Forecast of Economic Tight Oil and Gas Production in Permian Basin

We adopt a physics-guided, data-driven method to predict the most likely future production from the largest tight oil and gas deposits in North America, the Permian Basin. We first divide the existing 53,708 horizontal hydrofractured wells into 36 spatiotemporal well cohorts based on different reservoir qualities and completion date intervals. For each cohort, we fit the Generalized Extreme Value (GEV) statistics to the annual production and calculate the means to construct historical well prototypes. Using the physical scaling method, we extrapolate these well prototypes for several more decades. Our hybrid, physico-statistical prototypes are robust enough to history-match the entire production of the Permian mudstone formations. Next, we calculate the infill potential of each sub-region of the Permian and schedule the likely future drilling programs. To evaluate the profitability of each infill scenario, we conduct a robust economic analysis. We estimate that the Permian tight reservoirs contain 54–62 billion bbl of oil and 246–285 trillion scf of natural gas. With time, Permian is poised to be not only the most important tight oil producer in the U.S., but also the most important tight gas producer, surpassing the giant Marcellus shale play.

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Comment on “The intensification of the water footprint of hydraulic fracturing”

Science Advances ◽

10.1126/sciadv.aav2110 ◽

2020 ◽

Vol 6 (8) ◽

pp. eaav2110

Author(s):

Daniel Raimi

Keyword(s):

Hydraulic Fracturing ◽

Water Consumption ◽

Energy Production ◽

Oil And Gas ◽

Water Footprint ◽

Gas Production ◽

Permian Basin ◽

Oil And Gas Production ◽

Oil And Natural Gas ◽

Water Intensity

Kondash et al. provide a valuable contribution to our understanding of water consumption and wastewater production from oil and gas production using hydraulic fracturing. Unfortunately, their claim that the water intensity of energy production using hydraulic fracturing has increased in all regions is incorrect. More comprehensive data show that, while the water intensity of production may have increased in regions such as the Permian basin, it has decreased by 74% in the Marcellus and by 19% in the Eagle Ford region. This error likely stems from an improper method for estimating energy production from wells: The authors use the median well to represent regional production, which systematically underestimates aggregate production volumes. Across all regions, aggregate data suggest that the water intensity of oil and natural gas production using hydraulic fracturing has increased by 19%. There also appears to be an error in estimates for water consumption in the Permian basin.

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Satellite-based characterization of methane point sources in the Permian Basin

10.5194/egusphere-egu21-15877 ◽

2021 ◽

Author(s):

Itziar Irakulis-Loitxate ◽

Luis Guanter ◽

Yin-Nian Liu ◽

Daniel J. Varon ◽

Joannes D. Maasakkers ◽

...

Keyword(s):

Oil And Gas ◽

The United States ◽

Gas Production ◽

Point Sources ◽

Permian Basin ◽

High Concentration ◽

Regional Study ◽

Oil And Gas Production ◽

Emission Point

The Permian Basin is known for its extensive oil and gas production, which has increased rapidly in recent years becoming the largest producing basin in the United States. It is also responsible for almost half of the methane emissions from all oil and gas producing regions in the country. Given the urgent need to reduce greenhouse gas emissions, it is crucial to identify and characterize the point sources of emissions. To this end, we have combined three new high-resolution hyperspectral sensors data onboard the GF-5, ZY1 and PRIMA satellites to create the first regional study to identify methane sources and measure the emitted quantities from each source. With data collected over several days in 2019 and 2020, we have identified a total of 37 point source emissions with flux rates >500kg/h, that is, a high concentration of extreme emission point sources that account for nearly 40% of the Permian annual emissions. Also, we have found that new infrastructure (post-2018) is responsible for almost 60% of the detected emissions, in many cases (21% of the cases) due to inefficient use of flaring of the gas that they cannot store. With this study, we demonstrate that hyperspectral satellite data are a powerful tool for the detection and quantification of strong methane point emissions.

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Influence of CO2 retention mechanism storage in Alberta tight oil and gas reservoirs at Western Canadian Sedimentary Basin, Canada: hysteresis modeling and appraisal

Journal of Petroleum Exploration and Production Technology ◽

10.1007/s13202-020-01052-7 ◽

2020 ◽

Author(s):

Perumal Rajkumar ◽

Venkat Pranesh ◽

Ramadoss Kesavakumar

Keyword(s):

Oil Recovery ◽

Fossil Fuels ◽

Oil And Gas ◽

Injection Pressure ◽

Retention Mechanism ◽

Gas Production ◽

Tight Oil ◽

Gas Reservoirs ◽

Oil And Gas Reservoirs ◽

Tight Oil And Gas

AbstractRapid combustion of fossil fuels in huge quantities resulted in the enormous release of CO2 in the atmosphere. Subsequently, leading to the greenhouse gas effect and climate change and contemporarily, quest and usage of fossil fuels has increased dramatically in recent times. The only solution to resolve the problem of CO2 emissions to the atmosphere is geological/subsurface storage of carbon dioxide or carbon capture and storage (CCS). Additionally, CO2 can be employed in the oil and gas fields for enhanced oil recovery operations and this cyclic form of the carbon dioxide injection into reservoirs for recovering oil and gas is known as CO2 Enhanced Oil and Gas Recovery (EOGR). Hence, this paper presents the CO2 retention dominance in tight oil and gas reservoirs in the Western Canadian Sedimentary Basin (WCSB) of the Alberta Province, Canada. Actually, hysteresis modeling was applied in the oil and gas reservoirs of WCSB for sequestering or trapping CO2 and EOR as well. Totally, four cases were taken for the investigation, such as WCSB Alberta tight oil and gas reservoirs with CO2 huff-n-puff and flooding processes. Actually, Canada has complex geology and therefore, implicate that it can serve as a promising candidate that is suitable and safer place for CO2 storage. Furthermore, injection pressure, time, rate (mass), number of cycles, soaking time, fracture half-length, conductivity, porosity, permeability, and initial reservoir pressure were taken as input parameters and cumulative oil production and oil recovery factor are the output parameters, this is mainly for tight oil reservoirs. In the tight gas reservoirs, only the output parameters differ from the oil reservoir, such as cumulative gas production and gas recovery factor. Reservoirs were modelled to operate for 30 years of oil and gas production and the factor year was designated as decision-making unit (DMU). CO2 retention was estimated in all four models and overall the gas retention in four cases showed a near sinusoidal behavior and the variations are sporadic. More than 80% CO2 retention in these tight formations were achieved and the major influencing factors that govern the CO2 storage in these tight reservoirs are injection pressure, time, mass, number of cycles, and soaking time. In general, the subsurface geology of the Canada is very complex consisting with many structural and stratigraphic layers and thus, it offers safe location for CO2 storage through retention mechanism and increasing the efficiency and reliability of oil and gas extraction from these complicated subsurface formations.

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GROWTH, PROTECTION AND VALUE REALISATION USING DERIVATIVES

The APPEA Journal ◽

10.1071/aj03042 ◽

2004 ◽

Vol 44 (1) ◽

pp. 781

Author(s):

D.M. Heard ◽

S.J. Grenfell

Keyword(s):

Real Options ◽

Real Option ◽

Oil And Gas ◽

Investment Decision ◽

Gas Production ◽

Equity Returns ◽

Oil And Gas Production ◽

Oil And Gas Producers ◽

Secured Debt ◽

Future Production

Oil and gas producers are familiar with the use of derivatives to hedge oil price risk.Beyond this, derivatives provide opportunities to enhance more general corporate finance activities.An example is raising finance for acquisitions or developments. When the maximum senior debt has been obtained, the choice between equity funding or other sources (such as subordinated debt) should also consider the up-front cash available from a structured derivative program—this may lower the overall cost of capital for the acquirer, and directly improve equity returns through lower dilution.A notable aspect of oil and gas production businesses is the high degree of embedded optionality. Option pricing methods can be used to value and monetise these real options—creating a new source of finance by transferring part of this embedded optionality to a party which can explicitly value and trade it.Generating value from real options (such as the opportunity to develop a proven, undeveloped reserve) can represent a critical source of finance.The value of such development assets is not fully recognised by traditional lending banks when the final investment decision remains some way off.By contrast, monetising real option value can provide funds at a point where they can be applied to appraisal drilling, thus funding the development of the project to a point where conventional debt or project-secured debt becomes feasible.Companies with both existing unhedged future production and a portfolio of PUD real options are best-placed to benefit from this source of finance.

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NOx emissions from U.S. oil and gas production using TROPOMI NO2 and the divergence method

10.5194/egusphere-egu21-13554 ◽

2021 ◽

Author(s):

Barbara Dix ◽

Colby Francoeur ◽

Brian McDonald ◽

Raquel Serrano ◽

Pepijn Veefkind ◽

...

Keyword(s):

Natural Gas ◽

Oil And Gas ◽

Ground Level ◽

Gas Production ◽

Nox Emissions ◽

Permian Basin ◽

Oil And Gas Production ◽

Horizontal Drilling ◽

Surface Measurements ◽

Oil And Natural Gas

The development of horizontal drilling and hydraulic fracturing has led to a steep increase in the U.S. production of natural gas and crude oil from shale formations since the mid 2000s. Associated with this industrial activity are emissions of ground-level ozone precursors such as nitrogen oxides (NOx). Satellite data are important in this context, because surface measurements are limited or non-existent in rural regions, where most U.S. oil and gas production operations take place. Here we use TROPOMI NO2 observations to study NOx emissions coming from oil and natural gas production sites. Applying the divergence method we quantify basin wide emissions from well pad fields and aim to push spatial and temporal resolution of this technique. The divergence was method introduced by Beirle et al. (Science Advances 2019) to quantify point source emissions. It relies on calculating the divergence of the NO2 flux to derive NOx sources and estimating the NO2 lifetime to quantify sinks. Our analysis will include an assessment of different methods to constrain the NO2 lifetime, which becomes particularly important when applying this method to larger areas. Further we will compare our results with bottom-up derived emissions. Here we use the Fuel-based Oil & Gas (FOG) inventory that calculates NOx emissions based on fuel consumption. Initial results show good agreement for the Permian Basin (NM, TX) and we will expand our analysis to other U.S. basins.

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