ABSTRACT Internal corrosion of water distribution piping is often difficult to detect, diagnose, and mitigate, especially if the problems are localized. Corrosion can cause leaks, premature piping failures, and poor water quality in water distribution systems. New commercially available in-situ sensors can detect active corrosion and/or corrosive water and can notify facilities engineers that there is a problem. A new field demonstration of these sensors will be described in this paper.
Computer-based simulations of water distribution systems can also be used as a diagnostic tool to help solve corrosion problems. Simulations can help pinpoint areas in which localized hydraulic and/or water quality conditions are contributing to internal piping corrosion. An example will be presented in which an off-line dynamic simulation was used to help locate and diagnose a series of localized corrosion problems in an actual water distribution system.
Finally, the above sensors and simulations can be interfaced together with Supervisory Control and Data Acquisition (SCADA) systems to provide a highly accurate, near-real-time description of water system operation. Such a system can be used to automatically control the dosing of water treatment chemicals so that corrosion is mitigated.
INTRODUCTION Water distribution systems and water storage tanks should have a service life of 50 to 75 years. However, severe general and/or localized corrosion can shorten the service life to as little as 20 years due to leaks. A corroded and leaking water distribution system typically loses 20 to 25% of the water it conveys. Severe internal corrosion of unlined steel, cast iron, or ductile iron pipes usually results in poor water quality for occupants?water containing dissolved corrosion products (rust) is frequently discolored and may have an unpleasant taste and/or odor. In some cases the water may exceed the maximum contaminant level for iron of 0.3 mg/l as specified in the Environmental Protection Agency?s National Secondary Drinking Water Regulations. Water quality problems may become so severe that residents are forced to use expensive bottled water for drinking and cooking. The worst case is an unexpected catastrophic failure that occurs when the piping system is under stress due to high usage or environmental conditions, such as during firefighting or severely cold weather. Failure of a critical water main during a firefighting situation can result in loss of lives and property.
The first line of defense against internal water piping corrosion is an effective water treatment program. However, the quality of water tends to degrade as it travels from the treatment plant to the consumer. Water that stays in the distribution system for many hours or days can become corrosive and/or stagnant as the corrosion inhibitors and disinfectants are consumed. Water system hydraulics (flow rates, consumer demands, pressures) controls the amount of time the water remains in the distribution system. Piping and consumers that are located far away from the treatment plant or that are located in areas where water consumption is low may receive water that is very different from the high quality water that leaves the plant. Localized corrosion problems can occur in these remote and/or low usage areas.
Another related cause of internal water piping corrosion problems is inconsistent water quality over time. Inconsistent water quality prevents pipes from forming the protective oxide films that inhibit corrosion. Systems that obtain water from multiple sources (often for security and reliability reasons) are especially vulnerable to this problem.
Before action can be taken to correct remote and/or
ABSTRACT Aboveground coating condition surveys were conducted at several locations on a pipeline scheduled for rehabilitation. The methods included direct current voltage gradient (DCVG), alternating current voltage gradient (ACVG), and pipeline current mapper (PCM). The results of the surveys were compared with visual examinations of the coating condition after excavation of the pipelines. The overall objective was to determine the limitations/resolution of equipment typically used for modern aboveground ECDA work with respect to locating holidays and disbondments in the common coatings with varying spatial relationships and geometrical configuration. The results showed that DCVG and ACVG provided comparable data and were able to locate individual defects quite accurately, while PCM was able to locate large areas of disbondment but could not accurately size and orient the defect.
INTRODUCTION Multiple options exist for aboveground surveys to identify areas of disbonded coating on pipelines, all of which are valuable tools for external corrosion direct assessment (ECDA) of pipelines. The selection of a particular evaluation technique is often based on the operator?s skill and experience with the technique and the anticipated findings, rather than proven results from other studies. Some techniques are known to be better for locating and sizing only large disbonded areas, others are better for detecting smaller disbonded areas but may not be able to accurately size holidays. Other significant factors which will affect accuracy include cathodic protection system type and current output, stray current interference, orientation of the coating defects, and environmental conditions (soil type, moisture, etc.). Limited information regarding the usefulness, accuracy, and flexibility of each technique is available, and a side-by-side comparison of each technique on a real pipeline with visual confirmation of the results would provide a valuable informational resource to the industry. Beyond this, the knowledge of which holidays are detectable with accuracy and which may be missed or misinterpreted by any or all techniques is a critical component for proper tool selection and interpretation of ECDA surveys.
Previous validation work for ECDA showed that the process was able to discriminate between pipeline locations with respect to both coating and corrosion damage. Validation efforts by others have shown similar correlation. This work was a study focused on the individual survey techniques and their relative accuracy.
The overall objective was to determine the limitations/resolution of equipment typically used for modern aboveground ECDA work with respect to locating holidays and disbondments in the common coatings with varying spatial relationships and geometrical configuration. The specific tasks of this program are the following: Task 1. Perform aboveground coating surveys on several underground pipelines on the selected pipeline system using three different survey techniques Task 2. Compare the results of the three techniques with visual examinations of the coating defects after excavation of the surveyed pipelines
DCVG, ACVG, and PCM surveys were conducted on several miles of pipelines in South Carolina during the fall of 2004. Areas were initially selected based on variations in the above conditions, then final selections were made based on access. After the surveys were completed, only the sections of pipe which were scheduled for excavation during that time frame were further evaluated for coating defect size/location. Two sites were selected. The first was a 128? section known to have wet, rocky soil. The second was
ABSTRACT Design and engineering companies in the offshore sector often strive to find the best technical specification for new building coatings by requiring compliance with standards and prequalification testing, among other things. However, these specifications often overlook the feasibility of maintaining the coating systems once in service.
This fact, in addition to a general low priority given to corrosion protection and coating application during construction, (especially close to the scheduled time of delivery) leads to early coating breakdown and unnecessary high maintenance cost.
This paper will via a number of case stories attempt to point out such problems observed during the maintenance in service of offshore installations. Problems caused by wrong decisions made by key decision makers during the planning, designing, engineering and construction of offshore assets.
The cases are based the author?s first-hand experience of coating performance while managing coating maintenance of offshore installations for operators in the North Sea, the Arabian Gulf and West Africa.
INTRODUCTION Never has corrosion and the breakdown of coating systems on offshore structures, played the crucial role that we see today. Offshore structures, from floating production systems, drilling rigs to fixed platforms worldwide are aging at a fast rate, bringing increased concerns forward on maintenance. Owners ask for extended lifespan of their installations to match the improved oil recovery facilities and requests for lifespan expansions of the double or more than the initial design criteria are not unusual.
The intention of this paper is to point out problems observed during the maintenance in service of offshore installations, due to critical and sometimes wrong decisions made by key decision makers during the planning, designing, engineering and construction of offshore assets.
New Building Decision Makers The planning and execution of a new offshore installation, goes through a vast amount of in-depth decisions that will have their effect on the future lifespan and maintenance of the structure. Typically, offshore construction projects have many interested parties involved that can make a difference on the final output of the projects´ corrosion protection and its later maintenance.
The first and initial player is the owner/operator, who can be defined as the pre-scriber of the project specification. The owner?s defines the scope of the project and may call on engineering companies. Concerning corrosion protection, the owner/operator in many occasions will have its own team of Corrosion Engineers who will decide which coating manufacturers/coating systems are pre-qualified for their projects. In many occasions, owners will have a global list of preferred coating suppliers.
The Corrosion Engineers pre-qualification of coating systems may also be based on results of accelerated testing (carried out by the paint supplier or an independent laboratory). The requirements will typically be based on standards such as NORSOK M-501, ISO 20340, etc., and in the future also NACE TM 0104, 0204, 0304, 0404 etc.
This may be a source of later problems as especially the first two standards focus on a very few coating parameters only and with very tough acceptance criteria?s. The testing is carried out under ideal laboratory conditions. In real life conditions are seldom ideal and there is a risk that coating systems are sub-optimised and other important coating properties are sacrificed in the process.
Such sacrifices can include the maintainability of the coating system as well as the general robustness of the coating system in terms of surface
ABSTRACT The following paper provides a method to estimate current distribution of cathodic protection systems using a simple electrostatic model in a common spreadsheet. The model is intended to allow for a rapid analysis of current distribution, polarization, and circuit resistance without having to resort to more complex BEM-type tools. The model is based on the representation of anodes and cathodes by simple charges.
INTRODUCTION A corrosion engineer is often faced with the design of complex cathodic protection systems. One of the more challenging aspects of this design effort is the ability predict the distribution of current from one or more anodes to the structure protected. There are various empirical methods for making such estimates as well as comprehensive, computer-based software for modeling complex structures. Yet a reasonable estimate of current distribution can be made on the basis of the principles of electrostatics. The following paper describes such an approach.
APPROACH In the electrostatic modeling under discussion, the system of interest is divided into an arbitrary number of charges; increasing the number of charges increases the current distribution information returned. For simplicity the charges are assigned dimensions within a Cartesian Coordinate system (x, y, z axis). The charges may be either current sources or current sinks. The cumulative effects of the charges are determined by the three key principles.
(1) Ohm?s Law ? The voltage across any two points is the product of the current between the two points and the resistance between the two points.
The application of Ohm?s Law to each charges requires one to establish a resistance associated with current from (or to) that specific point. In each case we are going to consider the flow of current from (or to) a point to infinity, or an infinitely large sink (or source). In the simplest case, we will assume a spherical distribution of current from each source (or to each sink).
Consider the resistance between two concentric spheres: sphere A of radius r1 and sphere B of radius r2 (assume r1 << r2). The resistance between these two spheres is given by:
R = ¿ (¿ dr)/4 p r2
Where: R = Resistance, ohms; ¿ = Resistivity, ohm-cm; r = Radius, cm
Integrating from r1 to r2, R = ¿/4 p (1/r1 ? 1/r2). For r2 >> r1, R= ¿ /4 p (1/r1). For spheres that may be located next to an insulating plane, perhaps the earth surface or a coated structure, the current distribution is more likely that of a hemisphere and the resistance of the charge is doubled. This results in a resistance of:
R = ¿/(2 p r1)
If the charge to be modeled is not amenable to the geometry of a sphere or hemisphere, then the resistance of the element may be modeled by more appropriate equations, such as Dwight?s equation for rod-type anodes, etc. The best possible model should be used. (Reference 1 provides a wide range of papers for calculating resistances for alternative shapes.)
(2) Superposition Principle ? The voltage response between any two points to any number of current sources applied simultaneously is equal to the sum of the voltage response when the current from each source is applied independently.
For the system of many charges, the superposition principle allows one to calculate the voltage response at a point One due to current flowing from point One and add, as a scalar value, the voltage observed at point One when current flows to / from any other point(s) (i.e., Two, Three, etc.) in the system to an infinite earth. Thus the voltage at point One will be given as follows:
ABSTRACT Corrosion prevention is an important aspect of oil and gas production. The pipelines are protected from internal corrosion by the application of corrosion inhibitors. In recent years the application of ?green chemistry? principles to the area of corrosion inhibitors has attracted lot of attention which has resulted in the reduction/elimination of toxic inhibitors and the production of ?green? or low toxicity environmentally friendly formulations. In order to develop inhibitors with low or zero environmental impact there is a need to review the requirements which these green inhibitors have to fulfill under the various regulations that exist in various countries. A number of corrosion inhibitors have been developed with low environmental impact while preserving the inhibitor efficiency. The test methods and development of environmentally friendly corrosion inhibitors under different regulations are discussed. A brief account of the Paris Commission (PARCOM), UK, Norwegian regulations are also given.
INTRODUCTION Corrosion inhibitors continue to play a key role in controlling internal corrosion associated with oil and gas production and transportation. Future oil and gas production will occur in more remote areas specifically offshore from deep sea floor. Since in offshore production many inhibitors are added to the aqueous phase to maximize the inhibitor efficiency. The unused inhibitor concentrates and its disposal into the ocean may cause damage to the marine environment. Conventional corrosion inhibitors are toxic and hazardous to the environment, causing pollution and damage to aquatic and human life. Hence the strategy is to develop environmentally friendly formulations in offshore oil fields.
In recent years there is a realization to protect the environment from the harsh and hazardous effects of chemicals by using low toxic environmentally friendly chemicals through the ?green chemistry? principles. Green chemistry, or pollution prevention at molecular level, is chemistry designed to reduce or eliminate the use or generation of hazardous material associated with manufacture and application of chemicals. Green chemistry combines critical elements of environmental improvement, economic performance and social responsibility.
As a result stringent regulations for the protection of the environment, limits the number of chemicals allowed for use as inhibitors in accordance with mainly three criteria- their level of biodegradability, bioaccumulation and toxicity. An ideal green inhibitor according to the Paris Commission (PARCOM) is non-toxic, readily biodegradable, shows no bioaccumulation.
Thus the development of green inhibitors is a process, which requires the knowledge of the pertinent country regulations, the evaluation of the environmental performance for the environment to which the inhibitor will be exposed and the excellent corrosion protection this inhibitor is designed for.
In this paper the different evaluating practices in accordance with the various regulations in various parts of the world that are used to develop environmentally friendly corrosion inhibitors are reviewed. A brief account of the green inhibitors currently developed for oil and gas application is also presented.
PARIS COMMISSION The North Sea (U. K, Norway, Denmark, The Netherlands) with its fast growing offshore oil industry activities is at a potential risk from pollution. In an effort to protect the marine environment a number of regulations and guidelines regarding harmonization of procedures of approval, evaluation and testing of offshore chemicals and drilling muds were issued by a working group set up under Paris Commission (PARCOM) in 1990. These g
ABSTRACT The method for assessing internal corrosion in normally dry gas systems, DG-ICDA, relies upon the ability to identify the locations along the pipeline most likely to accumulate electrolyte. This requires calculating critical angles for liquid accumulation at different pipeline operating conditions. The critical angle correlation developed during the original DG-ICDA work was based on multiphase flow modeling data covering operating conditions typical of Gas Transmission Pipelines. The present work extended the flow modeling data to conditions typical of local distribution companies. An improved critical angle equation was developed. This new equation does not require iterations to calculate critical angles and is applicable to the full range of conditions typical of both gas transmission and local distribution pipelines.
INTRODUCTION A method to assess internal corrosion in normally dry natural gas systems has been developed and termed Dry Gas Internal Corrosion Direct Assessment (DG-ICDA). The final report on the development project1 is now incorporated by reference in the Final Rule 49 CFR Part 192 on Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines) and the method is embedded in the proposed NACE Standard Recommended Practice on DG-ICDA.
A requirement for DG-ICDA to be applied to normally dry gas systems is that any liquid in the pipeline is under stratified flow (i.e., it flows along the bottom of the pipe). The original work performed to develop DG-ICDA was guided by an INGAA group whose focus was on gas transmission pipelines with pipeline operating pressure of 500 to 1100 psi (3.4 to 7.6 MPa), temperature of 60 to 130 °F (16 to 54 °C), less than 25 ft/s (7.5 m/s) superficial gas velocity, and 20 to 48 inch (0.51 to 1.2 m) pipe diameter. Flow modeling was performed under these operating conditions, and it was found that stratified flow existed in this range of pressure given low liquid volumes. Since that time, local distribution companies have expressed a desire to apply DG-ICDA to lower pressures typical of their systems. The mechanics of flow dictate that stratified flow will also exist at lower pressures. However, flow modeling had not been performed at low pressures to verify that the simple prediction of critical angles could be directly applied.
Therefore, it was required to perform additional multiphase flow model calculations so that the range of pressures, superficial gas velocities and pipe diameters under which the simplified critical angle prediction can be extended. These new data would then be used to modify the existing correlation and spreadsheet predictor of critical angle (if needed) so that it could be applied under a wide range of conditions to include those typical of local distribution pipelines.
This paper presents the results of the flow model calculations and the development of a new critical angle correlation that fit well both high and low pressure data, and does not require using iterations.
Flow Modeling Approach The same flow modeling software used in the previous work OLGA-S(2), was used in this study in order to be able to incorporate the new low pressure results to the previously obtained data. More information about this model and its applicability for predicting liquid hold-up in inclined pipelines normally transporting dry gas, can be found elsewhere.
For wet gas systems, liquid holdup has been found to strongly depend on gas velocity and the angle of inclination. At low rates, the liquid holdup can increase by a factor of 100 or more as the inclination angle changes a fraction of a degree.
ABSTRACT After forty years of use, many end users do not recognize one very important benefit of Fusion Bonded Epoxy (FBE) pipeline coating, it is "Fail Safe". As with all pipeline coatings, FBE coatings have failed while in service, but rarely is there corrosion on the pipe under the failed coating. When adequate cathodic protection is available, FBE is "Fail Safe" because it does not shield CP current when disbondment occurs. Those who are responsible for selecting pipeline coatings should consider the use of "Fail Safe" coatings, so that when the coating fails, the pipe will be protected by the CP.
INTRODUCTION Fusion Bond Epoxy (FBE) coatings offer the end user with a pipeline coating that will allow (adequate) cathodic protection to actually protect the pipe steel under any failed or disbonded coating. This is a "Fail Safe" pipeline coating system. A "Fail Safe" coating system is defined as one that will allow cathodic protection (CP) current to pass through it to protect the substrate - not shield CP - should the coating bond fail and adequate CP is available. 1 This is not a 100% claim, but this phenomenon has been witnessed and documented on many in-service pipelines coated with FBE. When FBE fails, corrosion is rarely present under the failed FBE when adequate CP is available.
There are many parameters that must be considered when selecting pipeline coating systems. One of the parameters many engineers fail to include in the coating selection criteria, is "What will happen if and when the coating fails?" A key consideration should be "Will the coating shield CP if the bond fails? ''2 However, all coatings experience some disbondment and, therefore, the behavior of a disbonded coating is important in the
FAILURE MODES OF COATINGS All coatings can and will fail. There are many reasons why a coating fails. These failure modes have been welt documented 3,4,6,7,8,9,10,11 so they will be briefly discussed in this paper.
Surface Preparations Improper surface preparation is the reason for most coating failures. Contaminants, such as ionic salts will mix with water to cause disbondment and blistering. Hydrocarbons will not allow proper adhesion. FBE requires a well prepared and clean surface (near white) with a profile of 1.5 to 3.0 mils of anchor pattern.
Application Techniques Application processes can be a critical problem for all pipeline coatings. Application temperature is the most critical for the proper application of FBE.
Soil Stress Soil stress can damage many types of coating systems as documented in many articles. When the coating strength is less than the stresses introduced by the soil, the coating will fail. 6 FBE is rarely affected by soil stress, but most other coating systems can be damaged easily by soil stress.
Selection Criterion Many times coatings are selected for reasons that do not take into account all the possible failure modes and the resulting consequences when they do fail. All coatings will and do fail. All coatings have openings, pinholes, micro-fissures and other methods of allowing water, oxygen and other corrosion causing compounds to migrate through at different rates. FBE for example allows some water to penetrate as mentioned in the book "Fusion-Bonded Epoxy (FBE)" by J. Alan Kehr. However, FBE maintains its insulating properties in the presences of moisture and cathodic protection current. 7
Operating Temperature Operating temperature is always a critical factor in choosing a proper coating system. Many coatings, including FBE, are affected by the operating temperature of the pipeline. Higher or lower than specified temperatures can cause coatings to deteriorate, crack,
ABSTRACT Many process conditions in refinery amine units are known to promote accelerated corrosion. Monitoring corrosion in these units typically is limited to the traditional means- coupons, linear polarization probes, electrical resistance probes and so forth. Amine analyses are useful but not entirely without shortcomings when applied to corrosion monitoring. Computer modeling has evolved to become a useful tool in identifying potentially corrosive environments in localized areas within the unit. In this paper, a computer model is developed using data from a refinery system using MDEA to remove hydrogen sulfide from a process stream also containing carbon dioxide. Rules for reducing corrosion developed in-house or in literature are applied to anticipate corrosion.
INTRODUCTION The development of process simulation software that can estimate the composition, chemical and physical parameters of process streams in refinery amine unit service is not new. These types of programs have been used to identify operating variables and equipment for several decades. This paper illustrates some of the uses of process simulation software in predicting corrosive environments in amine units.
Amine solutions are used to remove hydrogen sulfide (H2S) and mercaptans from refinery process streams by adsorption. Carbon dioxide (CO2) and many other acid specie are also absorbed by the amine solution from the process stream.
Still other acid specie are reported to form in the amine solution from compounds in the feed stream such as carbon monoxide, oxygen and hydrogen cyanide.
The weakest of these acids, hydrogen sulfide and carbon dioxide, are removed from the amine solution by steam stripping. The steam stripping is not complete so residual hydrogen sulfide and carbon dioxide remains in the lean amine solution.
Many of these acids are not removed by steam stripping and are called Heat Stable Salts (HSS) or, unless otherwise neutralized, Heat Stable Amine Salts (HSAS). The accumulation of HSAS in the amine solution has been documented and generally agreed to as increasing corrosion activity. Heat Stable Amine Salts can be removed from the solution (called reclaiming) or neutralized insitu.
Amine solutions used in refinery service
The amine solvent is selected to meet specific processing needs with the most common being (mono) ethanolamine (MEA), diethanolamine (DEA), methyldiethanolamine (MDEA) and Diglycolamine (DGA). Each amine solvent has distinct advantages and disadvantages.
One of the most important parameters in selecting an amine solution is "selectivity" for H2S over other acid gases. Of the amines listed here, MDEA is the only amine with significant selectivity in commercial applications. This selectivity reduces the amount of carbon dioxide absorbed by the solution allowing for higher capacity or lower energy usage. H2S selectivity also reduces the amount of CO2 in the acid gas feed stream to the sulfur plant. H2S selectivity increases as MDEA concentration is reduced.
Mercaptan removal is important for many petrochemical feed stocks. DGA is reported to provide the best mercaptan removal.
All of the amines have some solubility in hydrocarbon streams such as liquefied petroleum gas or LPG. Literature 3 indicates that at the maximum recommended concentrations, DEA has the lowest LPG solubility. Amine losses resulting from solubility in LPG increase with amine solution concentration. The literature source indicates that MDEA solubility in LPG increases from about 135 ppm to 300 ppm as MDEA concentration increases from 35 to 50-wt%.
In refinery service, all amine solutions that accumulate HSAS require reclaimin
ABSTRACT Accurate corrosion growth predictions are important to determining pipeline integrity verification reassessment intervals and to justify maximum allowable intervals. One existing method to determine a corrosion growth rate is to measure corrosion rate on the basis of linear polarization resistance (LPR) at a dig site where corrosion was identified. This method requires technical improvements to represent corrosivity of a pipeline. Thus, the need was identified to develop an electrochemical testing method which can be employed at the pipeline excavation (dig) sites which will generate corrosion rate data for determining external corrosion integrity verification reassessment intervals. The scope included developing and field-testing of the cells for in-situ corrosion rate measurements. Two cell designs were assembled to enable Linear Polarization Resistance (LPR) measurements in situ in field conditions. Field demonstrations indicate that utilization of the cells facilitates the use of the LPR technique as the basis for determining integrity verification reassessment intervals. The proper approach to corrosion rate calculation requires the use of raw data generated during the LPR test (polarization resistance free from the soil resistance contribution) and direct measurements of the anomaly dimensions (particularly the depth of the anomaly). To estimate the effect of corrosion mitigation due to cathodic protection, the amount of polarization shift must be known and the Tafel behavior of the steel/surface products interface must be either determined during the field measurements or assumed.
INTRODUCTION Accurate corrosion growth predictions are important to determining integrity verification reassessment intervals and to justify maximum allowable intervals. A method to determine accurate and not overly conservative corrosion growth rates for pipelines without consecutive inline inspection (ILI) runs is presently not available. Two methods are presently used to determine external corrosion reassessment intervals for pipeline integrity verification:
1. A rate is calculated by extrapolating corrosion rate from previous metal loss. This can be done through analysis of consecutive ILI inspections (limiting the approach to those lines for which multiple ILI runs exist) or by measuring what is believed to be the most severe defect and assuming it grew uniformly over some time period. The assumption that a defect grew uniformly over the life of a pipe from time of installation is not considered accurate in most cases because corrosion initiation and dormancy are not considered, and corrosion rates are typically not constant over time either because of corrosion product formation or environmental changes.
2. Generic corrosion rates are used to represent pipeline steels in soils. NACE RP0205 on ECDA suggests the use of 16 mpy when other data is not available, but this number does not reflect the differences in corrosion rates on specific pipelines in specific environments. The number is overly conservative for most pipelines and does not represent the pipelines that experience anomalously high corrosion rates. External corrosion rates have been measured in soils and conservative average values in the range of 10 to 28 mpy are reported. However, none sufficiently address local corrosion rates along a specific pipeline or the expected distribution of corrosion rates along the length of a specific pipeline. An improvement over using one corrosion rate (or range) for all pipelines is to use corrosion rates based on soil type (e.g., National Bureau of Standards Data,) including an estimate for maximum corrosion depth given the size of a sample. However, matching the soils by geological p
ABSTRACT At Alaska?s North Slope, existing fields span a large geographic area where three phase production fluids can cause severe corrosion. To monitor corrosion and provide feedback for the chemical mitigation program, electrical resistance probes connected to remote data collectors are installed at approximately 80 locations. Measurements are made on a four hour interval at each location, and data are collected during weekly site visits. A wireless remote monitoring unit utilizing a mesh network of 900 MHz spread spectrum radios was developed to collect data from the existing hardware and transmit it to a central location. In a pilot project, five remote monitoring units and one central unit were successfully deployed in the summer of 2005.
INTRODUCTION BP Exploration (Alaska), Inc. is the operator of Greater Prudhoe Bay (GPB), which is one of several fields located along Alaska?s North Slope (see Figure 1). GPB is a remote field that is spread across an area of ~400 mile (1,036 km2) with drill sites connected by a road network. Three-phase production fluids coming from wells are combined together and transported to separation facilities via flow lines. With 12% CO2 and water cut in excess of 70%, sweet corrosion can be severe and is mitigated with continuous injection of corrosion inhibitor. Electrical resistance (ER) probes are used to monitor short term trends in corrosion rates on the flow lines and provide feedback to the chemical mitigation program. There are ~80 ER probes in service throughout GPB, making measurements on 4- hour intervals. The data are stored in a remote data collector (RDC) and downloaded to a handheld unit once per week by a technician. The data are then uploaded from the handheld unit to a database where they are available for analysis.
Figure 1 - Alaska's North Slope Oil Fields
The ER probe locations are typically remote from any power or communication infrastructure. This lack of infrastructure provided the reason to evaluate wireless remote monitoring technologies. The term wireless remote monitoring can have many meanings; within the context of this paper it is considered a Class 5 network that has no immediate operational consequence.
WIRELESS REMOTE MONITORING REQUIREMENTS General Hardware Requirements Given the significant investment in existing hardware and training, designing a wireless solution that would interface with the existing hardware was one of the chief requirements. Secondary requirements for the new Remote Monitoring Unit (RMU) included: · Reducing technician visits from once per week to once per quarter, · Operating in an extremely remote and harsh environment, · Providing power and control of a suitable communication device, · Providing data logging capability (possible future use with other applications), · Utilizing modular construction for ease of installation and maintenance, · Operating from a field replaceable battery pack (or from an optional external power source), · Providing secure data transmissions, · Allowing remote reconfiguration of the hardware, · Providing for system expansion or redeployment.
Selection of a Communication System Central to the process of recovering data from remote locations is the communication system itself. In choosing the most appropriate communication system, a number of technologies were evaluated including two-way paging, cellular, satellite, and radio (VHF, UHF and microwave). Each of these options was assessed against a list of important selection criteria, including the following:
· System reliability, · Maintaining data integrity, · Operating in remote areas, without the need for communi