DEP is developing a revised Chapter 95 proposal that has three basic elements:

 A “watershed-based” approach to regulating TDS for most sectors

• Some form of mandatory or incentive-based recycling and reuse program for the Marcellus Shale gas industry
• A sector-based approach for high-TDS dischargers (Oil & Gas).     

 Watershed Based Approach 

 DEP is proposing what it describes as a watershed based approach, which was characterized as a “pre-TMDL” program under which DEP would identify watersheds which are approaching and threaten to exceed some percentage of their assimilative capacity as measured at the applicable downstream public water supply intakes. 

DEP’s watershed approach does not include allowance for real time discharge management based on flows.  DEP understands that a number of commenter’s suggested this approach.  The question posed was whether this could be done within existing regulations, and whether any necessary changes to existing state regulations would be acceptable to EPA (which DEP contends would need to approve those changes as part of the state’s administration of the NPDES program).  DEP takes the position that the water quality standards include an “anti-degradation” approach for all streams, in that existing uses that are currently being achieved must be protected. 

Discharge Standard for Significant New or Expanded High-TDS Load Discharges

Under the new proposal, DEP would impose a discharge limit on significant new or expanded High-TDS loads as follows: 

• Subject to several exclusions, new or expanded TDS-loads of greater than 5,000 pounds per day, and involving concentrations > 2000 mg/l would be subject to a discharge limit.  This discharge limit would apply only to the new or expanded load.  Any pre-existing TDS discharge loads, regardless of mass or concentration would not be subject to this limit. 
• Such significant new or expanded TDS-loads would be subject to an effluent limit of 2000 mg/l, but with a provision allowing a “variance.”  The variance procedure would allow DEP to set a higher effluent limit if the watershed wasteload analysis indicated that such a limitation was not needed to meet downstream TDS limits at the nearest water supply intake or near field protection of instream uses.
• DEP will conduct an annual analysis of all affected watersheds, based on information from the water quality monitoring network.  DEP understands that the water quality network will need to be upgraded, with real-time conductance monitors installed in additional watersheds.  Currently it appears that there are 36 water supply intakes in watersheds of potential concern.  If it appears that TDS trends are increasing, and assimilative capacity is threatened, DEP would then consider imposing more stringent TDS limits on major TDS load dischargers following a wasteload allocation approach.  For purposes of this rule, DEP defines “watershed” based on surface water and GUDI water supply intake locations (current existing point of Ch. 93 compliance for TDS) and the contributing watershed areas upstream of each applicable water supply intake.

Marcellus Shale Natural Gas Wastewater

• DEP will be proposing recycling/reuse requirements, the details of which will be released soon.

Oil and Gas Sector Limit

• DEP will propose that all new or expanded TDS loads from the Oil & Gas sector be subject to a 500 mg/l discharge limit.  This would apply to new or expanded TDS loads from both conventional and Marcellus Shale development.

What’s Next:  DEP plans to present this revised package to the WRAC (Water Resources Advisory Committee) on April 14 and intends to present the revised package to the EQB “this spring”.  Industry is urged to formulate and provide comments and concerns to DEP as soon as possible.

For more information on this topic, or for help with identifying and implementing a strategy to meet the rules proposed above, please contact Travis Buggey, Venture Engineering & Construction, at 412-231-5890, ext. 325.

According to PADEP, the justification for its new permitting strategy is a finding of high TDS concentrations in the Monongahela River and West Branch of the Susquehanna River. That surface water is used by power plants, steel mills and other industries as a source of cooling water and the high TDS was causing operational issues.

In its Permitting Strategy for High Total Dissolved Solids Wastewater Discharges (April 11, 2009), PADEP describes a program that requires new high-total dissolved solids (“TDS”) dischargers to install adequate treatment to meet requirements based on the receiving stream’s assimilative capacity, and dischargers to publicly owned treatment works must meet local limits.

A high TDS discharge is proposed to be anything that exceeds a TDS concentration of 2,000 mg/l or exceeds 100,000 pounds per day. Existing dischargers, including power plants, chemical manufacturers, food processors, and mining and mineral producers, will be impacted, as many of them have discharge levels that would exceed the proposed limits.

No new or expanded high TDS wastewater sources will be permitted unless the applicant proposes to install adequate treatment of TDS by January 1, 2011.
For existing industrial facilities – PADEP will permit the continued treatment and disposal of existing sources of High-TDS wastewaters at existing permitted facilities as follows:

1. Existing industrial sources of High-TDS wastewaters will be able to continue to operate under their existing permit limits and conditions until such time as they propose to expand or to increase their existing daily discharge load of any pollutant of concern. At that point, such a facility would be subject to the following schedule:

• Prior to January 1, 2011, for new sources of High-TDS industrial waste proposing treatment for DS, an allocation of available assimilative capacity may be authorized. Wastewaters discharged from these facilities also must meet any other applicable treatment standards and requirements.

• After January 1, 2011, the more stringent of the applicable effluent standards or water quality based effluent limitations.

These new regulations, which are to be proposed for comment within the next few months, have the potential to significantly affect discharge requirements for most major NPDES permit holders. The technology required to treat high TDS discharges is very expensive both from a capital cost and operating cost perspective, and limited to reverse osmosis and evaporation/crystallization. Both would still result in either a highly concentrated brine, or a solid crystalline material that would require off-site disposal.

For more information on this topic, or for help with identifying and implementing a strategy to meet the schedule(s) listed above, please contact Don Olmstead, PE – Manager Engineering, Venture Engineering & Construction, at 412-231-5890, ext. 302.

Geothermal energy is usually associated with the western states and Yellowstone National Park or “The Geysers” field in Northern California.  However, geothermal energy can be utilized just about anywhere in the US and is economical when employed in residential applications in the Northeast.  Homeowners who install a qualified geothermal heat pump system in 2009 and later years are eligible for a provision in the Stimulus Bill allocating a 30% tax credit applied to the purchase price of a new system.  A credit of 10% of the total investment is also available (no maximum) for a commercial system installation.

The system’s basic concept takes advantage of the earth’s constant temperature, approximately 55 degrees, to heat and cool a building.  By tapping this steady flow of heat from the earth in the winter, and displacing heat in the earth in the summer, a geothermal heat pump can save homeowners 40 to 70 percent in heating costs and 30 to 50 percent in cooling costs compared to conventional systems.

Ground source heat pumps (GSHPs) work in a similar manner as air source heat pumps, minus the higher operating cost.  A typical household can save on average $1,500 a year resulting in a payback period of three to five years.  GSHP’s are more than three times as efficient as the most efficient fuel furnace. By moving heat that already exists in the earth, instead of burning a combustible fuel, GSHP’s deliver three units of energy for every one unit used to power the heat-pump system.

Ground source heat pumps work by circulating water or an antifreeze solution through a closed loop of polyethylene pipe that is buried in the ground or set in a body of water.  A closed loop system, the most popular, can be laid out either vertically in 50-250 foot deep holes drilled like a well, or horizontally in 3-6 foot deep trenches. The less common open loop system circulates a constant source of ground water and dispels the water back to its origin, such as a stream, well, or pond.

The principle action of a heat pump moves heat from lower temperature location to a higher temperature location.  A ground source heat pump works in a similar manner, except that its heat source is the warmth of the earth. The process of elevating low-temperature heat to over 100 degrees F and transferring it indoors involves a cycle of evaporation, compression, condensation and expansion.  A refrigerant is used as a heat-transfer medium which circulates within the heat pump.

The ductwork is no different than that of a conventional forced-air system.  The difference is found in the temperature of the air flowing from the registers in the winter.  With a conventional air source heat pump, the air flow is seldom warmer than 80 degrees.  But because water transfers a greater volume of heat than air, the GSHP is able to deliver warmer air, typically about 110 degrees F.

Another benefit of a ground source heat pump is utilizing a desuperheater. This component transfers residual heat from the compressor to water.  In the summer, when the system is working to get rid of heat, the desuperheater can provide practically free hot water. And since most systems are oversized, there is usually enough warmth left over for low cost hot water in the winter too.

While GSHPs require a small amount of electricity to concentrate the energy and circulate it through the system, most systems derive approximately 70 percent of their energy from a renewable source – the earth.  GSHPs do not require a flue, and since there is no on-site combustion, there’s less chance of fire, and no chance of carbon monoxide infiltrating the home. GSHPs also carry the Environmental Protection Agency’s Energy Star Label, which is used to designate energy-efficient equipment.  Often homeowners may find tax benefits, lower mortgages, or utility rebates.

For more information on Venture Engineering’s geothermal systems, please contact Travis Buggey at (412) 231 – 5890 x 325.

In fact no major commitment of any project’s funds occurs until the permit is issued, save the cost of lawyers and environmental consultants deployed to negotiate with various local, state and federal permitting agencies.   And for what purpose?  The regulators have a fiduciary responsibility to verify that projects conform to local zoning, applicable codes, and environmental requirements.

The fact is that permit applications, as submitted, typically contain best or maximum available technology for environmental controls.  But in the twenty four months it takes to accomplish regulatory review, public notice, and issuing the permit, little, if any, changes are typically made and incorporated into a project.  Certainly no major environmental controls.  Regulators respond to criticism with legitimate arguments that they are undermanned, that projects are complex and they have no relief from requirements to carefully screen projects, and that they are subject to criticism no matter what they do – from groups on all sides of the issue.  

Inexperience and indecision are also a factor. And why not – it’s hard to find reviewers who are expert on everything. But that burden could be relieved by taking advantage of another regulatory avenue available through state engineering boards – put more onus for a compliant work product on Professional Engineer’s (PEs). PEs work hard to earn their seals and they mean something.

Some projects have been held up recently after a permit was issued. The interferences range from petty harassment to preposterous.  Locally, a commercial enterprise acquired a neighboring property, with a 2000 sq. ft. block building of contemporary construction. The new owner checked for asbestos, received a demolition permit from the township and began demolition. DEP stopped the work and assessed a $10,000 fine, which was contested and reduced. The rationale – the owner should have known that the township permit was not enough.  Perhaps not enough people are tapping the brakes on their projects?

Farther afield, consider the development of a new coal fired power project in Utah.    After the US EPA’s Denver office granted the environmental permit to Deseret Power Electric Cooperative, an environmental activist group (Sierra Club) challenged the permit before the US EPA’s appeals panel because the issued permit did not address carbon dioxide emissions controls.  And in due course, the US EPA’s appeals panel agreed and rejected the federal permit, because EPA’s Denver office failed to adequately support its decision to issue a permit for the Bonanza plant without requiring controls on carbon dioxide, placing the $300M project in limbo.  The basis for the decision is a 2007 case in which twelve states and several cities of the United States brought suit against the United States Environmental Protection Agency (EPA) to force that federal agency to regulate carbon dioxide and other “greenhouse gases” as pollutants. The decision did not address the validity of global warming, but determined that greenhouse gases fit within the Clean Air Act’s definition of air pollutants, that EPA has authority under the Clean Air Act to regulate greenhouse gas emissions, that EPA’s rationale for not regulating was inadequate, and EPA was required to revisit and more substantively justify why it should not regulate greenhouse gases, or change its position.

Nonetheless, carbon dioxide is still not a currently regulated pollutant under the federal Clean Air Act.  So now an owner must anticipate what might happen in the future at the time of submitting a permit application and spend money on control mechanisms for contaminants that are not currently regulated?

Instead of spending hundreds of billions of tax payer dollars via these recent ‘Stimulus Bills’ and further mortgaging all of our futures all in the name of creating and maintaining jobs, why don’t we do the sensible thing and simply reduce the time it takes to issue a federal permit.  There are hundreds of billions of dollars ready to be spent by private industry right now.  Hundreds of thousands of jobs in limbo awaiting a permit.  You want a stimulus plan that will work, at no cost to the tax payer?  Reduce the time to permit.  How do you do that? One way is eliminate redundant functions between regulators and professional engineers. Does anyone have a better idea?

Twenty four months.

Really.

Dave Moniot

President & CEO

Venture Engineering & Construction

Pittsburgh, PA

Venture Engineering’s siloxanes removal system is based on a multitude of practical landfill gas processing experience and was founded on the principals of design of siloxanes/NMOC removal systems located at various client installations, all of which were stick built, non-proprietary, industry standard unit operations. The Venture siloxanes removal system encompasses the best of all of our designs into one modularized, shop fabricated system.  Venture’s system includes regenerative selective adsorption followed by activated carbon adsorption.

Siloxanes removal systems have been in landfill gas service for 25 plus years.  Until the more recent development of various molecular sieves, activated carbon was the primary removal device for siloxanes.  A large enough activated carbon system will remove siloxanes to just about any level required.  However, large activated carbon systems require space and energy to regenerate on-site.  Furthermore, moisture, NMOC’s and hydrogen sulfide also compete for adsorption surface area inside the activated carbon system.

Venture uses several different types of selective adsorbants including activated alumina, silica gels, and in some instances, molecular sieves in the first stage adsorption skid.  The ultimate combination depends on the individual characteristics of the LFG to be conditioned.

The basic system includes a dual-swing bed adsorption skid, followed by a multi-bed activated carbon skid.  Both systems are regenerated on-site either using waste heat (via inert tail-gas), or via low watt density electric heating elements.  For high BTU gas plant applications, regeneration using heated tailgas (from a TOU heat exchanger as an example) is the preferred method.  However, for IC engine or turbine plants, no such inert tailgas stream exists.  As such, a combination of cleaned LFG gas (slip stream) and electric heating elements provide the regeneration for the off-line vessels.

Benefits of Venture’s Siloxane Removal System:

Venture’s skid mounted gas conditioning system has been designed primarily to consistently remove siloxanes from biogas to levels acceptable for combustion or to meet a pipeline specification.  In addition to siloxanes removal, Venture’s gas conditioning system will also reduce the levels of other contaminants such as hydrogen sulfide and halogenated organics, which has a tremendous benefit on downstream operations, as discussed below.

Siloxanes

During combustion of biogas containing siloxanes, silicon is released and can combine with free oxygen or various other elements in the combustion gas. Deposits are formed containing mostly silica and silicates (SiO₂ and SiO₃), but can also contain calcium, copper, sodium, sulfur, and zinc. Most deposits caused by combustion of siloxanes are off-white to light brown in color and are of varying texture, some very smooth with a powdery-looking surface, while others are coarse and grainy. These deposits can ultimately build to a surface thickness of several millimeters and are difficult to remove by chemical or mechanical means. The propensity for silica/silicate deposition will vary based on flame front, heated surface area, rotation/tip speed, post combustion equipment, heat recovery and catalyst. The damage caused by siloxanes combustion byproducts and deposits can be severely limiting to operations.

Reciprocating piston engines experience fouling in the combustion chamber, on the valves, valve seats, piston crowns and cylinder walls. Sometimes deposits collect under the exhaust valves resulting in blowby and burnt valves. This can significantly reduce compression and engine efficiency. In gas turbines, deposits from siloxanes combustion form in the hottest areas, mainly on the first few rows of nozzles and blades. Prolonged operation of gas turbines where siloxanes are present in the biogas can lead to severe erosion of the turbine blades and a significant drop in operating efficiency.

Because of the difficulty in removing the silicon-based deposits and the cost to overhaul engines and turbines, many manufacturers have already set very low limits for siloxanes with warranty provisions that are linked to these siloxanes limitations.   So either remove the siloxanes, or live without the manufacturer’s warranty if they’re not controlled.  The following table lists current (as of 1/31/2009) siloxanes limits for some common manufacturers.

                                                                    Siloxane

            Engine Manufacturer                     mg/m³  (in Landfill Gas)

            Caterpillar                                       28

            Jenbacher                                      10

            Waukesha                                      25

            Deutz                                             5

            Solar Turbines                              0.1

            IR Microturbines                             0.06

            Capstone Microturbines                0.03

Additionally, various emissions controls devices that use catalysts have been negatively affected by siloxanes. Siloxanes, as reduced silicon dioxide, coat the catalyst and creates an impermeable glass. This reduces the efficiency of the catalyst for removal of formaldehyde and other byproducts from combustion.  By removing the siloxanes ahead of combustions, the life of the catalyst can be greatly extended. 

Hydrogen Sulfide

Hydrogen sulfide is highly corrosive and can be just as detrimental to an IC engine or turbine, as siloxanes.  Hydrogen sulfide is oxidized into sulfur dioxide which dissolves as sulfuric acid. Sulfuric acid, even in trace amounts, can make a solution extremely acidic. Extremely acidic electrolytes dissolve metals rapidly and speed up the corrosion process. This is particularly true in high temperatures, such as is the case with an IC engine.  Studies have shown that the first part of a biogas engine to wear out is the cylinder liner at the upper position of the piston ring. Excessive wear in cylinder liners at this position is caused by the corrosion phenomena. Even if there is no oxygen present, biogas can corrode metal. Hydrogen sulfide can become its own electrolyte and adsorb directly onto the metal to form corrosion. If the hydrogen sulfide concentration is very low, the corrosion will be slow but will still occur due to the presence of carbon dioxide. 

Venture’s gas conditioning system, while sized to remove siloxanes, will also significantly reduce hydrogen sulfide concentrations in the activated carbon process.  Alumina, silica gels and molecular sieves do not remove hydrogen sulfide.

Halogenated Hydrocarbons

Halogenated hydrocarbons (primarily chlorinated and fluorinated) can also have a detrimental effect on an IC or Turbine plant.  Like hydrogen sulfide, chlorinated and fluorinated hydrocarbons form their respective acids:  hydrochloric acid and hydrogen fluoride.  By reducing the levels of these halogenated hydrocarbons, corrosion problems are reduced and engine performance is increased. 

Venture’s gas conditioning system employs two successful removal media’s for halogenated hydrocarbon removal:  activated alumina and activated carbon.  Silica gels and molecular sieves have little effect on heavy hydrocarbon concentrations.

Siloxanes Removal System Specs (LFG to Electricity Installation)

• Carbon steel with coal-tar epoxy interior coating (or stainless steel if preferred), is used for all pressure vessels, stainless steel is used for piping and valves. Vessels are designed to the requirements of ASME Section VIII, and piping is designed to the requirements of ASME B31.3 with Class 150 flanges.
• High efficiency 0.01 micron coalescing pre-filtration and 1 micron particulate after filtration is provided. Filter elements are contained in stainless steel housings designed to ASME Section VIII.
• Oxygen analyzer (for process and safety control)
• High temperature valves with metal seats (activated carbon system)
• Piping and vessel insulation (activated carbon system)
• Inlet blower, motor and VFD (where raw LFG feed pressures are below 5-7 psig)
• Air cooled heat exchanger (to remove heat of compression (175F to 95F) of the raw gas prior to selective adsorption)
• Heaters use low watt density elements with outlet temperature controls suitable for use in a Class 1 Div 2 environment and are fully insulated for personnel protection.
• Electrical enclosures are stainless steel, providing NEMA 4X ingress protection, and are purged and pressurized for a Class 1 Div 2 environment.
• Operation is controlled using a PLC with a full color interactive digital display on a panel mounted operator interface.
• Safety features include alarm contacts for connection to a client’s main PLC system, and cycle control and safety overrides interlocked to the PLC via valve limit switches, temperature controls and pressure transmitters.

The following requirements are the responsibility of the Owner/Installer (or optionally provided by Venture):

• Site location suitable for operations and maintenance
• Concrete pad for skids
• A single point 460/3/60 power supply via a suitable fusible disconnect
• Inlet & outlet connections including bypass
• Emissions exhaust connection to a local flare or thermal oxidizer, including a flame arrestor device
• Connection of the condensate drain ports to a local condensate treatment or storage facility
• Connection of alarm contacts and alarm monitoring
• Single point instrument quality air to the skid location
• Instrument air supply for pneumatic valve actuation

System Performance:

The system described herein is completely modularized and designed to remove siloxanes from raw biogas with an inlet flowrate of up to 4000 SCFM (modules in increments of 1000 SCFM) and inlet siloxanes concentration of 75 ppmv or less to an outlet concentration of 1.0 ppmv or less.  This assumes that total gaseous non-methane organics (NMOCs) does not exceed 6000 ppmv (as ppm methane), and hydrogen sulfide ≤35 ppmv.  Higher NMOCs and/or hydrogen sulfide will affect the size of the system.  In instances where hydrogen sulfide concentrations are significantly higher (>100 ppmv), it may be more economical to employ a hydrogen sulfide removal step ahead of the selective adsorption skid.  This will be determined on a case by case basis.

The initial investment (capital) for a Venture Siloxane Removal and Gas Conditioning skid can be as low as $180/SCFM (inlet) and up to $225/SCFM, depending on specific gas composition, flow rates, temperature and pressure requirements.

For information, call Mr. Bill Slatosky, Process Engineering Manager, at 412-231-5890.

The following are Venture Engineering’s insights about LFG, what we’ve been doing with it, the types of systems we’ve engineered, and for all those developers and/or engineers out there that rely so heavily on rules of thumb, we have those too.

Years ago, landfill operators recognized the opportunity for energy recovery from landfill gas (LFG).  Starting about the early to mid 1980’s landfill operators began to collect and capture the landfill gas and began producing electricity with it.  And this was done well in advance of the NSPS requirements to collect and control methane from landfills.  Landfill gas, in general, consists of about 50% methane and 45% carbon dioxide, 2-3% nitrogen, 0.5% oxygen, and 1.5%-2.5% others (usually non-methane organic carbon constituents called NMOCs).  As such, it has about half the heat content of natural gas.  In those early days, LFG was converted to electricity using mostly internal combustion engines and generators (i.e., IC engine gensets).  Because of the gas properties and the IC engine technologies that existed then, it took about 600 cfm of LFG to produce 1 MW of power.  Today, after some 25 years of engine development, a good current rule of thumb is 1MW of power from 400 cfm of landfill gas.

Subsequently, and especially in the current energy market, there are attractive alternatives to on-site electric generation. Today’s technologies allow for methane recovery and the economic production of high Btu gas which can be prepared to meet the most stringent of natural gas fuel specifications and delivered into local natural gas pipelines for sale to end users. Such fuel production strategies deliver to the landfill operator valuable revenues as well as recognition of environmental stewardship.

Venture and its staff have been involved in a number of LFG to energy projects, including LFG to electricity using both IC engine as well as turbines, LFG to high BTU using pressure swing adsorption and membranes, and landfill gas to boiler (direct use medium BTU application).  While there are other technologies available to produce high BTU gas (i.e., amine solvent extraction, etc.), only the PSA and membrane technologies are attractive in most cases.

Additionally, Venture has found that a high BTU gas project can often offer greater value than a LFG-to-electricity project. In areas where there is a low spark spread, which is the difference between the cost of fuel required to produce electricity and the price of that same unit of electricity, a high BTU gas project may be economically viable where a power plant would not.  High BTU gas projects offer many distinct advantages over an on-site electric generation project. These include:

• Shorter development time, allowing for quicker returns on capital. Venture can realize a high BTU gas plant within 12 months of a notice to proceed compared to 18 to 24 months for a power project. (using 100% modularized PSA process described in more detail below)
• Delivering the gas into a nearby pipeline for distribution so that electric generation can be maximized off-site, utilizing a high efficiency combined cycle power plant.
• Lower noise levels and emissions than an electric generation plant, thereby creating greater community support.
• Less permit requirements due to negligible air emissions.
• Modular units can be easily moved and assembled. Allows for ease in future expansion as LFG flows increase.

LFG has been successfully processed into High BTU gas at various facilities in the US for over 20 years. At one time, only very large sites were commercially feasible for processing LFG into pipeline quality gas. Prior to recent developments and improvements in technology, a good rule of thumb was around 3,000 to 4,000 cfm (inlet) to be economically feasible.  Processing LFG at much smaller volumes is now possible given the current gas economics, improvements in processing technology, and a modularized approach.  In fact, it is now feasible for processing LFG into high BTU gas with as little as 1,000 cfm of LFG (and as low as 300 cfm for anaerobic digester gas!)

Further, Venture believes that the most economical LFG to high BTU gas process is done via Pressure Swing Adsorption.  Venture has developed a completely modularized high BTU gas plant, using several industry proven components.  The heart of the process includes QuestAir Technologies, Inc. patented PSA process.  A typical LFG to high BTU gas plant includes gas conditioning skids (drying, sulfur and siloxanes removal), followed by compression, pressure swing adsorption, and a flare/TOU for off-gas control.  Depending on site specific conditions and gas analysis, a standard 2,500 cfm system capable of producing high BTU pipeline quality gas with a 90% recovery efficiency (i.e., a 2500-90), can be implemented in under 12 months for as little as $5.5M.  Standard modularized plant sizes include 2000-90, 2500-90, and 4000-90.  Additionally, if higher recovery efficiencies are economically feasible, a second stage PSA can be added to any of the standard ‘90’ packages that would increase the recovery to as much as 96%.

Furthermore, this same technology has been readily applied on anaerobic digester gas (biogas) and coal bed methane.  The only real differences between the applications are the upfront gas conditioning requirements (typically less complex for digester and coal bed methane)

To learn more about Venture Engineering & Construction’s capabilities with respect to landfill gas processing, please contact Mr. Bill Slatosky at 412-231-5890, or email at bslatosky@ventureengr.com.

Now that the Democratic Party has taken control of both houses of Congress and the Executive Branch, there is hope amongst senior Democrats that they will be able to convince the president that caps on greenhouse gases are needed as well.

“We have an opportunity to put an emphasis on issues of clean energy, renewable energy, global warming, climate change, in a way that wasn’t possible during the last several years,” says the incoming Democratic Party head of the Senate energy committee, Jeff Bingaman.

Mr. Bingaman supports set federal limits on greenhouse gases. He recently co-authored a letter to President Bush urging him to work with the Democrats to develop solutions to the global warming problem.

And, according to many publications, the largest contributor to global warming is carbon dioxide (CO2), and a push will likely be made to curb these emissions. 

Coal Fired Power Plants & CO2 Emissions

The world meets 25% of its primary energy demand with coal, a number projected to increase steadily over the next 25 years. With respect to carbon dioxide (CO2), the most prevalent greenhouse gas, coal combustion was responsible for 41% of the world’s CO2 emissions in 2005 (11 billion metric tons). Coal is particularly important for electricity supply. In 2005, coal was responsible for about 46% of the world’s power generation, including 50% of the electricity generated in the United States, 89% of the electricity generated in China, and 81% of the electricity generated in India.   Coal-fired power generation is estimated to increase 2.3% annually through 2030, with resulting CO2 emissions estimated to increase from 7.9 billion metric tons per year to 13.9 billion metric tons per year.

For example, during 2006, it is estimated that China added over 90 gigawatts (GW) of new coal-fired generating capacity, potentially adding an additional 500 million metric tons of CO2 to the atmosphere annually.

Many in Congress now believe that developing a means to control coal-derived greenhouse gas emissions is an imperative if serious reductions in worldwide emissions are to occur in the foreseeable future. Developing technology to accomplish this task in an environmentally, economically, and operationally acceptable manner has been an ongoing interest of the federal government and energy companies for a decade, but no commercial device to capture and store these emissions is currently available for large-scale coal-fired power plants.

Background: What Is Carbon Capture Technology and What Is Its Status?

Major reductions in coal-fired CO2 emissions would require either precombustion, combustion modification, or post-combustion devices to capture the CO2. Because there is currently over 300 GW of coal-fired electric generating capacity in the United States and about 600 GW in China, a retrofittable postcombustion capture device could have a substantial market, depending on the specifics of any climate change program. The following discussion provides a brief summary of post combustion technology under development that may be available in the near-term.  It is not an exhaustive survey of the technological initiatives currently underway in this area, but illustrative of the range of activity.

Post-Combustion CO2 Capture

Post-combustion CO2 capture involves treating the burner exhaust gases immediately before they enter the stack. The advantage of this approach is that it would allow retrofit at existing facilities that can accommodate the necessary capturing hardware and ancillary equipment. In this sense, it is like retrofitting postcombustion sulfur dioxide (SO2), nitrogen oxides (NOx), or particulate control on an existing facility.

Post-combustion processes capture the CO2 from the exhaust gas through the use of distillation, membranes, or absorption (physical or chemical). The most widely-used capture technology is the chemical absorption process using amines (typically monoethanolamine (MEA)) available for industrial applications. Pilot plant research on using ammonia (also an amine) as the chemical solvent is currently underway with demonstration plants announced. These approaches to carbon capture are discussed below. Numerous other solvent-based post-combustion processes are in the bench-scale stage.

Monoethanolamine (MEA) – The MEA CO2 carbon capture process is the most proven and tested capture process available. The basic design (common to most solvent-based processes) involves passing the exhaust gases through an absorber where the MEA interacts with the CO2 and absorbs it. The now CO2-rich MEA is then pumped to a stripper (also called a regenerator) which uses steam to separate the CO2 from the MEA. Water is removed from the resulting CO2, which is compressed while the regenerated MEA is purged of any contaminants (such as ammonium sulfate) and recirculated back to the absorber.

The process can be optimized to remove 90-95% of the CO2 from the flue gas.  Although proven on an industrial scale, it has not been applied to the typically larger volumes of flue gas streams created by coal-fired power plants. The technology has three main drawbacks that would make current use on a coal-fired power plant quite costly.

First is the need to divert steam away from its primary use — generating electricity — to be used instead for stripping CO2 from MEA.

A second related problem is the energy required to compress the CO2 after its captured — needed for transport through pipelines — which lowers overall power plant efficiency and increases generating costs.

A recent study by the Massachusetts Institute of Technology (MIT) estimated the efficiency losses from the installation of MEA from 25%-28% for new construction and 36%-42% for retrofit on an existing plant.  This loss of efficiency comes in addition to the necessary capital and operations and maintenance cost of the equipment and reagents. For new construction, the increase in electricity generating cost on a levelized basis would be 60%-70%, depending on the boiler technology.  In the case of retrofit plants where the capital costs were fully amortized, the MEA capture process would increase generating costs on a levelized basis by about 220%-250%.

A third drawback is degradation of the amine through either overheating (over 205^oF) in the absorber or through oxidation from oxygen introduced in the wash water, chemical slurry, or flue gas that reacts with the MEA. For example, residual SO2 in the flue gas will react with the MEA to form ammonium sulfate that must be purged from the system. This could be a serious problem for existing plants that do not have highly efficient flue gas desulfurization (FGD) or selective catalytic reduction (SCR) devices (or none), requiring either upgrading of existing FGD and SCR equipment, or installation of them in addition to the MEA process.

Chilled Ammonia (Alstom) - An approach to mitigating the oxidation problem identified above is to use an ammonia-based solvent rather than MEA. Ammonia is an amine that absorbs CO2 at a slower rate than MEA. In a chilled ammonia process, the flue gas temperature is reduced from about 130^oF to about 35-60^oF. 

This lower temperature has two benefits: (1) it condenses the residual water in the flue gas, which minimizes the volume of flue gas entering the absorber; and (2) it causes pollutants in the flue gas, such as SO2, to drop out, reducing the need for substantial upgrading of upstream control devices.

Using a slurry of ammonium carbonate and ammonium bicarbonate, the solvent absorbs more than 90% of the CO2 in the flue gas. The resulting CO2-rich ammonia is regenerated and the CO2 is stripped from the ammonia mixture under pressure (300 pounds per square inch [psi] compared with 15 psi using MEA), reducing the energy necessary to compress the CO2 for transportation (generally around 1,500 psi).

Ammonia (Powerspan) - A second ammonia-based, regenerative process for CO2 capture from existing coal-fired facilities does not involve chilling the flue gas before it enters the absorber. Using higher flue gas temperatures increases the CO2 absorption rate in the absorber and, therefore, the CO2 removal. However, the higher flue gas temperatures also mean that upgrades to existing FGD devices would be necessary.

Ramifications of CO2 emissions control and mitigation

The most obvious ramification is that the cost of electricity will increase.  With 50% of the US electricity supply coming from coal fired power plants, the option of not producing power from coal is nill.  For some plants CO2 trading may mitigate some costs. 

While most of the CO2 captured will likely be sequestered (underground) at a cost, some facilities may be able to offset a portion of the cost by selling to a growing CO2 market.  CO2 has been increasing used as an enhanced oil recovery technique (rather than using water).  However, supply will surely out grow demand in this regard.

To learn more about Venture Engineering’s capabilities in this regard, please contact Mr. Bill Slatosky – Manager Process Engineering at 412-231-5890, ext. 305.

1.)   Through the use of smart software tools which allow data to be entered one time and then shared by several programs.

2.)   By the use of smart programs which automatically perform repetitive tasks.

For the controls side of engineering, I/O schematics must be created to show the wiring between the control system modules (PLC cards or DCS modules) and the final control devices.  These drawings are generally created in these days of CAD by building base templates for each type of card used, copying over as required, and manually editing each drawing to show the correct device, wire numbers, power wiring, terminal numbers, etc. This leaves room for errors in re-typing data as well as consistency issues with the information in the I/O list.  It is not unusual to have as many as 500 of these drawings for a large project. 

Since it is common to build an I/O or instrument list for each job it makes sense to try and utilize this information as much as possible, entering it once and using many times over.  This ensures that all documents have the same tagging and description for these items.  It also allows pertinent information to be added, such as, rack/slot/point, address, and card type for each device, creating a database instead of just a list.  Once this is done the next step can be taken…. using an intelligent software package to automatically populate the I/O drawings with this information.

The Venture Engineering I&E group has been using AutoCAD Electrical to do just that.  This package allows generation of I/O schematics from a spreadsheet or other database format.  This method uses AutoCAD’s parametric drawing features to draw the I/O module and rungs, place the control devices, determine the card type, and fill in the wire numbers, terminals, and tag information. Once the data is mapped and the project is configured (this can take time and many iterations to get the desired output), the process is started. This package can progress through multiple drawings and card types, reading data from the spreadsheet to build each drawing.  Typically a drawing can be completed in less than a minute.  These drawings do require further manual editing, but between 50% and 90% of the drawing can be completed automatically.  This translates to time savings and an improvement in drawing information quality and consistency.

To learn more about Venture’s capabilities in this regard, please contact Mr. Alex Ussia, Manager – Electrical/Controls Group at 412-231-5890, ext. 306.

More than $5 billion in federal R&D tax credit benefits are given out annually.  That’s worth restating….more than $5 billion.

While the tax credit is expired, an increasing amount of research funding is being committed to countries such as Ireland, China and Canada with more attractive R&D tax incentives luring research jobs away from the United States

But unlike what you might think of as an R&D expense, a taxpayer is actually allowed to claim credit for qualified research expenditures (QREs) — costs associated with investments in innovation and improvements that go well beyond product R&D. For example, investments made in process improvements may qualify, and many manufacturers invest far more in improving their processes than in developing products. Another example is wages paid to line employees involved in research activities. Suppose an employee spent a month investigating ways to achieve an improvement (like evaluation of low emissions processes). The employee’s wages may be considered a QRE. Other areas in which QREs often hide in the company include quality assurance, engineering, product design, and in-house software development.

While not every dollar spent on R&D is recoverable by this credit, for many companies, their investment in R&D activities yield returns of up to six and one half percent (6.5%) in the form of a federal tax credit. And in some states (California), there are even additional state tax credits.

So who does this affect?  Obviously, just about any U.S. based manufacturer.  So while Congress spends the next several weeks/months arguing over off-shore drilling, all those folks that make their living doing R&D will simply hold their breath and wait (like they’ve done 12 times in the past), and hope Congress gets it right one more time and reinstitutes the R&D Tax Credit.  Otherwise, Ireland, China and Canada will be very happy indeed!

Gas exploration today not only requires better reservoir knowledge and superior drilling methods, but also highly targeted completion technologies. Marcellus Shale Play developers are looking at ways to improve their use of precious water assets to support not only multi-stage fracturing, but also well completion efficiencies and improved water conservation.

A gallon of water involved in fraccing has an interesting journey. First it receives a mixture of chemical additives: a friction reducer (a polymer to reduce the viscosity of the water and improve its flowability so it’s easier to pump down the well), a special grade of light sand, and a proprietary gel that helps to carry the sand down into the well. This fraccing fluid is injected into a gas hole at a high flow rate and pressure to break up the formation, increasing the permeability of the rock and helping the gas flow toward the surface. As the water cracks the rock formation, it deposits the sand. As the fractures try to close, the sand keeps them propped open. Fraccing typically occurs once when a well is newly drilled, and again after a couple of years when the rate of gas flow begins to decline.

Underground, the fraccing fluid picks up other contaminants present in the rock formation, including barium, calcium bicarbonate, iron, magnesium sulfate, sodium chloride, and strontium.

Each gas well in the Marcellus Shale uses two- to four- million gallons of water for drilling and fracturing and even more if the well must be re-fractured.

As little as 25 percent and as much as 100 percent of the fracture water returns to the surface. This water, often referred to as flow-back water, contains hydrocarbons, salts, dissolved solids, etc. The first flow-back water has a salt content of only between 1,500 and 2,000 parts per million, but the longer the water remains in the Marcellus Shale, the saltier it becomes. By the end of the first week, the salt content can reach 45,000 parts per million. Sea water averages between 10,000 and 35,000 parts per million. The high salt content makes the water highly corrosive to metals and harmful to land, vegetation, and other living organisms.

Some water continues to flow out of gas wells once they are in production. This water is referred to as produced water.  Some wells may indeed have more produced water than flowback water.

A typical Marcellus well development will involve approximately 30,000 barrels (1.26 MG) of flowback.  The present philosophy is to send this flowback, as well as produced water to off-site treatment and disposal that may be many, many miles away, requiring a fleet of some 300 vehicles to haul the flowback water to an acceptable treatment facility.  Furthermore, the current off-site treatment and disposal capacity in Western Pennsylvania is severely lacking.  Furthermore, in May of 2008, the PA DEP sent formal letters to all of the publically owned treatment works (POTWs) explicitly outlining that they were prohibited from taking this waste stream without a rigorous permitting step, if at all.

Under current off-site disposal philosophy, this flowback water is not recycled.  Millions of gallons of natural water resources are lost.  For every well, the estimated 300 transport trucks will also release an estimated 40 tons of CO2 emissions into the environment.  These transport trucks make hundreds of round trips a day, congesting traffic flow in the surrounding community and deteriorating roads and highways.  In addition, at the current price of diesel, significant cost impact is realized via this current philosophy.  Off-site treatment is estimated to cost between $0.03 and $0.05 per gallon.

The solution to off-site disposal is on-site treatment and reuse.  An estimated 50% – 60% total savings can be realized by treating and reusing flowback and produced water on-site.  There are a number of on-site treatment options worth considering including evaporation/crystallization, advanced oxidation, membrane filtration, etc.  A few of these technologies are discussed in more detail below.

At Venture, we are working with our clients to determine the most economically viable treatment option for each site.  Site factors such as available power and final water quality are often the determinant in treatment selection.  After determining the most economical on-site treatment solution, Venture designs (using 3D AutoCAD Inventor) mobile skids that can be deployed directly to the well-site to improve water recovery, reduce environmental impact, eliminate hauling costs, and drastically reduce off-site treatment costs.  Further, because the treatment and recycle plant is mobile, it can be moved and reused at multiple well sites, and requires far less time to permit and install (since it is not a permanent facility).

On-site treatment technologies have proven capable of recovering between 70% – 80% of the initial water to potable water standards and made immediately available for reuse in the frac process.  The remaining 20% – 25% is very brackish and considered brine water.  In addition produced water has even higher salt concentrations than flowback.  Some technologies can further treat the brine water, increasing recoverability by as much as 24%.  In most cases, this recovered brine water cannot achieve potable water standards, but can sufficiently be cleaned for other on-site or off-site uses as ‘process water’.  In other cases, the brine water is simply sent for off-site treatment and disposal.  The economics here are primarily distance from a treatment facility with available capacity to undertake your development.

On-Site Flowback/Produced Water Treatment Alternatives

Advanced Oxidation Process

The advanced oxidation process (AOP) is successfully used to decompose many hazardous chemical compounds to acceptable levels, without producing additional hazardous by-products or sludge which require further handling. The term advanced oxidation processes refers specifically to processes in which oxidation of organic contaminants occurs primarily through reactions with hydroxyl radicals. AOPs usually refer to a specific subset of processes that involve O3, H2O2, and/or UV light.  The most widely applied advanced oxidation processes (AOP) have been:

• Peroxide/ultraviolet light (H2O2/UV),
• Ozone/ultraviolet light (O3/UV),
• Hydrogen peroxide/ozone (H2O2/O3)
• Hydrogen peroxide/ozone/ultraviolet (H2O2/O3/UV) processes.
• Ozone/Ultrasonic cavitation

Advantages of Advanced Oxidation Processes

• Rapid reaction rates
• Small foot print
• Potential to reduce toxicity and possibly complete mineralization of organics treated
• Does not concentrate waste for further treatment with methods such as membranes
• Does not produce materials that require further treatment such as “spent carbon” from activated carbon adsorption
• Non selective pathway allows for the treatment of multiple organics at once

Disadvantages of Advanced Oxidation Processes

• Capital Intensive
• Complex chemistry must be tailored to specific application
• For some applications quenching of excess peroxide is required

Mechanical Vapor Recompressor Evaporation/Crystallization

A vapor-compression evaporator, like most evaporators can make reasonably clean water from any water source. In a salt crystallizer, for example, a typical analysis of the resulting condensate shows a typical content of residual salt not higher than 50 ppm or, in a different concept, not higher than 10 μS/cm. This results in a drinkable water, if the other sanitary requirements are fulfilled.

For economic reasons evaporators are seldom operated on low-TDS water sources. Those applications are filled by reverse osmosis or membranes.  However, vapor compression chiefly differs from these thanks to its ability to make clean water from saturated or even crystallizing brines with total dissolved solids (TDS) up to 650,000 mg/L. Membranes and RO systems can make clean water from sources no higher in TDS than approximately 35,000 mg/L.

A mechanical vapor recompression evaporator system is similar to a conventional steam heated, single-effect evaporator, except that the vapor released from the boiling solution is compressed in a mechanical compressor. Compression raises the pressure and saturation temperature of the vapor so that it may be returned to the evaporator steam chest to be used as heating steam. The latent heat of the vapor is used to evaporate more water instead of being rejected to cooling water in a condenser. The compressor provides energy to the vapor that increases in pressure and temperature, thereby recycling the evaporated water into usable steam to meet the evaporative load of the incoming fluid. This reduces the steam needed to meet the evaporative load of the overall system. The energy or driving force for pressure increase is provided through shaft horsepower.

In order to maximize the investment in on-site treatment technologies, a mobile solution is necessary.  Mobile MVR’s are possible within the footprint of a traditional MVR evaporator.  Because the units can be skid-mounted and designed for highway transport on low-boy trailers, they don’t require special permitting and can easily be moved from well to well.

All that is needed in addition to the process skids are interconnecting pipes and electrical connections, and a small spark-ignited generator set.   This type of set-up would eliminate the need for any external source of electric power, as natural gas, drawn directly from the well, is used to operate the compressor and to drive the generator, which produces electricity to power the pumps, instruments, and controls.

When treatment at one site is finished, the operators can drain the system, load it on the trucks with a crane, haul it to a new site, and have it set up within a couple of days.

Summary

There are a number of challenges facing development of the Marcellus shale gas, including siting, permitting, drilling challenges, access to pipelines, etc.  However, water acquisition and disposition should not be one of them. 

At Venture, we are confident that an on-site treatment facility similar to one of the above would save significant time and money for any development.  Because Venture Engineering is not an equipment supplier/dealer, we have the ability to look at each development with an unbiased opinion on technology.  We evaluate each site and match the technology the best fits the situation, even, in some cases, if that means that off-site treatment is indeed the least cost alternative. 

For more information on Venture Engineering’s process engineering capabilities, please contact Travis Buggey at 412-231-5890, ext. 325.  Or visit us on the web at www.ventureengr.com .