Document ID: EPA-HQ-RCRA-2010-0695-0101
Agency: epa
Document Type: Supporting & Related Material
Title: 
Posted Date: 2014-01-03T05:00Z

Carbon Dioxide Pipelines in the United States
                                       
                                       
                                       
                                       
                             Contract EP-W-10-055
                              Work Assignment 27 
                        Technical Directive 3, Part 1 
                                       
                                       
                                       
                                       
                                       
                                       
                                       
                                       
                                       
                                       
                     Submitted by The Cadmus Group, Inc. 
Under Subcontract to Eastern Research Group, Inc.
Carbon Dioxide Pipelines in the United States

1.0 Introduction
   Enhanced oil recovery is the largest use of carbon dioxide in the United States, exceeding the use for food grade carbon dioxide by a factor of ten (Interstate Oil and Gas Compact Commission (IOGCC), 2010). This carbon dioxide is transported from sources to oil fields for injection by means of pipeline. Pipelines are favored for carbon dioxide transport because they are the easiest means to transport large volumes of carbon dioxide the distances required to the oil fields. While transport is possible by tanker trucks or ships, transporting the volumes required for enhanced oil recovery would require an inordinate number of vehicles, would require significant storage, and would make continuous delivery of carbon dioxide difficult. 
   Increased interest in geologic sequestration (GS) of carbon dioxide will significantly increase the need for carbon dioxide pipelines. Like oil recovery, pipelines would be the transportation mode of choice to enable delivery of carbon dioxide continuously at volumes and pressures adequate for GS injection. Estimates of the required mileage of pipeline to meet sequestration needs under a carbon regulation scenario range from 11,000 miles to 66,000 miles (Carbon Sequestration Leadership Forum, undated; IOGCC, 2010). This will represent a large increase in the total mileage of carbon dioxide pipelines. To ensure the safety of these future pipelines, it is instructive to review the current state of knowledge regarding carbon dioxide pipelines.
   This report will review the current state of knowledge of carbon dioxide pipelines in the United States, and provide the following information: 
      * An overview of the existing pipeline network, including amounts of carbon dioxide shipped, miles of pipeline, and a description of the pipelines. 
      * A review of various considerations for pipeline construction including materials, size, and other guidelines. 
      * Costs of pipeline projects including capital, operations and maintenance, and other fees. 
      * Pipeline safety, including regulations and past incidents. 
      * A discussion of planned future pipelines.
   
2.0 Pipeline Statistics
   Pipeline safety is regulated by the Pipeline Hazardous Materials and Substance Administration (PHMSA), which is a branch of the Department of Transportation. The PHMSA keeps statistics on all pipelines transporting hazardous substances. Although carbon dioxide is not considered a hazardous substance, it is regulated with hazardous liquids, as the construction requirements for supercritical carbon dioxide are similar to those for hazardous liquids (e.g., petroleum products) pipelines. Statistics are kept on all transportation pipelines. The segments covered would include pipelines from the source up to the individual oil fields. Feeder lines to individual wells are not included in PHMSA statistics. Statistics are kept according to operator and not by pipeline. Therefore, PHMSA statistics do not enable analysis by pipeline or source. The following sections describe the statistics compiled by PHMSA supplemented by other sources to describe the current carbon dioxide pipeline situation.
      2.1 Carbon Dioxide Transported 
      Table 1 gives the PHMSA statistics for carbon dioxide transported for 2010, the most recent year available. The table lists 25 operators transporting nearly 2 trillion barrel-miles of carbon dioxide. As a comparison, the 2008 statistics as cited in the Assessment of the Potential Costs, Benefits, and Other Impact of the Conditional Exclusion from the RCRA Definition of Hazardous Waste for CO2 Streams Managed in UIC Class VI Wells for the Purposes of Geologic Sequestration (EPA, 2011) lists 26 operators (Genesis is listed twice) transporting 34 billion barrel-miles of carbon dioxide. It is not known whether Transpetco, the operator not reported in the 2010 statistics is inactive or if operation of that pipeline was assumed by another company. The 2010 values represent a significant increase from the 2008 values. 
      The largest shipper of carbon dioxide was Exxon/Mobil with nearly 1.8 trillion barrel-miles of carbon dioxide transported. The next biggest shippers of carbon dioxide in 2010 were Kinder Morgan, Enmark, and Bravo. All of the major operators saw significant increases. Exxon/Mobil saw a nearly 15 percent increase. Kinder Morgan nearly tripled its barrel-miles transported; Enmark went from just over 13 thousand barrel-miles to over 52 billion barrel-miles. Bravo saw a slight increase from 19.1 to 19.5 billion barrel-miles. It is possible there is some skew in the increase in delivery of carbon dioxide since results are reported in barrel-miles. The increase may represent increased volume delivered or it could represent increased distances of delivery. Most likely, both factors play into the significant increase.
      Table 1: Barrel Miles of Carbon Dioxide Transported in 2010
      
      Source: PHMSA (2010)
      2.2 Miles of Pipe
      The transport of nearly 2 trillion barrel-miles of carbon dioxide necessitates a significant pipeline network. The total miles of pipe by operator is shown in Table 2.  PHMSA statistics indicate there were 4,477.6 miles of pipeline in 2010. This is an increase in approximately 200 miles over the 2008 statistics. Much of the increase was an addition of about 330 miles of pipeline for Denbury Offshore. They are in the middle of a pipeline project to bring carbon dioxide from sources in Mississippi and Louisiana to the Gulf Coast of Texas. The increase by Denbury was offset by the loss of the Transpetco pipeline from the 2010 data. Several other operators experienced small changes in their total pipe. Some of these changes may represent transfers of ownership rather than building or retiring of pipeline. 
      Table 2.  Miles of Pipeline by Operator 
      Source:  PHMSA (2010)
      * These pipelines were not included in the 2010 PHMSA data but appeared in previous years or were listed in other sources, their current status is unknown.
      In terms of miles of pipe operated, the largest operators are Kinder Morgan, Bravo, and Denbury. These three operators represent over half of the carbon dioxide pipelines in service. 
      
      
      2.3 Map 
      Figure 1 displays a map of current known and planned carbon dioxide pipelines in the United States. The date of the map is unknown, but the Denbury-Green pipeline shown as planned has been completed. The map shows the main transmission carbon dioxide pipelines in the United States. It does not show small lines to individual fields or wells. 
Figure 1:  Map of Carbon Dioxide Pipelines in the United States 
      
      Source: Marston Law accessed at: http://www.marstonlaw.com/index_files/CO2pipeline_regulation.htm on 5/16/2012
      
      2.4 Description of Pipelines
      There are essentially three main carbon dioxide pipeline networks in the US, along with several other carbon dioxide pipelines that supply individual fields. This section includes brief descriptions of each pipeline including its sources and sinks.

      West Permian Basin
      The largest and oldest carbon dioxide pipeline network is in the West Permian Basin in Western Texas and Eastern New Mexico. Most of the pipelines feed from sources into a carbon dioxide hub located near Denver City, TX. Carbon dioxide is distributed from there to several pipelines feeding oil recovery fields in Western Texas, New Mexico, and Oklahoma. The first pipeline in both this basin and the nation was the Canyon Reef pipeline, carrying carbon dioxide from several gas plants in West Texas to the SACROC oil field, and is operated by Kinder Morgan. The Bravo Pipeline carries carbon dioxide from the Bravo Dome in Colorado into the Texas hub and is jointly owned by Occidental, XTO, and Kinder Morgan. The Sheep Mountain Pipeline carries carbon dioxide from a natural source in Colorado and connects into the central hub near Denver City, TX. The Cortez Pipeline extends from the McElmo Dome in Utah to the hub in Texas and is operated by Kinder Morgan. Another pipeline from a Doe Canyon natural source in Utah also connects into the Cortez Pipeline. From the Denver City hub, pipelines extend to several different oil fields including the Postle Field, Comanche Creek Field, North Ward Estates Field, and fields in Cochran, Hockley, and Yoakum County Texas. Operators active in the Permian basin carbon dioxide pipelines include Kinder Morgan, Exxon/Mobil, XTO, Occidental, Hess, Trinity Pipeline, and Apache. In addition, Sandridge CO2 also operates a pipeline from the Pike's Peak gas plant in Texas to the Val Verde oil fields also in Texas. 
      LaBarge Pipeline
      The second major area of carbon dioxide supply is from the Exxon/Mobil Shute Creek gas plant in Sublette County, Wyoming. The plant is currently capable of producing 365 million cubic feet of carbon dioxide a day (Oil and Gas Journal, 2010). Gas is shipped from the plant to oil fields in Wyoming and Colorado. Oil fields supplied by the LaBarge plant include Beaver Creek, Rangeley, Salt Creek, and Monell. Operators active in this area include Exxon/Mobil, Anadarko, Chevron, and Devon. 
      Jackson Dome Area
      The last major pipeline network carries carbon dioxide from the Jackson Dome in Mississippi. It currently extends to the Hastings Oil Field near Houston, Texas. Denbury has also negotiated, or is in the process of negotiating, deals with several gas plants and power plants to supply gas to this pipeline as well. Denbury is the main operator in this area with Enmark being active as well. This pipeline was also used to deliver carbon dioxide to the Cranfield Department of Energy (DOE) Carbon Capture and Storage (CCS) demonstration site in Mississippi.
      Dakota Gasification Pipeline
      While the Dakota Gasification Pipeline has a single source and sink, it is still one of the major carbon dioxide pipelines. Completed in the 1990s, it delivers carbon dioxide from the Dakota Gasification Plant in North Dakota to the Weyburn oil field in Canada. The pipeline stretches over 200 miles, with about 167 of those miles inside the United States. 
      Chapparal Energy Pipelines
      Chapparal Energy also runs several pipelines from dedicated sources to oil fields. One such pipeline runs from the Arkalon ethanol plant in Kansas to the Farnsworth Unit in Oklahoma. Another line runs from a fertilizer plant in Texas to the Camrick Unit in Oklahoma.
      Enid Pipeline
      Merit Energy runs a carbon dioxide pipeline that runs from the Enid Fertilizer plant in Enid, Oklahoma to the Purdy oil field also in Oklahoma. 
      White Frost Pipeline
      Although it is not listed in the current PHMSA statistics, there is a carbon dioxide pipeline that runs from the DTE gas plant in Michigan to some Niagaran Reef oil formations in Michigan. This pipeline operates periodically, depending on the economics of oil recovery using carbon dioxide. The pipeline also has capabilities to deliver to a DOE CCS demonstration project in Michigan. 
3.0 Pipeline Construction
   Carbon dioxide is pumped in the supercritical state in order to maximize the efficiency of pumping large amounts of carbon dioxide. The supercritical state has a higher density and therefore allows larger masses of carbon dioxide in the same diameter pipeline. Because the supercritical state behaves like a liquid, it can also be transported using pumps instead of compressors. Carbon dioxide can also be corrosive when combined with water. Some impurities found in carbon dioxide streams may also be corrosive. Pipelines must be designed to handle the supercritical state of the carbon dioxide as well as potential corrosivity. The following section discusses various design specifications typical of carbon dioxide pipelines.
      3.1 Pipe Material
      When selecting pipe materials, the pressure experienced and the potential corrosivity are taken into consideration. Steel is sufficient to withstand the pressures required to transport supercritical carbon dioxide. Carbon steel, however, can be corroded by carbon dioxide in the presence of water. Stainless steel is not as susceptible to corrosion as carbon steel, but is considerably more expensive. According to PHMSA regulations, all carbon dioxide pipelines must be steel, with the exception of some grandfathered pipelines (49 CFR 195.112). PHMSA data indicate that all existing pipeline is steel pipe. The data do not differentiate between carbon steel and stainless steel. All but 9 miles of the nearly 4,500 miles of pipeline is coated and cathodically protected to prevent corrosion. Over 3,000 miles of that pipe were constructed using high frequency electric resistance welding. Data is also supplied on the date of construction of pipelines. Figure 3 shows the current inventory of pipeline by date of construction.
      Figure 3. Percent Pipeline by Date Constructed
      
      Source:  PHMSA (2010)
      As Figure 3 shows, carbon dioxide pipeline construction reached a peak in the 1980s. Significant pipeline construction continues, however, and additional pipelines are being planned for the future. Further discussion of planned pipeline projects is included in Section 6.0. The first pipeline built explicitly for carbon dioxide transport for oil recovery was constructed in the 1970s. The pipelines that were constructed before that date were most likely originally constructed for other purposes and converted for carbon dioxide transport. Such transfer of purpose of pipelines has occurred. For example, Denbury purchased a natural gas pipeline in Louisiana and converted it to carbon dioxide transport (FERC, 2006). There are also cases of the opposite occurring, such as Bravo converting a portion of its Slaughter carbon dioxide pipeline to a natural gas gathering pipeline (Texas RRC, 2012). It should be noted that pipelines cannot be transferred to and from carrying natural gas without approval by the Federal Energy Regulatory Commission (FERC), which regulates this activity and may require public hearings.
      3.2 Pipe Sizes and Depth 
      The PHMSA data also includes information on the size of pipe. Pipeline size depends on the amount of carbon dioxide being transferred and the pressure and temperature of the pipeline. Pipeline sizes range from less than 4 inches to 30 inches in diameter. Generally, the smaller diameters are for lines to specific oil fields. The larger lines are generally the transmission lines. Figure 4 shows the percent of total pipeline represented by each size diameter. 
      Figure 4 Percent of Carbon Dioxide Pipeline by Diameter (inches)
   
   Source:  PHMSA (2010)
      The most common pipe sizes are 20 and 24 inches, representing nearly 20 percent of the total length of pipeline each. Pipelines of 8, 16, and 30 inches are also common. 
      Federal regulations require most pipe to be buried (49 CFR 195.248). Minimum burial depths required by the regulation range from 30mm to 48mm, but actual burial depths are likely much greater. PHMSA does not have statistics on depth of burial. Some data was available in the incident reports provided by PHMSA as well as some project reports for specific pipelines. Depths were generally between 3 and 6 feet but could be as deep as 100 feet in areas such as river crossings. Depth is likely to vary depending on local temperature and geology, as well as factors such as road or stream crossings.  
      3.3 Construction Guidelines 
       As mentioned previously, pipelines must be designed to carry the appropriate amount of carbon dioxide at supercritical pressures, which are greater than about 1,100 psi (Barrie et al., 2004). Pipeline diameter is determined by the desired flow and the pressure of the pipeline. 
      PHMSA regulations specify construction standards for carbon dioxide pipelines. The regulations are generally performance standards and also incorporate industry standards such as API and ASME standards.  Carbon dioxide pipelines must be designed for the pressure the pipe experiences and pipeline must be compatible with the fluids it will carry (49 CFR 195.4, 108, 110).  One major concern with carbon dioxide pipelines is longitudinal fractures, which can propagate quickly over long distances. Pipelines must be designed to prevent such fractures (49 CFR 195.111). Preventing such fractures can be achieved by specifying the proper thickness and toughness. Mechanical fracture arrestors are also often installed along the pipeline to prevent cracks from propagating over long distances if they start (Cosham and Eiber, 2007). Valves, hooked to automatic control systems, are also installed to enable isolation of leaks should they occur. They are required at pump stations, surface water crossings, laterals, and sensitive areas (49 CFR 195.260). Generally, pipelines would be buried at depths shallow enough to be above the saturated zone of the soil, so groundwater would not be a concern. Too many valves, however, can be problematic, as they can themselves fail and become sources of leaks (see Section 5.2). Another consideration in transporting supercritical gases is that supercritical gases will rapidly expand and cool if a loss of pressure occurs. Temperatures can drop quickly enough that the carbon dioxide can freeze. Therefore, carbon dioxide pipelines must be designed to resist very low temperatures (40 CFR 195.102). Theoretically the temperature could get as low as the freezing point of carbon dioxide which is -78.5 [o]C at atmospheric pressure.
      Corrosion control is another concern. Carbon dioxide mixed with water can be corrosive. Other potential impurities in carbon dioxide streams such as nitrogen oxides and hydrogen sulfide can also be corrosive. The DeWaard/Milliams nomograph can be used to predict corrosion of steel based on carbon dioxide concentration and temperature. Typically, carbon dioxide streams are dehydrated and carbon steel is used for pipelines. A typical value of 50 ppm or less water content is a common requirement for carbon dioxide transported in pipelines (Fredet et al., 2007). While carbon steel is often used for carbon dioxide pipes, stainless steel may be required for turbulent areas near valves and pumps (Barrie et al., 2004). As noted above, most carbon dioxide pipelines also use cathodic protection and lining to prevent corrosion problems. 
      3.4 Quality Considerations
      The composition of the carbon dioxide stream provides several important considerations for pipeline design. These include transport properties of the stream, corrosivity, and viability of the carbon dioxide for its final use. Mixtures of gases can often have very different properties from pure gases. This can be important for designing pipelines. For example, combined with water, carbon dioxide can form solid hydrates at low temperatures and high pressures. The solid hydrates can clog pipelines. These hydrates can form at temperatures as high as 10[o]C (Fredet et al., 2007). Impurities can also alter the critical temperature and pressure of the carbon dioxide being transported. Raising the critical pressure and temperature will require higher operating pressures and therefore greater costs. Lowering the critical temperature and pressure may help reduce costs. Nitrogen oxides can lower the critical pressure and temperature of the carbon dioxide stream. Hydrogen gas, on the other hand, can raise the critical temperature and pressure (Seevam et al., 2007). Nitrogen and methane may also increase the critical pressure and require higher operating pressures (IOGCC, 2010).
      Water is the most significant component that can increase the corrosivity of carbon dioxide streams, and must be limited to avoid significant corrosion or expensive materials. Hydrogen sulfide is corrosive to pipeline materials and is toxic. Additional requirements are often imposed on pipelines with significant sulfide, although several pipelines do transport higher levels of hydrogen sulfide. Like carbon dioxide, sulfur and nitrogen oxides may also be corrosive in the presence of water. Oxygen can cause corrosion and is often specified to be below 10 to 20 ppm to prevent corrosion (IOGCC, 2010). Corrosion can be prevented or mitigated by limiting corrosive impurities and by specifying corrosion resistant materials and cathodic protection.
      The last factor that can affect the quality of carbon dioxide shipped in pipelines is the end use. For existing carbon dioxide pipelines, the end use is enhanced oil recovery. Some impurities can change the miscibility of carbon dioxide with oil and therefore change its effectiveness in recovering oil. Nitrogen gas decreases the miscibility of carbon dioxide with oil and therefore decreases its value for recovering oil. Many pipelines have maximum specifications for nitrogen gas because of this. Sulfide, sulfur oxides, and nitrogen oxides, on the other hand increase the miscibility and make carbon dioxide more attractive for enhanced oil recovery.
      Table 3 shows the purity of carbon dioxide stream specifications in some existing pipelines. The specifications represent agreed upon limits of the concentrations allowed in the pipelines. The table shows that current carbon dioxide streams generally contain 95 percent or more carbon dioxide. Common impurities can include methane, hydrogen sulfide, and nitrogen.
      Table 3.  Carbon Dioxide Stream Specifications for Several Existing Pipelines
Pipelines
Carbon Dioxide Content (Percent)
Methane Content (Percent)
Higher Hydrocarbon Gases (Percent)
Nitrogen Content (Percent)
Hydrogen Sulfide Content (Percent)
Canyon Reef Carriers
                                      95
                                       5
                                       -
                                   < 0.5
                                     0.01
Central Basin Pipeline
                                     98.5
                                      0.2
                                       -
                                      1.3
                                       -
Sheep Mountain Pipeline
                                     96.8
                                      1.7
                                      0.6
                                      0.9
                                       -
Bravo Pipeline
                                     99.7
                                       -
                                       -
                                      0.3
                                       -
Weyburn
                                      96
                                       -
                                      2.3
                                     0.03
                                      0.9
      Source:  Seevam et al., 2007
      
      
      
      
4.0 Costs
   Several costs comprise the cost of transporting carbon dioxide by pipeline. These include the capital cost to construct the pipeline, costs to operate and maintain the pipeline, and fees charged by either state regulators for permitting of the pipeline or fees charged by pipeline operators for use of the pipeline.
      4.1 Construction Costs 
      Capital costs for a pipeline will depend on many factors. These include the capacity of the pipeline, pipeline materials required, and terrain. Table 4 shows costs compiled by the Interstate Oil and Gas Compact Commission (IOGCC) from several existing pipelines, including some estimates compiled by Federal Energy Regulatory Commission (FERC) and the Oil and Gas Journal. The costs represent total capital costs for the project including installation divided by the length and diameter of the pipeline. Costs in 2009 ranged from about $27,000 per inch-mile of pipeline to nearly $94,000 per inch-mile. The costs are normalized by length and diameter of the pipeline as these are the biggest factors in determining pipeline cost. For example a cost model from Carnegie Mellon University, based on natural gas pipeline costs, found a relationship where cost for a pipeline in the Midwest was:
      Cost = 10[3.112]*L[0.901]*D[1.590]
      Where L is the length of the pipeline and D is the diameter (Rubin et al., 2008). It can be seen that the diameter is the biggest factor, while length is also important. While depth may have an effect on costs, it was not considered in any of the cost models examined in the scope of this paper (MIT, 2007; Rubin et al., 2008). The only consideration of depth were general statements that rugged terrain and urbanized areas can increase costs. 
      Table 4 Pipeline Capital Costs 
Pipeline
Location
Cost (2009$/in-mile)
Dakota Gasification
North Dakota
46,500
Hall-Gurney
Kansas
26,650
Coffeyville Resources
Kansas
54,000  -  83,000
Green Pipeline
Louisiana, Mississippi
93,750
Oil and Gas Journal Average Cost
National Estimate
64,900
FERC data
National Estimate
39,400
      Source:  IOGCC 2010
      It should be noted that the cost of the steel pipe is approximately 15 to 35 percent of the total pipeline cost (IOGCC, 2010). This is significant, as the price of steel pipe greater than 24 inches has risen from $500 per meter in 2000 to over $1,400 per meter in 2007 (CRS, 2008). 
      4.2 Operating Costs 
      Operating costs include power costs for operating pumps and compressors, labor costs for pipeline operation and maintenance, and material costs for maintenance. Table 5 shows operating costs for several pipelines. 
      Table 5  Pipeline Operation and Maintenance Costs 
Pipeline
Pipeline Length and Size
Year 
O&M Costs ($/yr)
Source
Ohio Network (proposed)
450 miles
12 inch diameter
2008
2,300,000
Pew Charitable Trust, 2008
Russell, Kansas Geosequestration/EOR Project
7 miles
2007
1,900,000  -  2,300,000
Carr & Dubois, 2007
Estimated costs for IGCC pipeline
300 miles
2003
480,000  -  720,000
Bock et al., 2003 
      
      Costs vary depending on length of the pipeline, the pressure at which it operates, and complexity of operations. A study by Pew Charitable Trust for a proposed carbon dioxide pipeline in Ohio estimated an annual cost of $2.3 million/year for operating costs of a 450 mile pipeline (Pew Charitable Trust, 2008). Several studies have estimated total costs of transporting carbon dioxide by pipeline. The costs include annualized capital costs and operation and maintenance costs. One study by the Massachusetts Institute of Technology estimated costs for a 100 kilometer pipeline from $1.21 per ton to $11.16 per ton with an average of $3.82 per ton for carbon dioxide pipelines to oil reservoirs. An NETL study estimated $0.55 per ton for carbon dioxide pipelines from carbon dioxide domes to oil fields in Texas (IOGCC, 2010). An IOGCC report estimated $1.25 per thousand cubic feet of carbon dioxide from natural sources and $1.30 to $1.75 for carbon dioxide from natural gas plants (IOGCC, 2010). 
      4.3 Fees 
      There are several kinds of fees that may apply to carbon dioxide pipelines. First, fees may be administered by PHMSA or States for pipeline permitting. PHMSA assesses a user fee for all hazardous liquid pipelines. That fee is $109.91 per mile and is used to offset costs of PHMSA and state programs. Usage fees are also charged by the companies that own the pipeline. Such fees would not apply in cases where the source, pipeline, and final use of the carbon dioxide are all owned by the same entity. It does apply, however, to companies that own and operate pipelines and transport carbon dioxide to other companies operating oil fields. Generally, such contracts are negotiated between the pipeline company and the purchaser of the carbon dioxide. Such agreements may contain provisions linking fees to the price of oil and the pressure or quality at which the carbon dioxide is delivered. Some carbon dioxide pipelines are considered common carriers, meaning they must transport carbon dioxide from any source for the same published price. The Bureau of Land Management has required many carbon dioxide pipelines crossing federal lands to be common carriers. The State of Texas requires pipelines to be common carriers if they want eminent domain rights in the State. While being a common carrier usually requires publishing of rates, administrative bodies have not required carbon dioxide common carriers to publically post their rates. One source found that carbon dioxide transport fees ranged from $2 to $3/ton for a pipeline of 50 to 100 miles in length (Bergman and Winter, 1997). Other fees may also apply such as State, County, or Local fees. However, no listing of such costs or fees was found within the scope of this paper.
5.0 Pipeline Safety
   Pipeline safety is a prime concern with carbon dioxide pipelines and is regulated by the PHMSA and State regulatory agencies. The prime concern is that carbon dioxide is an asphyxiant and is heavier than air. Therefore, carbon dioxide may leak and accumulate in poorly ventilated, low lying areas and potentially build up to dangerous or lethal levels. Another concern is that if high pressure pipelines fail catastrophically, the rapid depressurization can cause solid carbon dioxide to be ejected at high rates causing potential damage to property and life. While there are significant safety concerns with carbon dioxide pipelines, pipelines have operated safely for decades. The following sections include records of significant safety incidents and a summary of state and federal regulations governing pipeline safety.
      5.1       Regulations 
      Pipeline safety is regulated by the Department of Transportation through the PHMSA. Regulations governing carbon dioxide pipelines fall under 49 CFR 195. The regulations cover topics such as material selection, construction requirements, pressure limits, and reporting requirements. Many of the requirements are either performance standards, such as requiring pipelines to be compatible with the fluids they carry (e.g. 49 CFR 195.4), or refer to other standards. A total of 40 standards are incorporated into the pipeline regulations by reference, these are listed in Appendix A. The federal regulation provides that States that have standards at least as stringent as the federal standard and have effective enforcement programs oversee pipelines within their state if their regulations are at least as strict as federal standards. For the most part, states have adapted the federal regulations verbatim. A brief review of the regulations found that where they did vary from federal requirements they were often to provide more specific requirements or requirements for local conditions. For example, New Mexico specifies certain types of leak detection tests. Other differences between state and federal laws can include things such as lower reporting limits for leaks or requiring more frequent inspection for high risk pipelines. Generally though, most states follow the federal regulations. 
      Agreements between States and the Federal Office of Pipeline Safety (OPS) dictate who performs inspection and enforcement activities within each state. A brief review of state agreements was conducted for states that have existing or planned carbon dioxide pipelines. In many states, OPS regulates and inspects all hazardous liquid pipelines, including carbon dioxide pipelines. These states include: Colorado, Illinois, Kansas, Michigan, Montana, North Dakota, Ohio, Utah, and Wyoming. Another common agreement is for OPS to regulate interstate pipelines and the state to regulate intrastate pipelines. This type of agreement is in place in Indiana, Louisiana, New Mexico, Oklahoma, and Texas. In Arizona and California, all pipelines are regulated by the state. Pipelines contained entirely on the property of the pipeline owner are not covered by Federal OPS or State regulations. Some smaller pipelines, such as those extended from the main line to an individual injection well may also not fall under federal regulations. Such pipelines, however, would not be totally unregulated. OSHA standards may apply to some aspects of pipeline construction and operation. For example 49 CFR 192 covers transportation of natural gas and other gas by pipeline. OSHA also has regulations that would apply during pipeline construction. Construction will also likely be regulated by local authorities and may require meeting industry standards, plan review, and construction inspections. For example, if the pipeline is for a sequestration project, Class VI UIC regulations require submittal of construction plans which would include surface facilities such as pipelines (40 CFR 146.82(a)(11). ASME B31.4 is a standard often used for pipeline construction. While local construction permits most likely require meeting such standards a review of such codes is beyond the scope of this paper. Insurance policies may also require meeting design standards and following best management practices. A study for the Pennsylvania Department of Conservation and Natural Resources stated that insurance was readily available for carbon dioxide pipelines and many pipelines had such insurance (Tetra Tech, 2009). In order to set premiums for an insurance policy insurance companies typically perform a risk assessment of the project. The risk assessment would include items such as age and design of the pipeline, whether increased design standards were used in high risk areas such as river crossings, company operating and maintenance procedures, and existing emergency and response plans (Radevsky and Scott, 2004). 
      5.2 Incidents
      PHMSA requires reporting of any incidents that release more than 5 gallons of supercritical carbon dioxide (49 CFR 195.50). Table 6 shows a list of incidents on carbon dioxide pipelines reported to PHMSA for the period of 1992 to 2011. 
      Table 6  Reported Safety Incidents on Carbon Dioxide Pipelines 1992  -  2011
      
      Source:  PHMSA 
      Thirty-four incidents were reported during the nearly twenty year period. This is significantly lower than the incidents reported for natural gas or petroleum product pipelines. For example, there were 3,009 incidents reported for hazardous liquid pipelines other than carbon dioxide during the period 2002 to 2009. No deaths or injuries were reported as a result of the reported incidents. The incidents resulted in the release of 126,000 barrels (5,292,000 gallons) of carbon dioxide and resulted in a little less than $1 million in damages. Most of the damages were for the loss of the carbon dioxide product and repair of the pipeline. Costs for remediation and cleanup were very low, indicating that little environmental damage occurred. Most of the incidents were either leaks or operation of a pressure relief valve, with one reported incident of a puncture caused by excavation. The most common causes of the incidents were failure of welds or of pipeline components such as valves, seals, and pumps. Malfunctioning relief valves were also implicated in several cases. 
6.0 Future Projects 
      An increase in the number and mileage of carbon dioxide pipelines is predicted for the future. The continued interest in using carbon dioxide to boost oil recovery is leading to new proposed projects to bring carbon dioxide to oil fields. GS is also moving forward, with several new research projects moving forward and the first commercial scale facilities being planned. Future projects can be divided into two categories: (1) projects that are in the planning stages and have permit applications or other planning documents and (2) pipelines that may be associated with projects that have not been planned or are only in the conceptual stages. Those in the first category can be identified by searching public documents such as news releases, permit applications, and project reports. Those in the second category must necessarily be predicted using assumptions of the extent of pipelines needed and the projects that will be built. Table 7 shows a list of projects that have been proposed or are in the permitting stages. Following the table is a brief description of each project.
   
   Table 7.  Proposed Carbon Dioxide Pipelines.
Project  -  Operator
Miles of Pipe
Source
Sink
Anticipated Completion Date
GreenCore - Denbury
232
Lost Cabin Natural Gas Plant, Medicine Bow Synfuel Plant, Riley Ridge Gas Plant 
Bell Creek Oil Field, 
2012
Midwest  -  Denbury
500  -  700
Gasification Plants in IN, IL, and KY
Gulf Coast Oil Fields
Uncertain
Hydrogen Energy California
4
Rio Tinto Hydrogen Plant, CA
Elk Hills Oil Field
2015
Chapparal
70
Coffeeville Fertilizer Plant
Existing EOR pipelines
2013
Cano Milnesand Pipeline
40
Cortez CO2 Pipeline
Milnesand and Chaveroo Oil Fields
2015
Conestoga Pipeline
15
Garden City, KS ethanol plant
Stuart Oil Field
2011
Archer Daniels Midland CCS project #1
1.2
Decatur, IL ethanol plant
Mt. Simon Saline Aquifer
2013
Taylorville Energy Center
4.75
Taylorville Energy Center
Mt. Simon Saline Aquifer
2013
FutureGen
32
FutureGen Power Plant
Mt. Simon Saline Aquifer
2015
Kevin Dome
6
Kevin Dome
Duperow Formation
2013
Williston Basin
150
Antelope Valley Power Plant
Williston Basin Oil Field
2013
Virginia City Hybrid Energy Center 
25
Virginia City Hybrid Energy Center Power Plant
Coal Seams and Saline Aquifers
2015
St. John's Pipeline
200  -  400
St. John's Dome, Cottonwood Canyon Dome
Denver City Hub or McElmo Pipeline
2016
Mesaba Energy Project
265  -  610 
Mesaba Energy Plant
Sequestration Site or Oil Fields
2014
Kimberlina Project
5 -10
Kimberlina Power Plant
Oil Fields
2015
Mountaineer Project
12  -  26
Mountaineer Power Plant
Mt. Simon Aquifer
Cancelled
Future Gen 1
1  -  59
Power Plant 
Aquifer
Unknown
C-6 Resources
Unknown
Local Industrial Sources
Aquifer
Cancelled
   
   Denbury's Greencore Line: Denbury has started construction on this project. The first phase involves 232 miles of pipeline from the Lost Cabin Gas plant in Colorado to the Bell Creek Oil Field. That phase of the project is expected to be completed in December, 2012. Denbury eventually plans on expanding the pipeline to take carbon dioxide from a coal to liquids plant run by DKRW near Medicine Bow, MT and a gas plant near Riley Ridge, WY. The Medicine Bow plant is expected to come on line in 2014. A date was not mentioned for the hook up with Riley Ridge. The line will also likely extend to other oil fields that Denbury is looking to acquire in Wyoming (Fugleburg, 2011). 
   Denbury's Midwest Line: Denbury has proposed building a carbon dioxide pipeline from several coal gasification plants in the Midwest. Denbury has proposed two routes -- either east through Kentucky and Tennessee to Mississippi or west through Missouri and Arkansas into Louisiana. The pipeline would connect with Denbury existing pipelines from Jackson Dome. The pipeline would be 500 to 700 miles in length depending on the route chosen. Four gasification plants have tentative agreements with Denbury to supply carbon dioxide: Rockport, IN; Taylorville, IL; Cash Creek, KY; and Edwardsport, IN. Only the Edwardsport facility has begun construction and the other three gasification plants are awaiting funding or permit approval. Therefore, this pipeline is tentative and it is difficult to predict when and if it will be constructed (Lydersen, 2012).
   Hydrogen Energy of California: This facility is in the planning process. It plans to take carbon dioxide produced from a hydrogen plant owned by BP and Rio Tinto. It will use a 4 mile long pipeline to transport the carbon dioxide produced to the Elk Hills Oil Field outside of Bakersfield, CA. The plan is to sequester the carbon dioxide while performing enhanced oil recovery. The project is expected to be complete in 2015 (Hydrogen Energy California, 2009).
   Chapparral Energy Pipeline: Chapparral Energy is planning on building a carbon dioxide pipeline that will tie in their existing carbon dioxide pipelines and add a source from the Coffeyville fertilizer plant. The pipeline would extend from the Coffeeville plant in southeastern Kansas to existing lines from the Koch fertilizer plant in Oklahoma, the Arkalon ethanol plant in Kansas, and the Agrium Fertilizer plant in Texas. It would extend to oil fields in the panhandle of Oklahoma, some of which are currently supplied by carbon dioxide from the Permian basin hub. The initial phase will include 70 miles of pipe to the North Burbank unit in northeastern Oklahoma. That phase is expected to be complete in 2013. The pipeline to connect all the projects together is scheduled for a later, unknown date (Chapparal Energy, 2011).
   Conestoga Energy Partners Pipeline: Conestoga Energy Partners is constructing a pipeline to bring carbon dioxide from a Garden City, Kansas ethanol plant to the Stuart Oil Field in Kansas. The project will involve a little less than 15 miles of pipeline and was expected to be operational in 2011 (Global CCS Institute, 2010).
   Cano Pipeline: Cano has entered an agreement to take carbon dioxide from the Cortez pipeline for use in its Chaveroo and Milnesand oil fields. The pipeline will be 40 miles long and 8 inches in diameter. Completion is expected in 2015 (Investorhub, 2012).
   Archer Daniels Midland (ADM) Projects: ADM is planning two carbon sequestration projects that will take carbon dioxide from their Decatur, IL ethanol plant and inject it into the Mt. Simon saline aquifer. The UIC permitting process is currently underway and injection is anticipated to begin sometime in 2013. The project will involve a 6,400 foot, 6 inch pipeline from the plant to the injection wells. It is a demonstration project and is planned to operate for three years. Its planned use may be extended if initial tests are successful (ADM, 2012).
   Taylorville Energy Center: The Taylorville Energy Center is a proposed IGCC plant that is proposing to inject carbon dioxide into the Mt. Simon aquifer in Illinois for carbon sequestration. The project includes 4.75 miles of pipe from the plant to 3 or 4 injection wells. The main pipe will be 16 inches in diameter, with 12 inch pipes leading to the wells. The project is currently in the permitting process and will likely begin operation with one well in the next year or two (TEC, 2012).
   FutureGen 2.0: The FutureGen project will retrofit an existing coal burning power plant in Meredosia, IL with oxycombustion technology. Carbon dioxide will be captured from the plant and stored in a sequestration site in the Mt. Simon Formation. The project will require a 32 mile pipeline and is expected to be completed in 2015 (Lee, 2011).
   Kevin Dome: The Big Sky Regional Carbon Sequestration Partnership is planning a sequestration study project in the Kevin Dome in Montana. The project will involve 6 miles of 2 inch pipeline from the source in the Kevin Dome to the sequestration site. The project is currently scheduled to begin injection in late 2013 (BSCSRP, 2012).
   Williston Basin: The Williston Basin project is a DOE sponsored sequestration project. It has already been through its preliminary test injections. The final project includes a 150 mile pipeline from the Antelope Valley Power Plant in North Dakota to the Williston Basin oil fields (NETL, 2008).
   Virginia City Hybrid Energy Center: This project is a carbon sequestration demonstration project. It will involve up to 25 miles of pipeline from Dominion Power's Virginia City Hybrid Energy Center to coal seams and saline aquifers in southwest Virginia. It is planned for completion in 2015 (McGee, 2005).
   St. John's Pipeline: The St. John's pipeline is a proposed project by Kinder Morgan. It is designed to take carbon dioxide from its newly acquired natural carbon dioxide sources in the St. John's unit and Cottonwood Canyon unit and transport it to Kinder Morgan's network in Texas. Testing of wells is currently being conducted. Depending on the production obtained from the carbon dioxide injection wells, either a 400 mile, 20 inch pipeline will be constructed directly to Kinder Morgan's Denver City hub or a 200 mile, 10 inch pipeline will be constructed to tie-in to the McElmo Dome pipeline (Arizona Geology, 2012). 
   Mesaba Energy Project: The Mesaba Energy Project is a planned energy plant in Minnesota. As part of the plan, several options for sequestration were proposed. Options ranged from a 265 mile pipeline to a local saline aquifer sequestration site, to a three phase pipeline to oil fields in North Dakota and Canada. The project was originally scheduled for completion in 2014 but its current schedule is unknown (DOE, 2007).
   Kimberlina Project: The Kimberlina Power Plant is a planning to sequester carbon dioxide initially on-site as a research project. After approximately 4 years they anticipate building a 5 to 10 mile pipeline to local oil fields outside of Bakersfield, California. The original schedule was for enhanced oil recovery to begin in 2015. It is not known if the project is on schedule (Clean Energy Systems, 2012).
   Mountaineer Project: The Mountaineer project planned to inject 90 percent of the output of the Mountaineer Power Plant in West Virginia into the Mount Simon Aquifer at an injection site about 12 miles from the plant. A total of up to 26 miles of pipeline was planned. After an initial test phase the project was cancelled because of unfavorable economics (DOE, 2011). 
   Future Gen 1 Project: The FutureGen project proposed to build a new IGCC power plant that would inject all of its flue gas into a saline aquifer. Initial evaluation was done for 5 sites that required between 1 and 59 miles of pipeline (DOE, 2006). This initial phase was cancelled. 
   C-6 Resources: The project had planned to pipe carbon dioxide from various industrial sources in the San Francisco Bay area to a sandstone aquifer in Solano County. Exact pipeline routes had not been planned. The project received initial funding from DOE for some pilot tests but the project was cancelled before any pipelines were planned or constructed (CIEE, 2010)
   It should be noted that all of the above projects are planned, but not yet constructed. Some have been cancelled and others may not be completed. The above list, however, provides a reasonable estimate of the magnitude and types of projects that can be expected over the next five years.
   Predicting future carbon dioxide pipeline production beyond 2015 involves making some assumptions and predictions regarding the number of projects planned for the future. Sequestration projects are not likely to be financially attractive absent carbon dioxide legislation or some other financial incentives. If such incentives were lacking, future carbon dioxide would likely be limited to a few federally funded projects along with enhanced oil recovery projects. Oil recovery projects will likely continue to grow, as there is economic incentive without the additional benefit of carbon sequestration. The increase in pipelines to oil fields will depend to some extent on oil prices but is more likely to proceed without federal funding or legislation. As Figure 3 demonstrates, carbon dioxide pipelines have been built at a rate of 500 to 1,000 miles a decade after the initial boom in the 1980s. Since the increase in 2010 alone is already several hundred miles, it would appear that pace might be picking up again. Table 7 suggests that between 1,500 and 2,000 miles of pipeline could be built in the next 5 years. Even without large regulatory incentives, based on the above planned projects, it is possible that as much as 6,000 to 8,000 miles of carbon dioxide pipeline could be constructed in the next 20 years.
   If a large impetus for carbon sequestration develops, a larger network of carbon dioxide pipelines will be built. While there have been several modeling exercises to predict federal or state level pipeline networks connecting multiple sources to multiple sequestration sites, it seems like such an extensive network would likely be in the more distant future. IEA has predicted about 17 sequestration projects by 2020 with much more significant growth to 250 projects by 2050. An IOGCC report predicted that about 77 percent of sequestration projects could store carbon dioxide on the same site as it is captured. An additional 11 percent could store the carbon dioxide within 100 miles (IOGCC, 2010). Therefore, large sequestration pipeline networks may not be needed and, if they are, would likely be built over in the longer-term. If such a network became necessary, several studies have estimated the miles of pipeline that would be required to meet national carbon emission goals. An Interstate National Gas Association of America study found that a network of between 5,900 miles and 36,050 miles would be required to sequester carbon dioxide in the United States by 2030. The lower number presumes a 15 percent reduction in carbon dioxide emissions and low use of carbon dioxide for enhanced oil recovery. The higher figure assumes a 50 percent reduction in carbon dioxide emissions and a high use of carbon dioxide for enhanced oil recovery (INGAA, 2009). A Pacific Northwest National Laboratory Study estimated 11,000 miles of pipeline would be needed by 2050 to reach a goal of limiting atmospheric carbon dioxide concentrations to 550 ppm, and 23,000 miles would be needed to meet a goal of limiting atmospheric carbon dioxide to  450 ppm (Dooley et al., 2009). Given the currently planned projects, the high end of these figures seems unlikely in the next 20 years; however, the lower end of these figures might represent a more reasonable estimate for carbon dioxide pipelines in the next 20 years.
   
   References 
ADM. 2012. Archer Daniels Midland Permit Application.

Arizona Geology. 2012. Accessed at: http://arizonageology.blogspot.com/2012/04/kinder-morgan-outlines-plans-for-major.html

Barrie, J., K. Brown, P.R. Hatcher, and H.U. Schellhase. 2004. Carbon Dioxide Pipelines: A Preliminary Review of Design and Risks. Presented at GHGT 2004.

Bergman, P.P., and E.M. Winter. 1997. Disposal of Power Plant CO2 in Depleted Oil and Gas Reservoirs in Texas. Energy Conversion and Management. V. 38 pp. S211  -  S216.

Bock, B., R. Rhudy, H. Herzog, M. Klett, J. Davidson, D.G. De La Torre, and D. Simbeck. 2003. Economic Evaluation of CO2 Storage and Sink Enhancement Options.

BSRCSP. 2012. Accesses at: http://www.bigskyco2.org/research/geologic/kevinstorage

Carbon Sequestration Leadership Forum. Undated. CO2 Transportation: Is it Safe and Reliable? http://www.cslforum.org/publications/documents/CSLF_inFocus_CO2Transportation.pdf 
 
Carr, T.R., and M.K. Dubois. 2007. Results of Integrated Biofuels and Value Added Sequestration Project in Russel, KS. Presented at the 6[th] Annual Conference on Carbon Capture and Sequestration.

CIEE. 2010. Background Reports for the California Carbon Capture and Storage Review Panel. 
California Institute for Energy and Environment.

Clean Energy Systems. 2012. Accessed at http://www.cleanenergysystems.com/faq.html#17

Cosham, A., and R. Eiber. 2007. Fracture Control in Carbon Dioxide Pipelines. Journal of Pipeline Engineering. 3[rd] quarter. p. 147

Chapparal Energy. 2011. Wells Fargo Energy Conference. Available at http://www.chaparralenergy.com/pressreleases/Wells%20Fargo%20Energy%20Conference_To%20print%20for%208K%20and%201x1.pdf

DOE. 2006. Final Risk Assessment Report for the FutureGen Project Environmental Impact Statement.  

DOE. 2007. Mesaba Energy Project, Draft EIS. 

DOE. 2011. Mountaineer Commercial Scale Carbon Capture and Storage Project: Draft Environmental Impact Statement Summary. 

Dooley, J.J., R.T. Dahowski, C.L. Davidson. 2009. Comparing Existing Pipeline Networks with the Potential Scale of Future U.S. CO2 Pipeline Networks. Energy Procedia 1. Pp. 1595-1602.

EPA. 2011. Assessment of the Potential Costs, Benefits, and Other Impact of the Conditional Exclusion from the RCRA Definition of Hazardous Waste for CO2 Streams Managed in UIC Class VI Wells for the Purposes of Geologic Sequestration

FERC. 2006. 115 FERC 962,266

Fredet, A., S. Saysset, P. Odru, P. Broudin, J. Ruer, and M. Bonnisel. 2007. Technical and Economic Assessement of CO2 Transportation for CCS Purposes. 

Fugleburg, J. 2011. Construction of Carbon Dioxide Pipeline Starts this Year. Wyoming Star-Tribune May 26, 2011.

Global CCS Institute. 2010. Global Status of BECCS Projects 2010.

Hydrogen Energy California. 2009. Revised Application for Certification for Hydrogen Energy California.

INGAA. 2009. Carbon Sequestration and Storage: Developing a Transportation Infrastructure.

IOGCC. 2010. A Policy, Legal, and Regulatory Evaluation of the Feasibility of a National Pipeline Infrastructure for the Transport and Storage of Carbon Dioxide.

Investorhub. 2012. Available at http://investorshub.advfn.com/boards/read_msg.aspx?message_id=72260578

Lee, D.S.W., 2011. FutureGen "Clean Coal" Project Still has Hurdles to Clear. McDonough Voice.com April 6, 2011.

Lydersen, K. 2012. With no sources of CO2, Midwest pipeline project in limbo. Midwest Energy News, April 26, 2012.

Marston Law. 2012. http://www.marstonlaw.com/index_files/CO2pipeline_regulation.htm accessed on 5/16/2012

McGee, D. 2009. Tech, Dominion Propose Carbon-Capture Project. Richmond Times Dispatch, August 26, 2009.

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NETL. 2008. Plains CO2 Reduction Partnership, Williston Basin Demonstration Test Fact Sheet. Accessed at http://www.netl.doe.gov/publications/proceedings/08/rcsp/factsheets/20-PCOR_Williston%20Basin%20Demo%20Test_PhIII_and_EOR_Demo.pdf

Oil and Gas Journal. 2010. Exxon Mobil Finishes Shute Creek Carbon Capture Expansion.

Pew Charitable Trust. 2008. The Role of CO2 Enhanced Oil Recovery in Ohio's Economy and Energy Future. 

Radevsky, R., and D. Scott. 2004. Pipeline Insurance: Technical Aspects of Underwriting and Claims. Presented at the Conference on Terrain and Geohazard Challenges Facing Onshore Oil and Gas.

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Seevam, P., J.M. Race, and M.J. Downie. 2007. Carbon Dioxide Pipelines for Sequestration in the UK: an Engineering Gap Analysis. Journal of Pipeline Engineering 2007, 3[rd] quarter. pp. 133-146.

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   Appendix A
   Standards Incorporated by Reference into Federal Pipeline Regulations

   AGA Pipeline Research Committee, Project PR-3-805, "A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe" 
   ANSI/API Specification 5L/ISO 3183 "Specification for Line Pipe"
   API Recommended Practice 5L1, "Recommended Practice for Railroad Transportation of Line Pipe" 
   API Recommended Practice 5LW, "Transportation of Line Pipe on Barges and Marine Vessels" 
   ANSI/API Specification 6D "Specification for Pipeline Valves 
   API Specification 12F "Specification for Shop Welded Tanks for Storage of Production Liquids" 
   API 510 "Pressure Vessel Inspection Code: In-Service Maintenance Inspection, Rating, Repair, and Alteration" 
   API Standard 620 "Design and Construction of Large, Welded, Low-Pressure Storage Tanks" 
   API Standard 650 "Welded Steel Tanks for Oil Storage" 
   ANSI/API Recommended Practice 651 "Cathodic Protection of Aboveground Petroleum Storage Tanks" 
   ANSI/API Recommended Practice 652 "Lining of Aboveground Petroleum Storage Tank Bottoms" 
   API Standard 653 "Tank Inspection, Repair, Alteration, and Reconstruction" 
   API Standard 1104 "Welding of Pipelines and Related Facilities'
   API Recommended Practice 1130, "Computational Pipeline Monitoring for Liquids: Pipeline Segment" 
   API Recommended Practice 1162, "Public Awareness Programs for Pipeline Operators" 
   API Recommended Practice 1165, "Recommended Practice for Pipeline SCADA Displays," 
   
   API Standard 2000 "Venting Atmospheric and Low-Pressure Storage Tanks" 
   API Recommended Practice 2003 "Protection Against Ignitions Arising out of Static, Lightning, and Stray Currents" 
   API Publication 2026 "Safe Access/Egress Involving Floating Roofs of Storage Tanks in Petroleum Service" 
   API Recommended Practice 2350 "Overfill Protection for Storage Tanks in Petroleum Facilities" 
   API Standard 2510 "Design and Construction of LPG Installations"
   API Recommended Practice 1162 "Public Awareness Programs for Pipeline Operators," 
   API Recommended Practice 1168 "Pipeline Control Room Management," 
   ASME/ANSI B16.9-20073 (February 2004) "Factory-Made Wrought Steel Buttwelding Fittings" 
   ASME/ANSI B31.4-20062 (October 2002) "Pipeline Transportation Systems for Liquid Hydrocarbons and Other Liquids" 
   ASME/ANSI B31G-1991 (Reaffirmed; 2004) "Manual for Determining the Remaining Strength of Corroded Pipelines" 
   ASME/ANSI B31.8-20073 (February 2004) "Gas Transmission and Distribution Piping Systems" 
   ASME Boiler and Pressure vessel Code, Section VIII, Division 1 "Rules for Construction of Pressure Vessels,"
   ASME Boiler and Pressure Vessel Code, Section VIII, Division 2 "Alternate Rules for Construction of Pressure Vessels" 
   ASME Boiler and Pressure vessel Code, Section IX "Welding and Brazing Qualifications,"
   MSS SP-75-2004 "Specification for High Test Wrought Butt Welding Fittings" 
   ASTM Designation: A53/A53M-07,04a (2004) "Standard Specification for Pipe, Steel, Black and Hot-Dipped, Zinc-Coated Welded and Seamless" 
   ASTM Designation: A106/A106M-08,04b (2004) "Standard Specification for Seamless Carbon Steel Pipe for High-Temperature Service" 
   ASTM Designation: A 333/A 333M-05, "Standard Specification for Seamless and Welded Steel Pipe for Low-Temperature Service" 
   ASTM Designation: A 381-96 (Reapproved 20051), "Standard Specification for Metal-Arc-Welded Steel Pipe for Use With High-Pressure Transmission Systems" 
   
   
   ASTM Designation: A 671-06,04 (2004) "Standard Specification for Electric-Fusion-Welded Steel Pipe for Atmospheric and Lower Temperatures" 
   ASTM Designation: A 672-0896 (Reapproved 2001) "Standard Specification for Electric-Fusion-Welded Steel Pipe for High-Pressure Service at Moderate Temperatures" 
   ASTM Designation: A 691-98 (Reapproved 20072), "Standard Specification for Carbon and Alloy Steel Pipe Electric-Fusion-Welded for High-Pressure Service at High Temperatures" 
   NFPA 30(2003) "Flammable and Combustible Liquids Code" 
   NACE SP0169-2007, Standard Practice, "Control of External Corrosion on Underground or Submerged Metallic Piping Systems" 
   NACE SP0502-2008, Standard Practice, "Pipeline External Corrosion Direct Assessment Methodology"