Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Results
ABSTRACT In oilfield water injection systems, bacteria contribute to a number of problems, including filter plugging, loss of injectivity, formation damage, and microbiologically influenced corrosion. The injectivity and overall water quality is often monitored by filtration through a Millipore filter. Reduction in filtration rates and volumes are generally due to solids accumulation, such as iron sulfide, drilling and formation fines, organics, polymer additives, and bacteria. Bacterial impact on filtration is typically attributed to bacterial exopolymer (slime) and biomass and/or biogenic iron sulfide production. However, in this study, we investigated a water flood where reduction in filtration was primarily attributed to high concentrations of bacterial cells present in the water independent of the slime or biogenic iron sulfide. This effect did not appear to depend on cell viability. For instance, when regular biocide applications were made upstream of the monitoring point, no improvement in filtration was observed, even though a significant reduction in viable cell counts, biogenically produced H2S and iron sulfide occurred. Laboratory filtration tests indicated that hydraulic fracturing polymer and water clarifier, present in the injection water, could also reduce filterability. However, oxidizers and HCI, which could break these polymers in synthetic brine, had little effect on the filterability of field injection water. Scanning electron microscopic analysis showed that during filtration of the field injection water numerous bacterial cells were deposited onto the membrane surface and inserted into the pores, concomitant with the onset of plugging. Comparisons of bacterial cell concentration versus filterability in synthetic brine and in field injection water indicated a threshold for exponential impediment to filtration between 106 to 107 bacterial cells per ml. INTRODUCTION In oilfield water floods, considerable attention is given to the quality of the water injected into the formation to ensure that optimal injectivity is maintained and to prevent the occurrence of formation damage. Formation damage depends on the properties of the fluids and the geological porous media, and their respective interactions ~. During water flooding, suspended solids introduced into the formation via the injected water are a major cause of reduction in permeability of the formation rock. Thus formation damage can be caused by suspended silts, clays, scale, oil, or bacteria, which may be present in the injection water 2. The concept that bacteria present in the injection waters can contribute to formation damage has been well documented 3~. During the late 1950's and early 1960's several investigators identified bacteria as a critical factor contributing to formation damage and loss of injectivity 68. This can be the result of bacterial cells or products of their metabolism such as iron sulfide or the exopolymer slime that they produce. The exopolymer entraps particulates and adheres to the formation face, effectively plugging the pores 9. Resolution of this plugging often requires costly treatments involving combinations of acid and hypochlorite 9~, which may effectively break down the integrity of the exopolymer, but may not necessarily eliminate the bacterial cells themselves. Several reports in the literature document a threshold number of bacterial cells (between 106-10 z cells per ml), that if injected, can lead to plugging of the formation pores 3. This plugging can occur irrespective of cell viability. As a result, a simple biocide treatment of the water may not necessarily resolve the problem. Instead, a strategy must be devised to mitigate the microbial problem at the source.
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.55)
- North America > United States > California > Los Angeles Basin (0.99)
- South America > Brazil > Parnaiba Basin > Block PN-T-68 > California Field (0.97)
ABSTRACT Sea water injection systems have traditionally been treated with biocide to inhibit growth of sulfate reducing bacteria (SRB) and reduce microbial induced corrosion (MIC). Laboratory experiments have shown that nitrate treatment can be an effective alternative to biocide treatment to reduce the number and activity of SRB. Based on such experiments the decision was made to implement nitrate treatment to the injection water on the oil platform Veslefrikk (North Sea). Addition of low dose of nitrate resulted in a decrease in the amount and activity of SRB in the water injection system. After 4 months nitrate addition, the activity of SRB in biofilm samples were strongly reduced. Corresponding to the decrease in SRB, an enrichment of nitrate reducing bacteria (NRB) was observed. After 32 months nitrate treatment SRB numbers were reduced 20 000 fold and SRB activity 50 fold. Corrosion measurements on metal coupons showed a decrease in weight loss from 0.7 mm/year to 0.2 mm/year. The results show that nitrate treatment can efficiently inhibit growth of SRB and control MIC in C-steel top side sea water injection sy stems. As opposed to the use of biocides such as glutaraldehyde, nitrate does not represent health hazard to platform personnel. Glutaraldehyde is classified as "Toxic" and may cause allergy to personnel handling the chemical. Inorganic nitrate salts have no negative environmental implications. INTRODUCTION At Veslefrikk sea water is injected into the oil reservoir in order to maintain reservoir pressure. In this process oxygen is removed in an attempt to minimise corrosion. This produces ananoxic environment that due to access of sulfate selects towards sulfate reducing bacteria (SRB). By anaerobe respiration with sulfate SRB produce the highly toxic and corrosive gas hydrogen sulfide (H2S). The growth of SRB in injection pipelines causes corrosion of iron and steel alloys. Laboratory experiments with oil reservoir model column have shown that injection of nitrate inhibits sulfide production 1. Nitrate reducing bacteria (NRB) reduce nitrate to N2, where the first step in the reaction is reduction of nitrate to nitrite. SRB is believed to be inhibited by nitrite and an increased redox potential due to chemical oxidation of sulfide by nitrite.
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > Block 30/6 > Veslefrikk Field > Statfjord Group Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > Block 30/6 > Veslefrikk Field > Dunlin Group Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > Block 30/6 > Veslefrikk Field > Brent Group Formation (0.99)
- (11 more...)
ABSTRACT The application of biocides to inhibit SRB in offshore seawater injection systems has generally been controlled by budgetary requirements rather than chemical effectiveness. This has led to many systems in the North Sea becoming heavily contaminated by SRB (resulting in MIC and reservoir souring) despite the regular application of biocide chemicals over years of operation. With many platforms now remaining in production several years over their anticipated lifetime, greater emphasis is placed on preventative maintenance. As a result, operators are now looking for assurance that failures due to MIC can be minimised by effective treatment. This has resulted in an emphasis on biocide efficacy as the main criteria, although naturally cost considerations remain vitally important. A microbiological audit performed in April 1997 showed high numbers (10 ~ per cm 2) of sessile SRB and high general corrosion rates on corrosion coupons in the Magnus water injection system. In response to this an MIC control plan was put in place, requiring a more robust biocide dosing programme. By April 2000, SRB numbers at the same location were 102 per cm 2 and corrosion rates were significantly decreased. Following from this success, an attempt was made to reduce the cost of biocide treatment by reducing the frequency of additions. This project utilised the results from a biofilm monitoring device for routine sessile monitoring. An audit in April 2000 showed that planktonic SRB numbers had increased indicating biofilm formation in the deaerators. The biocide application was immediately returned to the weekly treatment. This paper demonstrates that prior to biocide efficacy being the controlling factor, SRB inhibition was not effective. Once the emphasis was changed to biocide efficacy, SRB were inhibited and corrosion rates decreased. However, once budgetary control was reinstated, SRB numbers started to increase again. INTRODUCTION The injection of seawater to maintain reservoir pressure during oil winning operations has been standard practice in most oilfields in the North Sea for the past 30 years. Problems due to bacterial growth, in particular the growth of Sulphate-reducing Bacteria (SRB), have been encountered [1]. Typically, the problems are manifest in MIC [2] and reservoir souring [3] due to the production of hydrogen sulphide by the SRB. In order to control SRB growth, organic biocides are routinely batch dosed. It is extremely difficult to estimate the actual cost of corrosion attributable to the activity of SRB in the offshore oil industry. However, even individual failures attributed to SRB in recent years have resulted in costs of $10 - $45 million for remedial action and replacement of failed equipment. The costs involved in attempting to control SRB activity are also significant, with annual budgets of $150,000 per platform for biocide chemicals alone not unusual.
- North America > United States (0.68)
- Europe > United Kingdom > North Sea (0.45)
- Europe > Norway > North Sea (0.45)
- (3 more...)
- Water & Waste Management > Water Management > Constituents > Treated Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
INTRODUCTION ABSTRACT Reservoir souring commonly occurs in oilfields after waterflooding for secondary oil recovery. This is due to the activity of sulfate reducing bacteria (SRB) in the reservoir, which use nutrients from formation and/or injected water to generate sulfide. Conventional bactericide treatments may exert limited SRB control downhole. An alternative is the use of nitrate, encouraging the growth of nitrate utilizing bacteria to inhibit sulfide production by SRB. Laboratory tests were undertaken to determine the optimum nitrate treatment regime for a fractured chalk reservoir, including investigations into the potential for damaging effects such as corrosion, formation impairment, biofouling and solids removal or re-deposition. Upon completion of these tests, nitrate was dosed into the injection water on the Skjold field in the Danish sector of the North Sea. In one well pair with a short breakthrough time a reduction in HzS production of some 80 % was achieved. However, in less fractured regions with longer breakthrough times, the reduction in HzS concentration in the production was much less pronounced. The Skjold oilfield is located in the Danish Sector of the North Sea and is operated by Maersk Oil and Gas AS. Production of oil and gas commenced in 1982. Two wellhead platforms are installed in the Skjold field but control and operation are conducted from the nearby Gorm Platform where the Skjold production is processed. Water injection (primarily seawater), to maintain reservoir pressure, was commenced in 1985. The producing horizon is Maastrichtian Age Chalk. Skjold is a dome shaped chalk reservoir with a low matrix permeability of<1 mD (<10 -9 m 2) and a high, but variable, degree of naturally occurring fractures. The reservoir temperature and pressure are typically 80ยฐC and 3100 psi (21.4 MPa). The field is completed with 20 producers and 8 water injectors. All injection wells, except one, are completed in the water zone but, due to the fractured nature of the reservoir, injection water breakthrough times can be very short. In particular, the water injector Skjold-7 is connected, via fractures, to the producer Skjold-12 and the transit time between the injector and the producer, is only a few hours. The first recorded H2S production was in September 1985, following the start-up of water injection in April 1985 with Skjold-2 showing 1.8 ppm HzS in the gas phase. Seawater breakthrough occurred 1991 and the HzS production has increased steadily since that time. Presently, the wellhead H2S concentration in the produced gas varies between 10 ppm and 1000 ppm. ] Produced H2S data are expressed in terms of total kg/day in all three phases rather than ppm in the gas phase, avoiding misleading patterns due to changing ratios between gas, liftgas, oil and water. The HzS concentration in the gas phase is measured using Drgger tubes. The H2S concentrations in the liquid phases are then calculated using a PVT simulator. The total HzS production is calculated based on mass flow rates from well tests. Figure 1 shows that the produced HzS mass flow increased from 100 kg/day in 1994 to the present level of 700 kg/day. However, fluctuations in the HzS production pattern have been observed with a maximum HzS production of 1150 kg/day in late 1999. A
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Constituents > Bacteria (0.61)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.57)
- Europe > Denmark > North Sea > Danish Sector > Central Graben > Block 5504/16 > Skjold Field > Zechstein Formation (0.99)
- Europe > Denmark > North Sea > Danish Sector > Central Graben > Block 5504/16 > Gorm Field (0.94)
- Europe > Denmark > North Sea > Danish Sector > Central Graben > Block 5504/15 > Gorm Field (0.94)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Health, Safety, Environment & Sustainability > Health > Noise, chemicals, and other workplace hazards (1.00)
ABSTRACT Reducing the sulfate content of injected seawater will significantly reduce the ability of sulfate reducing bacteria to produce hydrogen sulfide. This paper documents research and development performed over a period of five years that suggests treatment of seawater by nanofiltration membranes deserves serious consideration as a methodology to control reservoir souring. Comparison of the effects of injected raw and desulfated seawater on hydrogen sulfide production is demonstrated by reservoir simulation methodology. INTRODUCTION Historically, oil reservoirs found to be 'sweet' at discovery usually turn sour after seawater is injected for pressure maintenance 1. The reason for this is that indigenous sulfate reducing bacteria or SRB injected with the seawater metabolize low molecular weight volatile fatty acids (VFAs; formic, acetic, propionic and butyric) in the formation water and in combination with the sulfate from seawater, the SRBs convert the sulfate to sulfide (hydrogen sulfide). This phenomena is referred to as 'reservoir souring'. The production of hydrogen sulfide may cause a variety of problems for the operator: corrosion, unsaleable gas, health hazards, etc. Any and or all of these associated problems can be (1) Consultant to Pratt Technology Management, Formerly Manager of Commercial Technology for Marathon Oil, Littleton, CO 80122 7 costly, and when encountered offshore in confined spaces, sometimes deadly. To prevent or minimize the process of reservoir souring, the operator usually treats the injected seawater with biocides to kill the SRBs. This treatment can take various forms, from continuously injected biocide to shock treatments applied on a periodic basis. Other methods that have been applied include a novel approach utilizing ultraviolet light 2 to kill SRBs in injected seawater. For reservoirs already soured, hydrogen sulfide must be scavenged from the produced fluids to render the hydrocarbon gas saleable. Spraying chemicals (triazines) into the gas phase downstream of the separators has been utilized as well as the injection of acrolein 3. The main difficulty with dealing with SRBs once they are flourishing is the inability to contact them in the reservoir environment. Even high kill rates leave some SRB to reproduce themselves and eventually the souring problem returns. Once souring has commenced, the operator will more than likely have to deal with it for the economic lifetime of the oil- producing reservoir.
- Europe > United Kingdom > North Sea (0.46)
- North America > United States > California (0.46)
- Europe > United Kingdom > England (0.46)
- North America > United States > Colorado > Arapahoe County > Littleton (0.24)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 3/8 > Ninian Field > Brent Group Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 3/3 > Ninian Field > Brent Group Formation (0.99)
- Africa > Angola > South Atlantic Ocean > Lower Congo Basin > Block 17 > Girassol Field (0.99)
- (5 more...)
Impact of Molecular Biology Techniques on the Detection and Characterization of Microorganisms and Biofilms Involved in MIC
Le Borgne, Silvie (Instituto Mexicano del Petrole) | Jan, Janet (Instituto Mexicano del Petrole) | Romero, Juan M. (Instituto Mexicano del Petrole) | Amaya, Manuel (Instituto Mexicano del Petrole)
ABSTRACT Recently, the application of molecular techniques has greatly improved our knowledge of microbial diversity and distribution in environmental samples. In this paper, we have reviewed the molecular biology techniques that can be used to study microorganisms and biofilms involved in the MIC phenomenon. These techniques include 16S ribosomal DNA (16S rDNA) gene based techniques. In particular, 16S rDNA sequencing, the construction of 16S rDNAs libraries, Fluorescence In Situ Hybridization (FISH), Denaturing Gradient Gel Electrophoresis (DGGE) and Random Amplification of Polymorphic DNA (RAPD) are techniques which can be used to identify and detect bacteria, as well as, to monitor bacteria organized in complex MIC biofilms. In addition to 16S rDNA, the RAPD technique can be applied to obtain probes for detecting bacteria involved in MIC, without any information concerning the bacteria of interest. These techniques can greatly improve our knowledge about MIC. INTRODUCTION Many bacteria inhabit oil and gas production and refining facilities. Some of them have a negative effect on the petroleum industry since they are responsible for biofouling and biocorrosion. In particular, biocorrosion or microbiologically influenced corrosion (MIC) is a serious problem, which has a great economical significance in this industry. Offshore water injection systems used for petroleum secondary recovery are particularly vulnerable to MIC since they transport non-sterile seawater that contains a wide variety of microorganisms able to form biofilms, which influence corrosion through a cooperative global metabolism on metallic surfaces 1' MIC problems are even more relevant in tropical marine environments where the warm water favors a high microbial diversity. In offshore water injection systems, the microorganisms generally involved in MIC are bacteria. Sulfate-reducing bacteria (SRB) have been widely implicated in the anaerobic corrosion of metals and consequently they are the most extensively studied group of bacteria associated with MIC 3. However, aerobic bacteria are also known to participate in MIC 4. Indeed, we previously isolated several aerobic corroding bacteria in an offshore water injection system located in the Gulf of Mexico that were involved in MIC 5' 6. Precise identification of key microorganisms involved in MIC is essential for the design of novel protective coatings and biocides that provide long-term, efficient protection against corrosion of metals in situ. Our studies indicated that some of the isolated strains could not be identified by classical biochemical tests based on culture-dependent methods. 16S ribosomal DNA gene (16S rDNA) sequencing was performed in order to identify these microorganisms. Novel bacteria can be identified by this method.
- Overview (0.48)
- Research Report (0.34)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Constituents > Bacteria (0.88)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
ABSTRACT The seawater nanofiltration process removes the sulfate component in injected seawater for oilfield waterflood operations. Benefits of the sulfate removal process include oil flow assurance by the elimination of scaling and well souring caused by the conversion of the sulfate to hydrogen sulfide by thermophilic sulfate reducing bacteria. Since its initial use on the Brae Alpha Platform in the North Sea for scale control, the nanofiltration process has found applications in other oilfield applications, has had technology improvements that have reduced its cost, and has provided exceptional benefits in complex reservoir developments. INTRODUCTION Early in the South Brae oil reservoir development, Marathon Oil realized that pressure maintenance with seawater would be required over the reservoir life. It was also discovered that the Brae reservoirs contained between 800 and 2,500 rag/1 barium in the formation water. By injecting seawater containing approximately 2,700 mg/1 sulfate into these reservoirs, severe scaling potential was anticipated due to the reaction of the sulfate in the seawater with the barium in the formation water. This was further complicated by the presence of radioactive radium 226 and 228 in the Brae formation water. Since the radium would also be precipitated by the sulfate in the injected seawater, a combination of barium and radioactive radium sulfate would be formed. This combination would (1~ Consultant to Pratt Technology Management, Formerly Manager of Commercial Technology for Marathon Oil. Littleton, CO 80122 result in a NORM (Naturally Occurring Radioactive Material) scale which presented handling, safety, and disposal problems. In addition, production tubulars completely blocked with scale were removed and taken to shore where the NORM scale could be milled from the tubing. Needless to say, this resulted in expensive workovers. With the high levels of barium in the Brae formation water, existing scale inhibitors simply were stretched beyond their capabilities and unable to prevent the precipitation of barium sulphate and resultant scaling. Further complicating factors associated with the Brae reservoir in the use of existing scale inhibitors, were the low pH of the formation water and high calcium levels 1. In an effort overcome these difficulties with the existing scale inhibitors, a series of sulphonate-based inhibitors, which would better meet the demanding requirements of the Brae reservoir, were developed. In addition to the improved sulphonate based inhibitors that worked well at reduced sulfate concentrations, Brae operations additionally took an innovative approach by examining the possibility of removing the sulfate from the injected seawater in order to render the sulfate scale problem manageable 2. Hence, the source of the scaling was dramatically reduced versus the traditional approach of attempting to control its precipitation in the supersaturated barium sulfate formation water entirely with scale inhibitors.
- Europe > United Kingdom > North Sea > Central North Sea (1.00)
- North America > United States > Colorado > Arapahoe County > Littleton (0.24)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (0.97)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Block P-36 > Roncador Field > Maastrichtian Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > South Viking Graben > Brae Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Moray Firth Basin > Witch Ground Graben > P.213 > Block 16/26a > Brae Field > Alba Field > Caran Sandstone Formation (0.99)
- (12 more...)