Biological reservoir souring happens when water injection is used for secondary oil recovery, especially in offshore installations where sulphate-rich seawater is used. The lack of oxygen, warm temperatures and the presence of sulphate, stimulates naturally-occurring microbes, which then produce toxic H₂S. Initiated at microbiological level. Exerts effect on entire reservoir

1. RESERVOIR SOURING
:- MECHANISM AND
PREVENTION
Anjali Tripathi

2. INTRODUCTION
◦ Biological reservoir souring happens when water injection is used for
secondary oil recovery, especially in offshore installations where
sulphate-rich seawater is used.
◦ The lack of oxygen, warm temperatures and the presence of sulphate,
stimulates naturally-occurring microbes, which then produce toxic H₂S.
◦ Initiated at microbiological level.
◦ Exerts effect on entire reservoir.

3. Conti….
◦ The injection of seawater or other water containing sulfate, with an inhgenous population of
viable SRB, is a common practice used to increase oil recovery beyond primary production by
maintaining reservoir pressure and sweeping oil towards production wells.
◦ Reduction of Sulfate by sulfate reducing bacteria (SRB) is the most significant mechanism of
H2S production in reservoir souring as a result of waterfloohng.

4. SYMPTOMS OF SOURING
◦ Increasing concentration of hydrogen sulfide in production has, typically after the initiation of
secondary recovery by water injection and some time after break through of injected water at
the production well.
◦ During the production life-time of a field, changes in the gas/oil ratio (GOR) and water ratse/total
liquid rate ratio (water cut) may result in apparent souring.
◦ Concentrations of gas-phase H2S as high as several thousand parts per million per volume
(ppmv) have been recorded in individual wells in reservoirs that are actively souring and in
those where existing H2S is merely being redistributed between phases.
◦ Across a souring field, significant masses of H2S can be generated.

5. ECONOMIC IMPACT
◦ From a survey of 12 reservoirs it was concluded that in all cases where the injection water
contained sulfate, souring to some degree resulted, therefore, all new seawater flood projects
should be designed for sourservice.
◦ Using sour service materials could add hundreds of thousands of dollars to the cost of each
well, resulting in millions of dollars of added costs to an entire project.
◦ If the H2S concentration cannot be controlled below this critical concentration, the export of
fluids would be curtailed with subsequent loss of revenue.
◦ Chemical scavenger treatments that remove H2S from the production gas may also impose
significant financial costs; owing to the volumes that must be transported and stored offshore,
these treatments may have significant logistical implications

6. MECHANISMS
◦ For reasons of corrosion control, steps are taken to remove oxygen
from injected water and this provides an environment conducive to the
growth of the obligately anaerobic SRB.
◦ In addtion, production chemicals, such as antifoams, scale inhibitors,
and chemical oxygen scavengers, are dosed into the injection water;
these may add to the nutrient pool of nitrogen, carbon, and phosphorus
available for SRB growth.
◦ Flocculants such as aluminium or ferric sulfate can also introduce
sulfate into previously sulfate-free systems by the injection of fluids
such as river water.

7. ◦ The viable SRB will be injected into water-flooded reservoirs, and in the case of seawater
flooding, in the presence of approximately 2,700 mg of available electron acceptor liter-1 in the
form of dissolved sulfate.
◦ Once inside the reservoir, the high specific area of reservoir rock, typically 0.93 to 5.5 m2 g-1
(Lake, 1989), provides a huge surface for colonization by SRB.
◦ Where injection wells connect with fractures in the rock colonization of fracture surfaces and
growth of biofilms may also contribute significantly to the H2S generation process.
◦ The establishment of sulfide producing biofilms in porous rock results in formation damage by
the production of extracellular polysaccharides and precipitation of metal sulfides, causing
plugging and reducing permeability.
◦ Another mechanism of formation damage in injection wells associated with the reinjection of
produced water involves the binding of asphaltene and iron sulfide solids, formation
particulates, corrosion inhibitors, and biomass into a paste-like mass, commonly referred to as
schmoo.

8. SRB PHYSIOLOGY
◦ Fourteen species of SRB that have been isolated hom oil fields have
individual growth temperatures spanning 4 to 85°C.
◦ Desulfotornaculurn spp. isolated from North Sea produced water have
been shown to reduce sulfate at 80°C when incubated at pressure up to
4,500 lb/in2
◦ SRB are nutritionally diverse and able to use electron donors and
carbon sources present in petroleum reservoirs such as acetate,
propionate, naphthenic acids, n-alkanes (C6 to C20), hexadecene,
benzoate, benzene, toluene, xylene, and phenol

9. PRODUCED WATER REINJECTION
(PWRI)
◦ Data from backflowed injection wells predominantly on seawater duty show that H2S
concentrations of tens of milligrams per liter can be generated in injection water in the close
vicinity of injection wells.
◦ The practice of PWRI as part of a waterflood has the potential to increase H2S production
beyond seawater-induced souring.
◦ produced water often contains significant concentrations of electron donors and carbon sources
in the form of acetate, propionate, and nitrogen (as ammonia). Produced water contains
different production chemicals compared to injected seawater, typically, scale inhibitor,
corrosion inhibitor, demulsifier, and wax inhibitor, which may contribute to the nutrient pool
available to SRB.
◦ Over time, produced water tends to contain a greater proportion of injection water that has
traversed the reservoir; if this injection water is seawater, it brings abundant sulfate

10. LIMITATION OF SULFATE REDUCTION
◦ Injecting large volumes of cool seawater even into high-temperature reservoirs has a significant
cooling effect on the zone adjacent to the injector.
◦ Injector backflows suggest that within this zone, concentrations of H2S are produced in the water
phase that could eventually account for hundreds of parts of H2S per million per volume of production
gas.
◦ Since the H2S is a by-product of bacterial sulfate respiration, it is formed in the water phase, the
water-rock interface, or the water-residual oil interface.
◦ Once generated, the H2S moves through the reservoir dssolved in the water phase in the direction of
the waterflood.
◦ The fate of the H2S within the ‘reservoir depends upon the prevailing physicochspecifiic conditions;
these are reservoir specific.