High pH Stress Corrosion Cracking (HpHSCC) is a significant threat to the buried pipelines, which are protected through simultaneous coating and cathodic protection strategies. In the past decades, extensive research has been devoted to assessing the influence of environmental and metallurgical factors on the susceptibility to HpHSCC. With reference to mechanical factors, previous studies employed either slow strain rate or constant amplitude testing methods. However, the pressure fluctuation data extracted from pipeline operations has indicated that pipelines experience highly variable amplitude loading conditions during their service. Accordingly, an important consideration in managing HpHSCC is load interaction. Statistics show a higher probability of HpHSCC failures within the 30 km downstream from pump/compressor stations where the pipeline steels experience elevated service temperatures, with incipient higher susceptibility to HpHSCC. However, the pipeline sections within the 30 km downstream from pump/compressor stations also experience the underload-type of pressure fluctuations that feature a maximum pressure close to the design limit, frequent and large amplitudes of depressurization, resulting in low stress ratio, R (minimum stress/maximum stress), and many smaller pressure fluctuations (minor cycles) with R ratio closer to +1.0. It has been well characterized that the underload-minor-cycle-type of pressure fluctuations has the significant acceleration effect on crack growth rates in near-neutral pH (NNpH) environments. However, the effect of the underload-type of pressure schemes on HpHSCC crack growth has not been well developed. In this research work, a cathodically protected X65 steel specimen in the developed high pH solution, composed of 1N Na 2 CO 3 and 1N NaHCO 3 , was subjected to different loading conditions. These loading waveforms simulate underload cycles (R = 0.5), minor cycles (R = 0.9) and variable amplitudes consisting of both underload and minor cycles, respectively. The HpHSCC test results showed that the highest and lowest crack growth rates were obtained in high and low R ratio constant amplitude loading conditions, respectively. Furthermore, an intermediate crack growth rate was obtained under variable amplitude loading condition. These results indicate that the underload cycles retard crack growth rate in high pH environments.

Vibration related issues can be a challenging part of pipeline integrity management, because they are frequently difficult to predict, diagnose, and remediate. Often, vibrational issues are not even considered until pipe movement is observed or failures occur. A wide variety of vibration problems are associated with pumps and compressors, and piping at pumping stations are often susceptible to vibration related issues. Excessive piping vibration may result in leaks at connections and flanges, and fatigue failures can occur, leading to leaks that present safety and environmental concerns. The energy responsible for pipeline vibration is usually provided by rotating or reciprocating pumping equipment, and is transmitted to the piping either by direct mechanical contact, pressure pulsations, or turbulence in the pumped fluid. Vibration problems usually occur when a mechanical natural frequency of the piping system, an acoustic natural frequency of the contained fluid, or both, is excited by the driving force. In this paper, a brief overview of vibration issues that occur in pipeline facilities is presented. Next, a selection of case studies is provided to illustrate some of the types of vibration induced failures that have been observed at pipeline facilities, and how they were addressed and resolved. These examples provide some insight into how to potentially avoid such issues, or if they occur, how to identify and mitigate them.

Internal pressure fluctuations during pipeline operations could contribute to crack growth in steel pipelines. These pressure fluctuations create a variable amplitude loading condition with large amplitude cycles at near-zero stress ratio, R (minimum stress / maximum stress) and small amplitude cycles (minor cycles) at near +1 R ratio which can both affect crack propagation. Mean stresses fluctuate with pressure due to fluid friction losses proportional to the distance from the pump/compressor station. A deeper understanding of mean stress sensitivity on crack growth rate in steel pipelines is sought. The aim of this research is to retard crack growth in pipelines by prescribing pressure fluctuations, thus controlling mean stress effects on imperfection growth in steel pipelines under a near neutral pH environment. This study shows that prescriptive mean load pressure fluctuations can be used to reduce crack growth rates in steel pipelines, thus expanding pipeline integrity management methods.

In the light of recent experience of wildfires in Alberta and British Columbia, Alliance Pipeline has strengthened their emergency preparedness in dealing with external fire events that have the potential to affect above-ground facilities connected with their high pressure natural gas pipeline system. As part of this initiative a quantitative methodology has been developed that enables the effects of a wildfire on an above-ground pipeline facility to be assessed. The methodology consists of three linked calculations which assess: 1. the severity of the wildfire, based on information from the Canadian Wildland Fire Information System, 2. the transmission of thermal radiation from the wildfire to the facility, and, 3. the response of equipment, structures and buildings to the incident thermal radiation. The predictions of the methodology agree well with the actual damage observed at a lateral block valve site following a wildfire in 2016. Application to example facility types (block valve sites, meter stations and compressor stations) has demonstrated that, in general, damage is only predicted for more vulnerable items such as cables. The sensitivity of the predictions of the methodology to the input parameters and key modelling uncertainties has been examined. This demonstrates that the results are sensitive to the distance of the facility from the tree line and the assumed vegetation type. This shows the importance of verifying the location relative to the vegetation and selecting the appropriate vegetation type from the Canadian Wildland Fire Information System for site specific assessments. The predictions of the methodology are particularly sensitive to the assumed flame temperature. However, a value has been chosen that gives good agreement with measured thermal radiation values from wildfires. Of the mitigation options considered, the most effective and practical is to increase the distance to the tree line. This measure has the advantage of reducing radiation levels for all items on the site. Even though the work shows that failure of exposed pipework due to wildfires is unlikely, maintaining the flow within pipes is recommended as this increases the radiative flux at which failure is predicted to occur. However, as failure of cables and hence control systems would occur at a lower flux levels the fail-safe actions of such systems needs to be confirmed. Shielding of cables or items of equipment in general is likely to be impractical but could be considered for particularly vulnerable equipment or locations.

Stress Corrosion Cracking (SCC) is a time dependent mechanism. Three conditions are required at the same location for the formation of SCC namely, susceptible material, susceptible environment and sufficient stress. Pipe age, operating stress level and coating type are significant parameters in determining the susceptibility to near-neutral pH SCC; whereas, additional parameters such as operating temperature and distance from compressor station are considered for high pH SCC. Environmental conditions such as soil type, topography and drainage have also shown correlation to SCC susceptibility. Several integrity assessment methods can be used to identify SCC on pipeline including hydrostatic testing, in-line inspection (ILI), and direct assessment (DA). Because the occurrence of SCC is a complex phenomenon and it depends on many parameters, it is important to develop a risk assessment model that can systematically incorporate all relevant evidences of SCC in a sensible way. This paper presents a robust risk assessment model for SCC, which uses evidence from failure histories, observation from assessments (i.e., digs, pressure tests, and ILIs), and mechanistic understanding of SCC (i.e. susceptible coating, pipe material, stress level, soil properties, etc.). This risk model is transparent and updateable, which allows incorporation of new scientific learnings and findings of SCC.

Pipelines are designed to operate below a maximum operating pressure in service. However, there are pressure fluctuations during operation. The presence of pressure fluctuations creates a drive for crack growth in steel pipes. In order to prevent catastrophic failure of pipelines, there is need for better understanding of the contribution of pressure fluctuations to crack growth rate in steel pipelines. Analysis of pressure fluctuation data in oil and gas pipelines shows that there are different types of fluctuations in a pipe due to friction loss with distance from the pump or compressor station. All these fluctuation types show a form of variable amplitude loading classified in this research as underload, mean load and overload. Studies of some structural systems shows that underload can cause acceleration of crack growth while retardation of crack growth is observed after an overload. This research aims to apply pressure fluctuations to manage integrity of steel pipelines through a novel approach of load sequence involving underload and overload in near neutral pH environment. Clear knowledge of the effect of load interaction involving load sequence of underload and overload is vital to control crack growth in steel pipelines under near neutral pH environment. The result of crack growth rate under different load sequence on X65 steel indicate that increase in overload ratio of 2, 3 and 4 caused an increase in crack growth rate of 1.68E−3, 1.89E−3 and 2.31E−3 mm/block respectively. These results are compared with results from other tests under variable amplitude without load sequence. Analyses were carried out on the morphology of the crack tip and the fracture surface after the test.

From extensive investigations for over 30 years since the discovery of near-neutral pH stress corrosion cracking (NNpHSCC), the physical processes of crack initiation and growth have been determined, despite that some details in various aspects of crack initiation and growth are still to be understood. The growth curve is a function of crack growth by direct dissolution of steels at localized areas on pipe surface during initiation or at the tip of a crack during early stage of crack growth (the dissolution growth curve), and by a process involving the interaction of fatigue and hydrogen embrittlement (corrosion fatigue, the hydrogen enhanced fatigue growth curve) in Stage II after crack initiation and early stage of crack growth. For the latter case, recent research shows that crack growth rate can be substantially enhanced by variable amplitude cyclic loading. One of the most severe scenarios of cyclic loading in terms of crack growth rate is the underload type of pressure fluctuations that is often found within 30 km downstream of a compressor station. This investigation is aimed to evaluate pressure scenarios that could reduce or retard crack growth during pipeline operation. Specifically, the effect of pressure holds was investigated. Different periods of static hold were performed to an X65 pipeline steel exposed to a near-neutral pH solution. It was found that a static hold at the maximum load for one hour immediately after a large depressurization-repressurization cycle (underload cycle) yielded the lowest crack growth rate, which was about one third of that of constant amplitude fatigue without the static hold. Static holds for a period shorter or longer than one hour have yielded higher crack growth rates. This observation can be applied to field pipelines during operations to retard crack propagation.

Natural gas leakage from unmanned facilities, such as compressor stations, gathering sites, and block valve locations, can pose significant economic and safety impacts. Additionally, methane, the primary constituent of natural gas, is a powerful greenhouse gas with 84 times the global warming potential of carbon dioxide on a mass basis over a 20-year period (IPCC 2013). Due to the remote location of many of these facilities, fluid leaks can persist for extended periods of time. Continuous leak detection systems would facilitate rapid identification and repair of leaks. However, existing technologies, such as infrared cameras, are cost-prohibitive to be installed at a high number of sites and are instead used in periodic monitoring as part of leak detection and repair programs. Such periodic monitoring does not provide for quick detection of “fat tail” leaks that dominate the emissions from gathering and transportation systems (Mitchell et al. 2015, Subramanian et al. 2015). A unique and innovative arrangement of various stakeholders was utilized to initiate a technology development and testing program aimed at expedited deployment of low-cost technologies at high numbers of sites. The technologies targeted for this work were low enough in cost to economically justify the installation of such sensors at every gas gathering and transportation site. This work was driven by an environmental advocacy organization under a partnership with eight different oil and gas companies and technical oversight from various universities, non-profits, and government agencies to give a wide perspective on the needs of such technology. Four different technologies were developed and tested in realistic release environments. The technologies ranged from sensors modified from automobile-based technology to laser-based systems used for monitoring gases in coal mines. The systems were treated as “end-to-end” units whereby all components (e.g., sensor, data acquisition, enclosures, etc.) needed to perform according to the provided specifications. The testing involved controlled releases under numerous environmental conditions and with different gas compositions. The largest focus of the testing was on outdoor releases where the systems had to detect the transient nature of gas plumes. The primary objectives of the testing were to determine the readiness of the technologies for pilot testing in the field and identify continuous improvement opportunities. The project demonstrated that there are newly-developed technologies that could be deployed as low-cost continuous monitoring solutions for the gas industry.

This paper presents a systematic and comprehensive procedure for the system-wide response to incidents (SWRI). This SWRI process has been used for identifying emerging threats and incorporating the learnings from major incidents into a pipeline integrity management program (IMP). This process also complements the IMP for threat identification and system wide risk assessment, thus giving consideration to all known threats and their interactions. A recent major incident due to thermal expansion on a TransCanada pipeline system was used to demonstrate the process of SWRI and the use of SWRI to identify the contributing factors of thermal expansion. An example was used to illustrate the engineering assessment for thermal expansion driven by the construction of two new compressor stations on an existing pipeline. The process documented in this case study has the potential to augment the integrity management programs and systemic corrective actions for pipeline systems in the energy industry.

With the rapid economic and rigorous requirement of environmental governance, natural gas serves as important energy source in industry consumption. In 2015, the total consumption of natural gas in China is approximately 142 billion m 3 . As the primary mode of natural gas transport, early pipeline operated for more than 20 years in China, and its reliability also attracts abundant concerns by the increasing potential risks. However, the process of pipeline reliability evaluating and estimation in China is still located under development. To solve the problem, a simplified reliability estimation method is introduced in this article. To begin with the main equipment of a compressing station, the filter, air cooler and compressors are three research objectives. Because of redundant design for enhancing reliability, the major equipment usually operates with a same spare unit. Thus, the simplified station is consisted by 3 main sections with multiple units as filter section, compressing section and cooling section. By assuming their reliability following normal distribution, the multivariate normal distribution model is available. Each unit is characterized by one dimension of the multivariate normal distribution. This article considers both relevant and irrelevant processes while the equipment is operating simultaneously and illustrates the results via two and three dimensions normal distribution calculation. Due to the model being singular function because of be established based on multivariate normal distribution and parameter estimation principles, the analytical solution is not available. Therefore, numerical computation is the compulsory solution. However, the reliability analysis of pipe is different from equipment and it has been studied for years in details from theory to experiments. Consequently, the reliability of pipe is analyzed by statistics method from collected operating data. A pipeline with 25-years operating data in China is applied in the case study chapter for reliability estimation and analysis. According to the operating data collected by China National Petroleum Corporation, the failure rate of major equipment is estimated by determining the parameters of each distribution and fitted a curve like bathtub curve. Similarly, the failure rate of pipe is indicated as failures per 10 3 km • year. For comparing, the operating data is also fitted a curve to validate the result of the model with the purpose of reasonably estimating the whole period reliability. The result demonstrates that the model is available in practice if the parameters are determined properly.

In 1997 Alberta Natural Gas Co. Ltd (ANG) completed a field testing program of its centrifugal compressor fleet. Field performance and surge testing of centrifugal compressors in pipeline service was done for efficiency evaluation and to re-establish surge line control. By confirming the actual location of the surge line, surge controllers are adjusted to allow a more efficient and greater operating range resulting in fuel savings and operating flexibility. The results of this testing provides an accurate operating window for the compression equipment which is then transferred to a hydraulic analysis computer model used to provide accurate capacity estimates in support of additional gas transmission contractible volumes. As part of the surge testing, suction to impeller eye differential pressure readings (used for surge control) were evaluated to determine strength, stability and repeatability. Finally, baseline data was established to determine current compressor operating efficiencies and will be used to determine future efficiency degradation. ANG is a wholly owned subsidiary of TransCanada PipeLines, one of North America’s leading transporters of natural gas through its energy transmission businesses. ANG owns and operates the British Columbia segment of the Alberta-California pipeline system (ref Figure 1). Compression is provided at three compressor stations with eleven compressors totalling 187,000 installed ISO HP.

Natural gas transmission systems have many sources of fugitive methane emissions that have been difficult to eliminate. This paper discusses an option for dealing with one such source for operations using turbo-compressor units fitted with dry gas seals. Dry seal leakage ultimately results in waste gas that is emitted to the atmosphere through the primary vent. A simple, cost effective, emission disposal mechanism for this application is to vent the seal leakage in to the gas turbine’s air intake. Explosion hazards are not created by the resultant ultra-lean fuel/air mixture, and once this mixture reaches the combustion chamber, where sufficient fuel is added to create a flammable mixture, significant oxidation of the seal vent gas is realized. In principle, this system is easily implemented with simple modifications to the existing vent piping. However, the inherent safety of ultra-lean fuel/air mixture applies only when the gas turbine is operating with gas turbine airflow overwhelming the seal leakage flow. A potential design solution for managing this emission avoidance mechanism including safe operation during gas turbine shutdown periods is detailed.

Gas transmission companies are sometimes disappointed with the results of efforts to control noise from reciprocating and centrifugal compressor packages, including new compressor station designs and retrofit programs. In an effort to begin to standardize noise control equipment specifications and performance testing procedures, the PRC I undertook a project to develop a series of “ Guidelines ” for implementing engineering noise control designs for compressor station equipment. The project was sponsored by the PRC I nternational (PRC I ). The project report consists of eleven stand-alone Guidelines that can be used by gas transmission companies to develop their own noise control specifications for major compressor station equipment. The intent of the Guidelines is to maintain traditional vendor/sub-vendor roles between compressor packagers and component manufacturers while maintaining the practice of vendor design - vendor guarantee. The noise control requirements can be verified by pre-establishing field performance testing methods. Specific field performance testing methods for various typical mechanical equipment are provided in each Guideline. The Guidelines are structured to draw a distinction between mechanical equipment components which are noise generators, sound attenuators or acoustic radiators, as each requires a different specification format. To fulfill this aspect, a high temperature microphone probe was researched, developed and tested. This piece of hardware, along with the developed measurement methodology, allows optional diagnostical testing of the engine exhaust noise component of compressor station noise. These diagnostics can assist in isolating the noise generated by the engine versus the attenuation provided by the exhaust silencer. The measurement procedures do not require silencer removal from the package or equipment shutdown to test, which thus reduces testing costs.

Today’s new pipeline projects have to meet countless technical, regulatory, economic, or social requirements before they can go from the drawing board to reality. One of the more recent considerations is in the area of environmental noise. Environmental noise from pipeline facilities is particularly difficult to control because of the complexities of sound propagation and the subjective nature of that sound relative to some receptor. The extent of noise control from facility equipment such as compressors, coolers, piping, valves, blowdown, emergency flares, even telephone horns, therefore, becomes very difficult to estimate. There must be some understanding of baseline expectations from all interested parties. In addition, pipeline operators must treat environmental noise control as an integral part of project concept and design and not as an afterthought or additional non-core responsibility. Environmental noise control is not an additional cost, it is part of the overall cost of the pipeline transportation business.

Transmission gas pipeline network consume significant amounts of energy. Then, minimizing the energy requirements is a challenging task. Due to the nonlinearity and poor knowledge of the system states, several results, based on the optimal control theory, are obtained only for simple configurations. In this paper an optimization scheme in the face of varying demand is carried out. It is based on the use of a dynamic simulation program as a plant model and the Pareto set technique to sell out useful experiments. Experiments are used for the identification of regression models based on an original class of functions. The nonlinear programming algorithm results. Its connection with regression models permits the definition off-line and for a long time horizon, of the optimal discharge pressure trajectory for all the compressor stations. The use of adaptive algorithms, with high frequency, permits to cancel the effect of unknown disturbances and errors in demand forecasts. In this way, an on-line optimization scheme using data of SCADA system is presented.

Automatic and remotely controlled main line valves are used in natural gas transmission pipelines to provide early shutoff of gas flow in the event of a pipeline rupture. Operating experience, however, shows that these valves and their associated rupture detection and valve operator systems are not always reliable in sensing a line break and in achieving valve closure. There are documented instances of pipeline ruptures going undetected, and of main line valves not closing completely after even a full line break. False valve closures have also occurred, causing pipelines to be shut down unnecessarily. Under sponsorship of the Gas Research Institute (GRI), a technology assessment program was conducted by Southwest Research Institute (SwRI) to define the present state of the art of automatic and remotely controlled main line valves, to evaluate their effectiveness in achieving isolation of a ruptured line, and to identify technology improvements that are needed to improve valve reliability. This study was based on a survey of the U.S. natural gas industry’s experience with line break control equipment, and upon computational modeling of typical pipeline systems to simulate the generation and propagation of pressure and flow transients created by a line break. Line break transients were also compared to the transient levels generated by normal pipeline operations (start-up and shutdown of compressors, branch load changes, etc.). Also during this study, a semi-empirical computer model was developed to calculate pipeline blowdown time as a function of break size, pipeline configuration, and operating conditions, even in cases where valve closure is delayed for some period after the line break occurs. This information can be of value to pipeline engineers and emergency response planners. Results of the technology assessment show that the primary source of unreliability in present day line break control systems lies in their inability to discriminate between a line break transient, and those generated by other pipeline operations. In most cases, automatic control valves (ACV’s) sense the rate of pipeline pressure drop (ROPD) to detect a line break. In many field applications, however, transient pressure signals caused by compressor operations and load changes are stronger than those produced by a line break. In order to avoid false valve closures which could otherwise result, sensitivity of the rupture detection systems is “backed off,” often to the point of inoperability of the ACV. Other fluid transient signals besides pressure drop are also generated in the pipeline during a line break, and these can sometimes be used advantageously to replace or confirm the traditional ROPD signal. In looped parallel pipelines, for example, crossover flow rate is usually a more reliable line break signal when crossovers are open. The resultant line-to-line differential pressure also provides a viable option when crossovers are either open or closed. In general, however, no one detection parameter is optimum for all applications. Of even more importance is the rupture sensor location. The concept of locating additional sensors between the main line valves (rather than just at the valves) provides the most promising approach for enhancing the reliability of present ACV’s and for providing needed line break information to remote controlled valves (RCV’s). In either case (ACV’s or RCV’s), rupture sensor location is much more important than valve location or valve spacing in ensuring reliable rupture isolation. However, valve spacing does affect the volume of gas blown down after shut-in of a ruptured section. This time can often be from 10 to 60 minutes for typical pipeline valve spacings.

This paper presents how a major U.S. gas transmission and storage company restored gas storage peaking capacity by repowering obsolete gas turbine compressor units. Consumers Power Company’s Ray Field located in Macomb County, Michigan, USA, was developed as a 44 BCF working capacity gas storage field in 1966. Due to the high deliverability, the field is operated as a peaking reservoir, handling rates as high as 500 MMCFD on injection and 1,200 MMCFD on withdrawal. Ten (10) 2,750 horsepower gas turbine driven 4-stage centrifugal compressor units were installed in the mid to late 1960’s at the field. The compression is operated 2, 4 and 8 stage, as needed, to cover storage pressures of 450 to 1800 psig. Each centrifugal compressor is driven by a Pratt Whitney (PW) GG-12 Gas Generator firing into a Cooper-Bessemer (CB) RT-27 Power Turbine. By 1980 parts and maintenance services for the PW GG-12 Gas Generator became very expensive to non-existent. Aircraft use of the GG-12 (JT-12) had been phased out. Consumers Power, with 13 of these turbines on their system, was becoming the only remaining user. In the mid 1980’s four (4) of the Ray Field gas turbine compressor units were replaced with two (2) 6,000 horsepower reciprocating engine compressor units. These replacements maintained the deliverability of the field and provided salvageable engines and other parts to maintain the six (6) remaining turbines. However, by 1993 maintenance parts returned as a major problem as well as unit availability on the 6 remaining turbine units. In 1994 Consumers Power committed to a gas turbine unit repowering program as the preferred choice over unit replacement. Two (2) refurbished Solar Centaur T4500 Gas Turbine drives were purchased and installed to repower 2 of the obsolete turbine units. These installations have been very successful. Existing compressors, foundations, piping, coolers and auxiliary systems were re-used with only minor modification. The complete installed cost for repowering was about 33% of the cost experienced for replacement. Installation was completed within eight (8) months of project commitment. The low emission rates from the Solar SoLoNOx Combustors allowed short lead time (6 months) on air emissions permit. New sound attenuation enclosures met the new local noise ordinance and replaced equipment that had been a source of local complaint. PLC based controls improved reliability and flexibility of operation. The additional horsepower available from the T4500 Turbine (4,300 vs 2,750) allows for increased future capacity. Because of the success of the Ray Turbine Repowering Project, Consumers Power has committed to 2 more refurbished Solar Centaur T4500 Units to repower PW/CB Turbines at the St Clair Compressor Station. Solar is scheduled to delivery these 2 units by year-end 1995 for installation in 1996.

What’s new in the pipeline industry in terms of field automation and information systems technology? What impact are these technologies having on the business environment and how will they affect the way we do business in the future? How can we leverage these technologies to support the demanding business requirements of today and tomorrow? The paper takes a quick look back at the origin of the first field control systems and office automation. Through a chronological progression we arrive at what’s on the leading edge of information technology today. Based upon current architectures we identify how systems are implemented and some of the issues affecting the integration of field and office information systems. From small scale compressor control systems to large scale pipeline information systems we look at the informational requirements and how systems currently implement the required functionality. Within the business environment we examine the need for corporate-wide information access. Considering both operational and business/economic levels, we identify some of the key informational requirements for the effective operation and management of a pipeline. Based upon a corporate-wide information access model and current business and technology trends, we present an enterprise application architecture that would meet the operational and business requirements of a pipeline company. Finally, the paper takes at look at some of the business and management issues associated with implementing new information technology. It offers some basic guidelines on helping managers reduce the risks and ultimately deliver successful projects for their company.

Mechanical condition diagnostics have historically relied upon both human perceptions (sound, sight, smell) and mechanical measurements, such as vibration. In recent years, the ability to extract useful information about certain conditions of mechanical equipment driven by motors from motor energy transfer components (current, power, etc.) has been recognized. This paper discusses the use of motor data to assist in the understanding of certain fluid and mechanical conditions of compressors and pumps.

Pipeline projects impact the environment through soil and habitat disturbance, noise during construction and compressor operation, river crossing disturbance and the risk of rupture. Assigning monetary value to these negative project consequences enables the environment to be represented in the project cost-benefit analysis. This paper presents the mechanics and implications of two environmental valuation techniques: (1) the contingent valuation method and (2) the stated preference method. The use of environmental value at the project economic-evaluation stage is explained. A summary of research done on relevant environmental attribute valuation is presented and discussed. Recommendations for further research in the field are made.