ABSTRACT In the pulp and paper industry, variability in the process and wood source may result in high corrosivity waste liquors, called black liquors. It is well documented that the concentration of organic extractives is wood species dependent and prior research has demonstrated corrosion rates of carbon steel in pulp mill equipment ranging from <0.03 mm/yr to >2.54 mm/yr, depending on wood species pulped. Our research demonstrates the importance of operational strategies for wood species, wood chip usage and delivery to downstream process corrosion. Some black liquor constituents have been identified to increase the corrosivity of black liquors whereas others may act as corrosion inhibitors. Results from this study show the importance of water soluble extractives in wood, such as long chain fatty acids, catechols, and others on the corrosivity of black liquor towards carbon steel 516-Gr70.
INTRODUCTION Significant variation in the corrosion rate of carbon steel equipment in pulp mills using different tree species has been reported for a long time. In 1953, MacLean and Gardner demonstrated the effect of organic-metal complexing or sequestering agents in black liquors (BLs) on the corrosion of carbon steel digesters. Yet most of previously published work has focused on the concentration of inorganic species such as hydroxide and sulfide in pulping liquors and not on the wood. The organic components, which are wood species specific, come from extractives in the wood chips or are generated from the degradation of lignin, a phenolic compound, and other heartwood constituents during pulping. BL contains residual caustic, sulfide and other process and non-process inorganic chemicals as well as organic chemicals from the wood. Niemela characterized Scots pine (Pinus sylvestris) BL identifying more than 700 low-molecular weight organics compounds.
Singh et al evaluated corrosivity of BLs from commonly used wood species in the North American pulp and paper industry (PPI) and reported the rate of corrosion for carbon steels varied from <0.03 mm/yr to >2.54 mm/yr, depending upon the wood species pulped under otherwise similar conditions. In general, hardwoods (HW) were found to have lower corrosivity compared to the softwood (SW) species tested. A study by Pawel et al reported an increase in digester corrosion with increased Douglas fir furnish which demonstrates the importance of wood species in black liquor corrosivity. Results from studies on wood species and corrosivity indicate that organic constituents of BL play a significant role in variations of corrosivity amongst wood species. Although the role of an individual compound is not always certain, organic constituents in BL can be separated into two broad groups: corrosion activators and corrosion inhibitors. Catechol, a breakdown product of lignin, has historically been proposed as a corrosion activator. Organic extractives, such as resins, tannins, and fatty acids, which show considerable differences in concentration among different species as well as among differently aged trees, are suspected of having some inhibitory properties.
The main focus of the PPI concerning organic extractives is on tall oil production and pitch formation, not corrosion. Sterols, sterol esters, and waxes have been identified as non-soluble soaps under the alkaline conditions of Kraft pulping and the root cause of pitch problems, while glycerol esters completely saponify both fatty and resin acids which then readily dissolve. In some cases the debarking of logs, seasoning of logs, or the seasoning or biological treatment of woods chips with enzymes has been utilized to reduce downstream pitch problems. Therefore the seasoning of wood chips due to lifeti
ABSTRACT Cladding/overlay thickness measurements were made on several primary air ports fabricated from alternative composite tubes installed in a kraft recovery boiler to document the fireside corrosion. Laboratory corrosions tests were then conducted to reproduce the relative corrosion rates determined by the field thickness measurments. It was found that all of the major available composite tube systems are suceptible to corrosion. Hydrated sodium sulphide and oxygen in combination with sodium hydroxide are implicated as major components in the liquid environment that causes the corrosion. Prevenative measures discussed include the need for a well-sealed port, and the likely need to avoid having black liquor droplets contacting the port tubes while dehydration is incomplete.
INTRODUCTION Composite 304L stainless steel/SA-210 carbon steel tubes have replaced conventional carbon steel boiler tubes as the construction material for the lower-furnace of kraft recovery boilers to resolve the general fireside corrosion problems experienced with conventional carbon steel boiler tubes. While composite tubes have been very successful in resolving that concern, they have introduced other unanticipated problems. One such problem involves corrosion or balding, which has been observed predominantly on primary air port opening tubes. Corrosion of the 304L stainless steel cladding has occurred on both the cold-side surface and the fireside surface of primary air port opening tubes. Corrosion is a concern because of the potential for a water leak and subsequent explosion resulting from a smelt-water reaction.
To resolve the more serious composite tube cracking problem, boiler tube suppliers have promoted the use of alternative co-extruded tubes, weld-overlaid tubes, and chromized tubes. Several North American mills have installed primary air ports fabricated from those alternatives. Based on reported inspection results, those alternatives are susceptible to corrosion, some more so than others. Several mechanisms have been proposed to account for the corrosion, which include corrosion by molten hydroxide, molten smelt and molten pyrosulphate. However, until a consensus on the true mechanism is attained, a resolution to this problem may not be achieved.
Paprican has been involved in a collaborative United States Department of Energy research program with Oak Ridge National Laboratory to address the composite tube cracking problem in kraft recovery boilers. One task of the multi-disciplinary research program has been to identify the most likely corrosive environment that causes corrosion of primary air port composite tubes. This was done by conducting careful corrosion surveys within a single North American recovery boiler over an extended time frame to determine relative corrosion resistance of the various composite tubes installed, and by conducting lab-based corrosion testing to reproduce that relative corrosion resistance. This report documents the results of those efforts.
RECOVERY BOILER INSPECTION OBSERVATIONS
The relative corrosion resistance of composite tubes fabricated into primary air ports was determined from the analysis of inspection data, and from measuring the cladding/overlay thickness as a function of time. Essential design and operation details of the recovery boiler, within which observations and measurements were made, are provided below.
The recovery boiler under study is a 1997 Babcock and Wilcox (B&W) single-drum cogeneration unit constructed using 2½ in. (63.5 mm) diameter tubes on 3 in. (76.2 mm) centers in a membrane-type design with a sloped floor. The unit typically burns 3.6 million lbs (1.63 million kg) of black liquor dry solids
ABSTRACT Case histories are presented where thorough failure analysis revealed specific conditions or events that preceded failures of boiler components. These conditions were revealed even when background information was insufficient, inaccurate, or contradictory. Remedial actions to avoid recurrent failures are also discussed.
INTRODUCTION Many samples of boiler components can be examined by routine analysis to determine the general failure mechanism, such as overheating or corrosion. However, determining the root cause of a failure requires thorough analysis combined with appreciable background information about the system. Often, the ability to arrive at a definitive conclusion concerning the failure is limited by insufficient background information. In some cases, the supplied background information may even contradict the evidence on the sample. However, as a wise man often said, The metal doesn?t lie. The essence of the statement is that meticulous observation and exhaustive consideration of the possibilities can reveal the specific conditions or events that preceded the failure, even though background information is incomplete or even incorrect. Evidence obtained from the sample often far outweighs hearsay and anecdotal information regarding the failure and should be paramount in developing a correct diagnosis of the failure cause.
Failure analysis of boiler components parallels forensic science investigations in many aspects. A forensic investigation may require identification of a victim, an autopsy to determine cause and establish time of death, collection and characterization of evidence at the crime scene, and linking the evidence and cause of death to the perpetrator of the crime. These tasks are similar in many ways to investigations for failed boiler components. The overall procedures may incorporate the determination of the component alloy, analysis of material covering the surfaces, careful observations of surface features, characterization of the microstructure, examination of details on the microscopic scale, and background information of the surrounding environment. Many references are available that identify typical features related to specific failure mechanisms.
Determination of the alloy composition is not always needed as part of an analysis, as most boiler components are fabricated from plain carbon steel. However, in some cases alloy composition may be required as part of the investigation, as small alloying additions can dramatically effect some properties of the steel. For instance, low alloy steels (containing small additions of chromium and molybdenum) are often specified for high-temperature sections in superheaters and reheaters due to improved resistance to creep rupture and thermal oxidation that generally extends component life5. As another example, corrosion rates due to flow accelerated corrosion can be dramatically reduced by using low alloy steels instead of plain carbon steel. Verifying alloy composition in these cases can identify a material deficiency for the application or highlight possible remedial actions to avoid future failures.
The composition of the material, specifically deposits and corrosion products, that covers the external surfaces can indicate the cause of corrosive attack in many instances. This is also true for metal wastage on the internal surfaces. For instance, maricite (NaFePO4) has been associated with phosphate corrosion in boiler tubes. Internal surface deposition may also be implicated in overheat failures in addition to promoting corrosive attack. The morphology and composition of deposit and corrosion product layers can indicate how they formed. Deposit and corrosion product composition may identify
ABSTRACT The present work demonstrates that seawater corrosion potential ennoblement can persist during long-term immersion exposures for several corrosion resistant Ni-Cr-Mo alloys. The present study considers the implications of long-term and short-term seawater ennoblement on Alloy 625 (UNS N06625), Alloy 276 (UNS N10276), Alloy 59 (UNS N06059), Alloy 2000 (UNS N06200), and Alloy 686 (UNS N06686). When compared to freshly exposed specimens not influenced by ennoblement biofilms, seawater ennoblement of Ni-Cr-Mo alloys are shown to increase the seawater cathodic current capacity of such alloys at potentials more positive than ?400mV, but show a diminshed oxygen reduction capacity at potentials below this threshold. The work also explores the ability of seawater ennoblement biofilms to respond to changing cathodic demand. The degree of cathodic current adaptation is lower for mature ennoblement biofilms than for ennoblement biofilms formed on freshly exposed specimens, although the increase in cathodic current capacity ? the cathodic current density available to drive galvanic corrosion ? is not insignificant for long-term specimens.
INTRODUCTION Seawater corrosion potential ennoblement can occur in passive alloys such as stainless steels, Ni-Cr-Mo alloys, and alloys of titanium that are resistant to seawater pitting but are relatively poor oxygen reduction catalytic surfaces. The manifestation of corrosion potential ennoblement in natural seawater can cause corrosion potentials of such alloys to exceed 300mVAg/AgCl(SW). This represents an increase of nearly 250mV above the corrosion potentials obtainable in sterile or filtered seawater. Ennoblement is the result of biofilm-derived electrochemistry that provides an alternate oxygen reduction pathway on passive film surfaces. The predominant theories describing seawater corrosion potential ennoblement involve sequestration of Mn from seawater, and the establishment of an electrochemical redox couple involving MnO2 at the biofilm/alloy interface. Elevated corrosion potentials from seawater ennoblement has been linked to increased pitting and crevice corrosion damage for stainless steels8, and more recently for the Ni-Cr-Mo alloys.
A limited amount of research has been reported regarding the effects on ennoblement of increasing seawater temperature. Mollica et al. have demonstrated that temperature can influence corrosion potential ennoblement significantly. In their work with stainless steels, at temperatures between 25°C and 35°C, seawater organisms remained viable and active. Mollica?s specimens ennobled to values 400 to 500 mV more positive than the potentials observed after shortly after immersion (-100mV vs. SCE). However, at 40°C, the organisms on stainless steel surfaces became inactive and the potentials of these samples remained near the value observed shortly after immersion, i.e. between ?100 and 0 mV (vs. SCE). In related work on Ni-Cr-Mo-based Alloy 625 (UNS N06625), Martin et al. showed there is little if any ennoblement at temperatures above 40°C. This work suggested that crevice corrosion of Alloy 625 is more likely to initiate at temperatures below 40°C than at higher temperatures because of corrosion potential ennoblement, despite a precipitous decrease in crevice initiation potential over the same temperature range. It has been recently demonstrated that seawater ennoblement can persist through winter in cold seawater at near-zero temperatures.
To-date there has been a limited amount of published work on the response of seawater ennoblement biofilms to environmental parameters, and on the persistence of corrosion potential ennoblement for longer periods of time in seawater. It has been recently demonstrated tha
ABSTRACT Friction rock stabilizers (FRS), such as Swellex rock bolts are being considered as reinforcement material for the Yucca Mountain Nuclear Repository. Generally, expanded rock bolts are used for rock support in mining and tunneling applications due to various advantages. Expanded Mn24 rock bolts used for rock reinforcement in underground construction are made of High Strength Low Alloy (HSLA) steel. To our knowledge there are no electrochemical potentiodynamic studies performed on expanded Mn24 in the cold worked condition under certain YM environments for the repository. Corrosion behavior was studied from Potentiodynamic polarization tests performed on expanded Mn24 rock bolt with increasing the concentration of simulated YM water and also as a function of temperature under aerated and de-aerated conditions. Increase in corrosion rates were observed in de-aerated and aerated conditions at room temperature as a function of concentration. Increase in Corrosion rates as function of temperature in YM water chemistry under de-aerated and aerated conditions were observed. Corrosion mechanism of passive layer in anodic region was studied for rock bolt at room temperature in de-aerated condition. Corrosion rates of expanded rock bolt in deaerated are considerably low than the rates in aerated with both increase in temperature and concentration. From the analysis it was found that the uniform and pitting corrosion were the main contributors to the corrosion rate obtained. In this work, we present the corrosion mechanism and corrosion rates of expanded Mn24 rock bolt in different conditions.
INTRODUCTION Yucca Mountain (YM) is a federal owned land located at 100miles northwest of Las Vegas in the state of Nevada. This uninhabited region has a very dry climate receiving on average of 7.5 inches of precipitation. Underground of YM site was selected for the disposal of commercial spent fuel and high-level radioactive nuclear waste. Further details can be found on the website maintained by DOE. The underground construction of emplacement drifts demands considerable structural support in the form of rock reinforcement. Frictional Rock Stabilizers (FRS), which is widely used in mining industry are ideal for this purpose. Since its introduction in 1970?s, FRS has been widely used in the mining industry to provide roof support for underground construction . FRS is the thin-walled tubular device which exerts force for the entire length of the stabilizer after it is installed inside the rock. Split set and expanded rock bolts are few examples of FRS. This type of stabilizers holds the rock which prevents or minimizes the rock shifts, where as in the case of conventional rock bolts there is a chance of loosen the rock or breaking of rock bolts. The expansion of FRS inside rocks exposes the entire outer surface to the rock. When minerals of the rock combines with water, there is a great potential of rock damage in the form of corrosion. Earlier researchers have studied the corrosion problem of plain steel FRS in the underground mines under different mine water chemistries. Corrosion contribution to the failure of the FRS may be due to many variations in the mine-site conditions. For, example, the water chemistry in the mine is most essential factor for the corrosion. Lian et al. reported the corrosion rates of 1016 low-carbon steels in J-13 water chemistry using electrochemical techniques. Yilmaz et al. reported the corrosion behavior of medium carbon steel (AISI 1040) under simulated YM water, proposed at University of Nevada, Reno (UNR). Since, the water in the mine combined with the rock minerals can produce salts which can contribute the corrosion of rock bolt. J.Ranasooriya studied the Western Australian
ABSTRACT NACE RP1076, Corrosion Control of Steel, Fixed Offshore Platforms Associated with Petroleum Production, described recommended practices for corrosion control on fixed offshore platforms used to produce oil and gas. The document was originally written in 1976 and has been revised and updated three times. This paper presents the history of the document for the formation of the original task group through the various updates and up to the status of the current revision.
INTRODUCTION Quoting from the foreword to the document, which has remained almost completely unchanged over the years:
Offshore structures represent large capital investments. Structures are being placed in offshore areas worldwide and are being designed to withstand forces resulting from hurricanes, arctic storms, tidal currents, earthquakes, and ice floes. Moreover, platforms structures are currently being placed in deeper waters and, therefore, have become larger, more complex, and more expensive. Control of corrosion on structures is necessary for the economic development of oil and gas production, to provide safe support for working and living areas, and to avoid potential harm to the environment. For the purposes of this standard, offshore structures are considered to be stationary structures (platforms or subsea facilities) that are fixed to the sea floor by gravity, piling, and/or mooring cables.
RP0176 was written, approved and published in 1976 to provide guidance for the control of corrosion of these structures. Since that time, it has been cited by regulatory authorities in a number of areas around the world. Its application has also been expanded outside the stated scope of the document to provide guidance for the control of corrosion for floating oil production structures, marine docks and loading facilities and even subsea pipelines.
This paper presents the history of the document from inception to the revision that is currently in draft form.
BACKGROUND The first platforms in the Gulf of Mexico were installed in 1948 and 1949. In the 1950?s and 60?s, the industry became very active and many platforms were installed. These platforms were mostly in 40 to 60 feet of water and were 20 to 40 miles from shore. The technology to design long life systems were available, but the operators were not interested in making the large investments required for long life facilities. Cathodic protection for most of the platforms were provided by using 100 pound magnesium anodes that were hung from platform members by their copper cable. These anodes usually lasted about a year and crews were constantly replacing expended anodes. In 1962, a huge Gulf of Mexico lease sale was held and leases in 150 to 300 feet of water were obtained. These deeper waters made the use of magnesium anodes impractical. Some operators used zinc anodes while others used the aluminum-mercury anodes that were introduced in 1966. In 1976, the aluminum-indium anodes became available at the same time that RP0176 was being prepared.
FIRST EDITION - 1976 In early 1976, a committee was formed to prepare a recommended practice for the control of corrosion on offshore platforms. The committee was formed as Task Group T-1-1 under Group Committee T-1. The task group chair was Harry R. Hanson with vice chairs Gordon L. Doremus and John A. Burgbacher. Other committee members were:
TABLE OF COMMITTEE MEMBERS
The task group was composed of representatives from oil companies, pipeline companies, consulting firms, coating manufacturers and applicators, and material suppliers.
The task group met for the first time in February 1976 in Houston at Exxon Production Research. The first meetin
ABSTRACT X-ray photoelectron spectroscopy (XPS) studies on a duplex stainless steel, Zeron 100 (UNS S32760), showed differences in the oxide film composition for samples which received one of four treatments: cold, chlorinated seawater; cold seawater; ambient temperature chlorinated seawater; and ambient temperature seawater. The most evident difference was the amount of surface chloride with the cold, chlorinated seawater treated samples having the least chloride while the ambient temperature seawater treatment had the most. Further, the hydration of the oxide films for the exposure conditions was different with the cold, chlorinated seawater treatment samples having the highest concentration of O-2 ions.
INTRODUCTION Stainless steels have been used for many years in seawater applications where an increased resistance to corrosion is needed. More recently the nitrogen- a 50/50 mixture of austenite-ferrite structure with increased levels of Cr and Mo relative to the 300 series austenitic alloys have found widespread use especially in the oil and gas industry particularly in piping systems. However, these alloys still undergo localized corrosion in the form of pitting or crevice corrosion in many environments. The treatment of duplex stainless steel pipe lines with low temperature, chlorinated seawater prior to being placed in service has been shown to significantly improve of the corrosion life time of these pipes. Although service records of treated and non-treated pipelines show that the cold, chlorinated seawater (CCSW) treatment has been effective, there has been no research to establish the basis for the increased corrosion performance.
As a first step in understanding why CCSW might improve the localized corrosion resistance of Zeron 100, we examined the surface composition of samples receiving one of four treatments using X-ray photoelectron spectroscopy (XPS). Specifically, we were interested in determining if the amount of chloride differed as there is a significant body of work linking chloride uptake by oxide films to the first step in localized corrosion. The four treatment conditions used were: cold, chlorinated seawater (CCSW); cold seawater (CSW); ambient temperature chlorinated seawater (ATCSW); and ambient temperature seawater (ATSW).
Experimental Zeron 100 (Z100) samples were cut and polished to a 600 grit finish. Z100 is a duplex stainless steel the compositions being 25% Cr, 7.0 % Ni, 3.5% Mo, 0.7% Cu, 1.0% Mn, 0.7% W, 0.3% N, 0.3% Si, and the balance Fe.
Three samples of Z100 were exposed to one of four conditions: CCSW, ATSW, CSW, and ACSW for 2 weeks at the NRL facilities in Key West, FL. The chlorination level was 1 ppm free chlorine in seawater for sample exposed to chlorine and for the cold treatment, samples were held at 4°C. After exposure, and analyzed using XPS.
ABSTRACT Carbon steel is thermodynamically unstable in water with dissolved CO2 and the only reason that carbon steel is so attractive and can be so widely used in oil and gas production is that the steel surface becomes covered by a protective layer of corrosion products, oil, mineral scale or inhibitors. It is relatively easy to predict and explain the high corrosion rates on bare steel. The real challenge is to reduce the corrosion and that requires knowledge about the performance of the protective layers, means to predict the breakdown of the layers and methods and techniques to ensure that robust layers form on the surface.
The paper discusses how CO2 affects the water chemistry, the electrochemical reactions on the bare steel surface, and the initiation and growth of protective corrosion product films. As many sweet systems contain organic acids that affect the solution chemistry and the formation and stability of the FeCO3 corrosion product films, organic acids need also to be considered when the effect of CO2 is discussed.
INTRODUCTION The mechanism of carbon steel corrosion in a CO2 containing environment has been studied and debated for decades. Hundreds of papers related to CO2 corrosion have been published and a large variety of corrosion rates and mechanisms have been reported. Oil companies and research institutions have analyzed the data and developed a number of prediction models1 to take account of the various parameters that determine the corrosion rate. The models give up to two decades difference in the predicted CO2 corrosion rate and it all depends on how the various parameters are treated and how much conservatism that is built into the model.
In order to explain the confusion and the apparently contradictory observations and results that have been seen and reported, it is important to realize that the term CO2 corrosion and the effect of CO2 is not related to one mechanism only. A large number of CO2 dependent chemical, electrochemical and mass transport processes occur simultaneously on and close to the corroding steel surface. The various reactions respond differently to changes in CO2 partial pressure, temperature, water chemistry, flow and other operational parameters. All the reactions should be taken into account when corrosion in a CO2 containing environment is to be quantified and explained.
Many researchers have studied and discussed the electrochemical reactions taking place on the bare steel surface. The mechanisms that control the rate of the electrochemical reactions are of great academic interest, but are less important when it comes to the practical application of carbon steel. When carbon steel is directly exposed to water and CO2 the bare steel corrosion rate will under almost all circumstances become prohibitively high for practical use in oil and gas production. This is illustrated in Figure 1 where the corrosion rate has been predicted for various CO2 partial pressures and pH values as a function of temperature. The corrosion rate predicted up to 40 °C apply for bare steel, while partly protective films are formed at higher temperature. It is seen that the corrosion rates are in the order of several mm/year, even at CO2 partial pressures below 0.5 bar, i.e. pressures where the old rule of thumb says that carbon steel can be applied without any treatment.
In the present paper it is focused on fundamental corrosion mechanisms in sweet systems. Three major effects of CO2 will be addressed: The effect on the water chemistry, the effect on the electrochemical reactions, and the impact on the initiation and growth of corrosion product films. As many sweet systems contain organic acids that affect the solution chemistry an
ABSTRACT This paper presents an end-user?s root cause failure analysis of a fluorinated ethylene propylene (FEP) lined fiberglass reinforced plastic (FRP) steam-stripping column. The column stripped low levels of organics from an acidic aluminum chloride stream, and failed via through-wall weeping at a nozzle-to-shell joint in less than 18 months of service. In-depth visual and microscopic examination identified several root causes, the most significant of which were lack of fusion and improper weld technique at the FEP lining butt welds. Corrective recommendations for addressing the deficiencies and the root causes are also presented.
INTRODUCTION Corrosive applications in the Chemical Process Industry (CPI) often warrant exotic materials of construction, such as fiberglass-reinforced plastic (FRP) with an internal thermoplastic lining for added corrosion resistance. Plastic-lined FRP, also commonly called dual laminate construction, offers equivalent or superior corrosion resistance combined with lower fabricated equipment cost in comparison to many of the highly corrosion-resistant metals used for aggressive services. While dual laminate construction is typically limited to temperatures below 300°F (150°C) and pressures less than 150 psig (10.34 bar), this construction still satisfies the needs for many diverse applications. Being a comparatively smaller industry however, two aspects for which the dual laminate industry lags behind the metal industry are standardization of construction techniques and availability of sufficiently qualified fabricators.
While dual laminate construction is not a new technology and works well in many applications, failures do occur for many of the same reasons that affect metallic construction. Failure modes generally involve one or more of the following aspects: material selection, design, fabrication, installation, operation, and/or maintenance. Dual laminate equipment technology involves two distinctly separate material technologies, namely solid plastic and FRP construction, increasing the complexity of design and fabrication, and thereby creating additional opportunities for problems (i.e. ? failure modes) in these particular stages. Fabricator qualification and selection is thus a very important aspect.
Regardless, a necessary outcome of any failure for an end user seeking continuous improvement is an autopsy or failure analysis to accurately define the root causes for the failure and what went wrong. In the author?s view, a failure is not a failure unless nothing is learned.
Background The dual laminate stripping column discussed in this paper was 12 in. (300 mm) inside diameter (ID) by 15 ft.- 8 in. (4.775 m) overall length, and consisted of three flanged shell sections and two flat flanged heads. Figure 1 depicts the arrangement and overall dimensions of the column, while Figure 2 illustrates the cross-sectional construction at a typical nozzle. The column was provided with a 100-mil (2.54 mm) thick FEP extruded seamless tube lining with embedded knit-glass fabric backing for bonding to the FRP structure. In this construction, the individual FEP lining tube components (i.e. ? the shell and the nozzles) were joined via manual hot gas welding, where the components to be joined and the weld rod are simultaneously heated to the melting point and fused together using a manually-operated hot gas welding tool. In order to provide a butt joint connection between the shell lining and the nozzle lining, the opening in the shell lining is flared out using a heated forming mandrel to provide a short nozzle stub. Much like metal welding techniques, the hot gas welding technique is highly operator-dependent with regards to the quality an
ABSTRACT Scale control within produced fluids as water follows the cycle of injection, production, processing and reinjection in oil/gas production facilities is critical to the effective production of hydrocarbons in a safe, economic and environmentally acceptable manner.
The scale challenges associated with seawater injection into a South American offshore reservoir with a moderate Barium Sulfate scale challenge (180 ppm Barium within the formation water) are described. An integrated scale management strategy addresses these issues based on tracking production rates, ion chemistry changes and amount/composition of the suspended solids to evaluate the requirement to scale squeeze the production wells.
The impact of the reservoir stripping mechanism on scale ions concentration and the resulting impact on scale inhibitor chemical required to control scale is outlined. The selection of scale inhibitors for scale squeeze application, the optimization of these treatments to enhance squeeze life is also demonstrated.
INTRODUCTION Field Description The field is located in the Atlantic Ocean off the cost of South America. The A platform began production in 2003. The subsea wells produce oil, gas and water from long open hole gravel pack completions, 300 to 600 meter long completed within sandstone formations. The reservoir temperature is approximately 90°C. Scale formation has been a production issue in these fields as they are supported by injection of seawater and the formation brines containing up to 180 ppm barium and up to 300 ppm strontium ions. Wells with seawater breakthrough are scale squeezed using a phosphate ester scale inhibitor to control sulfate and carbonate scale formation within the wells and flowlines.
Brine Chemistry Table 1 contains the typical formation brine chemistry within this field. Injection quality seawater has been used to maintain reservoir pressure and improved fluid sweep within most of the reservoir units over the life of the field. Figures 1 and 2 show the mass of sulfate scale associated with injection water breakthrough under reservoir conditions for the brine present in the field. Figures 3 and 4 show the supersaturation values for this brine with injection water breakthrough. It is clear that barium sulfate is the most significant scale type present in terms of both mass of scale and supersaturation. Observation of scale samples recovered from the field supports these predictions, particularly barium sulfate being much more significant than carbonate scale. Where carbonate scale is observed it is associated with gas lifted, seawater rich produced fluids which may not have been scale squeezed as the sulfate scale risk was predicted to have been eliminated due to very high seawater fraction in the produced water and absence of barium ions.
INTEGRATED SCALE MANAGEMENT INTRODUCTION The objective of effective scale management for any hydrocarbon producing field is the minimizing of the cost that scale could bring to that operation. This cost would include deferred oil cost associated with scale related restrictions and its removal, the chemical, mechanical and manpower costs associated with treating to prevent and remove scale, health safety and environment (HSE) costs associated with handling radioactive scale, discharges of scale control chemicals to the environment and the maintenance of low levels of overboard oil in water.
It is more effective to manage the costs associated with scale by using an integrated team as actions of individuals can have a significant impact on the total cost of operation. In this field the integrated team involves individuals (Figure 5) from the operator (subsurface, r