This document summarizes a study analyzing the relative price responsiveness of unconventional (shale gas) versus conventional natural gas extraction. It finds that drilling investment, not production from existing wells or completion times, is most responsive to prices. The estimated long-run drilling elasticity is 0.7 for both types of gas. However, because unconventional wells produce on average 2.7 times more gas per well, the long-run supply responsiveness is almost 3 times larger for unconventional gas. Simulation results show unconventional gas production responds more strongly to price changes than conventional production in the long run.
In this project we basically studied scope of this project, its feasibility and market assessment, raw material availability, different routes to produce Syngas and their comparison, process selection and its complete description, its P&ID, and environmental consideration.
The use of Cooking Gas as Refrigerant in a Domestic RefrigeratorIJERA Editor
The application of cooking gas refrigerants in refrigeration system is considered to be a potential way to improve
energy efficiency and to encourage the use of environment-friendly refrigerants. Refrigeration operation has
been met with many challenges as it deals with environmental impact, how it affects humans and how it
contributes to the society in general. Domestic refrigerators annually consume several metric tons of traditional
refrigerants, which contribute to very high Ozone Depletion Potential (ODP) and Global Warming Potential
(GWP). The experiment conducted employs the use of two closely linked refrigerants, R600a (Isobutene) and
cooking gas which is varied in an ideal refrigerant mixture of 150 g of refrigerant and 15 ml of lubricating oil (to
a rating of 40 wt % expected in the compressor). The Laboratory process involved the use of Gas
Chromatography machine to ascertain the values of the mole ratio, molecular weight and critical temperatures.
Prode properties and Refprop softwares were used to ascertain other refrigerant properties of the mixture. The
results indicated that the mixture of R600a with lubricant confirm mineral oil as being the most appropriate for
the operation. The experimental results indicated that the refrigeration system with cooking gas refrigerant
worked normally and was found to attain high freezing capacity and a COP value of 2.159. It is established that
cooking gas is a viable alternative refrigerant to replace R600a in domestic refrigerators. Hence, its application
in refrigerating systems measures up to the current trend on environmental regulations with hydrocarbon
refrigerants
Production of Syngas from biomass and its purificationAwais Chaudhary
This document summarizes a project proposal for a biomass gasification plant in Pakistan. It discusses the motivation, basic chemistry, advantages of syngas, availability of raw materials, effects of temperature and residence time on syngas production, particulate matter, tars, sulfur, nitrogen compounds in biomass gasification. It also describes the gasification process selected, purification of syngas using hot gas cleanup technology, equipment list, environmental considerations, and concludes with recommendations for syngas production from biomass.
PLANT DESIGN FOR MANUFACTURING OF HYDROGEN BY STEAM METHANE REFORMING (SMR)Priyam Jyoti Borah
Steam methane reforming (SMR) is one of the most promising processes for hydrogen production. Several studies have demonstrated its advantages from the economic viewpoint. Nowadays process development is based on technical and economic aspects, however, in the near future; the environmental impact will play a significant role in the design of such processes. In this paper, an SMR process is studied from the viewpoint of overall environmental impact, using an exergoenvironmental analysis. This analysis presents the combination of exergy analysis and life cycle assessment. Components, where chemical reactions occur, are the most important plant components from the exergoenvironmental point of view, because, in general, there is a high environmental impact associated with these components. This is mainly caused by the energy destruction within the components, and this in turn is mainly due to the chemical reactions. The obtained results show that the largest potential for reducing the overall environmental impact is associated with the combustion reactor, the steam reformer, the hydrogen separation unit and the major heat exchangers. The environmental impact in these components can mainly be reduced by improving their exergetic efficiency. A sensitivity analysis for some important exergoenvironmental variables is also presented in the paper.
Synthesis gas, also known as syngas, is a mixture of carbon monoxide and hydrogen. It is primarily produced from natural gas and oil through steam reforming and the water-gas shift reaction. Syngas has many uses as a chemical feedstock and in producing derivatives like methanol and alcohols. Some of the major engineering challenges involved are removing sulfur from hydrocarbon feeds, efficiently supplying heat for the endothermic reforming reactions, preventing carbon formation on catalysts, and absorbing byproducts like carbon dioxide.
The document provides a detailed design report for a redesigned hydrogen production plant. The base case design produces 8,000 kg/hr of pure hydrogen gas using steam methane reforming and pressure swing adsorption. The plant can also flexibly operate at 60% capacity. Total capital investment is $112 million over 2 years. The plant is economically viable with a 9% internal rate of return over 30 years of operation. Gaseous emissions are a concern and various abatement methods are discussed to improve sustainability.
Refrigerants and Their Environmental ImpactSamet Baykul
DATE: 2019.04.15
This is a review of an article which introduces Refrigerants and their environmental impact. The study suggests a substitution an adequate refrigerant for hydro chlorofluorocarbon (HCFC) and hydro fluorocarbon (HFC).
In this project we basically studied scope of this project, its feasibility and market assessment, raw material availability, different routes to produce Syngas and their comparison, process selection and its complete description, its P&ID, and environmental consideration.
The use of Cooking Gas as Refrigerant in a Domestic RefrigeratorIJERA Editor
The application of cooking gas refrigerants in refrigeration system is considered to be a potential way to improve
energy efficiency and to encourage the use of environment-friendly refrigerants. Refrigeration operation has
been met with many challenges as it deals with environmental impact, how it affects humans and how it
contributes to the society in general. Domestic refrigerators annually consume several metric tons of traditional
refrigerants, which contribute to very high Ozone Depletion Potential (ODP) and Global Warming Potential
(GWP). The experiment conducted employs the use of two closely linked refrigerants, R600a (Isobutene) and
cooking gas which is varied in an ideal refrigerant mixture of 150 g of refrigerant and 15 ml of lubricating oil (to
a rating of 40 wt % expected in the compressor). The Laboratory process involved the use of Gas
Chromatography machine to ascertain the values of the mole ratio, molecular weight and critical temperatures.
Prode properties and Refprop softwares were used to ascertain other refrigerant properties of the mixture. The
results indicated that the mixture of R600a with lubricant confirm mineral oil as being the most appropriate for
the operation. The experimental results indicated that the refrigeration system with cooking gas refrigerant
worked normally and was found to attain high freezing capacity and a COP value of 2.159. It is established that
cooking gas is a viable alternative refrigerant to replace R600a in domestic refrigerators. Hence, its application
in refrigerating systems measures up to the current trend on environmental regulations with hydrocarbon
refrigerants
Production of Syngas from biomass and its purificationAwais Chaudhary
This document summarizes a project proposal for a biomass gasification plant in Pakistan. It discusses the motivation, basic chemistry, advantages of syngas, availability of raw materials, effects of temperature and residence time on syngas production, particulate matter, tars, sulfur, nitrogen compounds in biomass gasification. It also describes the gasification process selected, purification of syngas using hot gas cleanup technology, equipment list, environmental considerations, and concludes with recommendations for syngas production from biomass.
PLANT DESIGN FOR MANUFACTURING OF HYDROGEN BY STEAM METHANE REFORMING (SMR)Priyam Jyoti Borah
Steam methane reforming (SMR) is one of the most promising processes for hydrogen production. Several studies have demonstrated its advantages from the economic viewpoint. Nowadays process development is based on technical and economic aspects, however, in the near future; the environmental impact will play a significant role in the design of such processes. In this paper, an SMR process is studied from the viewpoint of overall environmental impact, using an exergoenvironmental analysis. This analysis presents the combination of exergy analysis and life cycle assessment. Components, where chemical reactions occur, are the most important plant components from the exergoenvironmental point of view, because, in general, there is a high environmental impact associated with these components. This is mainly caused by the energy destruction within the components, and this in turn is mainly due to the chemical reactions. The obtained results show that the largest potential for reducing the overall environmental impact is associated with the combustion reactor, the steam reformer, the hydrogen separation unit and the major heat exchangers. The environmental impact in these components can mainly be reduced by improving their exergetic efficiency. A sensitivity analysis for some important exergoenvironmental variables is also presented in the paper.
Synthesis gas, also known as syngas, is a mixture of carbon monoxide and hydrogen. It is primarily produced from natural gas and oil through steam reforming and the water-gas shift reaction. Syngas has many uses as a chemical feedstock and in producing derivatives like methanol and alcohols. Some of the major engineering challenges involved are removing sulfur from hydrocarbon feeds, efficiently supplying heat for the endothermic reforming reactions, preventing carbon formation on catalysts, and absorbing byproducts like carbon dioxide.
The document provides a detailed design report for a redesigned hydrogen production plant. The base case design produces 8,000 kg/hr of pure hydrogen gas using steam methane reforming and pressure swing adsorption. The plant can also flexibly operate at 60% capacity. Total capital investment is $112 million over 2 years. The plant is economically viable with a 9% internal rate of return over 30 years of operation. Gaseous emissions are a concern and various abatement methods are discussed to improve sustainability.
Refrigerants and Their Environmental ImpactSamet Baykul
DATE: 2019.04.15
This is a review of an article which introduces Refrigerants and their environmental impact. The study suggests a substitution an adequate refrigerant for hydro chlorofluorocarbon (HCFC) and hydro fluorocarbon (HFC).
Refrigerant environment and legislative update the future of refrigerants c...omairfarooq
The document discusses global regulations around refrigerants and their environmental impacts. It reviews the Montreal Protocol which phased out ozone depleting substances and indicates the protocol has been successful but work remains. It also discusses the Kyoto Protocol which aims to reduce greenhouse gas emissions. The document identifies indicators for the future of refrigerants, including focusing on total environmental impact rather than just direct effects. It provides examples of likely refrigerant alternatives for different sectors and notes solutions will continue to evolve as equipment innovates to meet energy efficiency demands.
This document summarizes a study that evaluated the performance of a CO2 refrigeration system enhanced with a dew point cooler (DPC). Key findings include:
1) Experiments were conducted on a 20 kW CO2 refrigeration system to characterize its performance with and without a DPC under ambient temperatures above 40°C. The DPC avoided transcritical operation and increased COP by up to 140% compared to the conventional system.
2) A mathematical model was developed and validated experimentally. The model identified the optimum condenser inlet air temperature for each condenser temperature to maximize COP across a range of conditions.
3) An annual case study for Adelaide, Australia found the DPC-enhanced CO2 system could
This is a report on the design of a plant to produce 20 million standard cubic feet per day (0.555 × 106 standard m3/day) of hydrogen (H2) of at least 95% purity from heavy fuel oil (HFO) with an upstream time of 7680 hours/year applying the process of partial oxidation of the heavy oil feedstock.
The document discusses a method for producing synthesis gas (syngas) from gasification of bagasse. Bagasse is a waste product from sugar production that is abundant in India. Syngas produced from bagasse gasification can be used as an alternative fuel source for power generation and other industrial processes. The method involves pyrolyzing bagasse in a free-fall reactor to produce char, and then gasifying the char in a packed bed reactor to produce syngas, which consists mainly of carbon monoxide and hydrogen. Experimental results show that syngas yield increases with higher temperature and smaller bagasse particle size during pyrolysis.
Optimizing Reactor Parameters to Achieve Higher Process Yield in Ex-Situ Oil ...IJERA Editor
Declining worldwide crude oil reserves and increasing energy needs have the attentions focused on developing existing unconventional fossil fuels including oil shale. America’s richest oil shale deposits are found in the Green River Formation of western Colorado, eastern Utah and south-western Wyoming. The current work describes process simulation of an ex-situ oil shale pyrolysis process in a pyrolytic reactor using a novel method involving external and internal heating to increase heat transfer and mixing ratio inside the reactor. Efforts to improve process yield for commercial operation relies on first developing a complete Aspen based process model of a proposed shale refining plant, identifying the key process parameters for the reactor and then optimizing the overall process. Simulation results are compared to earlier experimental data collected from a pilot scale rotary reactor operated by Combustion Resources Inc. (CR). This work identified the critical impact of bed temperature on crude production in such a way that for a bed temperature of less than 400°C, results showed less than 10% conversion in crude production and for bed temperatures between 450 and 500°C, above 90% conversion was achieved. The proposed model consists of four zones including drying, shale reactions, natural gas combustion and gas/oil recovery. Different cases were defined and studied based on various operational conditions. Optimized operational values for the key parameters including reactor temperature, reactor volume and feed rate were given as results to maximum shale oil production.
The document discusses carbon capture technologies that are likely to appear in future phases of carbon capture and storage (CCS) deployment. It provides information on various carbon capture technologies including post-combustion capture using solvents like amines, pre-combustion capture through integrated gasification combined cycle (IGCC) plants, and oxy-fuel combustion. Examples of large-scale CCS projects currently in operation or development are also mentioned, such as the Kemper County energy facility and White Rose CCS project.
Chemical Looping Combustion of Rice HuskIJERA Editor
A thermodynamic investigation of direct chemical looping combustion (CLC) of rice husk is presented in this paper. Both steam and CO2 are used for gasification within the temperature range of 500–1200˚C and different amounts of oxygen carriers. Chemical equilibrium model was considered for the CLC fuel reactor. The trends in product compositions of the fuel reactor, were determined. Rice husk gasification using 3 moles H2O and 0 moles CO2 per mole carbon (in rice husk) at 1 bar pressure and 900˚C was found to be the best operating point for hundred percent carbon conversion in the fuel reactor. Such detailed thermodynamic studies can be useful to design chemical looping combustion processes using different fuels.
Co2 removal through solvent and membraneRashesh Shah
1) Carbon dioxide separation from fossil fuel combustion gases is important for reducing greenhouse gas emissions. Amine-based chemical absorption is the most common existing method, using solvents like monoethanolamine (MEA) to capture CO2.
2) However, MEA absorption requires high energy costs for solvent regeneration. New solvents are being developed to improve the efficiency and reduce costs of CO2 capture from power plant flue gases.
3) Key challenges include the low pressure of flue gases, oxygen and sulfur oxide content, and solvent degradation. Integrating capture with power plants could utilize low-grade waste heat to reduce energy costs.
Absorber Models for absorption of Carbon dioxide from sour natural gas byMeth...IJERA Editor
Mathematical models of the absorber for the absorption of carbon dioxide (CO2)from sour natural gas in Methyl-diethanol Amine (MDEA)solution were developed. The resulting ordinary differential model equations were solved numerically using theode45 solver of MATLAB 7.5. The accuracy of the models was ascertained using industrial plant data from the carbon dioxide absorber of the Obiafu/Obrikom Gas Treatment plant in Rivers State, Nigeria. The models predicted the CO2 concentration in the sweet gas, gas and solvent (MDEA) temperature progressions along the packed absorber. The results obtained from solutions to the models compared favorably with the plant outputs with a maximum deviation between models predictions and industrial plant outputs of 0.44%. The models were used to simulate the influence of sour gas flow rates and solvent (MDEA) concentration in solution on the performance (absorption rates of CO2) of the absorber.The results show that the absorption rate of CO2 increases with increasing gas flow rate and solvent concentration.
The document discusses thermodynamic analysis of biomass gasification. It analyzes the reaction thermoneutral points (R-TNPs) for gasifying rice husk with different gasifying agents and their ratios. Key findings include:
- For CO2 alone, R-TNPs decreased with higher CO2:carbon ratios, with syngas output and CO2 conversion also decreasing. Heat requirements initially rose then fell with a heat exchanger.
- R-TNPs were not found for H2O alone at any ratio.
- With CO2+H2O, R-TNPs were only obtained at low total gasifier agent:carbon ratios. Higher ratios supported
Thermodynamic modeling and experimental study of rice husk pyrolysiseSAT Journals
Abstract Pyrolysis of agricultural waste is a promising route for waste to energy generation. Rice husk is a type of agro-waste that is available in plenty in India. It can be used as feed for pyrolysis to produce different products such as (solid) coke and silica, (liquid) tar and other organics and syngas. HSC Chemistry computer aided code for thermodynamic modeling was used to predict the products of rice-husk pyrolysis in this research study. The pyrolysis of rice husk was carried out between 100-1200°C in the pressure range of 1 – 15 bar. The pyrolysis products predicted by HSC calculations were mainly solid coke, gases like H2, CO2, CO, CH4, with small quantity of aromatic compounds like C6H6, C7H8, C8H10 (ethyl benzene), C8H10 (xylenes) and C6H5 –OH. An experimental study for product validation was also done and the results are presented. Keywords: Pyrolysis, syngas, HSC Chemistry, aromatic compounds.
SYNGAS PRODUCTION BY DRY REFORMING OF METHANE OVER CO-PRECIPITATED CATALYSTSIAEME Publication
The syngas manufacturing from the reforming of methane with carbon dioxide is tempting because of output in terms of extra pure synthesis gas and lower H2 to CO ratio than other synthesis gas production methods like either partial oxidation or steam reforming. For production of long-chain hydrocarbons though the Fischer-Tropsch synthesis, lower H2 to CO ratio is required and important, as it is a most likely feedstock. In recent decades, CO2 utilization has become more and more important in view of the emergent global warming phenomenon. On the environmental point of view, methane reforming is tantalizing due to the reduction of carbon dioxide and methane emissions as both are consider as dangerous greenhouse gases. Commercially, as cost effectively, nickel is used for methane reforming reactions due to its availability and lower cost compared to noble metals. Number of catalysts endures rigorous deactivation because of carbon deposition. Mainly carbon formation is because of methane decomposition and CO disproportionate. It is important and required to recognize essential steps of activation and conversion of CH4 and CO2 to design catalysts that minimize deactivation. Effect of promoters on activity and stability were studied in the detail. In order to develop the highly active with minimum coke formation the alkali metal oxides and ceria/zirconia/magnesia promoters were incorporated in the catalysts. The influence of ZrO2, CeO2 and MgO, in the performance of Ni-Al2O3 catalyst, prepare by co-precipitation method was studied in detailed. The XRD, FTIR, and BET and reactivity test for different promoted and unprompted catalyst was carried out.
Biomass gasification for hydrogen productionMd Tanvir Alam
Biomass gasification can be used to produce hydrogen fuel through thermal conversion processes. Gasification involves heating biomass with limited oxygen to produce syngas containing hydrogen, carbon monoxide, and other gases. Several pathways exist to convert biomass to hydrogen through gasification. Research has demonstrated hydrogen yields of up to 60% by volume from biomass gasification using fluidized beds and catalysts. Economic analyses show biomass gasification can competitively produce hydrogen compared to natural gas reforming. With environmental and economic benefits, biomass gasification is a promising option for renewable hydrogen production.
An Update on Gas CCS Project: Effective Adsorbents for Establishing Solids Looping as a Next Generation NG PCC Technology - presentation by Colin Snape in the Natural Gas CCS session at the UKCCSRC Cardiff Biannual Meeting, 10-11 September 2014
Gasification Performance Improvement of Treated SRF Residue by Using Minerals...Md Tanvir Alam
The document discusses gasification performance of treated solid refuse fuel (TSRF) residue. Key findings include:
1) TSRF gasification produced syngas mainly of H2, CO, CO2 and CH4. Maximum syngas yield and heating value occurred at an equivalence ratio of 0.2.
2) Adding minerals like dolomite or lime to the gasification bed increased syngas component yields and lowered tar. Dolomite addition yielded the highest syngas.
3) Co-gasifying TSRF with 25% biomass waste increased syngas component and heating values the most. Using a 25% biomass and dolomite blend yielded the highest
Study of Methane Emissions in the Marcellus, Haynesville and Fayetteville Sha...Marcellus Drilling News
A new study by researchers at the University of Colorado’s Cooperative Institute for Research in Environmental Sciences and the National Oceanic and Atmospheric Administration (NOAA). Titled "Quantifying atmospheric methane emissions from the Haynesville, Fayetteville, and northeastern Marcellus shale gas production regions," the new study finds very little methane leakage in the Marcellus Shale region--less than 1/2 of 1%.
Apec workshop 2 presentation 5 e apec workshop mexico capture technologies ...Global CCS Institute
This document summarizes different carbon capture technologies including post-combustion, pre-combustion, and oxy-combustion systems. Post-combustion systems use amine-based solvents to separate CO2 from flue gases, while pre-combustion separates CO2 from syngas before combustion using physical or chemical solvents. Oxy-combustion produces a concentrated CO2 stream by combusting fuels in oxygen instead of air. The document also discusses applying these technologies to industrial sectors like oil refining, cement production, and iron and steel manufacturing.
This document presents a project report on the design of a sulfur recovery unit (SRU) using the Claus process to produce 80 tons of elemental sulfur per day from natural gas. The report includes an introduction to natural gas processing and sweetening, an overview of sulfur recovery methods with a focus on the Claus process, material and energy balances across the SRU equipment, and designs for major units like the reaction furnace, reactors, condensers, and heat exchangers. Other sections address instrumentation and control, piping, cost estimation, safety considerations, and construction materials for refractory lining. The goal of the project is to design an economically feasible SRU for natural gas wells in Pakistan using the most suitable Claus process.
Gasification process for generating producer gas by updraft, downdraft etc. and advantage and disadvantages of gasifier and application of producer gas for generating electricity or motive power for running the engine.
Building An Earnings Accretive Energy CompanyKW Miller
The document discusses the natural gas market and production in the United States. It notes that natural gas prices are currently below $4/mmbtu but argues they will rise significantly due to new environmental taxes on fracking, deficiencies in gas distribution infrastructure, and the unknown production decline curve for shale gas wells. It also argues that if gas-fired power plants and other gas consumers increased usage, it would strain the distribution system and diminish any claims of excess gas supply. The document advocates for investment in natural gas infrastructure and production companies.
The 25-page executive summary for a study published in January 2014 by IHS titled "Fueling the Future with Natural Gas: Brining it Home." The new study finds that because of the ongoing rush of new natural gas supplies from shale drilling, the Henry Hub benchmark price will likely stay between $4-$5 per Mcf until 2035. It also finds homeowners will save a signifcant amount of money by heating with natural gas.
Refrigerant environment and legislative update the future of refrigerants c...omairfarooq
The document discusses global regulations around refrigerants and their environmental impacts. It reviews the Montreal Protocol which phased out ozone depleting substances and indicates the protocol has been successful but work remains. It also discusses the Kyoto Protocol which aims to reduce greenhouse gas emissions. The document identifies indicators for the future of refrigerants, including focusing on total environmental impact rather than just direct effects. It provides examples of likely refrigerant alternatives for different sectors and notes solutions will continue to evolve as equipment innovates to meet energy efficiency demands.
This document summarizes a study that evaluated the performance of a CO2 refrigeration system enhanced with a dew point cooler (DPC). Key findings include:
1) Experiments were conducted on a 20 kW CO2 refrigeration system to characterize its performance with and without a DPC under ambient temperatures above 40°C. The DPC avoided transcritical operation and increased COP by up to 140% compared to the conventional system.
2) A mathematical model was developed and validated experimentally. The model identified the optimum condenser inlet air temperature for each condenser temperature to maximize COP across a range of conditions.
3) An annual case study for Adelaide, Australia found the DPC-enhanced CO2 system could
This is a report on the design of a plant to produce 20 million standard cubic feet per day (0.555 × 106 standard m3/day) of hydrogen (H2) of at least 95% purity from heavy fuel oil (HFO) with an upstream time of 7680 hours/year applying the process of partial oxidation of the heavy oil feedstock.
The document discusses a method for producing synthesis gas (syngas) from gasification of bagasse. Bagasse is a waste product from sugar production that is abundant in India. Syngas produced from bagasse gasification can be used as an alternative fuel source for power generation and other industrial processes. The method involves pyrolyzing bagasse in a free-fall reactor to produce char, and then gasifying the char in a packed bed reactor to produce syngas, which consists mainly of carbon monoxide and hydrogen. Experimental results show that syngas yield increases with higher temperature and smaller bagasse particle size during pyrolysis.
Optimizing Reactor Parameters to Achieve Higher Process Yield in Ex-Situ Oil ...IJERA Editor
Declining worldwide crude oil reserves and increasing energy needs have the attentions focused on developing existing unconventional fossil fuels including oil shale. America’s richest oil shale deposits are found in the Green River Formation of western Colorado, eastern Utah and south-western Wyoming. The current work describes process simulation of an ex-situ oil shale pyrolysis process in a pyrolytic reactor using a novel method involving external and internal heating to increase heat transfer and mixing ratio inside the reactor. Efforts to improve process yield for commercial operation relies on first developing a complete Aspen based process model of a proposed shale refining plant, identifying the key process parameters for the reactor and then optimizing the overall process. Simulation results are compared to earlier experimental data collected from a pilot scale rotary reactor operated by Combustion Resources Inc. (CR). This work identified the critical impact of bed temperature on crude production in such a way that for a bed temperature of less than 400°C, results showed less than 10% conversion in crude production and for bed temperatures between 450 and 500°C, above 90% conversion was achieved. The proposed model consists of four zones including drying, shale reactions, natural gas combustion and gas/oil recovery. Different cases were defined and studied based on various operational conditions. Optimized operational values for the key parameters including reactor temperature, reactor volume and feed rate were given as results to maximum shale oil production.
The document discusses carbon capture technologies that are likely to appear in future phases of carbon capture and storage (CCS) deployment. It provides information on various carbon capture technologies including post-combustion capture using solvents like amines, pre-combustion capture through integrated gasification combined cycle (IGCC) plants, and oxy-fuel combustion. Examples of large-scale CCS projects currently in operation or development are also mentioned, such as the Kemper County energy facility and White Rose CCS project.
Chemical Looping Combustion of Rice HuskIJERA Editor
A thermodynamic investigation of direct chemical looping combustion (CLC) of rice husk is presented in this paper. Both steam and CO2 are used for gasification within the temperature range of 500–1200˚C and different amounts of oxygen carriers. Chemical equilibrium model was considered for the CLC fuel reactor. The trends in product compositions of the fuel reactor, were determined. Rice husk gasification using 3 moles H2O and 0 moles CO2 per mole carbon (in rice husk) at 1 bar pressure and 900˚C was found to be the best operating point for hundred percent carbon conversion in the fuel reactor. Such detailed thermodynamic studies can be useful to design chemical looping combustion processes using different fuels.
Co2 removal through solvent and membraneRashesh Shah
1) Carbon dioxide separation from fossil fuel combustion gases is important for reducing greenhouse gas emissions. Amine-based chemical absorption is the most common existing method, using solvents like monoethanolamine (MEA) to capture CO2.
2) However, MEA absorption requires high energy costs for solvent regeneration. New solvents are being developed to improve the efficiency and reduce costs of CO2 capture from power plant flue gases.
3) Key challenges include the low pressure of flue gases, oxygen and sulfur oxide content, and solvent degradation. Integrating capture with power plants could utilize low-grade waste heat to reduce energy costs.
Absorber Models for absorption of Carbon dioxide from sour natural gas byMeth...IJERA Editor
Mathematical models of the absorber for the absorption of carbon dioxide (CO2)from sour natural gas in Methyl-diethanol Amine (MDEA)solution were developed. The resulting ordinary differential model equations were solved numerically using theode45 solver of MATLAB 7.5. The accuracy of the models was ascertained using industrial plant data from the carbon dioxide absorber of the Obiafu/Obrikom Gas Treatment plant in Rivers State, Nigeria. The models predicted the CO2 concentration in the sweet gas, gas and solvent (MDEA) temperature progressions along the packed absorber. The results obtained from solutions to the models compared favorably with the plant outputs with a maximum deviation between models predictions and industrial plant outputs of 0.44%. The models were used to simulate the influence of sour gas flow rates and solvent (MDEA) concentration in solution on the performance (absorption rates of CO2) of the absorber.The results show that the absorption rate of CO2 increases with increasing gas flow rate and solvent concentration.
The document discusses thermodynamic analysis of biomass gasification. It analyzes the reaction thermoneutral points (R-TNPs) for gasifying rice husk with different gasifying agents and their ratios. Key findings include:
- For CO2 alone, R-TNPs decreased with higher CO2:carbon ratios, with syngas output and CO2 conversion also decreasing. Heat requirements initially rose then fell with a heat exchanger.
- R-TNPs were not found for H2O alone at any ratio.
- With CO2+H2O, R-TNPs were only obtained at low total gasifier agent:carbon ratios. Higher ratios supported
Thermodynamic modeling and experimental study of rice husk pyrolysiseSAT Journals
Abstract Pyrolysis of agricultural waste is a promising route for waste to energy generation. Rice husk is a type of agro-waste that is available in plenty in India. It can be used as feed for pyrolysis to produce different products such as (solid) coke and silica, (liquid) tar and other organics and syngas. HSC Chemistry computer aided code for thermodynamic modeling was used to predict the products of rice-husk pyrolysis in this research study. The pyrolysis of rice husk was carried out between 100-1200°C in the pressure range of 1 – 15 bar. The pyrolysis products predicted by HSC calculations were mainly solid coke, gases like H2, CO2, CO, CH4, with small quantity of aromatic compounds like C6H6, C7H8, C8H10 (ethyl benzene), C8H10 (xylenes) and C6H5 –OH. An experimental study for product validation was also done and the results are presented. Keywords: Pyrolysis, syngas, HSC Chemistry, aromatic compounds.
SYNGAS PRODUCTION BY DRY REFORMING OF METHANE OVER CO-PRECIPITATED CATALYSTSIAEME Publication
The syngas manufacturing from the reforming of methane with carbon dioxide is tempting because of output in terms of extra pure synthesis gas and lower H2 to CO ratio than other synthesis gas production methods like either partial oxidation or steam reforming. For production of long-chain hydrocarbons though the Fischer-Tropsch synthesis, lower H2 to CO ratio is required and important, as it is a most likely feedstock. In recent decades, CO2 utilization has become more and more important in view of the emergent global warming phenomenon. On the environmental point of view, methane reforming is tantalizing due to the reduction of carbon dioxide and methane emissions as both are consider as dangerous greenhouse gases. Commercially, as cost effectively, nickel is used for methane reforming reactions due to its availability and lower cost compared to noble metals. Number of catalysts endures rigorous deactivation because of carbon deposition. Mainly carbon formation is because of methane decomposition and CO disproportionate. It is important and required to recognize essential steps of activation and conversion of CH4 and CO2 to design catalysts that minimize deactivation. Effect of promoters on activity and stability were studied in the detail. In order to develop the highly active with minimum coke formation the alkali metal oxides and ceria/zirconia/magnesia promoters were incorporated in the catalysts. The influence of ZrO2, CeO2 and MgO, in the performance of Ni-Al2O3 catalyst, prepare by co-precipitation method was studied in detailed. The XRD, FTIR, and BET and reactivity test for different promoted and unprompted catalyst was carried out.
Biomass gasification for hydrogen productionMd Tanvir Alam
Biomass gasification can be used to produce hydrogen fuel through thermal conversion processes. Gasification involves heating biomass with limited oxygen to produce syngas containing hydrogen, carbon monoxide, and other gases. Several pathways exist to convert biomass to hydrogen through gasification. Research has demonstrated hydrogen yields of up to 60% by volume from biomass gasification using fluidized beds and catalysts. Economic analyses show biomass gasification can competitively produce hydrogen compared to natural gas reforming. With environmental and economic benefits, biomass gasification is a promising option for renewable hydrogen production.
An Update on Gas CCS Project: Effective Adsorbents for Establishing Solids Looping as a Next Generation NG PCC Technology - presentation by Colin Snape in the Natural Gas CCS session at the UKCCSRC Cardiff Biannual Meeting, 10-11 September 2014
Gasification Performance Improvement of Treated SRF Residue by Using Minerals...Md Tanvir Alam
The document discusses gasification performance of treated solid refuse fuel (TSRF) residue. Key findings include:
1) TSRF gasification produced syngas mainly of H2, CO, CO2 and CH4. Maximum syngas yield and heating value occurred at an equivalence ratio of 0.2.
2) Adding minerals like dolomite or lime to the gasification bed increased syngas component yields and lowered tar. Dolomite addition yielded the highest syngas.
3) Co-gasifying TSRF with 25% biomass waste increased syngas component and heating values the most. Using a 25% biomass and dolomite blend yielded the highest
Study of Methane Emissions in the Marcellus, Haynesville and Fayetteville Sha...Marcellus Drilling News
A new study by researchers at the University of Colorado’s Cooperative Institute for Research in Environmental Sciences and the National Oceanic and Atmospheric Administration (NOAA). Titled "Quantifying atmospheric methane emissions from the Haynesville, Fayetteville, and northeastern Marcellus shale gas production regions," the new study finds very little methane leakage in the Marcellus Shale region--less than 1/2 of 1%.
Apec workshop 2 presentation 5 e apec workshop mexico capture technologies ...Global CCS Institute
This document summarizes different carbon capture technologies including post-combustion, pre-combustion, and oxy-combustion systems. Post-combustion systems use amine-based solvents to separate CO2 from flue gases, while pre-combustion separates CO2 from syngas before combustion using physical or chemical solvents. Oxy-combustion produces a concentrated CO2 stream by combusting fuels in oxygen instead of air. The document also discusses applying these technologies to industrial sectors like oil refining, cement production, and iron and steel manufacturing.
This document presents a project report on the design of a sulfur recovery unit (SRU) using the Claus process to produce 80 tons of elemental sulfur per day from natural gas. The report includes an introduction to natural gas processing and sweetening, an overview of sulfur recovery methods with a focus on the Claus process, material and energy balances across the SRU equipment, and designs for major units like the reaction furnace, reactors, condensers, and heat exchangers. Other sections address instrumentation and control, piping, cost estimation, safety considerations, and construction materials for refractory lining. The goal of the project is to design an economically feasible SRU for natural gas wells in Pakistan using the most suitable Claus process.
Gasification process for generating producer gas by updraft, downdraft etc. and advantage and disadvantages of gasifier and application of producer gas for generating electricity or motive power for running the engine.
Building An Earnings Accretive Energy CompanyKW Miller
The document discusses the natural gas market and production in the United States. It notes that natural gas prices are currently below $4/mmbtu but argues they will rise significantly due to new environmental taxes on fracking, deficiencies in gas distribution infrastructure, and the unknown production decline curve for shale gas wells. It also argues that if gas-fired power plants and other gas consumers increased usage, it would strain the distribution system and diminish any claims of excess gas supply. The document advocates for investment in natural gas infrastructure and production companies.
The 25-page executive summary for a study published in January 2014 by IHS titled "Fueling the Future with Natural Gas: Brining it Home." The new study finds that because of the ongoing rush of new natural gas supplies from shale drilling, the Henry Hub benchmark price will likely stay between $4-$5 per Mcf until 2035. It also finds homeowners will save a signifcant amount of money by heating with natural gas.
ICF Study Showing $30B Per Year Needed on New Pipeline Infrastructure in US/C...Marcellus Drilling News
A new research report titled The study is titled, "North America Midstream Infrastructure through 2035: Capitalizing on Our Energy Abundance" that shows midstream (pipeline) and related infrastructure spending in the U.S. and Canada will need to be on the order of $30 billion per year through 2035 ($641B total) in order to keep pace with the rapid development of shale energy resources. The spending and buildout of new infrastructure will result in 432,000 new jobs and approximately $885 billion in new spending throughout U.S. and Canadian economies. Truly staggering numbers.
The new report was prepared by ICF International for the INGAA Foundation (Interstate Natural Gas Association of America) and ANGA (America’s Natural Gas Alliance).
A study released in December 2016 by the London School of Economics, titled "On the Comparative Advantage of U.S. Manufacturing: Evidence from the Shale Gas Revolution." While America has enough shale gas to export plenty of it, exporting it is not as economic as exporting oil due to the elaborate processes to liquefy and regassify natural gas--therefore a lot of the gas stays right here at home, making the U.S. one of (if not the) cheapest places on the planet to establish manufacturing plants, especially for manufacturers that use natural gas and NGLs (natural gas liquids). Therefore, manufacturing, especially in the petrochemical sector, is ramping back up in the U.S. For every two jobs created by fracking, another one job is created in the manufacturing sector.
This document analyzes challenges related to unconventional gas reserves reporting. Volatile natural gas prices can lead to downgrading of reserves if production costs are too high. New SEC rules have accelerated unconventional gas reserves growth but also introduced more volatility and risk. There is concern about investment security due to volatile gas prices and uncertainty around reported reserves volumes. This is exacerbated by unprecedented increases in proved undeveloped gas reserves reported by unconventional gas operators under new SEC rules. The document examines reserves reporting differences between conventional and unconventional gas companies.
Shale gas- a look into the past to leap into the futureApurva Mittal
This document discusses shale gas production in the United States, China, and India. It provides historical context on the development of shale gas extraction technologies in the US. While the US has seen a boom in shale gas production due to supportive policies and technological innovations, China has faced challenges replicating US success due to lack of experience, high costs, environmental concerns, and need for further technological development to access reserves deeper underground. India has significant shale gas reserves but also faces hurdles around infrastructure, regulations, and adapting extraction technologies to its geological conditions and water availability. Indian companies have invested in US shale production to gain experience that could help develop India's shale gas potential.
The document discusses life in Algeria, providing background information on the country. It notes that Algeria has the largest economy in Africa, with a GDP that has increased in recent years. Arabic is the main language and the currency is the dinar. Algeria's economy relies heavily on its natural gas production and exports, which have increased significantly and provide benefits both within the country and to other parts of Africa and Europe.
The evaluation and management of unconventional reservoir systemGregory Tarteh
This document discusses conventional and unconventional oil and gas reservoirs. It defines conventional reservoirs as high permeability reservoirs that can be economically produced through vertical wells, while unconventional reservoirs require stimulation or special processes. The document outlines how unconventional reservoirs, like tight gas sands and shale gas, will play an increasingly important role in meeting future energy demands as production from conventional reservoirs peaks and declines. It argues we will rely on liquids from natural gas, heavy oil, and unconventional gas to fill the gap between projected oil demand and supply from conventional reservoirs alone between now and 2020.
A new research paper recently published by researchers at the University of Wyoming takes a close look at the economic benefits and potential pitfalls of shale drilling. The paper, titled "The Economics of Shale Gas Development" was accepted last November for publication later this year in the Annual Review of Resources Economics. The upshot of the paper is this: there are ENORMOUS economic benefits from shale drilling--and we'll realize those benefits as long as we don't screw it up. That is, we need to be mindful of, and careful to manage, the environmental impacts from drilling.
A research paper published by the nonpartisan Brookings Institution that finds the shale and fracking revoluation in America have had enormous economic benefits for all Americans--particularly those who burn natural gas. The average gas-burning household now saves over $200 per year because of lower gas prices, thanks to fracking.
This document provides an overview of PLG Consulting, a logistics and supply chain consulting firm, and discusses how shale gas development is driving a manufacturing revolution in the United States. It notes that technological advances have unlocked previously inaccessible shale gas resources, lowering energy costs and providing abundant feedstocks. This low-cost shale gas and natural gas liquids are attracting manufacturing industries back to the US and driving expansion of existing chemical and industrial facilities. The document outlines impacts along the natural gas supply chain from production through processing, transportation and end use.
This discussion paper on Energy Well Integrity focuses on typical onshore unconventional oil or gas wells, which are generally similar to wells used for conventional oil or coal bed methane production. The major topics covered in this paper are well design, construction, use and abandonment. Issues of cementing practices and gas migration pathways are given special emphasis because they are key aspects in establishing and understanding well integrity.
The report looks at federal, state and local activities to help control air pollution from oil and gas--both drilling and pipelines. Without taking sides, this report provides information on the natural gas industry and the types and sources of air pollutants caused by the industry. The report examines the role of the federal government in regulating these emissions, including provisions in the Clean Air Act and EPA's onerous regulatory activities.
This document provides an overview of a study on shale gas in India. It discusses the potential for shale gas extraction in India based on learnings from successful extraction in the US. Key sections cover the technology developments enabling economical shale gas extraction, India's identified shale gas basins and their potential, possible players in the Indian market, and increasing momentum for shale gas exploration in India with activities by public and private sector companies and the government. Challenges to shale gas extraction in India are also acknowledged.
Changes to the generation portfolio, the introduction of significant renewable resources, and the deployment of customer-side resources are fundamentally changing the way electricity is produced and delivered to customers. These changes are having a significant impact on the developments and operation of the transmission system and are occurring in an environment of decreasing demand growth which impacts utility revenues and puts pressure on rates. This presentation will examine how they will impact the amount and location of transmission needed, the rates that can be charged for it, and its relative value in a utility’s portfolio assets.
The document discusses rising energy prices in the United States after several years of low natural gas and electricity costs. It attributes the recent price declines to increased domestic natural gas production through shale gas extraction and a weak economy. However, the document notes several factors that are expected to drive energy prices higher in the coming years, including declining production from conventional gas basins, coal plant retirements being replaced by natural gas generation, increasing international demand for natural gas, and shale gas producers requiring higher price points to remain profitable. It concludes that companies need to update their energy budget and risk management strategies in light of these changing market fundamentals and rising price trends.
After a “perfect storm” of global recession and shale gas
expansion, a new wave of environmental, production, transport, and international demand drivers have the energy market on a bull run. This white paper outlines the driver for longer term energy price increase trends, and discusses steps an organization may take to minimize related risks. - Expertise authored by Ecova, Inc
Global Gas Shales And Unconventional Gas Unlocking Your Potentialsmithtj38
This document discusses unconventional natural gas and its potential based on quotes from various news sources. It summarizes comments from President Obama about the potential for shale gas production to increase US energy security and reduce greenhouse gas emissions. The rest of the document provides an agenda for introducing GTI, an overview of the organization, details on global shale gas resources, and how abundant natural gas could enable energy independence, reduce climate change risks, and provide economic benefits through jobs and tax revenue. It invites attendees to consider what opportunities unconventional gas may provide for their own countries.
The document provides an analysis of the natural gas industry by a senior energy executive. It discusses the key factors needed for economic recovery, including an affordable and dependable energy supply. It argues that natural gas is not currently in a state of permanent excess supply, and that claiming it is ignores constraints in the production, storage, transportation and distribution infrastructure. It also expresses skepticism about renewable energy and the current administration's energy policies.
Last Updated October 31, 2011Hydrofracking Is hydraulic fractu.docxsmile790243
Last Updated: October 31, 2011
Hydrofracking: Is hydraulic fracturing, or hydrofracking, a safe way to extract natural gas?
Pro/Con Article Media Editorials News
Page Tools Highlighting
FULL ARTICLE
Introduction
Background
Supporters Argue
Opponents Argue
Conclusion
Chronology
By the Numbers
Spotlights
Discussion Questions
Bibliography
Further Resources
Introduction
SUPPORTERS ARGUE
There is no proven case of hydrofracking contaminating drinking water, and the process is perfectly safe. Natural gas can revive local economies, reduce U.S. dependence on foreign oil, and provide a cleaner-burning fossil fuel. Further regulation is unnecessary and will only prevent an opportunity for the United States to develop an alternative energy source and create jobs.
OPPONENTS ARGUE
The chemicals used in fracking fluid are toxic and pose a danger to public health if they contaminate drinking water reserves or leak out of wells. Oil and gas companies are not being honest with the public about the dangers of hydrofracking, and the federal government should apply much stricter, nationwide regulations to ensure that hydrofracking does not cause widespread health problems that could plague the public for generations.
Issues and Controversies: Hydrofracking Workers
Workers at a natural gas well site in Burlington, Pennsylvania, in April 2010 prepare a drill to begin the process of hydraulic fracturing, or hydrofracking.
AP Photo/Ralph Wilson
Many observers have hailed natural gas as a solution to several energy problems facing the U.S. Utilizing the country's ample domestic supply of the resource, many have said, could greatly decrease U.S. dependence on foreign oil and possibly drive energy prices down. Furthermore, natural gas produces much less carbon dioxide than other fossil fuels, about half as much as coal, making it the cleanest burning fossil fuel available. Energy experts have also touted natural gas as a cheap alternative to renewable energy sources, such as wind or solar energy, until engineers devise a way to make renewable energy more cost efficient. According to the Department of Energy, natural gas already produces about one-fifth of the nation's electricity, a proportion that may increase as energy firms tap more domestic reserves of natural gas.
The Marcellus Shale, a 95,000-square-mile geologic formation deep underground that stretches from West Virginia through Pennsylvania to upstate New York, is estimated to contain as much as 500 trillion cubic feet of natural gas. In order to access the natural gas in the Marcellus Shale and other shale formations, however, energy companies have to employ a controversial procedure called hydraulic fracturing—also known as "hydrofracking" or simply "fracking." Hydrofracking is a technique that releases natural gas by pumping millions of gallons of water, laced with sand and chemicals, thousands of feet underground to blast open, or fracture, shale formations, freeing the gas. [See Today's Science: Nat ...
Similar to Trophy Hunting vs. Manufacturing Energy: The Price Responsiveness of Shale Gas (20)
Professor Ibrahim Dincer is a leading expert on ammonia as an energy vector. Ammonia could help displace high-sulfur bunker fuel used in shipping by 2020 and enable the growth of ammonia-fueled ships. Ammonia refrigeration systems are more efficient and less expensive to build and operate than CFC or HCFC systems, and ammonia has no ozone depletion or global warming potential. Ammonia is also being explored as a sustainable transportation fuel for internal combustion engines and fuel cells due to its high octane rating and the existing global production and distribution infrastructure. The DOE and ARPA-E are beginning to explore ammonia's potential as an energy carrier due to its superior attributes
Mitacs comprehensive evaluation of nh3 production and utilization options for...Steve Wittrig
This document is a final report submitted to Mitacs on March 25, 2017 for the Accelerate Project grant IT08015. The report evaluates options for clean energy applications of ammonia production and utilization. It includes 11 chapters that analyze ammonia synthesis techniques like electrolysis and from hydrocarbons. Life cycle assessments are presented for using ammonia in transportation sectors like shipping, aviation and road. Economic and scale-up analyses are also included to assess solar-based ammonia production. The comprehensive evaluation covers technical, environmental and economic aspects of various ammonia production methods and applications.
Ammonia (nh3) as a potential transportation solution for ontario uoit dincer ...Steve Wittrig
This document discusses the potential for using ammonia as a transportation fuel in Ontario. Some key points:
1) Ammonia is a carbon-free fuel that contains hydrogen and nitrogen and can be produced from renewable resources. It has the potential to help Ontario meet its greenhouse gas reduction targets for transportation which currently accounts for one third of emissions.
2) Ammonia is already used widely as an industrial chemical and refrigerant. With some modifications, it can be used directly in combustion engines, gas turbines, and fuel cells. It has properties making it suitable for storage and pipeline transportation similar to LPG.
3) Potential applications of ammonia as a transportation fuel discussed include use in locomotives, ships,
Ammonia (nh3) as a carbon free fuel uoit vezina white paper hydrofuelSteve Wittrig
This document discusses ammonia as a potential carbon-free fuel for transportation and power generation. It summarizes that ammonia has significant potential as an alternative fuel since it does not emit direct greenhouse gases during combustion. Ammonia can be used in internal combustion engines, gas turbines, and fuel cells with only small modifications. It also discusses factors to consider in setting renewable fuel standards targets post-2020, such as environmental impacts, costs, production methods, and infrastructure requirements. The document analyzes the greenhouse gas reductions and costs of using ammonia compared to diesel and gasoline. It concludes that ammonia could reduce life cycle greenhouse gas emissions by 70-150 grams per kilometer traveled and has the lowest cost per unit of energy among alternative
KINETIC EMERGY OVERVIEW AND RESUME DR STEVE WITTRIG SEP17Steve Wittrig
Kinetic Emergy, LLC is a company founded in 2015 by T. Stephen Wittrig to develop new energy, manufacturing, agricultural and urban infrastructure systems using emerging technologies. The company aims to model and integrate technologies like ammonia production, liquid air energy storage, gas reservoirs with CO2 storage and sequestration, digital camless engines, ammonia-powered microgrids, plasma arc gasification and sCO2 power cycles. The goal is to create robust systems models that can demonstrate the technical and economic viability of regional-scale low-carbon infrastructure.
Tsinghua bp clean energy centre established time magazine tony blair 2003Steve Wittrig
The document discusses the work of Prof. Li Zheng and the Tsinghua-BP Clean Energy Research and Education Center. It summarizes their polygeneration research which converts coal into a cleaner gaseous fuel for electricity generation and as a petroleum substitute. This could reduce China's carbon emissions from coal and dependence on oil imports. It also describes the Center's research focus on clean coal power systems, energy policy studies, and renewable energy.
T. Stephen Wittrig has an extensive background in chemical engineering and the energy industry. He received BS and PhD degrees in chemical engineering and held various roles at companies including Amoco Oil, Amoco Chemical, and BP focused on process development, business development, and technology strategy. More recently, he has advised non-profits on clean energy technologies and founded Kinetic Emergy to model and develop integrated systems using technologies such as ammonia and liquid air energy storage to enable scalable zero-carbon solutions.
Atlas v-2015 Department of Energy (DOE) Carbon Storage Atlas Julio et al 2015Steve Wittrig
This document provides a summary of the Carbon Storage Atlas Fifth Edition published by the U.S. Department of Energy's National Energy Technology Laboratory. It estimates the potential storage resources for carbon dioxide in the United States and North America. The introduction provides background on the development and impact of previous editions. It also acknowledges the collaboration between government agencies, industry, and academics that contributed to the atlas. The atlas estimates a total potential storage resource of 2.6 to 21.9 billion metric tons of CO2 across oil and gas reservoirs, unmineable coal, and saline formations. It highlights ongoing carbon storage field projects and their efforts to advance the technology.
Mitacs hydrofuel-uoit comparative assessment of nh3 production and utilizatio...Steve Wittrig
This report conducts a comparative life cycle assessment of various vehicle fuels and technologies, including internal combustion engine vehicles fueled by gasoline, diesel, LPG, methanol, CNG, hydrogen, and ammonia. Electric vehicles and hybrid electric vehicles are also considered. Production processes are analyzed from raw material extraction to vehicle disposal. Seven environmental impact categories are evaluated, finding that electric/hybrid vehicles have higher human toxicity, terrestrial ecotoxicity, and acidification due to manufacturing and maintenance, while hydrogen and ammonia vehicles are most environmentally benign. The report also investigates ammonia production from hydrocarbon dissociation using current technologies. Multiple decomposition pathways are discussed. Finally, the report performs cost and feasibility analyses of ammonia production, storage,
Mitacs hydrofuel-uoit nov 2015 200 pp cost and tech analysis of a wide variet...Steve Wittrig
The document provides a feasibility analysis of using high-pressure electrolysis for ammonia production in Ontario. Some key points from the analysis:
1. High-pressure electrolysis has the potential to reduce hydrogen production costs by eliminating the need for external hydrogen compressors, saving approximately $0.40/kg.
2. The compression cost of hydrogen to 20 bar alone constitutes around 15% of overall production costs, or $1.03/kg.
3. Using high-pressure electrolyzers at 432 bar can reduce compression costs to $0.31/kg, but increases feedstock costs by $0.31/kg.
4. The lowest estimated cost of ammonia production using high-
mitacs uoit study it05701 july 2015 vezina comparative ammonia costs producti...Steve Wittrig
The document provides an overview of ammonia production methods and utilization opportunities in transportation. It discusses conventional ammonia production via the Haber-Bosch process using natural gas as well as potential renewable production methods. The life cycle impacts of different production techniques are analyzed using SimaPro software. Key opportunities for green ammonia include production via electrolysis powered by renewable energy as well as solid state ammonia synthesis. Ammonia has advantages over hydrogen as an energy carrier and can be used in various transportation applications including engines and fuel cells with modest modifications to infrastructure.
This document summarizes the results of two life cycle assessment studies on ammonia production and utilization. Some key findings include:
- Ammonia has potential as a low-carbon transportation fuel with benefits such as no direct greenhouse gas emissions during use.
- Production of ammonia from renewable resources like solar and wind has the lowest environmental impacts compared to conventional methods.
- Utilizing ammonia in vehicles results in lower life cycle global warming potential than gasoline, diesel, or natural gas vehicles.
- The cost of ammonia as a vehicle fuel per unit distance traveled is lower than other fuels such as hydrogen, CNG, and gasoline based on tank costs and fuel efficiency.
This document is a 2016 state of the climate report presented at a UN climate conference. It summarizes key climate data and highlights that global temperatures have been flat for 18 years, extreme weather events have not increased, and polar bears and sea level rise are not threats. It questions climate models and policies, noting that CO2 is essential for life and climate is influenced by many factors. Prominent scientists are now doubting or reversing beliefs in catastrophic human-caused global warming. Proposed solutions would have no measurable impact on climate.
China automotive energy research center brief rr advisory committee ditan lab...Steve Wittrig
The document provides an overview of the China Automotive Energy Research Center (CAERC) Research Program. It outlines the center's mission to conduct multidisciplinary research on automotive energy and assist the Chinese government in developing sustainable automotive strategies. It describes CAERC's research resources which include institutions affiliated with Tsinghua University and external partner institutions. It also presents CAERC's administrative structure and outlines its research focus areas including energy supply chains, integrated automotive energy roadmaps and policies, and energy demand assessments.
Methanol institute 2016 overview of rapidly emerging methanol markets for fue...Steve Wittrig
This document discusses methanol as a transportation fuel. It notes that methanol production can bridge conventional fossil fuels and renewable feedstocks. Methanol can be used directly as a fuel through blending with gasoline or producing dimethyl ether, or indirectly through producing biodiesel, MTBE, or fuels through methanol-to-olefins or methanol-to-gasoline processes. China is a leader in using methanol fuel, with over 7 million metric tons of methanol blended annually in gasoline as M15. Guidelines are provided for safe handling of methanol at blending terminals and retail fuel stations.
Air liquide lurgi 2016 overview of coal heavy oil ch4 to syngas h2 ammonia me...Steve Wittrig
This document provides an overview of Air Liquide's coal gasification and syngas generation capabilities. It discusses various gasification technologies like Lurgi FBDB and MPG that can convert coal and residues into syngas for downstream products like hydrogen, ammonia, methanol, and power. It also summarizes Air Liquide's experience with over 75 gasification units and references various coal and residue gasification projects around the world. Finally, it briefly discusses steam methane reforming technology and Air Liquide's experience with building large hydrogen plants.
Floating city-project-report-4 25-2014 seasteading institute white paperSteve Wittrig
The Floating City Project aims to establish the first floating city with significant political autonomy by 2020. A market survey found demand for such a residential seastead. The Dutch firm DeltaSync designed practical 50m platforms that could house 20-30 residents for $15 million, meeting market preferences. High-level talks are underway with a potential host nation willing to allow political independence in exchange for benefits. The project presents a path to starting seasteading through a floating city in territorial waters, reducing costs compared to the open ocean.
Roles of cecc eil ceftf evolution and sources of value - china programs kinet...Steve Wittrig
This document outlines the roles and value creation opportunities for different types of professionals involved in developing and commercializing new energy technologies. It describes how researchers can discover new ideas and optimize processes. Engineers can design pilots and commercial plants to reduce costs. Commercial managers can provide early market guidance and develop licensing strategies. The IP department can secure patents and develop licensing strategies to protect intellectual property. Overall it shows how each role contributes to progressing technologies from initial concepts through commercialization.
Shenhua ccs program strategy and accomplishments for China Ren Xiankun 2009Steve Wittrig
This document discusses carbon capture and storage (CCS) in China's coal-to-liquids and coal chemical industries. It notes that Shenhua Group, China's largest coal producer, is actively researching CCS to reduce CO2 emissions from its coal gasification and chemical processes. Specifically, Shenhua is collaborating on projects to study capturing and storing CO2 from its direct coal liquefaction plant and investigating CCS opportunities at its proposed coal chemical facilities. The document outlines various technical and policy suggestions to help advance CCS in China, such as considering CO2 storage when siting new energy and chemical projects.
The CBC machine is a common diagnostic tool used by doctors to measure a patient's red blood cell count, white blood cell count and platelet count. The machine uses a small sample of the patient's blood, which is then placed into special tubes and analyzed. The results of the analysis are then displayed on a screen for the doctor to review. The CBC machine is an important tool for diagnosing various conditions, such as anemia, infection and leukemia. It can also help to monitor a patient's response to treatment.
Batteries -Introduction – Types of Batteries – discharging and charging of battery - characteristics of battery –battery rating- various tests on battery- – Primary battery: silver button cell- Secondary battery :Ni-Cd battery-modern battery: lithium ion battery-maintenance of batteries-choices of batteries for electric vehicle applications.
Fuel Cells: Introduction- importance and classification of fuel cells - description, principle, components, applications of fuel cells: H2-O2 fuel cell, alkaline fuel cell, molten carbonate fuel cell and direct methanol fuel cells.
Embedded machine learning-based road conditions and driving behavior monitoringIJECEIAES
Car accident rates have increased in recent years, resulting in losses in human lives, properties, and other financial costs. An embedded machine learning-based system is developed to address this critical issue. The system can monitor road conditions, detect driving patterns, and identify aggressive driving behaviors. The system is based on neural networks trained on a comprehensive dataset of driving events, driving styles, and road conditions. The system effectively detects potential risks and helps mitigate the frequency and impact of accidents. The primary goal is to ensure the safety of drivers and vehicles. Collecting data involved gathering information on three key road events: normal street and normal drive, speed bumps, circular yellow speed bumps, and three aggressive driving actions: sudden start, sudden stop, and sudden entry. The gathered data is processed and analyzed using a machine learning system designed for limited power and memory devices. The developed system resulted in 91.9% accuracy, 93.6% precision, and 92% recall. The achieved inference time on an Arduino Nano 33 BLE Sense with a 32-bit CPU running at 64 MHz is 34 ms and requires 2.6 kB peak RAM and 139.9 kB program flash memory, making it suitable for resource-constrained embedded systems.
CHINA’S GEO-ECONOMIC OUTREACH IN CENTRAL ASIAN COUNTRIES AND FUTURE PROSPECTjpsjournal1
The rivalry between prominent international actors for dominance over Central Asia's hydrocarbon
reserves and the ancient silk trade route, along with China's diplomatic endeavours in the area, has been
referred to as the "New Great Game." This research centres on the power struggle, considering
geopolitical, geostrategic, and geoeconomic variables. Topics including trade, political hegemony, oil
politics, and conventional and nontraditional security are all explored and explained by the researcher.
Using Mackinder's Heartland, Spykman Rimland, and Hegemonic Stability theories, examines China's role
in Central Asia. This study adheres to the empirical epistemological method and has taken care of
objectivity. This study analyze primary and secondary research documents critically to elaborate role of
china’s geo economic outreach in central Asian countries and its future prospect. China is thriving in trade,
pipeline politics, and winning states, according to this study, thanks to important instruments like the
Shanghai Cooperation Organisation and the Belt and Road Economic Initiative. According to this study,
China is seeing significant success in commerce, pipeline politics, and gaining influence on other
governments. This success may be attributed to the effective utilisation of key tools such as the Shanghai
Cooperation Organisation and the Belt and Road Economic Initiative.
Comparative analysis between traditional aquaponics and reconstructed aquapon...bijceesjournal
The aquaponic system of planting is a method that does not require soil usage. It is a method that only needs water, fish, lava rocks (a substitute for soil), and plants. Aquaponic systems are sustainable and environmentally friendly. Its use not only helps to plant in small spaces but also helps reduce artificial chemical use and minimizes excess water use, as aquaponics consumes 90% less water than soil-based gardening. The study applied a descriptive and experimental design to assess and compare conventional and reconstructed aquaponic methods for reproducing tomatoes. The researchers created an observation checklist to determine the significant factors of the study. The study aims to determine the significant difference between traditional aquaponics and reconstructed aquaponics systems propagating tomatoes in terms of height, weight, girth, and number of fruits. The reconstructed aquaponics system’s higher growth yield results in a much more nourished crop than the traditional aquaponics system. It is superior in its number of fruits, height, weight, and girth measurement. Moreover, the reconstructed aquaponics system is proven to eliminate all the hindrances present in the traditional aquaponics system, which are overcrowding of fish, algae growth, pest problems, contaminated water, and dead fish.
Electric vehicle and photovoltaic advanced roles in enhancing the financial p...IJECEIAES
Climate change's impact on the planet forced the United Nations and governments to promote green energies and electric transportation. The deployments of photovoltaic (PV) and electric vehicle (EV) systems gained stronger momentum due to their numerous advantages over fossil fuel types. The advantages go beyond sustainability to reach financial support and stability. The work in this paper introduces the hybrid system between PV and EV to support industrial and commercial plants. This paper covers the theoretical framework of the proposed hybrid system including the required equation to complete the cost analysis when PV and EV are present. In addition, the proposed design diagram which sets the priorities and requirements of the system is presented. The proposed approach allows setup to advance their power stability, especially during power outages. The presented information supports researchers and plant owners to complete the necessary analysis while promoting the deployment of clean energy. The result of a case study that represents a dairy milk farmer supports the theoretical works and highlights its advanced benefits to existing plants. The short return on investment of the proposed approach supports the paper's novelty approach for the sustainable electrical system. In addition, the proposed system allows for an isolated power setup without the need for a transmission line which enhances the safety of the electrical network
Null Bangalore | Pentesters Approach to AWS IAMDivyanshu
#Abstract:
- Learn more about the real-world methods for auditing AWS IAM (Identity and Access Management) as a pentester. So let us proceed with a brief discussion of IAM as well as some typical misconfigurations and their potential exploits in order to reinforce the understanding of IAM security best practices.
- Gain actionable insights into AWS IAM policies and roles, using hands on approach.
#Prerequisites:
- Basic understanding of AWS services and architecture
- Familiarity with cloud security concepts
- Experience using the AWS Management Console or AWS CLI.
- For hands on lab create account on [killercoda.com](https://killercoda.com/cloudsecurity-scenario/)
# Scenario Covered:
- Basics of IAM in AWS
- Implementing IAM Policies with Least Privilege to Manage S3 Bucket
- Objective: Create an S3 bucket with least privilege IAM policy and validate access.
- Steps:
- Create S3 bucket.
- Attach least privilege policy to IAM user.
- Validate access.
- Exploiting IAM PassRole Misconfiguration
-Allows a user to pass a specific IAM role to an AWS service (ec2), typically used for service access delegation. Then exploit PassRole Misconfiguration granting unauthorized access to sensitive resources.
- Objective: Demonstrate how a PassRole misconfiguration can grant unauthorized access.
- Steps:
- Allow user to pass IAM role to EC2.
- Exploit misconfiguration for unauthorized access.
- Access sensitive resources.
- Exploiting IAM AssumeRole Misconfiguration with Overly Permissive Role
- An overly permissive IAM role configuration can lead to privilege escalation by creating a role with administrative privileges and allow a user to assume this role.
- Objective: Show how overly permissive IAM roles can lead to privilege escalation.
- Steps:
- Create role with administrative privileges.
- Allow user to assume the role.
- Perform administrative actions.
- Differentiation between PassRole vs AssumeRole
Try at [killercoda.com](https://killercoda.com/cloudsecurity-scenario/)
Advanced control scheme of doubly fed induction generator for wind turbine us...IJECEIAES
This paper describes a speed control device for generating electrical energy on an electricity network based on the doubly fed induction generator (DFIG) used for wind power conversion systems. At first, a double-fed induction generator model was constructed. A control law is formulated to govern the flow of energy between the stator of a DFIG and the energy network using three types of controllers: proportional integral (PI), sliding mode controller (SMC) and second order sliding mode controller (SOSMC). Their different results in terms of power reference tracking, reaction to unexpected speed fluctuations, sensitivity to perturbations, and resilience against machine parameter alterations are compared. MATLAB/Simulink was used to conduct the simulations for the preceding study. Multiple simulations have shown very satisfying results, and the investigations demonstrate the efficacy and power-enhancing capabilities of the suggested control system.
Advanced control scheme of doubly fed induction generator for wind turbine us...
Trophy Hunting vs. Manufacturing Energy: The Price Responsiveness of Shale Gas
1. 1616 P St. NW
Washington, DC 20036
202-328-5000 www.rff.org
August 2016 RFF DP 16-32
Trophy Hunting vs.
Manufacturing
Energy: The Price-
Responsiveness of
Shale Gas
Richard G. New ell, Brian C. Prest, and Ashley Vissing
DISCUSSIONPAPER
3. Over the past decade, technological developments have driven increased natural
gas and oil extraction by opening access to resources stored in shale and other
“tight” formations. These unconventional technologies and resources have allowed
drillers to extract from significantly larger subsurface acreage using fewer wellbores
and with much higher production per well. The combination of hydraulic fracturing
and horizontal drilling techniques has underpinned this unconventional supply and
the resulting shale gas boom.1
Supported initially by high natural gas prices during
much of the 2000s, the United States has experienced significant increases in natural
gas and oil production.
The shale revolution has fundamentally changed how gas and oil are produced
in the United States. In the words of one industry expert,2
conventional oil and
gas investments resemble high-risk/high-reward, “big game trophy hunting,” which
involves drilling many dry holes in search of a few highly productive ones. This
stands in stark contrast to modern unconventional extraction from shale, which is
commonly said to resemble a “manufacturing process” in that operators have much
more flexible and certain control over their production levels.
Multiple features of unconventional gas lead to this flexibility. First, industry
operators have better information about the location and scale of shale resources
than they do for conventional formations; the obstacle is extracting them. As one
industry analyst stated, “[w]e knew the shale formations were there but we didn’t
1
Conventional wells tap porous and permeable resources that flow to the wellhead naturally once
the well is drilled. Unconventional wells require hydraulic fracturing, where tight shale resources
are artificially stimulated with high-pressure water causing fissures that are propped open to allow
the gas and oil to flow to the wellhead. The process requires more time and at a higher cost to
complete the well.
2
Rob Jacobs, Caird Energy, personal communication.
1
4. have the technology to extract from them.”3
Second, shale resources produce a
much larger amount of resources quickly, suggesting a tighter relationship between
drilling effort and realized production. Altogether, experts have suggested that these
factors make unconventional gas and oil more responsive to prices.4
To the extent that unconventional gas is more price responsive, the shale boom
has likely “flattened out” the U.S. natural gas supply curve, thereby reducing price
volatility. Indeed, following the boom in shale gas, prices have been significantly
less volatile compared to the early 2000s. To the extent that unconventional gas
is responsible for this diminished volatility, continuation would help reduce un-
certainty for policymakers and businesses considering investments that are highly
sensitive to gas prices. For example, compliance with regulations reducing car-
bon dioxide emissions from power plants may involve higher reliance on natural
gas-fired generation, both as a substitute for coal and as backup for intermittent re-
newable power. The economic benefits of investments in LNG export infrastructure
also depend on stable natural gas prices, as do the benefits of domestic investments
in energy-intensive manufacturing and chemical production.
Given the differences in geology and changes to drilling technology, this re-
search seeks to disentangle the differences in operators’ price-responsive behavior
between conventional and unconventional gas. We consider different aspects of the
production process to assess the differences between unconventional and conven-
tional wells at each stage of the supply function, beginning with the decision to
drill the well, complete the well, and produce gas over time. We estimate these
3
Jodi Shafto, “Dry gas well drilling economics improved by drilling technology advancements,”
May 31, 2013, SNL Daily Gas Report.
4
For example, The Economist, “The economics of shale oil: Saudi America,” February 15, 2014.
2
5. relationships using econometric models that appropriately describe each stage of
well development and execute the analysis using detailed data from approximately
62,000 gas wells drilled in Texas between January 2000 and September 2015.
We find that the important margin for production responses to price changes
is drilling investment, whereas neither production from existing wells nor the time
from drilling to first production respond strongly to price changes. We estimate
a long-run drilling elasticity to prices of approximately 0.7 and find no clear evi-
dence that this elasticity is different for unconventional compared to conventional
gas drilling. While unconventional wells take somewhat longer to reach produc-
tion, they produce much more gas per well than conventional wells and have less
risk associated with variation in well productivity. This faster flow rate per well
turns out to be the primary margin by which aggregate supply from unconventional
gas production is more price responsive than conventional production.
We use these econometric results to conduct a simulation of the effect of an
exogenous 10 percent price shock on wells drilled and gas supplied over time, pro-
viding a time-varying price response. We find that unconventional gas production
responds more strongly to price changes (nearly 3-fold in the long-run) than con-
ventional production does. These are the first econometric estimates to isolate the
differences in supply response between shale gas and conventional gas.
I Literature
The paper spans several literatures related to the economics of the oil and natural gas
industry and more generally to non-renewable resource extraction. We contribute to
a nascent but growing area of research on the effects of greater accessibility to shale
3
6. gas (Joskow 2013). The study also contributes to understanding of price formation
in fossil fuel markets (e.g., Hamilton 2009; Kilian 2009). Specifically, we analyze
the separate phases of energy development and isolate the industry decisions that are
responsive to changes in natural gas and oil prices, effectively estimating a supply
elasticity in a much more disaggregated manner than is typical in past work.
The resource extraction literature seeks to characterize firms’ optimal extrac-
tion decisions and depletion rates (Nystad 1987; Adelman 1990; Davis and Cairns
1998; Cairns and Davis 2001; Thompson 2001; Smith 2012; Cairns 2014; Kellogg
2014). Our paper empirically tests the degree to which natural gas production deci-
sions are sensitive to shocks in prices and whether there are differential effects for
conventional versus unconventional resources and technologies. Using more disag-
gregated, well-level data applied to gas (rather than oil), we find similar evidence
to Anderson, Kellogg and Salant (2014) that the quantity produced from already-
producing wells is not elastic or price sensitive.
The demand and supply elasticity literature often compares short and long-run
results, typically finding that gas and oil supply elasticities are inconsequential once
wells have been drilled and that supply is less responsive in the short run than in the
long-run. Papers analyzing oil extraction elasticities include Griffin (1985); Hogan
(1989); Jones (1990); Dahl and Y¨ucel (1991); Ramcharran (2002); and G¨untner
(2014). There is very little published econometric evidence on natural gas supply
elasticities (Erickson and Spann 1971; Dahl 1992; Krichene 2002), much of which
is dated and none of which focuses on the impact of the recent shale gas revolution.
Our paper is specifically focused on estimating the heterogeneous responses for
unconventional compared to conventional drilling decisions, centered on the recent
4
7. shale gas boom occurring in states such as Texas, Pennsylvania, Louisiana, and
Arkansas. Hausman and Kellogg (2015) estimates aggregated supply and demand
elasticities to capture welfare impacts of the shale boom across industrial sectors
and producers, and heterogeneous effects across space.
Our study also contributes to understanding decline curves for unconventional
wells, which has important implications for the inertia and cyclicality inherent in
gas and oil markets. Decline curves from conventional wells are commonly mod-
eled using the “Arps equation,” which nests exponential, hyperbolic, and harmonic
decline curves. By contrast, Patzek, Male and Marder (2013) argue that uncon-
ventional gas wells in the Barnett shale formation follow a fundamentally different
functional form: proportional to 1 over the square root of time for the first few
years, and then exponential after that. This same functional form is also used in
Browning et al. (2014), among other studies. While we explore functional form in
this paper, we ultimately focus on a non-parametric approach to decline paths.
II Industry Background and Data
II.A Industry Structure
Unconventional drilling describes the technological combination of more advanced
hydraulic fracturing and horizontal drilling techniques that are used to extract nat-
ural gas and oil from tight-shale formations. Unconventional gas and oil reserves
are stored in these tight-shale formations where the resources are difficult to extract
unless the shale is artificially stimulated using a technique like hydraulic fracturing.
5
8. Further, large quantities of shale resources are located beneath more densely
populated regions of the country, and these resources can now be accessed through
horizontal drilling techniques, with laterals extending from the vertical well for
thousands of feet in any horizontal direction. Combined with advancements in seis-
mic and surveying technologies, these extraction methods increase the accessibility
to otherwise inaccessible natural gas and oil.
As a result, unconventional gas and oil production differs from conventional
methods in several ways across the stages of development, which are described
in the following subsections. In particular, the process can be broken down into
the following stages: leasing and permitting; spudding a well (i.e., commencing
drilling); well completion and stimulation; and production over time.
II.A.1 Leasing and Permitting
Before obtaining a permit to drill a well, a firm signs leases with the mineral rights
holders of acreage from which the firm wants to extract natural gas and/or oil,
and these mineral rights holders may be private landowners or government enti-
ties. Once the mineral rights are leased, firms apply for a permit to drill a well
from the relevant state regulatory agency. During the term of the lease, the lessor
(landowner) retains the ownership and use of the surface estate while the lessee
(firm) has the right to extract and sell the resources stored in the sub-surface min-
eral estate. In return for the right to extract, the lessor is paid a lump-sum bonus,
land rental payment, and royalty on the value of the extracted resources.
Currently, shale-based hydrocarbons are extracted from onshore reserves where,
in the United States, the mineral rights are typically privately held. In these cases, a
6
9. firm privately contacts and negotiates leases with landowners, which is in contrast
to first-price sealed bid auctions that allocate government-owned offshore rights.5
In the state of Texas, where we focus this empirical analysis, the Texas Railroad
Commission is the state regulator tasked with issuing and maintaining oil and nat-
ural gas permits along with monitoring well activity once drilling begins.
While we investigated estimating the permitting stage explicitly, this stage did
not add significantly to the analysis so we did not include it in our model. Permitting
tends to be quick and low-cost, in contrast to drilling and completion which require
significantly larger investments. For further research on the leasing decision see
Porter (1995); Libecap and Smith (2002); Fitzgerald (2010); and Vissing (2015).
II.A.2 Drilling
Once mineral acreage is leased and a well is permitted, drilling can commence, and
while drilling unconventional wells results in greater oil and natural gas production
per well, it is also more technically challenging and expensive than conventional
onshore extraction. An unconventional well is drilled both vertically and then hor-
izontally as compared to a conventional well that is drilled in only the vertical di-
rection. The vertical segments typically reach 4,000 to 13,000 feet in depth and the
horizontal segments typically extend 2,000 to 7,000 feet. The horizontal segment of
an unconventional well allows firms to extract more natural gas from a larger sub-
surface mineral acreage using a single wellbore. Drilling begins at the date a well
is “spudded.” The firm that owns the well typically does not drill it itself. Rather,
drilling is typically contracted out to specialized oilfield service companies (e.g.,
5
Offshore leases are typically awarded through competitive bidding in first-price sealed bid auc-
tions (where the bid is the up-front “bonus payment”, and royalty rates are fixed).
7
10. Schlumberger and Halliburton) that charge daily rates to rent their drilling rigs and
services. These rig rates are on the order of $15,000 per day.6
II.A.3 Well Completion and Stimulation
Following the drilling phase, a well must be completed. Completion primarily in-
volves casing, perforating, and possibly stimulating the well. A casing is a large
diameter pipe cemented into the wellbore, and it prevents the well from caving in
and protects groundwater from contamination. The horizontal part of the casing
in the shale formation is perforated using perforating guns containing explosive
charges so that gas and/or oil can flow into the casing and up to the surface.
Permeable conventional reservoirs have natural pressure that causes the resource
to flow easily to the surface without any additional work. However, the imper-
meability of tight-shale formations requires that the well be artificially stimulated,
generating fissures in the rock that allow the gas and oil to flow freely up to the well-
head. Shale wells are artificially stimulated through large-scale hydraulic fracturing
techniques. This process injects millions of gallons of water mixed with sand and
chemicals into the well at a high pressure. The pressure causes the rock to fracture,
generating fissures in the rock that are propped open by the sand in the fracturing
fluid. Once the fracturing fluid returns to the surface, the newly propped fissures
allow the gas and oil to flow more easily up to the wellhead.
6
However, this is a small piece of the total cost of developing a well. For example, according
to one industry expert, the overall cost of developing a well has been on the order of $4-12 million,
whereas payments to drillers may make up only $0.5 million of this (30 days at $15,000 per day).
8
11. II.A.4 Production over Time
Once a well is completed, it often produces oil and natural gas for many years,
even several decades in some cases. The largest quantity of production is realized
in early periods because of the higher reservoir pressure. Production from existing
wells involves little marginal cost, so firms’ incentives are to produce the resources
to recover their drilling and completion costs quickly. The flow rate of oil and
natural gas to the surface is therefore a direct function of the quantity of resources
remaining in the ground. As more hydrocarbons are extracted, there is less natural
pressure pushing what remains to the surface, reducing the flow rate.
As a result, the production rate of a typical well decreases quickly. In our data,
gas production typically decreases more than 60 percent from its peak after only
one year. In addition, in the first year of production, conventional and unconven-
tional gas wells realize 35 percent and 34 percent, respectively, of their total gas
production. In the first five years, they realize 78 percent and 77 percent of total
production, respectively. Further, because the marginal cost of production from an
existing well is fairly low, many wells continue to be kept in production even after
their flow rates asymptote to zero. Firms also have alternative extraction methods
to increase the flow rate in later periods, including reservoir stimulation methods
and pumps (for oil only). However, we do not directly observe whether firms have
employed these secondary and tertiary extraction techniques to increase flow rates.
II.B Data Sources
We use well-level data aggregated by Drillinginfo, a company that provides infor-
mation services on upstream oil and natural gas activity. We focus on wells drilled
9
12. in the state of Texas because of the superior quality of the data from that state.7
Texas onshore wells account for approximately 30 percent of total U.S. natural gas
production, and it has accounted for more than 40 percent of the growth in pro-
duction since 2000.8
In Texas, Drillinginfo collects onshore well data from the
Texas Railroad Commission. The data include natural gas wells going back many
decades, but we focus on wells drilled between January 2000 and September 2015.
We downloaded the Drillinginfo dataset on June 9, 2016.
The dataset describes characteristics of each well that do not vary over time in-
cluding the wells’ important dates (spud and first production dates), the geographi-
cal location of the well, the direction the well is drilled (horizontal versus vertical),
and the reservoir into which the well was drilled. The dataset also includes the
time series of each well’s natural gas and oil production for each month over the
well’s productive lifetime. In Texas, natural gas production is measured at the well
level, while oil production is measured at the lease level. Drillinginfo allocated oil
production to individual wells using well test data.
We drop apparently duplicated observations and observations with missing or
invalid dates (e.g., the first production date is reported to occur before the well is
reported to be completed).9
We focus on natural gas wells, ignoring oil wells. We
7
The data for other regions tend to be inferior because certain variables are unavailable, defined
differently, or reported less frequently. For example, in New Mexico, drilling direction is not reliably
tracked; in Pennsylvania, production is reported at the annual level, compared to monthly in Texas.
8
http://www.eia.gov/dnav/ng/ng_prod_sum_a_EPG0_FGW_mmcf_a.htm.
9
These occasional inconsistencies are primarily due to the way Drillinginfo updates data on re-
entered wells. For example, a well that initially began production in 1995, but was later re-worked
and re-completed in 2010, would have a first production date of 1995, but a 2010 completion date.
In these cases, the original completion date would be overwritten in Drillinginfo’s data by the more
recent 2010 completion. We also drop some wells because they report beginning production more
than 24 months after their spud date. These are likely data errors because permits generally expire
after two years, and leases typically expire if production does not begin within three to five years.
10
13. also compute the length of horizontal well “laterals” using the geodesic distance
between the well’s surface hole and bottom hole.
We categorize a well as unconventional if it is drilled in a low-permeability
or shale reservoir using horizontal or directional drilling techniques. Reservoirs
were classified using a dataset provided by the Energy Information Administration
(EIA) that maps labels field and reservoir names as either “conventional,” “low
permeability,” or “shale.”10
Correspondingly, a conventional well is defined as a
well that is drilled vertically into a conventional reservoir.11
Unless otherwise noted, we use the simple average of the next 12 months of
futures prices for natural gas price (Henry Hub) and oil (WTI). Each price is the
average of daily prices collected from Bloomberg and adjusted to 2014 dollars using
the CPI All Urban Consumer (All Items) index.
II.C Data Description
The cleaned dataset includes approximately 62,000 gas wells drilled between 2000
and 2015. For unconventional wells, we only include wells drilled in 2005 or later,
as this is the period when the shale gas revolution began in earnest. Figure 1 shows
a map illustrating the location of the wells in our data along with depictions of
10
Approximately half of the wells matched perfectly to EIA’s dataset. The remaining wells were
matched using the most similar reservoir name according to the Levenshtein distance between the
two text strings, which equals the number of character changes required to obtain a perfect match.
78 percent of the wells matched perfectly after changing no more than 1 character in the reservoir
name; 93 percent matched perfectly after changing no more than 4 characters. Many such matches
are either misspellings, abbreviations, or spelling variants (e.g., “Barnett shell,” or “Eagle Ford” ver-
sus “Eagleford”) or alternatively include extra unneeded information (e.g., “Helms Barnett shale”).
Inspection of the results suggests the match performs well. For example, very few wells classified
as “shale” appear before 2000.
11
“Mixed” wells (i.e., a vertical well in a shale reservoir, or a horizontal/directional well in a
conventional reservoir) are dropped from the analysis, although there are relatively few of these.
11
14. selected shale plays. Table 1 reports the summary statistics for conventional and
unconventional gas wells,12
along with summary statistics for our price data.
Figure 1: Location of Gas Wells in Data by Well Type and Selected Shale Plays
Sources: Well locations are from Drillinginfo data. Classifications based on EIA dataset. Map is
from Stamen.com via the ggmap package for R developed by Kahle and Wickham (2013). The
indication of shale formations is based on EIA’s shapefile for low permeability oil and gas play
boundaries in the Lower 48 States, available at
https://www.eia.gov/maps/maps.htm#geodata.
Unconventional wells are much more productive than their conventional coun-
terparts. On average, an unconventional gas well in our data produced nearly 70,000
thousand cubic feet (mcf) of natural gas in its first full month,13
compared to ap-
12
Decline rates represent decline from peak production, which is not necessarily the first full
month. Means, medians, and standard deviations are taken over relevant subsets of the data. For
example, wells that produced no oil are excluded from the calculation regarding oil decline rates.
13
Initial production is measured as production during its first full month of production, meaning
the second calendar month during which production is reported. It is standard to focus on the second
month because a well is typically only producing for a fraction of its first calendar month.
12
15. proximately 30,000 mcf from a conventional gas well, meaning on average over this
sample period (2000-2015 for conventional and 2005-2015 for unconventional),
unconventional wells are 2.3 times as productive. However, this average masks
trends in productivity (shown below in Figure 4); per-well productivity has been
rising substantially for unconventional wells and falling slightly for conventional
wells. Over the 2010-2014 period,14
the average initial production for unconven-
tional wells was 80,000 mcf per month (not shown in table), 2.7 times as productive
as the average conventional well (30,000 mcf over 2000-2015, as shown in Table
1).
Comparing the averages and medians illustrates the greater predictability of
unconventional wells by capturing the relative skewness of conventional drilling.
Many conventional wells end up producing relatively little, but the occasional “gusher”
compensates for the unproductive ones. The average and median production values
are more similar for unconventional wells (mean of about 68,000 mcf versus a me-
dian of about 50,000 mcf), the mean being about 37 percent higher than the median,
compared to conventional wells, for which the mean is more than twice as large as
the median (about 30,000 mcf versus 14,000 mcf).
14
We exclude 2015 from this computation because that rise is potentially due to temporary re-
focusing of efforts on “sweet spots” during low oil and gas prices, rather than persistent innovation.
13
16. Table 1: Summary Statistics
(1) (2) (3) (4) (5) (6)
Conventional Unconventional
VARIABLES Mean Median Std. Dev. Mean Median Std. Dev.
Well Data
Initial Gas Production (first full month, mcf) 30,261 14,214 55,055 68,244 49,918 68,183
First 12 Months' Total Gas Production (mcf) 217,060 106,619 397,392 493,399 371,878 463,673
Gas 3-Month Decline Rate (%) 47.9 46.8 23.2 43.4 40.6 20.5
Gas 12-Month Decline Rate (%) 70.8 72.9 19.7 68.3 68.1 16.6
Gas 24-Month Decline Rate (%) 80.5 83.0 16.1 78.8 79.4 13.6
Initial Oil Production (first full month, barrels) 344 0 1,347 2,245 0 5,050
First 12 Months' Total Oil Production (barrels) 2,311 150 8,770 14,503 253 32,140
Oil 3-Month Decline Rate (%) 70.3 72.7 26.6 64.6 63.7 26.8
Oil 12-Month Decline Rate (%) 86.0 92.4 17.7 84.3 87.4 16.0
Oil 24-Month Decline Rate (%) 91.5 97.9 13.1 91.1 94.3 11.2
Horizontal Well Length (ft) 4,003 4,009 1,836
Total Vertical Depth (ft) 8,963 9,250 3,287 12,414 11,780 3,066
Months Between Spud Date and First Production 2.53 2.00 3.08 4.73 4.00 3.64
Number of Wells 36,093 26,017
Price Data (Monthly, 2000-2015) Mean Median Std. Dev.
Henry Hub Natural Gas Price - Prompt Month Future ($/MMBTU) $5.95 $5.02 $2.71
Henry Hub Natural Gas Price - 12-Month Future ($/MMBTU) $6.31 $5.63 $2.64
WTI Oil Price - Prompt Month Future ($/barrel) $70.90 $73.12 $27.12
WTI Oil Price - 12-Month Future ($/barrel) $71.15 $76.13 $27.72
Sources: Authors’ calculations based on data from Drillinginfo, EIA, and Bloomberg
This greater predictability of unconventional wells is also demonstrated by the
standard deviation of their initial gas production relative to conventional wells. The
coefficient of variation (the standard deviation divided by the mean) is much smaller
for unconventional gas wells (1.0), compared to conventional wells (1.8).
On average, we do not observe a substantial difference in decline rates between
unconventional and conventional gas wells—somewhat contrary to conventional
wisdom. Decline rates measure the rate of change in production levels for a given
well beginning with the peak period, typically but not always the first full calendar
month of production. Unconventional gas wells extract more natural gas in earlier
periods because they are much larger on average. Unconventional gas wells also
have more consistent decline rates than conventional wells, as demonstrated by the
lower standard deviations for the decline rates for unconventional wells in Table 1.
According to industry participants, unconventional wells are more expensive to
drill and complete than conventional wells, so the gain in physical well productivity
14
17. also comes with higher costs. The primary costs associated with developing an
oil or gas well are associated with renting rigs during the drilling and completion
stages. These expenses depend on the amount of time the rigs are working on site,
which depends in turn on the depth of the well and the length of its laterals, also
summarized in Table 1. Average lateral lengths have been rising at a remarkably
linear pace over that period (not shown), from about 2,000 feet in 2005 to about
6,000 feet in 2015, with an average of about 4,000 feet over the full sample period.
Further, in section III.C we consider the length of time between spudding and first
production, which is greater for unconventional wells due to the extra steps required
to hydraulically fracture the well: unconventional gas wells begin producing within
4.7 months, on average, compared to 2.5 months for conventional gas wells.
Figure 2 shows the production profiles for two typical gas wells in our data, both
of which began producing in 2007. The unconventional well is located in Johnson
County, TX, overlaying the Barnett shale play. The conventional well is located in
Shelby County, TX, in the East Texas Basin. This graph and Table 1 illustrate that
while the level-decline in gas production is larger for the unconventional well, the
conventional and unconventional wells have quite similar percentage decline rates.
As shown in Table 1, after 12 months of production, the mean unconventional well’s
gas flow has fallen by about 40,000 mcf from its peak of 68,000 mcf, a drop of 59
percent. In the same amount of time, the mean conventional well’s production fell
by about 17,000 mcf from its peak of about 30,000 mcf, which is a comparable 56
percent reduction.
Figure 3 describes the number of new spuds each quarter of our data from 2000
to 2015 by well type (conventional versus unconventional gas wells), and the spud
15
18. Months Since Initial Production
MonthlyGasProduction(mmcf/month)
0 6 12 18 24 30 36 42 48 54 60 66 72 78 84 90 96 102 108
010203040506070
Unconventional Gas Well
Conventional Gas Well
Figure 2: Production Profile of Typical Gas Wells
Sources: Authors’ calculations based on data from Drillinginfo and EIA
counts are plotted along with natural gas and oil prices.15
The figure reveals that
the wells we have classified as unconventional are indeed a recent phenomenon,
supporting our classification method. Following the massive increase in uncon-
ventional drilling and collapse in gas prices, conventional gas wells have all but
disappeared.
As shown in the figure, gas drilling fell dramatically after the collapse of gas
prices in 2008. Natural gas prices continued to decline in the subsequent years,
during which the number of conventional gas wells drilled fell by 70 percent, while
15
Oil prices represent West Texas Intermediate (WTI) prices, divided by 5.8 to convert to dollars
per million British thermal units. Both oil and gas prices are the simple average of the next 12
months of futures prices in real 2014 dollars.
16
19. 0510152025
Year
HenryHub/WTIPrice($/mmbtu)
2000 2002 2004 2006 2008 2010 2012 2014
Gas Prices (left)
Oil Prices (left)
0500100015002000
WellsDrilled
Unconventional Gas Spuds
Conventional Gas Spuds
Total Gas Spuds
Figure 3: Number of Spuds by Well Type (right axis) and Oil & Gas Prices (left
axis), 2000-2015, Quarterly
Sources: Authors’ calculations based on data from Drillinginfo, EIA, and Bloomberg
unconventional wells drilling fell by about 8 percent.16
We explore the reasons for
this asymmetric relationship in detail in section III.
Figure 4 shows trends in the productivity of unconventional and conventional
gas wells from 2000 to 2015 (2005-2015 for unconventional, as explained at the
beginning of this subsection), measured by the average first full month of produc-
tion of all wells drilled in the prior two quarters.17
The figure shows the increase
in average unconventional well productivity, which has nearly doubled since 2005.
16
These numbers are the changes in total wells drilled for each well type in 2012, relative to 2010.
17
We use a two-quarter average to avoid the noise that would be created by focusing only on wells
drilled in individual months, some of which involve small numbers of observations, particularly
given the small number of of conventional wells drilled in recent years as illustrated in Figure 3.
17
20. This productivity improvement demonstrates how, for a given price of gas, each un-
conventional well has generated increasing revenue, and thus how focusing solely
on gas prices can misstate changes in the revenues gained from drilling.
To conclude, while the data focus on only Texas gas wells, these figures and
summary statistics illustrate that our dataset is consistent with commonly-discussed
trends in the industry and detailed conversations with industry participants.
020406080100
Year
InitialGasProduction(mmcf/month)
2000 2002 2004 2006 2008 2010 2012 2014
Unconventional Gas Wells
Conventional Gas Wells
All Gas Wells
Figure 4: Average Gas Production Per Well During the First Full Month, 2000-
2015, Quarterly
Sources: Authors’ calculations based on data from Drillinginfo and EIA
18
21. III Models and Results
III.A Overview
We divide our analysis of the natural gas production process into three stages: the
decision to commence drilling (or “spud”) a well, how quickly to complete and
start production at a well (conditional on spudding), and how quickly to extract gas
from the well (conditional on first producing a well). We describe our analysis of
the spud decision in section III.B, the completion and production start decision in
section III.C, and the profile of the quantity produced in section III.D. Finally, we
integrate the analysis of each of these different stages in section III.E.
III.B Stage 1: Commence Drilling (Spud) a Well
III.B.1 Drilling Estimation Method
Our empirical specification represents drilling activity as a log-linear approximation
of the expected profits from drilling, which is a function of the expected present
value of the future stream of revenues and costs associated with different types of
gas wells. Recall that gas wells may produce oil in addition to gas (see Table 1),
meaning that oil prices may affect the incentive to drill gas wells.
We estimate the relationship in first differences because both drilling activity
and our oil & gas revenue variables are non-stationary time series, while they are
stationary after taking first differences. This leads to the following specification for
the number of gas wells drilled:
∆ ln(wt) = β0 +
L
l=0
[β1,l∆ ln(˜pgas,t−l ˜qgas,t−l) + β2,l∆ ln(˜poil,t−l ˜qoil,t−l)]+γ (∆Xt)+εt (1)
19
22. where wt represents the number of wells that are spudded during period t, which is
measured in quarters. Expected revenue in each period is equal to a well’s expected
cumulative output of gas and oil (denoted ˜qgas,t and ˜qoil,t respectively) multiplied
by the price (˜pgas,t and ˜poil,t) expected to be received for each type of output (in
present value equivalents). Xt is an optional vector of cost controls for wells drilled
in period t (all measured in logs). The primary parameters of interest are β1,l, which
represent the l-lagged elasticity of gas well drilling. We include L = 2 quarterly
lags of the revenue variables to account for the fact that drilling a well takes time
due to the need to obtain mineral rights, drilling permits, contracts with drilling
service companies, and transport drilling rigs to well sites. In this specification, the
long-run drilling elasticity with respect to gas prices18
is given by L
l=0 β1,l.
The advantage of using expected revenue as an explanatory variable, rather than
simply gas and oil prices as in many other studies, is twofold. First, it more closely
reflects the reality that the incentive to drill a well depends on the well’s total rev-
enue, which depends in turn on the well’s overall productivity rather than the price
of one unit of its output. Second, the changes to well productivity contribute an
additional source of revenue variation in the data. Intuitively, a 10 percent increase
in production has the same revenue impact as a 10 percent increase in output prices.
For the expected future prices of gas and oil ˜pt, we use the simple average of the
next 12 months of futures prices for Henry Hub natural gas and WTI oil, adjusted
for inflation (see section II.B). This captures the fact that drilling decisions yield a
stream of production (and profits) over the course of the coming months into the
18
We do not distinguish between “revenue” or “price” elasticities since they are equivalent, due to
the equality β1,l ln(˜pgas,t−l ˜qgas,t−l) = β1,l ln(˜pgas,t−l) + β1,l ln(˜qgas,t−l). Intuitively, a 1 percent
increase in prices is equivalent to a 1 percent increase in revenues, holding productivity constant.
20
23. future. Due to discounting and the relatively rapid decline in production from oil
and gas wells (see Table 1), much of the present value revenue from oil and gas
wells depends on prices in the first year or so of production.19
Because we do not observe each firm’s expectations about well productivity
(˜qgas,t and ˜qoil,t), we proxy for it using the measure of recent gas well productivity
described in section II.C and plotted in Figure 4.20
Our preferred specifications do
not include controls, but including average well depth and lateral lengths as cost
controls has little effect on the results.21
Studies of U.S. oil supply elasticities have typically not instrumented for oil
prices based on the historically plausible argument that incremental production
from the United States (and Texas in particular) is small relative to the global oil
market. This argument is less sound for natural gas, which is primarily a North
American market and has been strongly affected by the shale gas boom. In addi-
tion, the shale revolution has arguably played some role in the drop in oil prices
in 2014 and 2015, raising new concerns about the endogeneity of oil prices. For
these reasons, we instrument for both of our contemporaneous oil and gas revenue
variables.22
19
Conversations with industry participants also confirm that using futures prices is a reasonable
approach for two other reasons: producers often look to futures markets for price expectations and/or
hedge their output prices (at least for their wells’ initial and most productive months).
20
Specifically, we use the average initial production values (first full month) for wells drilled in
the prior two quarters. Because production profiles decline quickly (Table 1), production in the
first full month is a fairly reliable indicator of a well’s long-term productivity. The correlation
between first-month production and first-year production is 0.89, and for mature wells in the data
that have produced the vast majority of their output, the correlation between first-month production
and cumulative production is 0.72.
21
The cost measures chosen are intuitive and comport with suggestions from industry operators.
22
We do not instrument for lagged revenues. For 1- and 2-quarter lagged oil and gas prices to be
potentially endogenous, one must argue that traders can anticipate changes in drilling activity and
hence production as far as 9 months in advance and for prices to immediately adjust based on those
21
24. We use four instruments: U.S. population-weighted heating degree days (HDD),
cooling degree days (CDD), lagged U.S. working gas inventories, and copper prices.23
We include both contemporaneous values and up to three quarterly lags of these in-
struments, with the exception of gas inventories for which we only use the lagged
values because the contemporaneous value is likely endogenous to gas prices.
The first three instruments are standard gas demand shifters. The final instru-
ment, copper prices, is included as a proxy for global commodity demand to instru-
ment for oil prices, inspired by Hamilton (2014). Indeed, the copper and oil prices
are highly correlated (0.92 in levels and 0.71 in log-differences during 2000 Q1 -
2015 Q3), suggesting that the price of copper is a reasonable proxy for commodity
demand shocks that also affect oil demand. Unless otherwise noted, all results are
estimated using two stage least squares (2SLS).
To show the importance of the instruments and of the non-stationarity of the
time series, we also present un-instrumented and un-differenced results. We also
present estimation results separately for unconventional and conventional gas wells
to test whether the drilling response is different for unconventional wells. The sam-
ple period begins in 2000 Q1 and ends 2015 Q3, and the unit of observation is one
quarter. All standard errors are HAC robust.
anticipations. Given that we are using quarterly data and that drilling activity is generally considered
very difficult to forecast, we find this argument implausible and treat lagged revenues as exogenous.
23
HDD, CDD, and gas inventory data is from EIA, available at http://www.eia.gov/
forecasts/steo/query/. Copper prices are the average of the futures strip in 2014 dollars,
collected from Bloomberg.
22
25. III.B.2 Drilling Estimation Results
Table 2 shows the results of estimating equation (1). The first three rows report the
estimated price elasticity of drilling for 0, 1, and 2 quarterly lags of gas revenues.
The sum of these effects is the long-run price elasticity (and revenue elasticity more
generally), also reported in the middle of the table along with standard errors. Our
preferred specification is the simplest one, found in column (1), finding a long-
run drilling elasticity of 0.66, significant at the 1 percent level.24
Column (2) adds
cost controls, average vertical depth and lateral lengths, to the specification; these
controls have little effect on the magnitude or significance of the long-run elasticity.
Columns (3) and (4) show results from re-estimating equation (1) separately for
unconventional and conventional gas wells, including computing well productivity
and revenues separately for each of these well types.25
Despite using very different
drilling activity and productivity variables (e.g., see Figures 3 and 4), the estimated
elasticities (0.64 and 0.65) are very similar to each other and to the result found for
both well types combined (0.66) shown in column (1). From this we conclude that
there is no meaningful difference between the drilling elasticity for unconventional
and conventional gas wells, supporting our preferred specification in column (1).
Column (5) shows the results of estimating the relationship without instruments.
The long-run elasticities are somewhat smaller, as would be expected with endoge-
nous gas and/or oil prices. Indeed, the Wu-Hausman tests reject the null of no
endogeneity in every specification. Moreover, Sargan tests cannot reject the null
24
This result is robust to using simple prices instead of our revenue variables. We still prefer to
use our revenue variables because we believe they are more accurate depictions of firm incentives.
25
For column (3)–the unconventional-only estimation–we focus on the 2005-2015 sample period
for the reasons described above. Further, the small number of unconventional wells in the early
2000s leads to noisy and unreliable productivity estimates for revenues before 2005.
23
26. that our overidentifying restrictions are valid,26
. This supports the need for and
validity of the IV approach and our preference for the specification in column (1).
Columns (6) and (7) show the results of estimating the model in levels, with and
without instruments. Given the non-stationarity of the time series, this approach
would tend to be biased towards finding a large and spurious relationship, and in-
deed we find a long-run gas drilling elasticity naively estimated to be approximately
1.6. Ignoring the non-stationarity of the time series thus threatens to significantly
overstate the gas elasticity.
In addition, the estimated relationship of gas drilling to oil prices changes sign
when estimating in levels. Oil prices were high during the 2009-2014 period, dur-
ing the time when aggregate gas drilling declined (mostly conventional, arguably
due to falling gas prices, see Figure 3), creating a negative correlation between gas
drilling and oil prices in levels. Taking differences avoids naively interpreting these
diverging, non-stationary trends as causal and identifies a positive relationship be-
tween oil prices and gas drilling. Further, the elasticity with respect to oil prices is
similar in size to the elasticity with respect to gas prices, consistent with operators
being indifferent between the gas-versus-oil composition of their revenue streams.
Our estimate, 0.66, is similar to those derived from other recent sources. Haus-
man and Kellogg (2015) estimate a long-run drilling elasticity of 0.81 using a dif-
ferent methodology and smaller sample.27
In addition, the long-run gas supply
elasticity implied by the EIA’s Annual Energy Outlook 2015 is approximately 0.5.
26
Based on 2 endogenous variables (gas and oil revenues) and 15 instruments: 0-3 lagged differ-
ences of HDD, CDD, and copper prices, along with 1-3 lagged differences of gas inventories.
27
That paper estimated the relationship in levels, rather than differences, which may in part ex-
plain their somewhat higher elasticity. Among other differences between our analyses, they used a
different data source that could not distinguish between unconventional and conventional drilling.
24
27. In the next two sections we build on the analysis of the drilling decision assessed
in this section and consider the subsequent stages of the production process. In sec-
tion III.C we analyze the amount of time it takes for a well to begin producing once
it is drilled. In section III.D we analyze the time profile of wells’ gas production.
III.C Stage 2: Spud-to-Production Time
III.C.1 Duration Model
Once a well is spudded, production does not typically begin until at least a month
later (see Table 1), and we find that there is considerable variation in how long
each well takes to reach initial production. After spudding the well, the time to
finish drilling the well depends on factors like well depth and the length of well
laterals. The completion stage follows the drilling stage and may require artificially
fracturing the well, which also increases the time to production. After completion,
the well can begin producing natural gas and oil. Other factors that might influence
completion times are fuel prices—whereby operators work faster when prices are
higher to achieve revenues earlier—and logistics like renting a completion rig.
Figure 5 shows non-parametric kernel density estimates of the distributions for
the spud-to-production time, separately for conventional and unconventional gas
wells. Consistent with Table 1, unconventional wells tend to take longer to reach
production, due to the additional labor required to horizontally drill and fracture.
To estimate the distribution of spud-to-completion times as a function of prices,
we use duration models (i.e., survival time or hazard models) with time-varying
coefficients. Denote the hazard function of well i of type j (conventional or uncon-
ventional) and beginning production t months after it was spudded by:
25
28. Table 2: Drilling Estimation Results
Dep. Var: Log(Wells Drilled) (1) (2) (3) (4) (5) (6) (7)
Log(Gas Revenues) 0.28 0.26 0.27 0.28 0.14 1.00 0.60
(0.15) (0.17) (0.14) (0.22) (0.09) (0.27) (0.09)
Log(Gas Revenues), 1 Lag 0.30 0.24 0.33 0.33 0.34 0.00 0.38
(0.1) (0.09) (0.17) (0.12) (0.09) (0.18) (0.1)
Log(Gas Revenues), 2 Lags 0.08 0.07 0.05 0.04 0.01 0.65 0.55
(0.13) (0.11) (0.15) (0.13) (0.09) (0.1) (0.04)
Log(Oil Revenues) 0.39 0.45 0.37 0.41 0.19 0.23 0.16
(0.17) (0.16) (0.17) (0.15) (0.11) (0.41) (0.09)
Log(Oil Revenues), 1 Lag 0.02 -0.02 -0.04 0.02 0.11 -0.21 -0.07
(0.15) (0.12) (0.14) (0.11) (0.12) (0.33) (0.05)
Log(Oil Revenues), 2 Lags 0.15 0.25 0.25 0.12 0.14 -0.28 -0.35
(0.15) (0.16) (0.18) (0.12) (0.16) (0.11) (0.07)
Log(Average Vertical Depth) -2.50
(0.85)
Log(Average Lateral Length) 0.41
(0.14)
Constant -0.06 -0.05 -0.05 -0.05 -0.05 -6.36 -5.23
(0.03) (0.03) (0.05) (0.02) (0.03) (0.52) (0.24)
Observations (Quarters) 63 63 43 63 63 63 63
R-Squared 0.37 0.44 0.26 0.44 0.46 0.68 0.70
Adj. R-Squared 0.30 0.36 0.14 0.38 0.41 0.65 0.67
Long-Run Gas Price Elasticity 0.66 0.56 0.64 0.65 0.50 1.65 1.53
(0.22) (0.22) (0.26) (0.29) (0.14) (0.08) (0.03)
Long-Run Oil Price Elasticity 0.56 0.68 0.58 0.56 0.44 -0.27 -0.27
(0.24) (0.25) (0.32) (0.22) (0.23) (0.03) (0.02)
Estimation Method 2SLS 2SLS 2SLS 2SLS OLS 2SLS OLS
Variables in levels or differences? Diffs. Diffs. Diffs. Diffs. Diffs. Levels Levels
Wells Included All Gas All Gas
Unconv.
Gas
Conv.
Gas
All Gas All Gas All Gas
First-stage F statistics
Gas Revenues 7.50 9.79 7.68 2.81 na 3.31 na
Oil Revenues 4.92 3.75 7.19 2.11 na 13.84 na
p-value, Wu-Hausman test for endogeity 0.009 0.017 0.022 0.000 na 0.000 na
p-value, Sargan overidentification test 0.480 0.318 0.334 0.732 na 0.119 na
HAC standard errors in parentheses. Sample period is 2000-2015, quarterly, with the exception of (3) which is estimated over 2005-2015
because that is when the shale gas boom began in earnest. Instruments are Cooling Degree Days (CDD), Heating Degree Days (HDD), copper
prices, and gas inventories. With the exception of gas inventories, contemporaneous and 1-3 lagged values are used as instruments.
Contemporaneous gas inventories are not used, as these are likely endogenous to gas prices. All variables are in differences with the exception
of (7) and (8). In (3) and (4), the computation of revenues is performed separately for unconventional and conventional wells to account for
differences in productivity trends between these types of wells.
Sources: Authors’ calculations based on data from Drillinginfo, EIA, and Bloomberg
h(t, Xi,j,t, θj) =
f(t, Xi,j,t, θj)
1 − F(t, Xi,j,t, θj)
, (2)
26
29. 0.00.10.20.30.4
Months From Spud to Production
Density
0 2 4 6 8 10 12 14 16 18 20 22 24
Unconventional Gas
Conventional Gas
Density
Mean
Figure 5: Non-parametric Densities of Time from Spud to Initial Production, by
Well Type
Sources: Authors’ calculations based on data from Drillinginfo and EIA
where f(t, Xi,j,t, θj) is the density function of the spud-to-production time, and
F(t, Xi,j,t, θj) is the corresponding cumulative distribution function. Xi,j,t is a
vector of explanatory variables, some of which may change over time (for example,
gas and oil prices can and do change over time). Hence, the hazard function de-
scribes the probability that a well with characteristics Xi,j,t will begin production t
months after it was spudded, given that it has not yet begun producing.
We estimate this model using maximum likelihood by assuming an underlying
density f(·) to specify the form of the baseline hazard function. We focus on us-
ing the generalized gamma distribution, which is a very flexible distribution that is
27
30. parameterized by two ancillary parameters determining the shape of the distribu-
tion.28
We found that the gamma distribution results in an estimated distribution
that closely resembles the non-parametric distributions shown in Figure 5 and also
yields a significantly higher log-likelihood than other alternatives.29
A hazard model estimated with the gamma distribution is parameterized in an
“accelerated failure time” (AFT) setup. In this setup, the explanatory variables can
be interpreted as additively affecting the observation’s logged expected “failure”
time, which here is the time it takes for a spudded well to reach production. This
implies that if an increase in gas prices encourages operators to work faster to speed
up the time of production, this would be represented as a negative coefficient in the
AFT model (i.e., reducing the time to production).
We estimate the hazard models for each unconventional and conventional wells
independently, with no cross-equation restrictions. This allows each well type to
have its own distribution, in addition to its own estimated parameters. As in the
drilling regressions in section III.B, the explanatory variables include (in logs): ex-
pected revenue from gas and oil production,30
and cost controls of well depths and
28
The density of the gamma distribution is given by,
f(t) =
γγ
σt
√
γΓ(γ) exp(z
√
γ − u) if κ = 0
1
σt
√
2π
exp(−z2
/2) if κ = 0,
where γ = |κ|−2
, z = sign(κ)(ln(t) − µ)/σ, u = γ exp(|κ|z), Γ(·) is the gamma function, and we
parameterize µ = Xi,j,tθj. We estimate the ancillary parameters σ and κ from the data.
29
We test the Weibull, exponential, Gompertz, Log-normal, and Log-logistic distributions. Sev-
eral of these distributions are special cases of the gamma distribution (namely, the Weibull, expo-
nential, and log-normal distributions). For those nested distributions we can test for whether the
gamma distribution’s better fit is statistically significant: we find it is in all cases. We also compared
the results to a Cox proportional hazards model, which leaves the baseline hazard unspecified: the
key estimates were generally in the same directions and of similar relative sizes.
30
As before, the results are robust to simply using gas and oil prices, but we use the revenue
variables as we believe they are more accurate depictions of firms’ incentives. We do not use in-
strumental variables as the theoretical and empirical literature for implementing them in duration
28
31. lateral lengths. We also explore the possibility that spud-to-completion times are
affected by drilling experience by including a cumulative count of unconventional
gas wells drilled as another control.
The unit of observation is a well-month, which means we can use well-specific
characteristics (lateral length and well depth) rather than the means across wells
used in the drilling equations of the prior section. Nonetheless, even though we ob-
serve wells’ realized production, we do not use it because firms do not know with
certainty how productive a well will be until it actually starts producing. Hence, us-
ing the well’s actual, ex post production as an explanatory variable would imply that
the firm responds to unobservable information. Instead, we use the same method of
calculating productivity and revenues used in the drilling equations.31
In the termi-
nology of hazard analysis, we consider a well to be “at risk” of being produced for
24 months following its spud month, at which point it exits our sample.32
III.C.2 Spud-to-Production Duration Estimation Results
Table 3 shows the estimates of the duration models. Our preferred estimates are
again the simplest ones, shown in columns (1) and (4) for unconventional and con-
ventional wells respectively. The first coefficient reported in column (1) is -0.172,
indicating that a 10 percent increase in the gas price (or revenues more generally)
is expected to reduce the time to production for an unconventional well by less than
2 percent. Across columns (1) through (3), unconventional wells have generally
models is very limited. We are aware of only one published paper, MacKenzie et al. (2014), that
considers the implementation of instrumental variables in duration models; that study only applies
to a Cox proportional hazard setup, as opposed to the accelerated failure time model that we use.
31
Since we conduct the hazard analysis at the monthly level, average revenues are calculated on a
monthly basis, rather than quarterly.
32
We chose 24 months for the reasons described in section II.B
29
32. consistent price response coefficients between -0.06 and -0.17. The corresponding
responses for conventional wells, found in columns (4) through (6), are somewhat
more modest, with coefficients in the range of -0.08 to -0.10.33
Table 3: Spud-to-Production Duration Model Results
(1) (2) (3) (4) (5) (6)
Spud-to-Production Survival Time Unconventional Gas Wells Conventional Gas Wells
Log(Gas Revenues) -0.172 -0.113 -0.0576 -0.0754 -0.0974 -0.0889
(0.0148) (0.0143) (0.0152) (0.00821) (0.00819) (0.00831)
Log(Oil Revenues) 0.0275 -0.0209 -0.0498 0.0855 0.0786 0.0228
(0.00340) (0.00381) (0.00500) (0.00613) (0.00593) (0.0110)
Log(Vertical Depth) -0.0217 -0.0297 0.226 0.222
(0.0163) (0.0162) (0.00745) (0.00746)
Log(Lateral Length) 0.187 0.18
(0.00472) (0.00470)
Log(Cum. Unconv. Gas Spud Count) 0.102 0.035
(0.0112) (0.00592)
Constant 2.856 1.371 0.235 0.992 -0.82 -0.791
(0.160) (0.214) (0.235) (0.0743) (0.0948) (0.0947)
Gamma Density Function Parameters
! 0.48 0.46 0.46 0.51 0.49 0.49
" -0.55 -0.60 -0.60 -0.66 -0.74 -0.74
Well-Months (N*T) 146,859 146,736 146,736 126,990 126,990 126,990
Wells (N) 25,725 25,701 25,701 36,055 36,055 36,055
Log-Likelihood -19,025 -18,130 -18,087 -29,148 -28,555 -28,536
p-value on test of equal unconv./conv. gas elasticities <0.0001 0.33 0.07
Clustered standard errors in parentheses. Standard errors are clustered at the well level. Coefficients can be interpreted as elasticities of expected
spud-to-completion time.
Sources: Authors’ calculations based on data from Drillinginfo, EIA, and Bloomberg
Increases in oil revenues seem to slightly discourage conventional natural gas
efforts, potentially representing a substitution effect, while having more muted and
ambiguous effects on unconventional effort. The coefficient on lateral lengths sensi-
bly indicates that unconventional wells with longer laterals take longer to reach pro-
duction, consistent with longer drilling and completion periods. Well depth plays an
analogous role for conventional wells: deeper wells take longer to reach production.
The “learning” proxy variable (unconventional spud counts) has a counter-intuitive
sign in the unconventional equation in column (3). However, this variable grows
33
These results are robust to including lagged oil and gas revenues. The coefficients on the lagged
values were small and generally insignificant. The sum of the contemporaneous and lagged coeffi-
cients were very similar to the coefficients reported in Table 3.
30
33. roughly linearly in time, and it therefore acts similarly to a time trend, and is there-
fore ambiguous to interpret. It is indicative that spud-to-production times have not
obviously fallen with experience. Indeed, the average spud-to-production time for
unconventional wells during 2005-2009 was 4.1 months, compared to 5.2 months
for 2010-2015. This positive coefficient on the cumulative spud counts cannot en-
tirely be explained by longer lateral lengths, because this variable is included in
equation (3). Regardless, these controls do not substantially affect the qualitative
conclusions regarding the price responsiveness of spud-to-production times.
The shape of the gamma distribution of spud-to-production time is also esti-
mated in the model, separately for each well type. The resulting shapes are plotted
in Figure 6 at covariate means, along with the same non-parametric, kernel den-
sity estimate of the underlying distribution shown in Figure 5. The fitted gamma
distributions strongly resemble the non-parametrically estimated densities, suggest-
ing that the gamma distribution fits the true baseline hazard distribution well and
is not driving the coefficient estimates. The estimated shape also demonstrates that
monotonic functional forms (exponential, Gompertz, Weibull) would be inappro-
priate. While the gas price response coefficients are precisely estimated and their
signs are consistent with economic expectations, they are small. For example, in
order to achieve a 10 percent reduction in spud-to-production time for conventional
wells, gas prices would have to nearly triple. For the more-responsive unconven-
tional wells, gas prices would have to nearly double.34
This lack of strong price response is illustrated in Figure 7. That figure plots
the parameterized gamma distributions for each well type under alternative natural
34
These required price changes represent the change in gas prices needed to shift the fitted distri-
bution, computed at covariate means, such that the mean of the distribution decreases by 10 percent.
31
34. 0.00.10.20.30.4
Months From Spud to Production
Density
0 2 4 6 8 10 12 14 16 18 20 22 24
Unconventional Gas
Conventional Gas
Non−parametric
Fitted Gamma
Figure 6: Estimated Spud-to-Production Time Distribution, by Well Type
Sources: Authors’ calculations based on data from Drillinginfo, EIA, and Bloomberg
gas price assumptions of $3.00 and $6.00 per million Btu.35
The effects are not
large. Despite an assumed doubling of natural gas prices, the effect on the spud-to-
production time distribution is modest.
These results suggest that once drilling has commenced, gas prices do not strongly
influence the decision about whether and how fast to begin producing a well. This
is sensible, since once drilling has begun, much of the well development costs have
been sunk. There also may be limited opportunities for speeding up the completion
35
This figure assumes 2015 average productivity values and a $50 per barrel oil price.
32
35. process beyond a certain point.36
With low additional marginal costs of production,
operators typically have strong incentives to begin production as soon as possible.0.00.10.20.30.4
Months From Spud to Production
Density
0 2 4 6 8 10 12 14 16 18 20 22 24
Unconventional Gas
Conventional Gas
Baseline ($3.00 per mcf)
Shock ($6.00 per mcf)
Figure 7: Illustration of Gas Price Effect on Spud-to-Production Time, by Well
Type
Sources: Authors’ calculations based on data from Drillinginfo, EIA, and Bloomberg
III.D Stage 3: Production Profile over Time
III.D.1 Production Profile Estimation Method
The final stage of the gas production process is the flow of gas from wells once they
begin producing, and how that flow evolves over time. In this section, we estimate
the time profile of well-level gas production and its relationship with prices.
36
Although there is always the option to slow down or stop the completion process in the face of
low prices, this may not save costs if service contracts are already in place.
33
36. Once a well begins producing, it often produces gas and oil for many years, with
the production profile being determined principally by reservoir pressure. Because
the variable cost of production from an existing well is very low, an operator would
typically want to produce oil and gas at a well’s capacity. For this reason, we would
not expect gas and oil prices to have a significant effect on production from existing
wells by a competitive firm. Instead, a well’s flow rate is largely determined by the
amount of pressure left in the reservoir to force the resource to the surface. The
flow rate is therefore generally out of the operator’s control.37
These arguments are
analyzed at an aggregate level for oil in Anderson, Kellogg and Salant (2014), and
we find similar results for gas at the well level.
Even if production from existing wells is not price responsive itself, understand-
ing the time profile of production is nonetheless still important to understanding
aggregate supply responsiveness. This is because these profiles determine the rela-
tionship between drilling effort and realized production over time, and production
profiles are quite different for unconventional versus conventional wells.
As described further in the next section, our estimates show a lack of price
response of output from existing gas wells using a detailed panel dataset describing
monthly gas production for each well’s productive life. Specifically, we run fixed-
effects regressions of the form:
ln(qi,gas,j,t) = χi + ηgas,j ln(pgas,t) + ηoil,j ln(poil,t) + gj(Agei,t) + εi,j,t, (3)
37
There are some exceptions. Firms can extract more hydrocarbons through investments in en-
hanced recovery methods like pumps (for oil) and various injection methods. For unconventional
reserves, firms have the added option to re-fracture the well, which can create new fissures that
release more hydrocarbons to the surface.
34
37. where i indexes the well and t indexes the calendar time in months. qi,gas,j,t is the
gas production from well i of type j in month t. χi is a well-level fixed effect,
which can roughly be interpreted as initial (log) production for well i. pgas,t and
poil,t are prompt-month gas and oil prices. The parameters of interest are ηgas,j de-
scribing the contemporaneous price elasticity of gas production from a well (of type
j) that has already been drilled. We use spot (i.e., prompt-month) oil and natural gas
prices because of the immediate nature of the potential price response from existing
wells.38
Given the well-level fixed effects, our identification of the price response
comes from changes in prices during the life of a well. The discussion above and
prior evidence suggests that this parameter would be estimated as being close to
zero. Regardless, the different production profiles of wells can still be consequen-
tial for the overall supply responsiveness to prices because this stage is conditioned
on the earlier drilling decision, which we found above is responsive to price.
Agei,t is the age of well i at time t (i.e., the number of months since it began
production). gj(Agei,t) is a function of the age of a well of type j, and we allow
for flexible production profiles by approximating this function using polynomials
of varying degrees as well as a cubic spline.39
We conduct specification tests to
select among these alternative flexible functional forms. We drop the first month of
production, as wells are often only operating for a fraction of this month, instead be-
ginning with the first full month of production. The age function is indexed by j to
allow the average production profile to vary based on well type (i.e., unconventional
versus conventional). Standard errors are clustered at the well level.
38
Using lagged prices does not substantially affect the results.
39
The cubic spline uses knots at every 12-month interval after initial production.
35
38. III.D.2 Production Profile Estimation Results
Table 4 contains the results for the fixed effects regressions for unconventional and
conventional gas wells. Consistent with the above discussion, we find very small
coefficients on natural gas prices, suggesting that gas production from existing wells
is not price responsive. The elasticity point estimates are small, typically ranging
between +0.09 and -0.04 (with one exception in column (5), discussed below), all
very close to zero and often of a theoretically implausible sign. The same is true
for oil price coefficients, which are generally very close to zero and occasionally
insignificant despite small standard errors.40
The substantial size of our dataset (over 5 million well-month observations for
conventional and unconventional wells combined) generates very small standard
errors. As a result, even many of these very small estimates (e.g., smaller than 0.02
in magnitude) are nevertheless significant at the 1 percent level. These negligible
elasticity estimates are generally robust to variations in the functional form describ-
ing the decline path. Polynomials of orders one through four and cubic splines
produce similar results. The linear-in-age specification in column (1) is probably
insufficiently flexible because production is commonly observed to decline slower-
than-exponentially (as captured by a positive “b” parameter in the Arps equation),
and a linear specification effectively assumes an exponential decline. We find sup-
port for slower-than-exponential declines in the significant positive coefficient on
the well-age-squared terms in columns (2) through (4). We also include a specifi-
cation using log(Agei,t), following Patzek, Male and Marder (2013) who argue for
40
Excluding oil prices from the specification completely (not shown) also has little effect on the
results, except in column (1), where it shrinks the gas price coefficients even closer towards zero.
36
39. Table 4: Well Production Profile Fixed Effects Regressions
Dep. Var.: Log(Gas Production) (1) (2) (3) (4) (5) (6)
Unconventional Wells
Log(Gas Price) 0.09 -0.01 -0.04 -0.03 0.08 -0.04
(0.009) (0.009) (0.008) (0.008) (0.009) (0.008)
Log(Oil Price) -0.07 0.04 0.01 0.01 0.03 0.01
(0.006) (0.006) (0.006) (0.006) (0.006) (0.006)
Well Age (months) -0.021 -0.044 -0.067 -0.086
(0.000131) (0.000276) (0.000476) (0.000749)
Well Age^2 (months) 0.00023 0.00076 0.00153
(0.000003) (0.00001) (0.000028)
Well Age^3 (months) -0.0000032 -0.0000136
(0.0000001) (0.0000004)
Well Age^4 (months) 0.00000004
(0.000000002)
Log(Well Age) -0.679
(0.00302)
Conventional Wells
Log(Gas Price) 0.09 -0.01 0.03 0.03 0.23 0.04
(0.006) (0.005) (0.005) (0.005) (0.005) (0.005)
Log(Oil Price) -0.19 0.01 0.01 0.02 -0.05 0.01
(0.005) (0.005) (0.005) (0.005) (0.005) (0.005)
Well Age (months) -0.017 -0.035 -0.052 -0.069
(0.000077) (0.000168) (0.000282) (0.000433)
Well Age^2 (months) 0.00011 0.00039 0.00085
(0.000001) (0.000004) (0.000011)
Well Age^3 (months) -0.0000011 -0.0000054
(0.00000002) (0.0000001)
Well Age^4 (months) 0.00000001
(0.0000000003)
Log(Well Age) -0.763
(0.00241)
N (Well-Months) 5,331,586 5,331,586 5,331,586 5,331,586 5,331,586 5,331,586
Number of Wells 62,568 62,568 62,568 62,568 62,568 62,568
Well Fixed Effects ü ü ü ü ü ü
Cubic Spline ü
R-Squared (Full Model) 0.744 0.759 0.762 0.763 0.762 0.764
R-Squared (Excluding Fixed Effects) 0.352 0.388 0.397 0.400 0.396 0.401
Clustered standard errors in parentheses. The first month of each well's production is dropped, as wells are typically operational for only
a fraction of its first month.
Sources: Authors’ calculations based on data from Drillinginfo, EIA, and Bloomberg
37
40. such a specification for unconventional gas wells in the Barnett shale formation, a
subset of our data.41
In general, we do not find a positive price response of gas production from ex-
isting wells. To our knowledge, this is the only published study that finds empirical
evidence for this proposition using well-level data. Because the negligible observed
price response from existing wells comports with both structural economic factors
and empirical evidence, we proceed to model production from existing wells as
completely unresponsive to price. This assumption also allows us to model well
production profiles non-parametrically in our combined model in Section III.E.
To represent the production profile from unconventional and conventional wells,
we use the mean monthly production in our dataset by well age. For example, to
estimate the production from an average unconventional well in its 7th
month of
production, we calculate the average production from every unconventional well
in our dataset during its 7th
month.42
The results of this procedure are illustrated
in Figure 8. The solid lines in that figure represent the mean production profile of
unconventional (orange) and conventional (gray) wells. The dashed lines represent
the median production profiles.
41
Patzek, Male and Marder (2013) specifically argue that the coefficient on log(Agei,t) should
be approximately -0.50 for unconventional gas wells, but we find a somewhat larger coefficient of
-0.68. If we include each wells’ first, partial month of production, we find an estimated coefficient
of -0.52, very close to -0.50. However, including the first, partial month is inappropriate when fit-
ting parametric decline curves, as an inspection of Figure 8 suggests. Regardless, our finding of no
meaningful price response is generally robust to including wells’ first, partial months. The only spec-
ification with an economically meaningful gas price response estimate is the one using log(Agei,t)
for conventional reservoirs, which is likely inappropriate because Patzek, Male and Marder (2013)
only advise using that functional form for unconventional Barnett wells, not conventional ones.
42
For each well that has ceased production before the end of our sample period, we impute zero
production in each month after its last month of production when calculating this average.
38
41. Months Since Initial Production
MonthlyGasProduction(mmcf/month)
0 6 12 18 24 30 36 42 48 54 60 66 72 78 84 90 96 108 120 132
01020304050607080
Unconventional Gas
Conventional Gas
Mean
Median
Figure 8: Mean and Median Profile of Monthly Gas Production from Gas Wells
Sources: Authors’ calculations based on data from Drillinginfo and EIA
These production profiles reflect the well characteristics presented in Table 1.
The mean and median unconventional production profiles strongly resemble each
other, suggesting that unconventional gas production profiles are generally not very
skewed in productivity. In contrast, the median conventional well produces much
less than the mean, indicating a right-skewed distribution with some highly-productive
“jackpot” reservoirs and many relatively “dry holes.” These facts align with discus-
sions of decline paths in industry and popular press.
However, as mentioned previously, in percentage terms, the decline curves are
not very different between unconventional and conventional wells in our data. Fig-
ure 9 shows these decline curves scaled as a percent of initial production, and all
39
42. Months Since Initial Production
MonthlyGasProduction(PercentofInitialProduction)
0 6 12 18 24 30 36 42 48 54 60 66 72 78 84 90 96 108 120 132
0102030405060708090100
Unconventional Gas
Conventional Gas
Mean
Median
Figure 9: Mean and Median Profiles of Monthly Gas Production from Gas Wells,
as a Percent of Initial Production
Sources: Authors’ calculations based on data from Drillinginfo and EIA
four curves appear nearly identical, suggesting that the main difference between un-
conventional and conventional gas wells in Texas are in the magnitude, rather than
shape, of the production profile.
III.E Integrating Natural Gas Supply Stages to Measure Overall Price Re-
sponsiveness
III.E.1 Integrated Model of Well Drilling, Production, and Decline over Time
In this section, we combine the analysis of the three gas supply stages from the
preceding sections into a single integrated simulation model. The purpose of this
40
43. integrated model is to understand the overall price-responsiveness of natural gas
supply, how it evolves over time, and how it differs between unconventional and
conventional resources. The three separate stages of the natural gas production
process are the spud decision, the time from spudding to the first production of
a well, and the production profile of a gas well over time. We link these stages
together by simulating the effects of an unexpected, permanent 10 percent shock
to natural gas prices (from $3.00 to $3.30 per million Btu). We then illustrate the
effect of this shock on drilling activity and natural gas production over time in a
manner readily understandable in percentage and elasticity terms.
This shock increases the number of spuds of each well type in every period,
based on the elasticities presented in Table 2. The additional spudded wells take
time to reach production, according to the estimated distributions associated with
the hazard estimation results in Table 3 (illustrated in Figures 6 and 7). We then use
the mean production profile shapes presented in Figure 8 to simulate the amount
of production from wells of each type. We scale up the unconventional profile
by a factor of approximately 1.2 to reflect the higher initial productivity levels of
about 80,000 mcf per month in recent years (2010 to 2014), relative to average
levels of about 67,000 over the entire 2005 to 2015 period.43
The result is a time
series of changes in production by well type. Given this, it is straightforward to
calculate a time-varying supply elasticity by dividing the change in production (as
a percentage) by the assumed price shock (10 percent in this simulation).
43
We exclude 2015 when computing recent productivity (of 80,000 mcf) out of concern that the
large jump in productivity during that year reflects not permanent innovation but instead a temporary
re-focusing of efforts on “sweet spots” during a time of low oil & gas prices, which can be seen in
Figure 4.
41
44. We begin by noting that, given the number of wells drilled, the number of
wells beginning production at month t is the accumulation of wells that were spud-
ded in recent months. We can write this relationship precisely using the spud-to-
production distributions in Table 3 (seen in equation (2) and illustrated in Figures 6
and 7). Denoting the discrete analogues of these distributions as fj,l for a well type
j beginning production l months after spudding, we can write the number of wells
beginning production at month t, denoted xj,t, as a function of fj,l and the number
of wells spudded in each of preceding 24 months, denoted wj,t, as follows:
xj,t =
24
l=0
wj,t−lfj,l. (4)
Equation (4) thus combines supply stages 1 and 2: well drilling and commence-
ment of production. Next, by combining this with stage 3—well-level production
profiles—we can calculate the total gas production over time. As in the production
profile analysis (see equation (3)), we use qgas,j,τ to denote gas production of a well
of type j in its τth
month of operation. Denoting the productive life of a well of
type j as Tj, we can write total gas production at time t from all wells of type j as:
Qgas,j,t =
Tj−1
τ=0
xj,(t−τ)qgas,j,τ . (5)
Using equations (4) and (5) and the results from the drilling, completion, and pro-
duction models (sections III.B, III.C, and III.D), we can simulate the effect of a
change in prices on spuds (wj,t), wells entering production over time (xj,t), and
aggregate gas supply over time (Qgas,j,t).
42
45. Note that it takes a significant period of time to reach a steady state in gas
production after a price shock because today’s production depends on events that
happened as long at Tj periods ago. For example, if a typical well produces for 10
years, then today’s production level depends to some degree on drilling 10 years
ago. This inertia is endemic to oil and gas supply dynamics, and it underpins much
of the cyclicality in these markets. However, since old wells produce little, the effect
of a price change is front-loaded. A key issue of interest for this paper is whether
unconventional resources and technologies may reduce the volatility inherent in this
industry characterized by large fixed investments and low variable production costs.
In our simulation’s baseline, we assume constant prices, implying that the quan-
tity of drilling wj,t does not vary over time, denoted wbase
j . Given this and equation
(4), the number of wells entering production each month in the baseline equilibrium
(i.e., without a price shock) is also constant:
xbase
j = wbase
j
24
l=0
fj,l = wbase
j , (6)
where the latter equality follows because the density of spud-to-production time
must sum to one: 24
l=0 fj,l = 1.44
This and equation (5), in turn, imply that baseline
gas production is also in steady state in the baseline:
Qbase
gas,j = xbase
j
Tj−1
τ=0
qgas,j,τ . (7)
44
In reality, not all spuded wells go on to produce. However, for simplicity we are ignoring this
complication. An exploration of Drillinginfo’s permit dataset found only a small fraction of the
wells in our dataset for which we could identify as unconventional or conventional that were drilled
but never reached production. For this reason, we ignore such wells. However, including them
would simply multiplicatively scale down the price responsiveness for both well types slightly.
43
46. Using equations (4) through (7), we compute the number of wells beginning pro-
duction and quantities of gas produced over time, by well type, under a baseline
price scenario of $3.00 per million Btu and a scenario with a permanent 10 percent
increase to $3.30 per million Btu.
III.E.2 Overall Unconventional vs. Conventional Gas Supply Responsiveness
For this analysis of the supply impact of a 10 percent gas price increase, we use our
preferred estimates for spud elasticities from columns (1) of Tables 2 and 3. The
production profiles are represented by the mean production over time for each well
type, shown by the solid lines in Figure 8, with the unconventional profile scaled up
to reflect productivity increases, as described above.
We must also specify how many wells of each type are drilled in the baseline.
To capture the relative supply elasticities, we run the simulation separately for un-
conventional and conventional wells, each time assuming the same spud baseline
of 72 wells for each type: wbase
conv = 72 or wbase
unconv = 72.45
From these baselines,
we simulate the time series of the number of new wells entering production and
aggregate gas production for each type of well.
We then convert the change in wells beginning production and gas produced to
percentage changes. To compare the results for unconventional and conventional
wells on an equal footing, when computing the percentage changes in gas produc-
tion, we divide by the same denominator in each case: the amount of gas consistent
45
72 is the average number of monthly unconventional gas spuds in our data during our final
sample year, January 2015 - September 2015. The breakdown was 61 unconventional spuds and 11
conventional spuds. We use the same baseline for unconventional and conventional spuds in order to
conduct the thought experiments, “what would the price responsiveness look like if all gas drilling
were conventional (unconventional)?” Using a different baseline for the two well types would bias
the comparison towards the one with the larger baseline.
44
47. with the types of wells actually drilled in our data, on average, in 2015.46
This equal
denominator allows one to observe that, even if more conventional wells existed in
2015 than actually did (72 instead of 11), their much lower productivity means that
they would still contribute relatively little to the overall gas supply response.
The simulation results are shown in Figure 10. The left panel shows the change
in number of wells beginning production each month for unconventional and con-
ventional wells as a percentage of the baseline number of wells. The price shock at
period zero leads to new drilling effort which gradually bears fruit over the course
of the subsequent 24 months and beyond. After 24 months, the wells reach a new
“steady state,” with the same number of wells beginning production in every month.
Months Since Price Shock
PercentChangein
WellsBeginningProduction
0 3 6 9 12 15 18 21 24 27 30
012345678
Unconventional
Conventional
Months Since Price Shock
PercentChangein
TotalGasProduced
0 24 48 72 96 120 144 168
012345678
Unconventional
Conventional
Figure 10: Change in Wells Beginning Production and Natural Gas Produced, Fol-
lowing a 10 Percent Price Shock
Sources: Authors’ calculations based on data from Drillinginfo and EIA
The right panel combines the results of the left panel with production decline
paths and traces out the effect of the price shock on incremental natural gas supply,
46
The baseline gas production corresponds to the production from 61 unconventional gas wells
and 11 conventional gas wells, computed in steady state using the average production profiles used
in this simulation and depicted in Figure 8. The amount is simply the cumulative total production
across the average well’s lifetime, by well type, multiplied by the baseline number of spuds (61 and
11 for unconventional and conventional respectively).
45
48. which shows a similar gradual adjustment. Each incremental well in the left panel
produces for many years; as a result, the rising drilling effort builds on itself, until
we reach a new steady state after more than a decade. Before reaching the steady
state, some portion of the production is from “legacy” wells drilled before the price
shock. In other words, an immediate 7 percent increase in drilling effort increases
total gas production by less than 7 percent because of the lack of response from
legacy wells, at least until those wells eventually cease production and a new steady
state is reached. Only once the increased drilling effort has propagated throughout
the system does it fully affect the level of gas produced.
The primary finding is that unconventional gas supply is in fact much more
responsive to price changes than is conventional gas supply once one takes an inte-
grated view of the entire production process. The time and shape of the path to reach
the steady state depends on both the shape of the spud-to-production distributions
and the production profiles. The more front-loaded the distribution and production
profile are, the faster the drilling effort translates into increased production.
Note that these effects are partly, but not completely, offsetting for unconven-
tional wells. On one hand, unconventional wells are more productive than con-
ventional wells (see Figure 8). This supports the notion that unconventional gas
production should respond more to a price change than conventional wells would.
On the other hand, unconventional wells generally take longer to reach produc-
tion (see Figure 6), which somewhat moderates the short-term effects of increased
drilling effort on gas production. Note that the superior productivity of uncon-
ventional wells more than offsets their longer drilling and completion times after
just a few months. On net, for the first three months of the simulation, unconven-
46
49. tional gas actually responds less than conventional gas as wells take longer to bring
online. But unconventional production quickly surpasses conventional production
after three months, once the much-more productive wells come online. By the 11th
month of the simulation, the unconventional gas supply response is more than twice
as large as the conventional response.
The right-hand panel of Figure 10 illustrates that, in the long run, the gas supply
response from unconventional wells is about 2.7 times (≈ 7.1 percent
2.6 percent
) larger than that
of conventional wells. This is entirely due to the fact that unconventional wells
are about 2.7 times as productive as conventional wells, with initial production of
approximately 80,000 mcf per month compared to 30,000 mcf per month.
IV Conclusion
We empirically analyze drilling and production from approximately 62,000 gas
wells in Texas from 2000 to 2015 to examine whether unconventional gas sup-
ply is in fact more responsive to price changes than conventional sources, as has
been widely conjectured. We consider separate stages of the natural gas extraction
process: drilling investment, time to completion and initial production, and the pro-
file of output over time. We find that neither production from existing wells nor
completion times respond strongly to price changes. Rather, the important margin
for supply response is drilling investment. We estimate a drilling elasticity with
respect to gas prices of approximately 0.7, finding no evidence that this elasticity is
different for unconventional versus conventional gas wells.
We also find other relevant differences between conventional and unconven-
tional wells. While unconventional wells tend to take longer to reach production,
47
50. they produce much more gas per well than conventional wells and have much lower
percent variation in production, consistent with the notion of a manufacturing pro-
cess. The faster flow rate per well turns out to be the primary margin by which ag-
gregate supply from unconventional gas production is more price-responsive than
conventional reservoirs. In particular, we find an approximately 2.7-fold greater
responsiveness of unconventional gas supply to price changes compared to conven-
tional gas, due entirely to greater well productivity. This distinction is critical in an
industry where drilling rigs are a major cost factor and the total number of operating
rigs is slow to change. Among other important results, this research demonstrates
why simply counting wells drilled or rigs operating is no longer sufficient to gauge
changes in gas supply, without also measuring heterogeneity in well productivity.
References
Adelman, Morris A. 1990. “Mineral depletion, with special reference to
petroleum.” Review of Economics and Statistics, 1–10.
Anderson, Soren T., Ryan Kellogg, and Stephen W. Salant. 2014. “Hotelling
Under Pressure.” National Bureau of Economic Research Working Paper 20280.
Browning, John, Scott W Tinker, Svetlana Ikonnikova, G¨urcan G¨ulen, Eric
Potter, Qilong Fu, Katie Smye, Susan Horvath, Tad Patzek, Frank Male,
et al. 2014. “Study develops Fayetteville Shale reserves, production forecast.”
Oil & Gas Journal, 112(1): 64–73.
Cairns, Robert D. 2014. “The green paradox of the economics of exhaustible re-
sources.” Energy Policy, 65: 78–85.
Cairns, Robert D., and G.A. Davis. 2001. “Adelman’s rule and the petroleum
firm.” Energy Journal, 22: 31–54.
Dahl, C. 1992. “Regional Cost of Natural Gas.” Technical report, American Gas
Association.
48
51. Dahl, Carol, and Mine Y¨ucel. 1991. “Testing alternative hypotheses of oil pro-
ducer behavior.” Energy Journal, 117–138.
Davis, Graham A, and Robert D Cairns. 1998. “Simple analytics of valuing pro-
ducing petroleum reserves.” Energy Journal, 133–142.
Erickson, Edward W, and Robert M Spann. 1971. “Supply response in a regu-
lated industry: the case of natural gas.” Bell Journal of Economics and Manage-
ment Science, 94–121.
Fitzgerald, Timothy. 2010. “Evaluating split estates in oil and gas leasing.” Land
Economics, 86(2): 294–312.
Griffin, James M. 1985. “OPEC behavior: a test of alternative hypotheses.” Amer-
ican Economic Review, 954–963.
G¨untner, Jochen HF. 2014. “How do oil producers respond to oil demand shocks?”
Energy Economics, 44: 1–13.
Hamilton, James D. 2009. “Understanding Crude Oil Prices.” Energy Journal,
30(2): 179–206.
Hamilton, James D. 2014. “Oil prices as an indicator of global economic condi-
tions.” Econbrowser.
Hausman, Catherine, and Ryan Kellogg. 2015. “Welfare and Distributional Im-
plications of Shale Gas.” National Bureau of Economic Research Working Paper
21115.
Hogan, William W. 1989. World oil price projections: a sensitivity analysis.
Harvard University, Energy and Environmental Policy Center, John F. Kennedy
School of Government.
Jones, Clifton T. 1990. “OPEC behaviour under falling prices: implications for
cartel stability.” Energy Journal, 117–129.
Joskow, Paul L. 2013. “Natural Gas: From Shortages to Abundance in the United
States.” American Economic Review, 103(3): 338–43.
Kahle, David, and Hadley Wickham. 2013. “ggmap: Spatial Visualization with
ggplot2.” The R Journal, 5(1): 144–161.
Kellogg, Ryan. 2014. “The effect of uncertainty on investment: evidence from
Texas Oil Drilling.” American Economic Review, 104(6): 1698–1734.
49
52. Kilian, Lutz. 2009. “Not All Oil Price Shocks Are Alike: Disentangling De-
mand and Supply Shocks in the Crude Oil Market.” American Economic Review,
99(3): 1053–69.
Krichene, Noureddine. 2002. “World crude oil and natural gas: a demand and
supply model.” Energy Economics, 24(6): 557–576.
Libecap, Gary D, and James L Smith. 2002. “The economic evolution of
petroleum property rights in the United States.” Journal of Legal Studies,
31(S2): S589–S608.
MacKenzie, Todd A, Tor D Tosteson, Nancy E Morden, Therese A Stukel, and
A James O’Malley. 2014. “Using instrumental variables to estimate a Cox’s
proportional hazards regression subject to additive confounding.” Health Services
and Outcomes Research Methodology, 14(1-2): 54–68.
Nystad, Arild N. 1987. “Rate sensitivity and the optimal choice of production ca-
pacity of petroleum reservoirs.” Energy Economics, 9(1): 37 – 45.
Patzek, Tad W, Frank Male, and Michael Marder. 2013. “Gas production in
the Barnett Shale obeys a simple scaling theory.” Proceedings of the National
Academy of Sciences, 110(49): 19731–19736.
Porter, Robert H. 1995. “The role of information in US offshore oil and gas lease
auctions.” Econom´etrica: Journal of the Econometric Society, 63(1): 1–27.
Ramcharran, Harri. 2002. “Oil production responses to price changes: an em-
pirical application of the competitive model to OPEC and non-OPEC countries.”
Energy Economics, 24(2): 97–106.
Smith, James L. 2012. “On the portents of peak oil (and other indicators of re-
source scarcity).” Energy Policy, 44: 68–78.
Thompson, Andrew C. 2001. “The Hotelling Principle, backwardation of futures
prices and the values of developed petroleum reserves-the production constraint
hypothesis.” Resource and Energy Economics, 23(2): 133–156.
Vissing, Ashley. 2015. “Private Contracts as Regulation: A Study of Private Lease
Negotiations Using the Texas Natural Gas Industry.” Agricultural and Resource
Economics Review, 44(2): 120–137.
50