The discovery of new shale formations throughout the world and the development of new drilling technologies have increased natural gas production and prompted government agencies to instigate tighter air-pollution control regulations on processing operations. Unfortunately, meeting environmental regulations is not a profit-generating endeavor. Simply put, the time and money spent on protecting air, water and land does not help midstream companies produce more natural gas to ensure the nation’s energy security. As a result, saving money while meeting or exceeding regulations should be on every midstream company’s wish list.
Much like other industries, oil and gas producers are often required by the Environmental Protection Agency(EPA) to obtain a Title V permit, the objective of which is to prevent untreated air pollutants from entering the atmosphere. In addition to their harmful effects on plants and trees, these pollutants, known as volatile organic compounds (VOCs) and hazardous air pollutants (HAPs) are known to cause respiratory ailments, heart conditions, birth defects, nervous system damage and cancer in humans.
Under the Clean Air Act, most companies with the potential to release more than 10 tons of a single VOC or HAP during a one-year period, or 25 tons of multiple compounds, must install either a pollution-control device or the maximum achievable control technology (MACT). Many of the pollution control devices currently used to abate these emissions also emit significant amounts of carbon dioxide (CO2) and nitrous oxides (NOX). With mandatory greenhouse gas (GHG) reporting on the horizon, processors could soon be paying for the carbon emissions generated by some of these pollution control systems, adding to the capital and operating costs associated with regulatory compliance.
MIDSTREAM’S ABATEMENT HISTORY
A number of production techniques and processes used by midstream companies are, or soon will be, regulated as emission sources. From stationary combustion engines to amine systems, the industry is facing some fairly strict legislation.
One area of great concern is amine tail-gas treatment. Amine systems are a very common and critical component used by natural gas-processing facilities to remove acid gases, CO2 and hydrogen sulfide (H2S) from the wellhead. This is accomplished by running the gas through a column with amine liquid flowing in the opposite direction, stripping acids from natural gas and absorbing them into the liquid. The natural gas is then sent for processing while the amine is sent to be regenerated. The regeneration process removes the acid gases from the amine solution, allowing it to be reused, but the process creates tail gas. This tail gas, and the means for treating it, offer the latest opportunity for the implementation of new technologies and increased profits.
Thermal and catalytic oxidizers are technologies commonly used on a wide variety of applications where VOC, HAP and odor abatement is required. They destroy harmful emissions through the process of high-temperature combustion. Midstream companies have historically used flares, vapor combustors, direct-fired thermal oxidizers (TOs) or recuperative systems for emission destruction. Applications where these devices are applied range from amine tail-gas treatment, nitrogen rejection units and liquefied natural gas (LNG) processes. The temperature in these systems is maintained somewhere between 1,400°F and 1,800°F so that hydrocarbons are converted to CO2 and water vapor, while the H2S is converted to sulfur dioxides (SO2 and SO3).
When designed properly, these older technologies are fairly dependable, but their effectiveness and efficiency can spark a heated debate. In the case of flares, water is often injected into the device to reduce visible black smoke. This drastically reduces the destruction efficiency-and the EPA is taking note. While TOs and vapor combustors can achieve destruction efficiencies around 99%, they share a common negative aspect with flares: They have a high fuel consumption rate.
Large amounts of fossil fuels are required to bring the air toxins up to proper destruction temperature. Rather than use the heat generated from combustion to preheat incoming pollutants, the energy is simply released into the atmosphere, along with CO as GHGs. Chart A demonstrates just how significant the carbon emissions can be from the various technologies.
ENTER THE RTO
All too often, production facilities take the “no news is good news” approach to their air-pollution control equipment when they really should be chasing the benefits of a “company stays green and saves green” approach. A proven, more fuel-efficient abatement technology, called the regenerative thermal oxidizer (RTO), is now being applied to tail-gas treatment where it was once thought impossible.
What differentiates it from other technologies is its ability to use the proper mix of temperature, residence time (or dwell time), turbulence and oxygen to convert pollutants into carbon dioxide and water vapor, while reusing the thermal energy generated to reduce operating costs. In some cases, emission destruction can occur without any additional natural gas or other supplemental fuel.
VOC and HAP laden process gas is routed into the inlet manifold of the oxidizer, flow control or poppet valves, which then directs this gas along with fresh air for combustion into energy-recovery chambers where it is preheated. The process gas and contaminants are progressively heated in the ceramic media beds as they move toward the combustion chamber.
Once oxidized in the combustion chamber, the hot purified acid gas releases thermal energy as it passes through the media bed in the outlet flow direction. The outlet bed is heated and the gas is cooled so that the outlet gas temperature is only slightly higher than the process inlet temperature. Poppet valves alternate the airflow direction into the media beds to maximize energy recovery within the oxidizer.
Thermal energy recovery (TER) within an RTO can reach 97%, reducing, and in some cases eliminating, the auxiliary fuel requirement. Some gas plants have reported over $500,000 in operating cost savings annually. With destruction capability over 99%, the RTO is not only an efficient alternative for this application, but also very effective. However, careful consideration must be given to the design and materials of construction to avoid corrosion, equipment failures, non-compliance and safety issues.
CASE IN POINT
The midstream division of a large, multinational energy corporation was operating several amine systems around the country with tail-gas treatment. A TO at one of these facilities in the western U. S. had numerous operational problems and extremely high operating costs.
The company asked Anguil Environmental Systems Inc., an oxidizer and air-pollution control systems provider, to evaluate various replacement options. The process data provided showed a tail-gas flow rate of about 15,000 pounds per hour (lbs/hr) or about 2,500 standard cubic feet per minute (SCFM) (4012.5 Nm3/hr), a calorific value of 6 Btu/SCF and 25 parts per million by volume (ppmv) of H2S. After evaluating numerous oxidizer technologies, including TOs and thermal recuperative oxidizers, Anguil determined that the best solution would be an RTO.
Having designed oxidizers for similar corrosive applications, the engineers at Anguil recommended that the RTO be built with special materials of construction and design considerations to combat the presence of both carbonic and sulfuric acid.
Carbonic acid is caused by high CO2 levels combined with a saturated process stream. Sulfuric acid is created when H2S is oxidized and the resulting SO3 combines with water vapor present in the RTO exhaust gas. The amine process exhaust at this midstream operation was inert, or lacking oxygen; therefore, fresh air was required for oxidation.
Heat released from combustion of these hydrocarbons can be very high, so fresh air is also added to keep the system from an over-temperature condition. To eliminate condensation of water vapor of the tail gas inside the RTO, this ambient air is preheated to protect metal surfaces from the inorganic acids condensing.
A unique system utilizing excess heat from the combustion chamber to provide the necessary heat was deployed on this system, further reducing operating costs. The preheat component eliminates the need for additional equipment (gas-fired heater, steam coil) and further minimizes auxiliary fuel consumption. The next step in the corrosion-protection strategy is to implement various stainless-steel alloys on critical components and a corrosion-resistant coating on the inside of the energy-recovery chambers and combustion chamber. The type of stainless steel chosen depends on the presence and concentration of H2S.
The critical components are chosen based on their function within the RTO and their location. These components see exhaust temperatures of up to 600°F, above the limit of corrosion-resistant coatings. The energy recovery chambers and combustion chamber are internally insulated with soft ceramic refractory insulation, limiting the shell temperature (and the maximum temperature to which the coating will be exposed) to 200°F, well below the safe limit of the coating. With the combination of extremely high TER, and the tail-gas calorific value of 6 Btu/SCF, this RTO requires no auxiliary fuel to achieve 99% hydrocarbon and H2S destruction efficiency.
By comparison, a TO or flare designed for the same process gas would consume more than $100 per hour of auxiliary fuel, resulting in an annual fuel cost of more than $750,000. Also, the reduced natural gas consumption results in an additional 2,600 lbs/hr of GHG emissions compared to the RTO.
With the industrial price of natural gas at $6 per thousand cubic feet, and a one-to-one correlation between a cubic foot of natural gas and a cubic foot of CO2 emissions, certified carbon credits could go for about $10 to $30 per metric ton or 1,000 kilograms. This is about 20,000 cubic feet of CO2 on a one-to-one cubic foot to cubic foot basis, then 20,000 cubic feet of natural gas produces one metric ton of CO2.
The credit might be worth $1 per thousand cubic feet of natural gas, or about 15% of the cost, meaning a reduction in natural gas consumption would not only save operating costs but it could, in theory, produce income, assuming a credit can be certified and traded.