Seawater Injection is an essential procedure in many offshore facilities in the North Sea. This water passes through a variety of different treatments and environments. It is chlorinated, filtered, deoxygenated and treated with biocide and other chemicals. The water is then injected into reservoirs under high pressure and sometimes high temperatures, to eventually (after months or years) break through into the production system, where it is subject to various different temperature environments.
Microorganisms react rapidly to changes in their environment, particularly temperature and salinity; given their short generation times, the effects on the microbial population can be pronounced. The objective of this study
was to characterise the microbial communities entering and leaving the reservoir with particular emphasis on sulfate-reducing bacteria (SRB) and Archaea, which are believed to be the major cause of microbiologicallyinfluenced corrosion (MIC).
Denaturing gradient gel electrophoresis (DGGE) and fluorescence in situ hybridisation (FISH) were applied to sessile and planktonic samples collected from a number of North Sea seawater injection and production systems
to compile a database of the microbial communities found in these systems. The FISH data were compared, to determine common traits and gross differences between topside seawater and production equipment locations.
Additionally, the counts of SRB/ Archaea types were assessed and consideration was given to how these may influence the risk of MIC. DGGE data was used to track certain organisms through the systems to find commonalities; primarily, if there were any relationship exists between biofilm communities at different locations in the two systems.
The results indicate that there are similarities as well as subtle differences between the two systems and these are discussed in detail in this paper.
Hassani, Shokrollah (U. of Tulsa) | Roberts, Kenneth P. (The University of Tulsa) | Shirazi, Siamack A. (U. of Tulsa) | Shadley, John R. (U. of Tulsa) | Rybicki, Edmund F. (Petrobras Cenpes) | Joia, Carlos-Jose Bandeira
Chemical inhibition is a common method for controlling erosion-corrosion in offshore mild steel pipelines, tubing and pipe fittings. The paper introduces a new approach for predicting inhibited erosion-corrosion in mild steel pipes including the effects of flow and environmental conditions, sand production, and an oil phase.
When sand is produced, sand particle impinging on piping surfaces can decrease the efficiency of corrosion protection systems such as iron-carbonate scale formation or chemical inhibition and result in severe corrosion and even pitting. The need to be able to predict inhibitor performance under sand production conditions is particularly acute when the wells are deep or off-shore because of the difficulty in running coupon tests to evaluate the inhibitor efficiency at critical points throughout a system. Research reported in this paper is aimed at providing producers with information that will help them make decisions on the design of the well given advanced knowledge of the inhibition options and their predicted effectiveness under sand production conditions. Inhibition mechanisms and the relation between inhibitor concentration and inhibitor coverage are described using adsorption isotherms. The Frumkin isotherm showed the best fit to experimental data for an imidazoline-based inhibitor used in sand-free conditions.
Flow loop tests indicated that sand particle erosion decreased the efficiency of the inhibitor. However, Frumkin isotherms modified to handle effects of erosivity, temperature, and oil phase were successfully fitted to erosion-corrosion data. Inhibitor adsorption isotherms, for both sand-free and sand production conditions, were integrated into a mechanistic model for prediction of CO2 corrosion rates as a function of inhibitor concentration and good results were obtained as compared with data.
Results of this study show that the inhibitor adsorption isotherm, modified to handle effects of sand production, temperature, and oil phase can be a valuable tool for predicting inhibited metal loss rates under sand production conditions.
Key words: Erosion-Corrosion, Inhibitor adsorption, Sand erosion, CO2 corrosion, iron-carbonate, Oil/Brine
Al-Taq, Ali Abdullah (Saudi Aramco) | Ali, Shaikh A. (King Fahd University of Petroleum and Minerals (KFPM)) | Al-Haji, Habeeb (Saudi Aramco) | Saleem, Jaffar A. (Saudi Aramco) | Al-Ibrahim, Hussain A. (Saudi Aramco)
Mono and diamine compounds were synthesized from 1, 12-dodecanediamaine, and evaluated as acid corrosion inhibitors for coiled tubing steel. The inhibition behavior of these compounds in concentrated HCl acid was examined using a gravimetric method. Weight loss tests were conducted in 28 wt% HCl acid at 60, 70 and 80oC for 2 hours. The results showed that both mono and diamine inhibitors exhibited a good protection efficiency for coiled tubing steel in 28 wt% HCl acid. However, monoamine compounds showed better performance. Addition of an intensifier was effective to enhance protection efficiency for both amine moiety compounds where more than 99% protection was obtained for some inhibitors. The effect of intensifier concentration on inhibition efficiency is also addressed in this paper. The results obtained are very promising and suggest that some of examined corrosion inhibitors have a good potential to be used in acid stimulation treatments of oil/gas wells.
Description of the Material Corrosion-associated biofilms found in oilfield pipelines are complex systems that typically form anaerobically under turbulent flow conditions, consume the metal substrate on which they form, produce hydrogen sulfide, and often have corrosion products or waxes embedded in their extracellular matrices. A model pipeline has been constructed in the laboratory to approximate these conditions. The development of this laboratory capability has enabled the screening of a series of biocides as treatments for corrosion-associated biofilms in a seawater system.
Application Corrosion in general is a constant concern in production and transmission systems, and the carbon steel pipelines that carry water, mixed phases, or water-laden hydrocarbons, are especially at risk for microbiologically influenced corrosion (MIC). The presence of water and nutrients encourages the propagation of bacterial communities and the formation of biofilms, especially on internal surfaces of pipelines. Once these biofilms are established they can quickly develop into breeding grounds for pitting corrosion. In order to control MIC, it is essential to have a method, such as properly applying an effective biocide, to control corrosion biofilms.
Results, Observations, and Conclusions The benchmarking process identified candidate chemistries that are effective at killing biofilm-associated bacteria in the model pipeline system. Further testing suggested that a periodic slug dose can help to kill and remove biofilm while preventing undesirable increases in planktonic cells and hydrogen sulfide levels. These results and treatment recommendations will be discussed in this paper.
Significance of Subject Matter The benchmarking results indicate that corrosion biofilms can be effectively treated with biocides. Guidelines have been established for the effective dosing of these formulations to help control MIC in pipelines, and will be presented herein.
During acidizing stimulation or cleanup operations, metal tubulars, downhole tools/valves, surface lines, etc. are exposed to acidic fluids and are prone to corrosion. Because corrosion rates drastically increase in high-temperature wells, controlling corrosion is critical and must be dealt with carefully. In addition, corrosion protection is important for maintaining the integrity and long life of downhole tools installed in a well. Several corrosion inhibitors, such as quaternary ammonium compounds, propargyl alcohol-based compounds, etc., have been effectively used in the industry. However, because of stringent environmental regulations, attention has focused on the development of new corrosion inhibitors that are environmentally benign. Food-grade products that are considered "green?? chemicals have significant potential as corrosion inhibitors in the oil and gas industry.
In this paper, application of chicory as a corrosion inhibitor for high-temperature and strong-acidic conditions is discussed. Chicory is a perennial bush plant available in many parts of the world. The root of the chicory plant can be roasted and ground for use as a coffee substitute or additive. Chicory is environmentally acceptable and, being of plant origin, is widely recognized as biodegradable in nature. This study shows that chicory can provide corrosion protection for alloys, such as N-80, 13Cr-L80, and 1010 steel, in the presence of either inorganic or organic acids at temperatures up to 250°F (121°C). Considering its good performance, low price, and no toxicity issues, chicory has significant potential for acid corrosion-inhibition applications. The mixing procedure for preparing the blend, experimental setup and test procedure, and laboratory results of high-pressure/high-temperature (HP/HT) corrosion tests are discussed.
The activity of sulfate-reducing bacteria (SRB) has long been a major concern in oilfield water systems and petroleum reservoirs because these microorganisms are one of the main causative agents of microbial-influenced corrosion (MIC) as well as reservoir souring.
Calcium nitrate and sodium nitrate treatments have gained popularity in recent years as alternatives or supplements to conventional biocide treatments. The object of these nitrate treatments is the suppression of SRB activity by the selective manipulation of indigenous bacteria.
The treatments have met with mixed success; in some cases SRB activity has been suppressed, whereas in other cases the treatment has failed. Cases where nitrate treatment has not been successful are less likely to be publicized than cases where the treatment has been deemed to be successful. There are also instances where nitrate treatment has been successful in suppression of SRB activity but has given rise to unacceptable increases in corrosion rates in water injection pipe-
In the experience of the author, nitrate treatments are rarely planned, trialed or implemented in a systematic manner, so as to maximize the chance of success and minimize unforeseen negative consequences. Based on practical examples from the author's experience and published information, this paper examines the most important factors that should be taken into account in methodical planning of trials and field-wide implementation of nitrate treatments, with particular reference to corrosion control.
Lean Duplex stainless steels are becoming attractive for applications in oilfield and marine environments due to their economic advantages, very good mechanical properties and relatively good corrosion resistance. However, there is little information about the pitting behaviour of lean Duplex stainless steels in oilfield and marine environments. This paper discusses the tendency for pitting corrosion to initiate through an evaluation of breakdown potentials of lean Duplex stainless steels UNS S32101, UNS S32304, LDX2404, standard Duplex stainless steel UNS S32205 and Austenitic stainless steels, 304L and 316L in aerated 3.5% NaCl and a CO2-saturated oilfield brine solution. Electrochemical measurements were made using a three-electrode electrochemical set up using an Ag/AgCl reference electrode and a platinum counter electrode. The results showed that breakdown potentials are generally higher in aerated 3.5% NaCl than the CO2-saturated oilfield brine solution for all the alloys tested. Lean Duplex stainless steel UNS S32101 and Austenitic stainless steel 304L showed comparable breakdown potentials in both environments while lean Duplex stainless steel UNS S32304 and Austenitic stainless steel 316L also have comparable breakdown potentials. There does not seem to be a universal relationship between Pitting Resistant Equivalent number and breakdown potential for the lean Duplex and Austenitic stainless steels.
Key words: Lean Duplex stainless steels, breakdown potential, aerated 3.5% NaCl, CO2 saturated oilfield brine.
Shirazi, Siamack A. (U. of Tulsa) | McLaury, Brenton S. (U. of Tulsa) | Husen, A.A. Anwar (BG Group) | Venkatesan, Krishna Prasad (BG Group plc) | Nadeem, Asaf (BG Group plc) | Hassaballa, Sherif (Rashpetco)
Sand production in oil and gas wells is becoming an increasing problem for operators due to sand settling, under-deposit corrosion, and/or erosion especially in sub-sea environment. The paper describes application of ultrasonic (UT) pipe wall thickness measurements and erosion calculations in assessing integrity management of pipelines in a subsea gas producing field. The subsea gas wells were completed with downhole sand control because of the unconsolidated nature of the reservoir sands. The gravel pack completions were designed to stop sand but allow some fines production to prevent plugging of the gravel packs and screens and hence loss of productivity. Some solids production was therefore expected over the life of the fields. After some time when additional gas wells were brought online, higher than expected sand production was observed. Thus, operators commissioned sand erosion studies and conducted UT wall thickness measurements in 2008 and two years later to measure wall thickness of the Pipeline End Manifold (PLEM) and associated spool pieces subsea. The results in the paper include a comparison of wall thickness measurements conducted in several key areas. The results indicate wall thickness measurements conducted in 2010 for most of the measurement locations were similar to 2008 results except for several regions where the UT measurements were questionable based on erosion calculations. One major observation from UT measurements is that most measured wall thicknesses were less than the nominal wall thickness by 0.5 to 1.0 mm including sections where no flow was going through (no erosion/ corrosion) indicating absolute values of UT measurements can not be trusted with confidence unless calibrated subsea. Finally, the paper describes how UT measurements, erosion calculations, production controls and operation philosophy can be combined to maintain asset integrity and to control erosion of pipelines.
This paper describes the chemical control and integrity management steps taken during the commissioning and start-up of the Combined Heat and Power plant (CHP) of a large field redevelopment. The chemical controls were carried out using a combination of new and established chemistries in oxygen scavenging, corrosion inhibition and scale inhibition. Carefully designed passivation and slugdosing, in addition to a clear and robust sampling and analysis plan, had a direct impact on the development of these operations. The lessons learned of two boiler systems are discussed together with the improvements implemented to achieve fit for purpose steam generation. This has included for instance, particular attention on the monitoring of boiler feed water quality and use of hydrogen meters. Furthermore magnetite formation was established for two boiler systems. This was confirmed by pH trends in the high pressure drums, sample appearance, hydrogen measurements and analysis of solids taken during various stages of monitoring. The results suggest that magnetite formation occurred at conditions different to what is the established rule of thumb during high pressure start-ups, e.g. 30 bar. It is speculated that such behavior was influenced by the chemical control selected. Key performance indicators (e.g. phosphate operational window) as well as automated chemical dosing is allowing good integrity control of the steam generation system as the facility migrates into steady state operation.
The Schoonebeek oilfield in the Netherlands is being redeveloped using the Gravity Assisted Steam Flooding (GASF) thermal production method to improve oil recovery1. Superheated steam, supplied by a Combined Heat and Power (CHP) plant will be injected into the reservoir via 25 wells adjacent to the production wells in 17 locations. Gross production will be evacuated from the reservoir via 44 horizontal wells in 18 locations using artificial lift pumps, with a Casing Vapour Recovery (CVR) System included to improve the gross lifting capability. Production from each wellsite location will be routed via a gross gathering system to the Central Treating Facilities (CTF). The CTF will include the required facilities to separate the oil, water and associated gas production and treat the respective streams to export quality. In later field life as wells warm up, the casing vapour will be spiked back into the gross production line. Cold production wells located at the border will be subsequently segregated from warm production wells by routing them to the CTF via the casing vapour recovery pipeline. Vapour separated from the oil in the CTF will be used as fuel gas in the CHP plant which is adjacent to the CTF. Together with heat integration between the CTF and CHP this minimizes energy consumption, CO2 emissions and heat losses to atmosphere from the two facility locations. Steam distribution plays a key role in the project. Chemical control and integrity management during the commissioning, start-up and steady state operation of the steam facilities is the subject of this case history paper.
Peralta, Juan D. (Schlumberger) | Caicedo Duran, Javier Omar (Schlumberger) | Gonzalez Marroquin, Vladimir (Schlumberger) | Bravo, Luciano (Schlumberger) | Gandolfo, Juan Martin (Ecopetrol) | Valera, Martin Marcelo
Inorganic scales are new identified phenomena in Casabe field while corrosion has started to increase to alert the field operations. The field has been under waterflooding since 1985 with no much success due to lack of vertical selectivity. It was resumed in 2004 and boosted from 25000 BWIPD to 110000 BWIPD, and in consequence, some injection related problems which had never been recognized in the field turned out to be an issue from wellbores to surface facilities. Failures in tubings, casing and flowline integrity and storage facilities with evidences of corrosion, lighted on the alarms regarding the corrosion processes in the field.
Diagnostic process started in 2010, revising the fluids being injected and the produced fluids from the wells, knowing that injected water is fresh and formation water has salinities up to 50000 ppm. Water samples were collected and analyzed to establish a current field wide corrosion baseline and evaluating the impact of the water injection process from the water source, injection lines and down into the injection wells and the reservoir, likewise the back to the producing wells x-mas trees.
Chemical treatment is being applied upfront in the injection system, and corrective treatments have been implemented in some wells to reduce corrosion downhole. Simultaneously, a surface flowline integrity survey, maintenance and replacement by new materials were initiated to avoid spills or unexpected failures in the gathering system.
Nevertheless, the current scenario is regularly under control, continuing monitoring is required in throughout the field. A new integrity management plan for the asset is under preparation since produced water is planned to be re-injected in the reservoir as primary source for the waterflooding. Whilst re-injection starts up, potential problems for corrosion could come up including scaling as it is indicated by Langelier Saturation index in the produced water.