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This paper investigates the strategic pricing behavior of a leader in a two-person, noncooperative game when profits depend on the purchasing response of a follower who not only reacts to changing prices instantaneously, but also builds long-lived consumption infrastructure that affects future demand. As an application of such a system, we formulate the relationship between these players in the natural gas and electricity generation industries as a bilevel problem. The leader is a natural gas producer whose objective is to maximize profit; the follower is an electric utility who solves a capacity expansion and dispatch problem with the objective of minimizing the cost of electricity generation and long-run investments. To find solutions, the bilevel problem is reformulated as a mixed-integer linear program by replacing the lower-level player's model with its Karush–Kuhn–Tucker conditions, which are necessary and sufficient for optimality here, and linearizing the upper-level player's objective function using the strong duality conditions of the lower-level problem. After parameterizing the model with publicly available data for Texas, we conduct scenario analyses through 2040, evaluating strategies of the natural gas producer under different policies regarding carbon taxes and incentives for carbon capture and storage (CCS). We then observe how the lower-level player responds to these strategies in terms of the evolution of the generation mix, added capacity, and CO 2 emissions. We also quantify the effects of strategic pricing by running scenarios where natural gas prices are fixed. Key findings include: (1) different levels of carbon tax and CCS incentive can have non-monotonic effects on the optimal natural gas price and producer profit, (2) effects of CCS incentives can spill over to technologies without CCS, and (3) omission of strategic pricing from the model not only decreases the profit for the producer but also can increase the costs for the electricity sector. • Bilevel model for interaction between natural gas producer and electric utility. • Carbon policy effects on electricity capacity mix, generation mix, and CO 2 emissions. • Effectiveness of different reformulations of bilevel programming problems. • Demonstration of how strategic natural gas pricing affects carbon policy outcomes. [ABSTRACT FROM AUTHOR]

• Integrated techno-economic assessment of the hydrogen value chain in the Permian Basin, spanning production, storage, and transportation. • Identified cost benefits in feedstock and tax credits for Permian-based hydrogen, balanced by transport expenses to Houston. • Scaling up to 412,000 metric tons/year can counterbalance transportation costs, positioning the Permian Basin competitively in the hydrogen market. This paper investigates the untapped potential of the Permian Basin, a multifaceted energy axis in Texas and adjoining states, in the emerging era of decarbonization. Aligned with current policy directives on regional hydrogen hubs, this study explores the viability of developing a hydrogen energy hub in the Permian Basin, thereby producing low-carbon intensity hydrogen from natural gas in the Basin and transporting it to the Greater Houston area. Diverging from existing literature, this study provides an integrated techno-economic evaluation of the entire hydrogen value chain in the Permian Basin, encompassing production, storage, and transportation. Furthermore, it comparatively analyzes the scenario of interest against an optimized base scenario, thereby underlining comparative advantages and disadvantages. The paper concludes that the delivered cost of Permian-based low-carbon intensity hydrogen to the Greater Houston area is $1.85/kg, benchmarked to the scenario, with hydrogen produced close to the Greater Houston area and delivered at $1.42/kg. Our findings reveal that Permian-based low-carbon intensity hydrogen production can achieve cost savings in feedstock ($0.25/kg) and potentially accrue a higher production tax credit due to a shorter gas supply chain to production ($0.33/kg). Nevertheless, a significant cost barrier is the expense of long-haul pipeline transport ($0.90/kg) from the Permian Basin to Houston as opposed to local production. Despite the obstacles, the study identifies a potential breakeven solution where increasing the production scale to at least 412,000 metric ton per year (about 3 steam-reforming plants) in the Permian Basin can effectively lower costs in the transport sector. Hence a scaled-up production can mitigate the cost difference and establish the Permian Basin as a competitive player in the hydrogen market. In conclusion, a SWOT analysis presents Strengths, Weaknesses, Opportunities, and Threats associated with Permian-based hydrogen production. [ABSTRACT FROM AUTHOR]

Formaldehyde (HCHO) exposures during a full year were calculated for different race/ethnicity groups living in Southeast Texas using a chemical transport model tagged to track nine emission categories. Petroleum and industrial emissions were the largest anthropogenic sources of HCHO exposure in Southeast Texas, accounting for 44% of the total HCHO population exposure. Approximately 50% of the HCHO exposures associated with petroleum and industrial sources were directly emitted (primary), while the other 50% formed in the atmosphere (secondary) from precursor emissions of reactive compounds such as ethylene and propylene. Biogenic emissions also formed secondary HCHO that accounted for 11% of the total population-weighted exposure across the study domain. Off-road equipment contributed 3.7% to total population-weighted exposure in Houston, while natural gas combustion contributed 5% in Beaumont. Mobile sources accounted for 3.7% of the total HCHO population exposure, with less than 10% secondary contribution. Exposure disparity patterns changed with the location. Hispanic and Latino residents were exposed to HCHO concentrations +1.75% above average in Houston due to petroleum and industrial sources and natural gas sources. Black and African American residents in Beaumont were exposed to HCHO concentrations +7% above average due to petroleum and industrial sources, off-road equipment, and food cooking. Asian residents in Beaumont were exposed to HCHO concentrations that were +2.5% above average due to HCHO associated with petroleum and industrial sources, off-road vehicles, and food cooking. White residents were exposed to below average HCHO concentrations in all domains because their homes were located further from primary HCHO emission sources. Given the unique features of the exposure disparities in each region, tailored solutions should be developed by local stakeholders. Potential options to consider in the development of those solutions include modifying processes to reduce emissions, installing control equipment to capture emissions, or increasing the distance between industrial sources and residential neighborhoods.

Natural gas flaring is a common practice employed in many United States (U.S.) oil and gas regions to dispose of gas associated with oil production. Combustion of predominantly hydrocarbon gas results in the production of nitrogen oxides (NOx). Here, we present a large field data set of in situ sampling of real world flares, quantifying flaring NOx production in major U.S. oil production regions: the Bakken, Eagle Ford, and Permian. We find that a single emission factor does not capture the range of the observed NOx emission factors within these regions. For all three regions, the median emission factors fall within the range of four emission factors used by the Texas Commission for Environmental Quality. In the Bakken and Permian, the distribution of emission factors exhibits a heavy tail such that basin-average emission factors are 2-3 times larger than the value employed by the U.S. Environmental Protection Agency. Extrapolation to basin scale emissions using auxiliary satellite assessments of flare volumes indicates that NOx emissions from flares are skewed, with 20%-30% of the flares responsible for 80% of basin-wide flaring NOx emissions. Efforts to reduce flaring volume through alternative gas capture methods would have a larger impact on the NOx oil and gas budget than current inventories indicate.

Background: Recent advancements in drilling technology led to a rapid increase in natural gas development (NGD). Air pollution may be elevated in these areas and may vary by drilling type (conventional and unconventional), production volume and gas flaring. Impacts of NGD on paediatric asthma are largely unknown. This study quantifies associations between specific NGD activities and paediatric asthma hospitalizations in Texas.Methods: We leveraged a database of Texas inpatient hospitalizations between 2000 and 2010 at the zip code level by quarter to examine associations between NGD and paediatric asthma hospitalizations, where our primary outcome is 0 vs ≥1 hospitalization. We used quarterly production reports to assess additional drilling-specific exposures at the zip code-level including drilling type, production and gas flaring. We developed logistic regression models to assess paediatric asthma hospitalizations by zip code-quarter-year observations, thus capturing spatiotemporal exposure patterns.Results: We observed increased odds of ≥1 paediatric asthma hospitalization in a zip code per quarter associated with increasing tertiles of NGD exposure and show that spatiotemporal variation impacts results. Conventional drilling, compared with no drilling, is associated with odds ratios up to 1.23 [95% confidence interval (CI): 1.13, 1.34], whereas unconventional drilling is associated with odds ratios up to 1.59 (95% CI: 1.46, 1.73). Increasing production volumes are associated with increased paediatric asthma hospitalizations in an exposure-response relationship, whereas associations with flaring volumes are inconsistent.Conclusions: We found evidence of associations between paediatric asthma hospitalizations and NGD, regardless of drilling type. Practices related to production volume may be driving these positive associations. [ABSTRACT FROM AUTHOR]

Hydrogen (H 2) shows promise as an energy carrier in contributing to emissions reductions from sectors which have been difficult to decarbonize, like industry and transportation. At the same time, flexible H 2 production via electrolysis can also support cost-effective integration of high shares of variable renewable energy (VRE) in the power system. In this work, we develop a least-cost investment planning model to co-optimize investments in electricity and H 2 infrastructure to serve electricity and H 2 demands under various low-carbon scenarios. Applying the model to a case study of Texas in 2050, we find that H 2 is produced in approximately equal amounts from electricity and natural gas under the least-cost expansion plan with a CO 2 price of $30–60/tonne. An increasing CO 2 price favors electrolysis, while increasing H 2 demand favors H 2 production from Steam Methane Reforming (SMR) of natural gas. H 2 production is found to be a cost effective solution to reduce emissions in the electric power system as it provides flexibility otherwise provided by natural gas power plants and enables high shares of VRE with less battery storage. Additionally, the availability of flexible electricity demand via electrolysis makes carbon capture and storage (CCS) deployment for SMR cost-effective at lower CO 2 prices ($90/tonne CO 2) than for power generation ($180/tonne CO 2). The total emissions attributable to H 2 production is found to be dependent on the H 2 demand. The marginal emissions from H 2 production increase with the H 2 demand for CO 2 prices less than $90/tonne CO 2 , due to shift in supply from electrolysis to SMR. For a CO 2 price of $60/tonne we estimate the production weighted-average H 2 price to be between $1.30–1.66/kg across three H 2 demand scenarios. These findings indicate the importance of joint planning of electricity and H 2 infrastructure for cost-effective energy system decarbonization. • Flexibility from electrolytic H 2 production enables more renewable integration. • Carbon capture occurs at lower CO 2 prices for production of H 2 than electricity. • Electrolytic H 2 production is dominant for CO 2 prices of $30–60/tonne or more. • Increased H 2 demand favors natural gas based H 2. • Emissions are less than 1.2 kg CO 2 /kg H 2 for CO 2 prices of $90/tonne or more. [ABSTRACT FROM AUTHOR]

Growth in unconventional oil and gas development (UOGD) in the United States has increased airborne emissions, raising environmental and human health concerns. To assess the potential impacts on air quality, we deployed instrumentation in Karnes City, Texas, a rural area in the middle of the Eagle Ford Shale. We measured several episodes of elevated Cl 2 levels, reaching maximum hourly averages of 800 ppt, the highest inland Cl 2 concentration reported to date. Concentrations peak during the day, suggesting a strong local source (given the short photolysis lifetime of Cl 2 ) and/or a photoinitiated production mechanism. Well preproduction activity near the measurement site is a plausible source of these high Cl 2 levels via direct emission and photoactive chemistry. ClNO 2 is also observed, but it peaks overnight, consistent with well-known nocturnal formation processes. Observations of organochlorines in the gas and particle phases reflect the contribution of chlorine chemistry to the formation of secondary pollutants in the area. Box modeling results suggest that the formation of ozone at this location is influenced by chlorine chemistry. These results suggest that UOGD can be an important source of reactive chlorine in the atmosphere, impacting radical budgets and the formation of secondary pollutants in these regions.

Objective: To assess associations between unconventional natural gas development (UGD) and perinatal outcomes. Methods: We conducted a retrospective birth cohort study among 158,894 women with a birth or fetal death from November 30, 2010-November 29, 2012 in the Barnett Shale, in North Texas. We constructed three UGD-activity metrics by calculating the inverse distance-weighted sum of active wells within three separate geographic buffers surrounding the maternal residence: ≤½, 2, or 10-miles. We excluded women if the nearest well to her residence was >20 miles. Metrics were categorized by tertiles among women with ≥1 well within the respective buffer; women with zero wells ≤10 miles (the largest buffer) served as a common referent group. We used logistic or linear regression with generalized estimating equations to assess associations between UGD-activity and preterm birth, small-for-gestational age (SGA), fetal death, or birthweight. Adjusted models of fetal death and birthweight included: maternal age, race/ethnicity, education, pre-pregnancy body mass index, parity, smoking, adequacy of prenatal care, previous poor pregnancy outcome, and infant sex. Preterm birth models included all of the above except parity; SGA models included all of the above except previous poor pregnancy outcome. Results: We found increased adjusted odds of preterm birth associated with UGD-activity in the highest tertiles of the ½- (odds ratio (OR) = 1.14; 95% confidence interval 1.03, 1.25), 2- (1.14; 1.07, 1.22), and 10-mile (1.15; 1.08, 1.22) metrics. Increased adjusted odds of fetal death were found in the second tertile of the 2-mile metric (1.56; 1.16, 2.11) and the highest tertile of the 10-mile metric (1.34; 1.04–1.72). We found little indication of an association with SGA or term birthweight. Conclusions: Our results are suggestive of an association between maternal residential proximity to UGD-activity and preterm birth and fetal death. Quantifying chemical and non-chemical stressors among residents near UGD should be prioritized. [ABSTRACT FROM AUTHOR]

Starting around 2008, there was rapid expansion of oil and natural gas (ONG) production into more heavily populated areas within the Dallas-Fort Worth metroplex in the Barnett Shale region of Texas. This colocation raised concerns regarding the effect of ONG activities on chemical levels in the air. In the current study, we examined the potential impacts of ONG activity on the types and concentrations of chemicals in ambient air in the Barnett Shale. Volatile organic compound (VOC) concentrations from 6-12 years (2008-2019) of hourly ambient air monitoring data from 15 monitors (4 monitors had ≥ 10 years of data) were compared to several metrics of ONG activity (number of active wells, natural gas production, condensate production) within a 2-mile radius of each monitor. Monitoring sites were also classified into urban, suburban, and rural areas as a surrogate for nearby vehicular emission sources. Analyses of this huge dataset showed that both peak and mean chemical concentrations of lighter alkane hydrocarbons (e.g., ethane) were most impacted by the number of gas wells. Levels of heavier alkanes (e.g., pentane) were increased by condensate production and at monitors located in areas with greater urbanicity, and therefore higher vehicular emissions. The levels of unsaturated alkynes (e.g., ethylene) were entirely driven by urbanicity and were unaffected by nearby ONG activity. The same pattern was seen with the ratio of iso:n-pentane, which is contrary to the findings of others and suggests an area for future research. Aromatic hydrocarbons were impacted by multiple emissions sources and did not show the same patterns as non-aromatic VOCs. No VOC concentrations were at levels of concern for human health or odor based on comparison to Texas air monitoring comparison values. Overall, ONG activities impact air quality, but this must be evaluated in the context of other emission sources such as automobiles., Competing Interests: Declaration of Competing Interest The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper., (Copyright © 2023 The Authors. Published by Elsevier Ltd.. All rights reserved.)

Oil and natural gas operations have continued to expand and move closer to densely populated areas, contributing to growing public concerns regarding exposure to hazardous air pollutants. During the Barnett Shale Coordinated Campaign in October, 2013, ground-based whole air samples collected downwind of oil and gas sites revealed enhancements in several potentially toxic volatile organic compounds (VOCs) when compared to background values. Molar emissions ratios relative to methane were determined for hexane, benzene, toluene, ethylbenzene, and xylene (BTEX compounds). Using methane leak rates measured from the Picarro mobile flux plane (MFP) system and a Barnett Shale regional methane emissions inventory, the rates of emission of these toxic gases were calculated. Benzene emissions ranged between 51 ± 4 and 60 ± 4 kg h-1. Hexane, the most abundantly emitted pollutant, ranged from 642 ± 45 to 1070 ± 340 kg h-1. While observed hydrocarbon enhancements fall below federal workplace standards, results may indicate a link between emissions from oil and natural gas operations and concerns about exposure to hazardous air pollutants. The larger public health risks associated with the production and distribution of natural gas are of particular importance and warrant further investigation, particularly as the use of natural gas increases in the United States and internationally. [ABSTRACT FROM AUTHOR]

The article offers information on an online survey, which brings the general public into the policy debate over shale gas development, in Pennsylvania and Texas as of January 2014. Topics discussed include general public being the most important stakeholder in the policy debate, organization Resources for the Future' (RFF) Center for Energy Economics and Policy's (CEEP) assessment of the environmental risks, and public support for shale gas development.

In the last decade, hydraulic fracturing for natural gas has exploded on the Barnett Shale in Texas, now home to the most intensive hydraulic tracking and gas production activities ever undertaken in a densely urbanized area. Yet, the debate is ongoing as to whether the explosive growth of gas industry operations poses a serious risk to public health and the environment. Concerns include the possibility that chemicals injected, naturally occurring substances disrupted, or toxins spiffed at the surface may contaminate soil or make their way into drinking water supplies. Particularly problematic are the endocrine-disrupting chemicals, which are known to cause latent abnormalities at infinitesimally small levels of exposure. Health effects may not surface for decades and could affect future generations. Although the gas industry is quick to claim that there are no proven cases of groundwater contamination related to hydraulic fracturing, local concerns are far more complicated. Leaks, spills, illegal dumping, and the attendant risk of soil contamination, ground and surface water pollution cannot be denied. Yet, a close review of federal and state regulatory provisions related to chemical reporting, monitoring, disclosure, tracking ,and cleanup reveal a fundamental problem: quality monitoring data is scarce. Moreover, information is not available on the hazards, or even the identity of all the potentially problematic chemicals associated with gas industry operations. Texas has adopted chemical disclosure requirements, but they are very limited, and unless trade secret claims are challenged, they are largely optional. There arc exceptions requiring disclosure of trade secrets to emergency medical personnel but not to toxicologists or epidemiologists. There are no exceptions for incidents where hydraulic fracturing chemicals are spilled on properly that have not (yet) resulted in identifiable health effects. There are no provisions allowing disclosure of trade secrets for the purpose of conducting sampling, assessing hazards, designing protective measures or engineering controls, or conducting studies to determine health effects. Even where chemicals associated with gas industry operations have been disclosed, they may still slip by undetected given limited surface and drinking water quality monitoring systems that focus narrowly on short and dated chemical lists. There is no comprehensive or systematic monitoring for industrial chemicals in groundwater. Given the difficult burden of proof, common law is also unlikely to serve as a reliable vehicle to identify contamination and hold industry accountable. The difficulty of toxic tort litigation, the ad hoc nature of litigation, and the veil of secrecy following settlement agreements requiring confidentiality all argue in favor of strong regulations governing gas industry operations. Gas-industry exemptions from federal regulation and a weak state regulatory system that relies on vague standards reminiscent of the early days of environmental law leave Texas cities at the forefront of the regulatory effort. After evaluating the federal and state regulatory framework, this Article reviews local regulatory efforts and concludes by discussing reasonable regulatory approaches to further strengthen and address soil and water contamination concerns. These approaches include adopting significant setbacks from the floodplain, a manifest system for tracking waste, monitoring, and reporting requirements, and clear standards to govern cleanup operations based on planned and restricted future land use. This Article also explores the possibility that local governments could adopt additional chemical disclosure requirements and share in the cost of any subsequent trade-secret litigation. Finally this Article discusses constitutional takings issues and concludes that public health concerns may outweigh the burden on property rights. [ABSTRACT FROM AUTHOR]

Between November 2009 and September 2011 the EarthScope USArray program deployed ∼25 temporary seismograph stations on a 70-km grid in south-central Texas between 27°N–31°N and 96°W–101°W. This area includes the Eagle Ford Shale. For decades this geographic region has produced gas and oil from other strata using conventional methods, but recent developments in hydrofracturing technology has allowed extensive development of natural gas resources from within the Eagle Ford. Our study surveys small-magnitude seismic events and evaluates their correlation with fluid extraction and injection in the Eagle Ford, identifying and locating 62 probable earthquakes, including 58 not reported by the U.S. Geological Survey. The 62 probable earthquakes occur singly or in clusters at 14 foci; of these foci, two were situated near wells injecting recently increased volumes of water; eight were situated near wells extracting recently increased volumes of oil and/or water; and four were not situated near wells reporting significant injection/extraction increases. Thus in this region, while the majority of small earthquakes may be triggered/induced by human activity, they are more often associated with fluid extraction than with injection. We also investigated the 20 October 2011 Fashing earthquake—the largest historically reported earthquake in south-central Texas—that occurred two weeks after the removal of the temporary USArray stations. A field study indicated that the highest-intensity (MMI VI) region was about 10 km south of 2010–2011 foreshock activity, and that there were no high-volume injection wells within 20 km of the MMI V–VI region or the foreshocks. However, the 20 October 2011 earthquake did coincide with a significant increase in oil/water extraction volumes at wells within the MMI V–VI region, and this was also true for previous earthquakes felt at Fashing in 1973 and 1983. In contrast, our study found significant increases in injection prior to an mbLG3.6 20 July 1991 earthquake near Falls City, Texas. Thus the Eagle Ford geographic region, with seismic activity associated both with extraction and injection, appears to be more complex than the Barnett Shale of northeast Texas, where a similar survey found possible correlations only with fluid injection. [ABSTRACT FROM AUTHOR]

Large-scale U.S. dependence on thermoelectric (steam electric) generation requiring water for cooling underscores the need to understand controls on this water use. The study objective was to quantify water consumption and withdrawal for thermoelectric generation, identifying controls, using Texas as a case study. Water consumption for thermoelectricity in Texas in 2010 totaled ∼0.43 million acre feet (maf; 0.53 km³), accounting for ∼4% of total state water consumption. High water withdrawals (26.2 maf, 32.3 km³) mostly reflect circulation between ponds and power plants, with only two-thirds of this water required for cooling. Controls on water consumption include (1) generator technology/thermal efficiency and (2) cooling system, resulting in statewide consumption intensity for natural gas combined cycle generators with mostly cooling towers (0.19 gal/kWh) being 63% lower than that of traditional coal, nuclear, or natural gas steam turbine generators with mostly cooling ponds (0.52 gal/kWh). The primary control on water withdrawals is cooling system, with ∼2 orders of magnitude lower withdrawals for cooling towers relative to once-through ponds statewide. Increases in natural gas combined cycle plants with cooling towers in response to high production of low-cost natural gas has greatly reduced water demand for thermoelectric cooling since 2000. [ABSTRACT FROM AUTHOR]

Decarbonizing power systems is a critical component of climate change mitigation, which can have public health cobenefits by reducing air pollution. Many studies have examined strategies to decarbonize power grids and quantified their health cobenefits. However, few of them focus on near-term cobenefits at community levels, while comparing various decarbonization pathways. Here, we use a coupled power system and air quality modeling framework to quantify the costs and benefits of decarbonizing the Texas power grid through a carbon tax; replacing coal with natural gas, solar, or wind; and internalizing human health impacts into operations. Our results show that all decarbonization pathways can result in major reductions in CO 2 emissions and public health impacts from power sector emissions, leading to large net benefits when considering the costs to implement these strategies. Operational changes with existing infrastructure can serve as a transitional strategy during the process of replacing coal with renewable energy, which offers the largest benefits. However, we also find that Black and lower-income populations receive disproportionately higher air pollution damages and that none of the examined decarbonization strategies mitigate this disparity. These findings suggest that additional interventions are necessary to mitigate environmental inequity while decarbonizing power grids.

• Commercial scale designs for a 2nd generation solvent regeneration system has been presented at NGCC conditions. • Base case design benefits from coarse packing in stripper, two stripper trains, small heat exchangers, and low energy price at the host site. • Advancements to the design have been suggested to reduce both capital and operating costs. • Equivalent work analysis suggests that the advanced design is better than existing stripper configurations at low heat exchanger size. • Operational advantages and limitations have been compared between the base case design and advanced design. The Texas Carbon Management Program is conducting a Front-End Engineering Design (FEED) for Piperazine with the Advanced Stripper™ (PZAS™) at a natural gas combined cycle power plant in west Texas. This paper presents the design of the advanced stripper system with an emphasis on the selection of packing type, packing height, column diameter, and heat exchanger size, demonstrates the effect of ambient temperature swing on the regeneration energy requirement, and investigates two alternate process configurations that provide better energy performance than PZAS™. The design uses 2 stripper trains, and each train uses two cold cross exchangers, one hot cross exchanger, a stripper column, a CO 2 exchanger, and a condenser. Each column consists of two sections of random packing with RSR 2 packing at the top and RSR 3 packing at the bottom, with a total packed height of 7.5 m. The cold exchanger was designed with an NTU of 6, the hot exchanger with an NTU of 2, and the CO 2 exchanger with an NTU of 5. At 0.4 rich loading and 0.2 lean loading, this design resulted in a heat duty of 2.85 GJ/tonne CO 2. The heat duty can vary up to 3.1 GJ/tonne CO 2 due to lower rich loading at higher summer temperature, but the absolute steam requirement is 8–15% lower in the summer. An alternate design, PZAS with hot rich bypass, is proposed, which can reduce the equivalent work of stripping by 1.5–3.5% compared to PZAS at low heat exchanger size, due to a reduction in stripper driving force. Using a hot rich bypass increases the vapor fraction of the total rich bypass stream from 0.3 to 1 mol% compared to using the warm rich bypass, which also contributes to a reduction in lost work in the column. PZAS with hot rich bypass outperforms PZAS in energy requirement below a packing height of 15 m, but fails to do so above 15 m of packing due to a column pinch that results in little change in LMTD of the column. PZAS with hot rich bypass has the potential to minimize capital cost in addition to reducing energy requirement as it requires less packing to strip CO 2 than PZAS and requires only one cross exchanger with 8 heat transfer units. [ABSTRACT FROM AUTHOR]

• Creative absorber design using pump-around intercooling for a 460 MW NGCC power plant. • Reduced absorber capital cost by using 7.6 m packing and eliminating DCC and trim cooler. • Improved performance by using low pump-around temperature and high circulation rate. • Flexible absorber operation strategy for various ambient temperatures. The Texas Carbon Management Program is preparing a Front-End Engineering Design (FEED) of the PZASTM (Piperazine with the Advanced StripperTM) for CO 2 capture at a natural gas combined cycle power plant in West Texas. This paper develops the absorber design for the capture system and studies the operational strategies of the absorber in response to ambient temperature swing. The design uses 2 absorber trains, and each train integrates absorption and a water-wash section in one column. Each column has a cross-section area of 174 m2 and consists of 3 sections of MellapakPlus® 252Y structured packing. Packing heights for each section are 3, 4.9, and 2.7 m from top to bottom. A pump-around intercooler applied at the bottom bed circulates solvent and eliminates the direct contact cooler. The baseline CO 2 removal rate is 90% and will vary between 78% and 90% with ambient temperature. The system uses air cooling to eliminate cooling water usage. The water balance in the system will be managed by operating the water wash at a high circulation rate (1300 kg/h) to condense water during the night and make up for water loss during the day. The proposed design reduces the capital cost of the absorber column by minimizing the packing height and eliminating the direct contact cooler (DCC), and improves the energy cost by lowering the pump-around intercooling temperature and increasing the pump-around rate. [Display omitted] [ABSTRACT FROM AUTHOR]