TECHNOLOGY Certain facility, equipment designs lessen environmental costs

S.S.R. Pappworth
Sound Environmental Solutions Inc.
Houston

Companies in the oil and gas industry can lessen the burden of environmental rules and regulations by changing the design and size of a facility or equipment.

Detailed knowledge of environmental rules and regulations can be turned into a company's economic and competitive advantage.

Multidisciplinary teams that include environmental and safety representation have become commonplace. However, the emphasis is usually on simply complying with the rules and regulations, instead of making the regulations work for the company.

Knowing that they will have to comply has led some companies to make environmental programs, if not pay for themselves, at least contribute towards their cost. Waste minimization programs are a typical example.

To this end many companies have recognized that "pollution prevention pays."

Understanding the rules

To make rules and regulations work to minimize environmental costs and liabilities, one has to know and understand the goals and objectives as well as the environmental rules and regulations.

Knowing what you want to do may sound obvious, but may not be. For example, often the reason something is done in a particular way is that it has always been done that way.

A company may routinely install 500 bbl tanks, regardless of expected production. However, a 500 bbl tank is subject to New Source Performance Standards (NSPS) whereas a tank smaller than 471 bbl is not.

Or a company may routinely oversize the field compressor in case production increases in the future. However, Texas Standard Exemption No. 6 permits installation of a compressor of less than 240 hp without requiring registering or stack testing the compressor. Therefore, in these days of rental compressors, good economic sense is to install a compressor of less than 240 hp, unless there is a need for more horsepower.

Knowing and understanding the environmental rules and regulations, however, can be time consuming, voluminous, and often complicated. And regulations can and do change.

To make environmental regulations work for your company, you have to understand the existing regulations as well as upcoming changes and trends.

Applicability

Environmental regulations can be made to work both in construction/development and in operations. But it is best done during the construction phase where environmental planning can be included in the initial phases of the project.

For example, if one wants to build a gas plant, but does not want to obtain a Prevention of Significant Deterioration (PSD) permit, because it is expensive and time consuming, one should approach the design by working backwards.

Determine the various possible equipment configurations and operating scenarios that allow the project to stay under the emissions cap that would require a PSD permit. Then, the operations people need to determine if any of these scenarios has enough operational flexibility to meet the objectives of the facility.

The environmental data then become a tool that can help management make good decisions concerning the facility.

At the operational level, an understanding of the environmental rules and regulations can again help make environmental regulations work for you. For example, understanding the oil field hazardous waste exemption can prevent inadvertently causing nonhazardous waste to become hazardous.

Air regulations

One area where air regulations should be considered is in the design of gas plants or compressor installations.

Small gas plant

The following steps show how a small gas plant in West Texas could be designed to reduce the impact of Air regulations.

Step 1-Determine what the company wants to do.

A company wants to build a small (5 MMscf) gas processing facility in West Texas to take advantage of an urgent need for processing facilities. Therefore, this facility should be built without having to endure the time delays and expenses for obtaining an individual air permit.

Step 2-Determine the appropriate regulatory scheme.

West Texas is considered an attainment area for all the National Ambient Air Quality Standards (Naaqs). The various trigger levels for permitting are shown in Table 1 [11777 bytes]. Note that the levels are presented from the most to the least desirable.

Step 3-Calculate the operating scenarios that would keep the emissions at levels that would allow the plant to operate under a standard exemption.

Work the emissions backwards to see what size and type of equipment can be operated within the standard exemption category. If the results do not give sufficient operational flexibility, then work backwards to determine the size and type of equipment within the state permit level.

One advantage of doing this is to help management decide what type and size of equipment to buy or rent.

Step 4-Determine whether the equipment chosen will require a Title V permit.

If the emissions put the facility over the Title V major source level, calculate the size and type of equipment that would stay below the trigger level. Bear in mind that the most probable problem emissions are carbon monoxide (CO) from the compressors and benzene, ethylbenzene, toluene, and xylenes (BTEX) from the dehydration units.

BTEX can be handled by installing a thermal oxidizer or a condenser unit. CO can be taken care of by installing a smaller compressor, if it can provide sufficient operational flexibility.

The Clean Air Act (CAA) considers facilities with common ownership on contiguous properties to be one facility for purposes of determining the applicable regulatory scheme. This means that if your compressor station is next to your gas plant the emissions from both sources are added together and it will be more difficult to eliminate costly and time-consuming permitting.

Step 5-Complete the paperwork.

After having decided on how to take advantage of the permitting schemes, it is important to make sure that all the appropriate documentation is completed.

The specific standard exemption that is used, if the plant is covered by a standard exemption, will specify whether the exemption needs to be registered with the Texas Natural Resource Conservation Commission (Tnrcc) on a PI-7 Form, such as compressors having more than 240 hp.

However, even if the location does not need to be registered, it is an extremely good idea to do so, because this is proof that the facility is permitted.

Compressors

To meet air regulations, the following steps show how an operator can approach the requirements of Standard Exemption No. 6 for compressors

Step 1-Determine what the company wants to do.

A medium-sized independent has a small compressor station in South Texas with two 750-hp compressors. The engines have been registered with the Tnrcc on Form PI-7 to demonstrate that they are properly covered by Standard Exemption No. 6.

The person at the company responsible for compliance would like to determine the most cost-effective and least-disruptive monitoring method required.

Step 2-Determine what the monitoring requirements are.

Standard Exemption No. 6 requires that within 60 days of initial engine start-up, and twice a year thereafter, the engine emissions are to be determined by stack testing.

The company can use an alternative method, if the method has been approved in advance by Tnrcc. For example, if the same size and engine model has been stack-tested by the company at another Texas location, the company can use those data in lieu of testing the "new" engine.

Instead of the twice-yearly monitoring, the company can choose to install an elapsed-operating-time monitor and test every 15,000 hr. This allows for tests every couple of years, or so. For this option, the operator has to send a report to the Tnrcc every 6 months documenting the hours the engine has operated since the last stack test.

Step 3-Determine what the options are along with their pros and cons.

There are several options available. Some of the options include:

• Stack testing the engines initially, and then every 6 months.

• Stack testing the engines initially, installing an elapsed-operating-time meter, and monitoring after 15,000 hr of actual running time.

• Using a stack test that had been performed by the operator in Texas on an identical engine, and then stack testing every 6 months.

• Using a stack test that had been performed by the operator in Texas on an identical engine, and then installing an elapsed-operating-time meter and monitoring after 15,000 hr of actual running time.

• Stack testing the engines initially, and then monitoring operating parameters and performing a mass balance.

• Using a stack test that had been performed, by the operator in Texas, on an identical engine, and then monitoring operating parameters and performing a mass balance.

Each option's pros and cons and availability depend to some extent on the exact circumstances of the facility and operator. For example, if the company has performed a stack test on the same engine at a different location in Texas within the last 12 months, it obviously makes good sense to use those data, unless there were some problems with the test.

Unless there is a problem with installing and maintaining an elapsed operating time monitor, performing the stack tests after every 15,000 hr of actual running time is preferable to stack testing every 6 months. Note that there are only 8,760 hr in a year. The disadvantage of this option is that reports have to be submitted every 6 months to the Tnrcc, although these reports are neither onerous nor complicated.

The option of monitoring operating parameters is very attractive if a pumper visits the facility daily, and/or if the facility is automated with the data transmitted in real time to an operator. However, to use this option, the company will have to submit the proposed method to the Tnrcc and obtain its approval prior to beginning the monitoring.

Step 4-Determine which option is the most cost effective.

Having considered all the possible options, it becomes a relatively easy task to determine the most suitable option for this facility, taking into account initial cost, operating cost, and reporting requirements.

Step 5-Complete the appropriate paperwork.

Depending on the option chosen, it may be necessary to submit a monitoring plan to the Tnrcc for its approval, or to submit six monthly reports. But for every option, it is important to communicate the specific requirements to all those involved, so that testing, and/or monitoring and reporting will be performed and submitted in a timely fashion.

Water regulations

Two areas impacted by water regulations are compressor installations and offshore water discharge.

Pipeline compressor

The following steps show an example of how storm water permitting requirement costs can be reduced.

Step 1-Determine what the company wants to do.

The company wants to install a pipeline compressor station in South Texas and would prefer not to be under the National Pollutant Discharge Elimination System (Npdes) storm water permitting net. It has already determined that the facility will be covered under Standard Exemption No. 6 for air emissions.

Step 2-Determine what options are available.

The Npdes storm water program applies to all industrial facilities where storm water can contact contaminants, and from which there can be a point source discharge of storm water.

One option is to construct the compressor station so that there is sheet flow off the property. As long as there is no point source discharge point, the station will not need an Npdes permit. An alternative is to cover the compressors so that storm water cannot contact contaminants.

Step 3-Determine pros and cons of the options.

The three options available are: to construct the station to ensure that there is only sheet flow, to cover the compressors, or to file a Notice of Intent (NOI) to be covered by the general Npdes permit. The pros and cons of each option should be presented to management for input into which path to take.

The pros and cons should include a review of installation and operational costs, time impacts, and the environmental liability exposure of each option. For example, filing a Notice of Intent is quick, inexpensive, and easy. However, to stay in compliance with the permit, a pollution prevention plan must be written for the facility, and the plan must be implemented. All impacted employees must receive the appropriate training.

On the other hand, installing roofing or site preparation enabling all surface flow to be sheet flow involves investment of more time and cost up front; but the operational costs are virtually nil.

Step 4-Complete paperwork.

Once an option is selected, you should make sure that all appropriate people know what was decided, complete any necessary paperwork (such as an NOI if one is required), and document the process in the file.

For example, if the facility uses sheet flow as a solution, the fact that the facility does not require an Npdes permit should be clearly stated, along with the reasons why, and retained for documentation during an inspection or audit.

It is important that personnel in the field also understand what was done and why. For example, if the field superintendent was unaware that the facility had been constructed to enable only sheet flow of storm water off the property, he might decide to be "helpful" and install a drain or ditch to make sure that the rain will run off quickly.

Platform discharges

The following steps describe how to handle and monitor discharges from a group of offshore oil producing platforms in the outer continental shelf (OCS) waters.

Step 1-Determine what the company wants to do.

A small independent has purchased three facilities in the OCS off the Texas coast. Currently, each facility has its own water-treating equipment and discharge point. The platforms discharge 450, 1,000, and 3,250 b/d.

The company would like to optimize its operations, and reduce operating costs for water discharges. One suggestion is to pipe the produced water to a central platform and have all the water treatment equipment and a single discharge point on that facility.

Step 2-Determine the applicable regulatory scheme and requirements.

Produced water discharges from a platform in the Western Gulf of Mexico OCS are covered under General Npdes Permit No. GMG290000. This permit sets discharge limits, specifies parameters to monitor, and establishes the frequency and type of the monitoring. Table 2 [41522 bytes] summarizes this information.

Step 3-Determine the pros and cons of consolidating the discharges and treatment on one platform.

One of the first things that emerges from the regulatory review is that the type and frequency of monitoring for toxicity, NORM, and doing a bioaccumulation study is dependent on the volume of produced water discharged.

To run an aquatic toxicity test is costly, about $1,500-2,000/sample. Therefore, you do not want to increase the frequency of toxicity monitoring.

In this example, if the discharges are not combined, two of the facilities are required to monitor aquatic toxicity on a quarterly basis, the third platform has to monitor annually. This adds up to nine toxicity samples per year.

If the discharges are combined, the total discharge will be over 4,600 b/d, requiring monthly aquatic toxicity testing. This results in three extra analyses per year. It should be noted that if the facility passes the toxicity test for a full year, the frequency drops back down to once per year.

The same situation occurs in the case of monitoring radium 226 and 228. After combining discharges, the number of analyses will increase by three.

The bioaccumulation study requirement is triggered if the facility discharges over 4,600 b/d. After combining the discharges, the platform is over this limit. Compliance cost with the bioaccumulation study can be extremely high, in the range of $30,000-60,000/year.

Currently, another option available to operators with discharges in the Gulf is to join the Offshore Operators Association's (OOC) bioaccumulation study. EPA has approved participation in OOC's study as a method of meeting the bioaccumulation requirements.

To join, an operator pays $3,000, if they have permitted discharge points that currently have no discharges, and $7,500/outfall with discharges.

In this example, if the discharges are not combined, no bioaccumulation study is required. By combining discharges, the operator must either conduct its own study, at a cost of $30,000-60,000, or join the OOC study for $7,500.

To determine whether a discharge point is subject to the bioaccumulation requirements, the 4,600 b/d limit must not be exceeded at any time during the 5-year life of the existing permit. Consequently, if a facility is close to the limit, the operator might consider joining the OOC study, rather than run the risk of having to conduct its own costly bioaccumulation study.

The operator also should consider what happens if the treatment facilities shut down. That is, if the equipment fails on one platform, the operator only loses the production from that facility. However, if the discharges are combined, and the treatment facilities fail, all production will be lost, unless a large amount of storage is available.

Step 4-Use the data obtained in Steps 1-3 to make a decision.

Once Steps 1-3 have been completed, it becomes a business decision as to which option is the most advantageous for the company.

Step 5-Complete the paperwork.

After a decision has been made, the option chosen should be documented, and all the appropriate paperwork should be completed. Again, it is extremely important that all those involved be informed of the decision (particularly those in the field) so that nobody inadvertently takes an action that undermines the company's compliance.

For example, in establishing permit limits, the Environmental Protection Agency (EPA) specifies the exact test methods that are approved. Any time an approved test method is used to analyze a parameter, the test results must be reported to EPA. This means that even if you are only required to monitor for oil and grease on a monthly basis, if you run two gravimetric oil and grease analyses, both must be reported.

However, the infrared (IR) method for analyzing oil and grease is not approved by EPA. Therefore, an operator can install and use an IR machine to monitor its oil and grease levels on a regular basis, without the data having to be reported. This enables the operator to "troubleshoot" the system and identify and correct any problems before the next Npdes analysis is due.

Waste regulations

Waste-handling issues are illustrated by examples in a maintenance yard and producing operations.

Maintenance yard

The following steps show an approach for handling waste regulations during the construction of a crude-gathering maintenance yard.

Step 1-Determine what the company wants to do.

A crude gathering company needs to establish a small maintenance yard in Central Texas. It wants the lowest costs, and preferably no costly permitting delays.

Step 2-Determine the applicable regulatory scheme.

In Texas, the Texas Railroad Commission (TRRC) has jurisdiction of crude-gathering operations. However, the fact that a facility is regulated by the TRRC, does not mean that it cannot generate hazardous waste, nor does it mean that the Tnrcc would not take over the jurisdiction if there were operational releases and spills that reach ground water.

Step 3-Determine potential areas of exposure and how to limit them.

As an example, installing underground fuel tanks raises the potential risk of a discharge into ground water. The current underground storage tank regulations require double liners, cathodic protection, or secondary containment to help minimize the risk of a leak, and monitoring to determine when, and if, a leak occurs.

For this facility, an underground storage tank probably does not make a lot of sense if an aboveground tank can be used.

Installing dikes around aboveground tanks to contain any releases should also be considered. This may be required under the Spill, Prevention, Control and Countermeasure (SPCC) regulations, if hydrocarbons are stored in the tanks. If the ground is very porous, the use of concrete liners for the tank and dike should be considered.

If trucks are washed, the washing facility should be designed to minimize the chance for ground or surface water contamination. If an available commercial truck washing facility is conveniently located near the proposed yard, the company should consider using this facility instead of building its own.

If truck maintenance is done at the yard, you should consider what type of filter-crushing presses could be installed to aid in recycling filters and the best way to handle lube oil so that it can be recycled.

Step 4-Using the data obtained in Steps 1-3, decide how to construct the yard to minimize cost and environmental exposure.

From Steps 1-3, management can choose the most cost effective options for developing the yard, while also limiting environmental liabilities.

Producing operations

The following steps show how wastes can be handled by a West Texas producing operator.

Step 1-Determine what the company wants to do.

A company would like to minimize waste disposal costs from its field operations.

Step 2-Determine what regulatory scheme applies.

Waste handling, storage, treatment, and disposal are regulated by the Resource Conservation and Recovery Act (RCRA) and its associated regulations.

An important part of these regulations is the definition of solid and hazardous wastes. Waste generated from the exploration and production of oil, gas, and geothermal energy is by definition a solid waste that is not a hazardous waste.

The exemption only applies to waste that is uniquely associated with oil and gas production, such as spent drilling fluids and produced water. It does not apply to, for example, lube oil from a compressor.

The exemption is "lost" at the point of custody transfer for an oil production facility and at the point of sale to a pipeline downstream of a gas plant.

Note the fact that a waste is not automatically hazardous if it does not have the oil and gas exemption. The waste is also not automatically not hazardous.

In Texas, oil and gas production waste is regulated by the TRRC. In the TRRC scheme, all TRRC-regulated waste must have at least one TRRC waste permit in its disposal chain.

For example, produced water that is sent to a TRRC-permitted Class II injection well for disposal does not require any additional permitting. However, a Minor Permit must be obtained from the TRRC prior to disposal if the operator plans to:

• Landfarm drilling mud and cuttings on the landowners field with his permission

• Dispose of mud down the well annulus

• Dispose of oily dirt by sending it to a Tnrcc-permitted landfill.

  The Minor Permit is site and waste specific and is valid for only 30 days. Recently, TRRC published Statewide Rule 98 that covers the registration, handling, storage, treatment, and disposal of hazardous oil field waste.

Step 3-Determine potential pitfalls and how to avoid them.

The biggest pitfall is inadvertently losing the oil and gas exemption.

For example, treater chemicals that have been down the hole are covered by the exemption, but prior to use they are not. It is therefore important not to add unused treater chemicals to, for example, a reserve pit. This could result in all the pit contents being considered hazardous waste.

The cost of handling and disposing of hazardous waste can be astronomical.

Of course the best way to minimize disposal costs is to not produce waste. It makes sense to only have on hand the needed chemicals and materials. Rather than disposing of unused chemicals, you should try to either use them or return them to the vendor. If any solvents are used in the field, you should ensure that these are non-hazardous.

Drums are often a problem. You should either buy in bulk or require that the chemical supplier take the drums back. Drums are also a problem when they are reused without proper cleaning and before having all old labels removed.

Step 4-Develop and implement a plan, and train.

After determining and addressing the potential concerns, the operator should put the findings in a practical field guide/plan, and train all personnel on its use. It is a waste of time and money to go through this exercise if the field personnel are not fully trained to take advantage of it.

The Author