly remove sulfide, and nitrite mediated side reaction may occur
Sources:
Bourgeois, J. P., Bloise, R., Millet, J. L., Apaix, N. (1979). Suggested explanation of hydrogen sulfide in natural gas underground storage structures by reduction of mineral sulfides contained in reservoir rock. Revue de L’Institute Francais du Petrole, 34:371
Kuijvenhoven, C., Noirot J. C., Hubbard, P., Oduola, L. (2005). One year experience with the injection of nitrate to control souring in Bonga deepwater development offshore Nigeria. SPE International Symposium on Oilfield Chemistry, Texas, U.S.A., 28 February – 2 March 2007.
Orr, W. L. (1978). Geological and geochemical controls on the distribution of H2S in natural gas. Advances in Organic Geochemistry. Proceedings from the 7th International Meeting, Madrid, 1975, pp. 571.
Peters, K. E., Martin, G. F. (2002). Application of petroleum geochemistry to exploration and reservoir management. Organic Geochemistry, 33:5-36
Wittingham, K. P., Hardy, L. A. (1985). Microbial corrosion control in water injection systems. Presented at the 6th International Conference, UK Corrosion, Harrogate.