Seawater Injection Research Articles

Interfacial rheological insights of sulfate-enriched smart-water at low and high-salinity in carbonates

Lowering the injection water salinity or modifying its chemistry can improve waterflooding displacement efficiency. This water modification has been frequently alluded to increase rock water-wetness. However, the presence of sulfate anions in the aqueous phase is shown here to also alter the crude oil–water interfacial rheology drastically, in ways similar to that associated to the reduction of water salinity. Under the right conditions, oil recovery could, in principle, be increased to a considerably degree by alteration of fluid–fluid interactions at high salinity. The purpose of this research is to contrast oil recovery behavior in cases when smart-water is designed based on either increasing the sulfate anion concentration in a high-salinity brine or by decreasing salinity considerably, when using seawater as the base aqueous phase. Interfacial rheological and coreflooding results are compared to the case of seawater injection. The effect of various ions on the interfacial shear rheological response of several crude oils and modified seawater were examined. Carefully designed corefloods using Indiana Limestone were run to evaluate the effect of each brine on recovery behavior. Mild temperature and short ageing time were imposed to hinder wettability alteration. Interfacial rheological results show that the visco-elasticity of the crude oil-brine interface is higher for a low-salinity brine compared to the higher-salinity counterpart represented by seawater. However, when the sulfate anion concentration is increased, the interfacial visco-elasticity increases noticeably. Coreflooding results show that brines leading to more a visco-elastic interface, including low salinity and sulfated seawater, yield higher oil recovery factor. Ion analysis of the effluent brine shows that for the model rock used, brine composition does not change significantly from contact with rock surfaces. The recovery response is found to be consistent with changes in interfacial rheology. After the injection of high salinity smart-water in secondary mode, the low-salinity water injection in tertiary mode apparently triggers connection and mobilization of oil ganglia, as hypothesized from the recovery response. Tracking water droplet size distribution seems to support this hypothesis. Low-salinity brine injection is generally conducive to increasing oil production. On the other hand, our findings reveal that the injection of sulfate-enriched water can modify fluid–fluid interactions and consequently the final oil recovery. However, this smart-water appears to lose effectiveness entirely, if injected as residual oil saturation is reached, indicating an apparent threshold in the oil saturation to draw benefits of high-salinity sulfated-water.

Modeling of Geochemical Reactions Occurring in the Gyda Field Under Cold-Seawater Injection on the Basis of Produced-Water-Chemistry Data and Implications for Scale Management

Summary The evidence from the produced-brine chemistry suggests that the Gyda field has experienced a variety of geochemical reactions caused by the high temperature and initial calcium (Ca) concentration, and so it is worth reviewing the produced-water data set and studying what in-situ geochemical reactions may be taking place. Produced-brine-chemistry data from 16 wells in the Gyda field are plotted and analyzed in combination with general geological information and the reservoir description. A 1D reactive-transport model is developed to identify the possible geochemical reactions occurring within the reservoir triggered by seawater injection, and then extended with the inclusion of thermal modeling and also to be a 2D vertical-cross-section model. Three possible classes of formation-water composition in different regions of the Gyda field have been identified by analysis of the produced-water data set. Anhydrite and barite precipitation are the two dominant mineral reactions taking place deep within the reservoir. Magnesium (Mg) stripping may be a result of multicomponent ion exchange (MIE), dolomite precipitation, or a combination of both. Reservoir temperature is lowered during cold-water injection. The solubility of anhydrite increases at lower temperature, and anhydrite will gradually dissolve in response to the movement of the temperature front, which is much slower than the formation/injection-water mixing front. The extent of mineral precipitation within the reservoir can be reduced by the heterogeneity; the modeling shows that the extent of ion stripping caused by mineral reactions in the reservoir is greatest when simulating a single uniform layer. Brine mixing and the occurrence of geochemical reactions caused by vertical mixing are not observable, even when assigning a high vertical permeability in a heterogeneous model. Thermal modeling is included to evaluate the effect of nonisothermal processes and heat transport on the geochemical reactions, especially the anhydrite mineral reaction. We have investigated how the difference in horizontal permeability in the two layers affects brine mixing of formation and injection water and geochemical reactions.

東京電力株式会社福島第一原子力発電所への海水及び／又は淡水の注入に伴う使用済燃料プールの水質変化挙動解析

海水及び／又は淡水が注入された東京電力福島第一原子力発電所の使用済燃料プールのpH，Cl－濃度及び電気伝導率κの測定結果から，炭素鋼などの腐食に影響するSO42－及びHCO3－の濃度を解析により推定した．

An Experimental Study on the Dispersion Characteristics of Seawater Injection Nozzle for Hull Cooling

An Experimental Study on the Dispersion Characteristics of Seawater Injection Nozzle for Hull Cooling

Preproduction-Deployed Scale-Inhibition Treatments in Deepwater West Africa

Summary The injection of seawater into oil-bearing reservoirs for the purposes of maintaining reservoir pressure and improving secondary recovery is a well-established, mature operation. Moreover, the degree of risk posed by deposition of mineral scales (carbonate/sulfate) to the injection and production wells during such operations has been much studied. The current deepwater subsea developments offshore West Africa and Brazil have brought into sharp focus the need to manage scale in an effective way. In a deepwater West African field, the relatively small number of high-cost, highly productive wells, coupled with a high barium sulfate scaling tendency upon breakthrough of injection seawater, meant that effective scale management was critical to achieving high hydrocarbon recovery and that even wells at low water cuts have proved to be at sufficient risk to require early squeeze application. To provide effective scale control in these wells at low water cuts, phosphonate-based inhibitors were applied as part of the acid-perforation wash and overflush stages before frac-packing operations. The deployment of this inhibitor proved effective in controlling barium sulfate scale formation during initial water production, eliminating the need to scale squeeze the wells at low water cuts (<10% basic sediment and water). To increase the volumes of scale inhibitor (SI) being deployed in the preproduction treatments and so extend the treatment lifetimes, SI was also added to the fracturing gel used to carry the fracturing sand. This paper outlines the selection methods for the inhibitor chemical for application in fracturing fluids in terms of rheology, retention/release, and formation damage, and presents the chemical-return profiles from the five wells treated (some treatments lasting longer than 300 days), along with the monitoring methods used to confirm scale control in the treated wells. Many similar fields are currently being developed in the Campos Basin, Gulf of Mexico, and West Africa, and this paper is a good example of best-practice sharing from another oil basin.

The Johan Sverdrup Field: Origin of Sulfate-Rich Formation Water and Impact on Scale-Management Strategy

Summary The Johan Sverdrup field will, at maximum, contribute 25% of the total oil production from the Norwegian Continental Shelf (NCS). Plateau production from the fully developed field is estimated at 550,000 to 650,000 BOE/D. Geochemical formation-water interpretation and development of a scale-management strategy have been performed to ensure high well productivity and process regularity of the field. Uncertainty over the composition of formation water made the decision to inject normal seawater or low-sulfate seawater into the reservoir for pressure support a challenge. Water compositions in samples obtained from appraisal wells were unusual for the Norwegian North Sea, being sulfate-rich with negligible barium. This was suspected to be an artifact of drilling-fluid contamination, and corrections were applied to obtain representative estimates. These estimates confirmed that the formation waters had variable salinity (21–48 g/L chloride), and were indeed sulfate-rich (94–746 mg/L) and barium-depleted (< 6 mg/L). The compositions may reflect (a) mixing of formation waters across the field over geological time and/or (b) interactions with the underlying Zechstein group (anhydrite). The focus here is on issue (b) because a detailed evaluation of local/regional aquifer movements in geological time, communication patterns, and flow restrictions is beyond the scope of this paper. Three appraisal wells in the Geitungen Terrace showed barium-rich formation water outside the main reservoir area where no underlying Zechstein group was present. Initially, there were concerns about the scaling risks associated with mixing sulfate- and barium-rich formation waters. However, present geological understanding indicates insignificant aquifer volumes with barium, implying that full-field development and scale strategy do not need to consider barium-rich water. Scale predictions were performed for various strategies: formation-water production, seawater injection, produced-water reinjection, and low-salinity/low-sulfate-water injection. Moderate strontium sulfate (SrSO4) and calcium carbonate (CaCO3) scalings are expected in the production wells. If third-party barium-rich waters are tied in, the topside barium sulfate (BaSO4) scaling risk increases. This work has shown Careful evaluation of formation-water samples/analyses reduces uncertainties associated with water compositions and increases confidence in results and decisions. Underlying geology can influence formation-water compositions. Good-quality water sampling is important for later-phase field development and scale management. The implications for field development are Seawater will be injected into the reservoir for pressure support, with no need for a sulfate-removal plant. Produced-water reinjection will gradually replace seawater to minimize environmental impact. Downhole scale-inhibitor injection has been recommended to protect the upper completion.

Microbial community analysis of three hydrocarbon reservoir cores provides valuable insights for the assessment of reservoir souring potential

Three hydrocarbon reservoir cores were obtained from a high temperature non-waterflooded offshore reservoir. All three cores were taken from a 56-m section of the same well. Under sterile conditions, DNA was recovered from the inner section of each core and the microbial community profiles were deduced by sequencing the 16S rRNA marker gene. Taxonomic analysis of the Operational Taxonomic Units (OTUs) recovered, identified a high proportion of members from the Oxalobacteraceae family (38.5%) followed by members from the Pseudomonadaceae and Comamonadaceae families (29.1% and 12.8% respectively). Representatives of all these families are known to degrade hydrocarbons as well as to use nitrate as a terminal electron acceptor under anaerobic conditions. Assuming these predominant microorganisms are indigenous to the reservoir and have not been introduced with the drilling fluids they might exhibit a relatively rapid response to nitrate injection for souring control. On the contrary, very few sulfate reducing bacteria (SRBs) were detected in these cores (<0.01%) suggesting unfavorable conditions to SRB growth. This however may well rapidly change upon seawater injections in the absence of nitrate addition.This study sets the microbial profiling “baseline” for the prediction of souring through modelling as well as for any upcoming biomonitoring surveys.

Using high- and low-salinity seawater injection to maintain the oil reservoir pressure without damage

The oil reservoir pressure declines due to oil production, and this decline will lead to reduction in the oil productivity. The reservoir pressure maintenance is a practice in the oil industry in which seawater is injected into the aquifer zone below the oil zone to support the reservoir pressure. Calcium sulfate scale is one of the most serious oilfield problems that could be formed in sandstone and carbonate reservoirs. Calcium sulfate may precipitate during the injection of seawater with high sulfate content into formation brine with high calcium content. Mixing seawater and formation water may cause precipitation of calcium sulfate, barium sulfate, and/or strontium sulfate. Seawater treatment does not remove the entire sulfate ions from the injected water. Low sulfate concentrations may cause damage. Enhanced oil recovery processes such as smart water injection, which originally is diluted seawater, may cause calcium sulfate precipitation as the reduction of water salinity will increase the sulfate precipitation and decrease its solubility. This study was conducted to investigate the damage caused by the deposition of calcium sulfate precipitation. A solution is proposed to prevent the damage due to calcium sulfate by using chelating agents. Several coreflooding experiments were conducted using Berea sandstone and Indiana limestone cores at reservoir conditions of pressure and temperature using seawater (high and low salinity) and formation water. Chelating agents used in this study are: EDTA (ethylenediaminetetraacetic acid), HEDTA (hydroxyethylenediaminetriacetic acid), and HEIDA (hydroxyethyliminodiacetic acid). HEDTA and HEIDA chelating gents are environmentally friendly and can be used in marine environment. High-salinity water injection caused severe formation damage, and the injectivity will decline faster compared to the low-salinity water injection. HEDTA and EDTA chelating agents at low concentrations performed better than HEIDA chelating agents in both Berea sandstone and Indiana limestone cores. HEDTA and EDTA chelating agents were able to prevent the damage due to calcium sulfate precipitation and enhanced the core permeability.

Mineral Precipitation Kinetics: Assessing the Effect of Hydrostatic Pressure and Its Implication on the Nucleation Mechanism

Sulfate minerals (barite, anhydrite, and celestite) can be a technological hindrance as a result of scale formation especially for operations where seawater injection is involved. The effect of pH, temperature, and saturation index (SI) on sulfate mineral nucleation and growth are fairly well-known, but the influence of pressure on the nucleation kinetics has attracted no attention. Here we show that nucleation kinetics of barite, anhydrite, and celestite is highly dependent on hydrostatic pressure applied even under constant thermodynamic driving force, that is, at the same supersaturation level. Activation parameters of barite nucleation kinetics were calculated, and measured values are in agreement with literature. The negative activation volume measured suggests that barite nucleation from hydrated Ba2+ and SO42– ions is coupled to an overall volume decrease, albeit a large volume increase due to dehydration is expected. The results indicate that nucleation is not controlled by desolvation of solvated...

Tracing Artificially Recharged Groundwater using Water and Carbon Isotopes

AbstractWe conducted an isotopic analysis of groundwater in Orange County, California, USA, around the Talbert Seawater Injection Barrier to determine if recycled water, used to artificially recharge local aquifers, carries a unique isotopic signature that can be used as a tracer. From September 2014 to April 2015, we collected groundwater from six privately owned wells within the coastal groundwater basin, along with various surface waters. All water samples were analyzed for their stable isotopic composition (δ18O, δD), the δ13C and14C signature of the dissolved inorganic carbon (DIC) pool, DIC concentration, pH, and salinity. The DIC of groundwater mixing with recycled water is enriched in14C above natural background levels, with varying signal strength through time, depleted in δ13C, and low in DIC concentration. Water isotopes further suggest that recycled water is a mixture of Colorado River water and regional groundwater. In contrast, groundwater found further away from the injection barrier has carbon and water isotope composition consistent with regional groundwater and Santa Ana River water. Our findings imply that recycled water injected through the Talbert Barrier is isotopically unique, and that14C enrichment may be used as an intrinsic tracer of artificial recharge within the basin.

Single-Well Chemical-Tracer Modeling of Low-Salinity-Water Injection in Carbonates

Summary The interest in low-salinity-water injection (LSWI) compared with seawater injection or high-salinity-produced-brine injection is increasing in both laboratory and field tests. The single-well chemical-tracer test (SWCTT) is also becoming increasingly popular as an in-situ test to assess the reduction in oil saturation caused by an enhanced-oil-recovery (EOR) process. Hence, accurate modeling of SWCTTs is essential. In this paper, modeling and simulation of the SWCTT of LSWI in a carbonate reservoir is investigated by use of the UTCHEM reservoir simulator, a nonisothermal, 3D, multiphase, multicomponent, chemical compositional simulator developed at the University of Texas at Austin (UTCHEM 2011). Both radial- and Cartesian-grid models are set up for a field-scale pilot by use of measured rock and fluid data of a Middle Eastern reservoir. Tracer reactions and the empirical LSWI model implemented in UTCHEM are used to estimate residual oil saturation (ROS) as a result of LSWI. Two approaches are used to estimate ROS to LSWI, including analytical and numerical methods. Results show that both approaches give consistent values for ROS for homogeneous radial- and Cartesian-grid models. The two approaches were inconsistent for the multilayer radial model, which highlights the necessity of the use of numerical approaches for layered reservoirs. The Cartesian-grid model was used to investigate the effect of heterogeneity on SWCTT results, where a new numerical approach is proposed for estimating ROS. This finding validates the approach used and the implementation of both tracer reactions and the LSWI model in UTCHEM. The proposed approach can now be used to estimate ROS of the SWCTT for reservoirs with different degrees of heterogeneity, which provides a clear insight into reservoir performance before planning multiwell demonstration pilots.

Experimental Study of Silver Cathode for Electrochemical Deoxygenation of Seawater for Enhanced Oil Recovery

Seawater injection into reservoirs is a common method to enhance oil recovery. In order to avoid corrosion in pipes, the oxygen has to be removed from the seawater. This study focuses on the use of silver cathodes in electrochemical cells for oxygen removal, and the physical parameters that affect the efficiency of this process. Three electrochemical cells have been constructed and tested with packed bed cathodes made up of pure silver particles and silver plated brass spheres. Experimental results showed that silver was a suitable cathode material for oxygen removal. The most important parameter for optimizing cell performance was the depth of the cathode chamber. In addition, the thickness of the silver plating is also an important parameter to adjust since a too-thin layer results in erosion giving rise to galvanic corrosion between brass and silver, which reduces the efficiency of the cell.

Mineralogical compositions of Late Permian coals from the Yueliangtian mine, western Guizhou, China: Comparison to coals from eastern Yunnan, with an emphasis on the origin of the minerals

This paper reports the mineralogical characteristics of a complete coal seam in the Late Permian Longtan Formation from the Yueliangtian mine, western Guizhou, southwestern China. The minerals in the coal were identified using optical microscopy, scanning electron microscopy with an energy dispersive X-ray spectrometer (SEM–EDS), and low temperature ashing plus X-ray diffraction (LTA+XRD). The results show that quartz and kaolinite are the major components of the coal mineral matter; followed by pyrite, marcasite, anatase, and calcite; and in some cases, mixed-layer illite/smectite, chamosite, illite, ankerite, apatite, and anorthite. The highly-elevated concentration of quartz in the coal is mostly derived from siliceous solutions produced by weathering of the Emeishan basalt. However, quartz discrete particles with large size (>100μm) and rounded shape probably resulted from the input of felsic rock materials. The distribution and modes of occurrence of kaolinite, mixed-layer illite/smectite, illite, and anatase reflect a terrigenous origin. In comparison with the coals from eastern Yunnan, the Yueliangtian coals have lower proportion of authigenic chamosite, the formation of which was probably related to the injection of seawater. Pyrite occurring as individual particles or clustered framboids was most likely influenced by seawater during the stages of peat accumulation or early diagenesis, while fracture-filling pyrite probably had an epigenetic origin. Additionally, an intra-seam volcanic ash-derived tonstein layer, which contains sharp-edged quartz, vermicular kaolinite, and well-developed zircon crystals, has been identified in the coal of the present study.

Implications of Limited Thermophilicity of Nitrite Reduction for Control of Sulfide Production in Oil Reservoirs.

Nitrate reduction to nitrite in oil fields appears to be more thermophilic than the subsequent reduction of nitrite. Concentrated microbial consortia from oil fields reduced both nitrate and nitrite at 40 and 45°C but only nitrate at and above 50°C. The abundance of the nirS gene correlated with mesophilic nitrite reduction activity. Thauera and Pseudomonas were the dominant mesophilic nitrate-reducing bacteria (mNRB), whereas Petrobacter and Geobacillus were the dominant thermophilic NRB (tNRB) in these consortia. The mNRB Thauera sp. strain TK001, isolated in this study, reduced nitrate and nitrite at 40 and 45°C but not at 50°C, whereas the tNRB Petrobacter sp. strain TK002 and Geobacillus sp. strain TK003 reduced nitrate to nitrite but did not reduce nitrite further from 50 to 70°C. Testing of 12 deposited pure cultures of tNRB with 4 electron donors indicated reduction of nitrate in 40 of 48 and reduction of nitrite in only 9 of 48 incubations. Nitrate is injected into high-temperature oil fields to prevent sulfide formation (souring) by sulfate-reducing bacteria (SRB), which are strongly inhibited by nitrite. Injection of cold seawater to produce oil creates mesothermic zones. Our results suggest that preventing the temperature of these zones from dropping below 50°C will limit the reduction of nitrite, allowing more effective souring control. Nitrite can accumulate at temperatures of 50 to 70°C, because nitrate reduction extends to higher temperatures than the subsequent reduction of nitrite. This is important for understanding the fundamentals of thermophilicity and for the control of souring in oil fields catalyzed by SRB, which are strongly inhibited by nitrite.

Potential of Low-Salinity Waterflood To Improve Oil Recovery in Carbonates: Demonstrating the Effect by Qualitative Coreflood

Summary Low-salinity waterflood (LSF) is a promising improved-oil-recovery (IOR) technology. Although, it was demonstrated that LSF is an efficient IOR method for many sandstone reservoirs, the potential of LSF in carbonate reservoirs is still not well-established because only a limited number of successful coreflood experiments are available in the literature. Therefore, the aim of this study was to examine the oil-recovery improvement by LSF in carbonate reservoirs by performing coreflood experiments. This paper proposes an experimental approach to qualitatively evaluate the potential of LSF to improve oil recovery and alter the rock wettability during coreflood experiments. The corefloods were conducted on core plugs from two Middle Eastern carbonate reservoirs with a wide variation of rock properties and reservoir conditions. Seawater (SW) and several dilutions of formation brine and SW were flooded in the tertiary mode to evaluate their impacts on oil recovery compared with formation-brine injection. In addition, a geochemical study was performed with PHREEQC software (Parkhurst and Appelo 1999) to assess the potential of calcite dissolution by LSF. The experimental results confirmed that lowering the water salinity can alter the rock wettability toward more water-wet, causing improvement of oil recovery in tertiary waterflood in plugs from the two reservoirs. Furthermore, SW is more-favorable for improved oil recovery than formation brine because injection of SW after formation brine resulted in extra oil production. This demonstrates that the brine composition plays an important role during waterflooding in carbonate reservoirs, and not only the brine salinity. It was also observed that oil recovery can be improved by injection of brines that cannot dissolve calcite on the basis of the geochemical modeling study. This implies that calcite dissolution is not the dominant mechanism of IOR by LSF. To conclude, this paper demonstrates that LSF has a good potential as an IOR technology in carbonate reservoirs. In addition, the proposed experimental approach ensures the verification of LSF effect, either it is positive or negative. However, further research is required to explore the optimum salinity and composition and the most-influential parameters affecting LSF response.

Efficiency of calcein tagging on juveniles of the sea urchins Diadema africanum and Paracentrotus lividus

AbstractWe evaluated the effectiveness of chemical tagging with the fluorescent marker calcein for two key species of herbivorous sea urchins, Diadema africanum and Paracentrotus lividus, to facilitate medium‐ and long‐term ecological experiments. In total, 98 juveniles of D. africanum and 98 P. lividus were tagged with this fluorescent marker, with 12 combinations of different tagging techniques (chemical bath or injection), concentrations of calcein (2, 10 and 20 mg · l−1), and soaking times (2, 4 and 24 h). Respective control treatments were conducted by means of seawater injection and bathing. The success of tagging was assessed after a month of feeding individuals ad libitum with the algae Dictyota sp. Sea urchins were dissected and their Aristotle's lanterns cleaned with 10% sodium hypochlorite to examine these structures under UV light using a binocular microscope. Each species was evaluated in terms of survival, percentage of tagged individuals and intensity of the resulting tag. The results showed that the method of soaking individuals of both species for 24 h in concentrations of calcein of 10 and 20 mg · l−1 gave the highest percentage survival (100%) and the resulting tags were clearly visible.

Root Cause Failure Analysis and Mitigation of Corrosion in Seawater Injection Piping

This paper illustrates the methodology for performing a root cause failure analysis of corrosion anomalies reported in the low pressure section of an FPSO seawater injection piping system. Specific practical actions are recommended for mitigating the identified root causes of failure. The primary root cause of failure is oxygen corrosion due to oxygen ingress at components upstream (u/s) and downstream (d/s) of the sulfate removal (SRM) pumps. Oxygen corrosion was worsened by underdeposit corrosion caused by unavailability of coarse straining of abstracted seawater. The secondary root causes are likely due to: deterioration of graphite-filled gaskets on the flanges; occasional bisulphite overdosing; incorrectly specified oxygen scavenger; non-optimized scavenger injection rates; incorrect risk assessment; and unavailability of hypochlorination of abstracted seawater. This paper recommends that the primary and secondary root causes should be further investigated and mitigated. The less difficult but big-impact mitigations which should reduce significantly the number and severity of reported anomalies include: modeling corrosion (based on dissolved oxygen concentration inputs) with predicted velocities (V) guiding operational adjustments within the target range 2 < V < 10 m/s and the predicted cumulative corrosion rates used to target and optimize inspection requirements; inspecting and testing each component u/s and d/s of the SRM pump, in order to identify locations of oxygen ingress; and checking deaeration performance especially possible leaks along the vacuum pump system. Results of KPIs should comply with the specified targets and be managed as part of the corrosion management system.

Mechanical properties and corrosion resistance evaluation of superduplex stainless steel UNS S32760 repaired by GTAW process

Superduplex stainless steels (SDSSs) are alloys widely used in the exploration and production of oil. They are used in marine and offshore components such as heat exchangers, umbilicals, sea water injection lines and various other equipment that requires high corrosion resistance with elevated mechanical strength values. These characteristics are due to its fine two-phase microstructure composed of similar proportions of austenite and ferrite and the alloying elements of Cr, Ni, Mo, N and W. However, during welding, and also in the stages of fabrication and pipe assembly, the presence of defects may occur that requires the need for repair procedures to be carried out on the welded joint. This study aims to characterise the microstructure, mechanical properties, nitrogen content and critical pitting temperature (CPT) of a SDSS pipe, UNS S32760, in certain regions of a welded joint, where the gas tungsten arc welding process was performed, with the completion of two sequential repair procedures. The results show that there is a decrease in the value of the CPT at the root of the weld, though there are not substantial variations in the mechanical properties analysed.

Validation of Autonomous Microbe Sensor Prototype for Monitoring of Microorganisms in Injection Seawater Systems

Microbial growth in the water injection system is a well-known problem with severe operational and financial consequences for the petroleum industry, including microbiologically influenced corrosion (MIC), reduced injectivity, reservoir plugging, production downtime, and extensive repair costs. Monitoring of system microbiology is required in any mitigation strategy, enabling operators to apply and adjust countermeasures properly and in due time. In previous studies [1] [2], DNA staining technology with SYBR Green dye was evaluated to have a sufficient detection limit and automation potential for real-time detection of microbial activity in the Saudi Aramco injection seawater. In this study, technical requirements and design solutions were defined, and an autonomous microbe sensor (AMS) prototype was constructed, tested and optimized in the laboratory, and validated in the field for automated detection of microorganisms in the harsh Saudi Arabia desert environment and injection seawater. The AMS prototype was able to monitor and follow the general microbial status in the system, including detection of periods with increased microbial growth or decreased microbial numbers following biocide injection. The infield AMS detection limit was 105 cells/mL. The long-term field testing also identified the areas for technical improvement and optimization for further development of a more robust and better performing commercial microbial sensing device.

Optimization of DNA Staining Technology for Development of Autonomous Microbe Sensor for Injection Seawater Systems

Microbial activity in the water injection system in oil and gas industry leads to an array of challenges, including biofouling, injectivity loss, reservoir plugging, and microbiologically influenced corrosion (MIC). An effective mitigation strategy requires online and real-time monitoring of microbial activity and growth in the system so that the operators can apply and adjust counter-measures quickly and properly. The previous study [1] identified DNA staining technology-with PicoGreen and SYBR Green dyes—as a very promising method for automated, online determination of microbial cell abundance in the vast Saudi Aramco injection seawater systems. This study evaluated DNA staining technology on detection limit, automation potential, and temperature stability for the construction of automated sensor prototype. DNA staining with SYBR Green dye was determined to be better suited for online and real-time monitoring of microbial activity in the Saudi Aramco seawater systems. SYBR Green staining does not require sample pre-treatment, and the fluorescence signal intensity is more stable at elevated temperatures up to 30℃. The lower detection limit of 2 × 103/ml was achieved under the optimized conditions, which is sufficient to detect microbial numbers in Saudi Aramco injection seawater. Finally, the requirements for design and construction of SYBR-based automated sensor prototype were determined.