Activity of Sulfate-Reducing Bacteria Under Simulated Reservoir Conditions
Authors: Rosnes J.T. , Graue Arne , Torleiv Lien 
Published: December 2007

Sulfate-reducing bacteria (SRB) have been isolated from hot oilfield watersfrom subsea oil reservoirs in the North Sea. Experiments with these bacteria ina reservoir simulator indicate that SRB may maintain their activity in theconditions found in most North Sea reservoirs and, if precautions are nottaken, may contribute to souring of the oil and gas. precautions are not taken, may contribute to souring of the oil and gas.

Introduction

Water flooded hydrocarbon reservoirs may offer good conditions for growth ofthe anaerobic SRB that produce toxic and give H2S. This is particularly thecase for offshore oil fields where oxygen-scavenged seawater with high sulfateconcentration (28 mM) is injected and mixed with the in-situ reservoir porewater containing different kinds of short-chained organic acids. For continuingmicrobial activity, however, both chemical and physical requirements must bemet. Hence, the SRB must be able to grow and generate H2S at the in-situpressures and temperatures in the reservoir. Reservoir conditions weresimulated with a flow rig and investigated with respect to SRB growth andactivity. This flow rig may simulate conditions in a reservoir down to 15,000ft [4.6km], corresponding to a geostatic pressure of 15,000 psi [100 MPa] and atemperature up to 248 degs F [120 degs C]. Spore-forming thermophilic SRB ofthe genus Desulfotomaculum were isolated from hot produced water on different North Sea oil platforms. The bacteria were injected into brine-saturatedsandstone cores inside the rig's pressure vessel. Thereafter, the cores withbacteria were gradually exposed to increasing temperature and pressure, and the SRB activity at the various combinations of high temperature and pressure wasmeasured as sulfate reduction rate. Results showed that the bacteria wereactive and produced H2S to a temperature of 176 degs F [80 degs C] and apressure of 4,500 psi [30 MPa]. Electron micrographs revealed bacterial growthon mineral surfaces. Slimy extracellular material was observed in connectionwith the settlement of the bacteria. Seawater injection often is used in therecovery of hydrocarbons from subsea oil reservoirs. To obtain a successfulrecovery, the microbiological aspects of the waterflood must also beconsidered. Failure to do so may result in severe production problems. Bacterial activity downhole and in the reservoir formation results in formationdamage by loss of reservoir production performance, by a reduction in oilquality, by souring of the off, and by the development of major corrosionproblems, in both injection and production wells. H2S also is poisonous ifinhaled and may present a health hazard for platform personnel. Naturalseawater contain several types of platform personnel. Natural seawater containseveral types of slime-forming and filamentous bacteria, among them SRB andiron-oxidizing bacteria. Under favorable conditions, it is likely that theseorganisms will colonize the huge surface of the reservoir matrix. Theavailability of nutrients is important in the development of a microbialcommunity. The best nutrient conditions for SRB are expected to occur in themixing zone between the injection and formation water. This mixing zonecontains a high concentration of sulfate from seawater and soluble organiccompounds from the formation water. If chemical and physical requirements aremet in such an anaerobic environment, the bacteria will be active and produce H2S. Although SRB activity has been known for decades, little is known abouttheir ability to be active under the extreme pressure and temperatureconditions found in oil reservoirs.. In North Sea reservoirs, pressure commonlyranges from 3,000 to 7,500 psi [20 to 50 MPa] and temperatures from 140 to 212degs F [60 to 100 degs C]. The highest at which biological sulfate reductionhas been observed so far is 199 degs F [93 degs C] by the bacteria Archaeoglobus fulgidus. Other thermophilic SRB are Thermodesulfobacteriummobile and Thermodesulfobacterium commune, with maximum temperature of 180 degsF [85 degs C], and Desulfotomaculum nigrificans, with a maximum temperature of158 degs F [70 degs C]. In this study, we simulated an oil reservoir in alaboratory flow rig, using realistic temperatures and pressure. Representativethermophilic SRB, isolated from hat produced water on North Sea oil platforms, are used to study the effect of these bacteria on the platforms, are used tostudy the effect of these bacteria on the reservoir.

Technical Procedure

Core Preparation.

The cores used in this study were drilled from a matrixblock of the eolic Hopeman sandstone. The block was obtained from an outcrop at Elgin in Scotland, the Clashach quarry. Petrographic and mineralogical studiesof the sandstone indicate Petrographic and mineralogical studies of thesandstone indicate a rather pure (91 %) quartz composition and only traceamounts of clay (muscovite). Grain sizes are on the order of 0.25 mm, with onlysmall variations. The average porosity is 18%, and the permeability ranges from700 to 800 md. Average pore diameter (26 m) was measured by mercury injection. Cylindrical cores 2.0 in. [5.1 cm] in diameter were drilled with length from 4to 30 in. [10 to 80 cm]. All cores were air dried at 176 degs F [80 degs C] for24 hours before cooling and weighing. End caps were mounted and the coresepoxy-coated. The cores were flushed with oxygen-free nitrogen and thenevacuated. This procedure was repeated several time to remove oxygen from themicropores. Several PV's of anaerobic brine containing nutrients for thebacteria were flushed through the cores before they were mounted in the flowrig. To establish a systematical approach, only brine was used to saturate thecore in these experiments. In later experiments, both oil and water wereused.

Flow Rig.

Fig. 1 illustrates the experimental flow rig. The main componentof the rig is a 3-ft [1-m] -long cylindrical steel pressure vessel with an IDof 2.8 in. [7.1 cm) and a 0.4-in. [1.0-cm] wall thickness. A core prepared asdescribed was pressurized in transformer oil inside the vessel. The rig cansimulate pressure conditions in a reservoir down to 15,000 ft [4 km], corresponding to a geostatic pressure of 15,000 psi [100 MPa]. Pressuretransducers monitored the simulated overburden pressure, water injectionpressure, and the differential pressure across the core. Pumping the fluidagainst a backpressure regulator gave pore pressures up to 10,500 psi [70 MPa]. Experimental flow rates ranged from 0.01 to 9.99 mL/min. A heating cable heatedthe pressure vessel and a thermostat regulated the temperature. Three standardthermocouple K-elements were placed at the inlet, in the middle, and at theoutlet end of the rig. Temperatures up to 248 degs F [120 degs C] could bemaintained with an accuracy of 1.8 degs F [1.0 degs C].

Porosity and Permeability measurements.

Average porosity was measured Porosity and Permeability measurements. Average porosity was measured with a Boyle's law porosimeter and checked by measuring the volume of the fluidsaturating the core Dual-piston pumps operating with pulseless constant flowrate were used to inject fluids from a piston-type accumulator cell. Aprogrammable liquid sampler was attached to the outlet end of the programmableliquid sampler was attached to the outlet end of the rig. The differentialpressure across the core, flow-rate measurements, and fluid and corecharacteristics were used in Darcy's equation to calculate permeability.