Unconventional oil and natural gas extraction enabled by horizontal drilling and hydraulic fracturing (fracking) is driving an economic boom, with consequences described from “revolutionary” to “disastrous.” Reality lies somewhere in between. Unconventional energy generates income and, done well, can reduce air pollution and even water use compared with other fossil fuels. Alternatively, it could slow the adoption of renewables and, done poorly, release toxic chemicals into water and air. Primary threats to water resources include surface spills, wastewater disposal, and drinking-water contamination through poor well integrity. An increase in volatile organic compounds and air toxics locally are potential health threats, but the switch from coal to natural gas for electricity generation will reduce sulfur, nitrogen, mercury, and particulate air pollution. Data gaps are particularly evident for human health studies, for the question of whether natural gas will displace coal compared with renewables, and fo...

/pdf/the-environmental-costs-and-benefits-of-fracking-5euzpukh6z.pdf

The Environmental Costs and Benefits of Fracking

Production data analysis of unconventional gas wells: Review of theory and best practices

Pore types, pore size, and pore abundance vary systematically across thermal maturity in the Eagle Ford Formation, Maverick Basin, southern Texas. Scanning electron imaging of 20 samples from four wells is used to assess the complex response of pores to chemical and mechanical processes, entailing both destruction of primary porosity and generation of secondary pores. Primary mineral-associated pores are destroyed by compaction, cementation, and infill of secondary organic matter, whereas secondary pores are generated within organic matter (OM). Destruction of primary pores during early burial (to ∼0.5%) occurs by compaction of ductile detrital OM and clays and, to a lesser degree, as a result of cementation and infill of secondary OM. Larger pores are associated with coccolith debris. The dominant OM is spatially isolated detrital OM “stringers.” Porosity is volumetrically dominated (average 6.2%) by relatively large, mostly interparticle mineral-associated pores (median size 51.6 nm [0.000002 in.]; detection limit near 3–4 nm [0.00000012–0.00000015 in.]). At low maturity, porosity and pore size correlate directly with calcite abundance and inversely with OM volumes. At higher maturity, further destruction of primary pores occurs through cementation, secondary OM infill, and greater compaction. Mineral-associated pores are present at high-maturity ( ∼1.2%–1.3%), but are smaller (median size 30.2 nm [0.0000011 in.]) and less abundant (average of 2.5%) than at low maturity. A large portion of OM within high-maturity samples is diagenetic in origin and has pervaded into primary pore space, coating cement crystals, and filling intraparticle pores. Substantial mineral-associated porosity is locally present in samples where incursion of primary pore space by secondary OM has not occurred. Abundant secondary porosity is generated as OM matures into the wet-gas window. Porosity in most high-maturity samples is volumetrically dominated (average of 1.3%) by smaller, OM-hosted pores (median size 13.2 nm [0.00000051 in.]).

Pore types and pore-size distributions across thermal maturity, Eagle Ford Formation, southern Texas

Natural gas from tight shale formations will provide the United States with a major source of energy over the next several decades. Estimates of gas production from these formations have mainly relied on formulas designed for wells with a different geometry. We consider the simplest model of gas production consistent with the basic physics and geometry of the extraction process. In principle, solutions of the model depend upon many parameters, but in practice and within a given gas field, all but two can be fixed at typical values, leading to a nonlinear diffusion problem we solve exactly with a scaling curve. The scaling curve production rate declines as 1 over the square root of time early on, and it later declines exponentially. This simple model provides a surprisingly accurate description of gas extraction from 8,294 wells in the United States’ oldest shale play, the Barnett Shale. There is good agreement with the scaling theory for 2,057 horizontal wells in which production started to decline exponentially in less than 10 y. The remaining 6,237 horizontal wells in our analysis are too young for us to predict when exponential decline will set in, but the model can nevertheless be used to establish lower and upper bounds on well lifetime. Finally, we obtain upper and lower bounds on the gas that will be produced by the wells in our sample, individually and in total. The estimated ultimate recovery from our sample of 8,294 wells is between 10 and 20 trillion standard cubic feet.

https://www.pnas.org/content/pnas/110/49/19731.full.pdf

Gas production in the Barnett Shale obeys a simple scaling theory

High-pressure fluid-phase equilibria: Experimental methods and systems investigated (2000-2004)

Production Analysis of Tight-Gas and Shale-Gas Reservoirs Using the Dynamic-Slippage Concept

Many tight/shale gas wells exhibit linear flow, which can last for several years. Linear flow can be analyzed using a square-root-oftime plot, a plot of rate-normalized pressure vs. the square root of time. Linear flow appears as a straight line on this plot, and the slope of this line can be used to calculate the product of fracture half-length and the square root of permeability. In this paper, linear flow from a fractured well in a tight/shale gas reservoir under a constant-flowing-pressure constraint is studied. It is shown that the slope of the square-root-of-time plot results in an overestimation of fracture half-length, if permeability is known. The degree of this overestimation is influenced by initial pressure, flowing pressure, and formation compressibility. An analytical method is presented to correct the slope of the squareroot-of-time plot to improve the overestimation of fracture halflength. The method is validated using a number of numerically simulated cases. As expected, the square-root-of-time plots for these simulated cases appear as a straight line during linear flow for constant flowing pressure. It is found that the newly developed analytical method results in a more reliable estimate of fracture half-length, if permeability is known. Our approach, which is fully analytical, results in an improvement in linear-flow analysis over previously presented methods. Finally, the application of this method to multifractured horizontal wells is discussed and the method is applied to three field examples.

A New Analytical Method for Analyzing Linear Flow in Tight/Shale Gas Reservoirs: Constant-Flowing-Pressure Boundary Condition

Mutual interactions between crude oil and CO2 under different pressures

Carbon dioxide flooding has been proven to be one of the most effective and viable enhanced oil recovery (EOR) processes for light and medium oil reservoirs. In the past, an extremely large number of laboratory experiments and numerical simulations have been conducted to study the CO2 EOR process. However, the specific effects of viscous and capillary forces on this tertiary oil recovery process are neither thoroughly studied nor well understood yet. In this paper, an experimental study is carried out to examine the detailed effects of viscous and capillary forces on the CO2 EOR under the actual reservoir conditions. First, the equilibrium interfacial tensions between a light crude oil and CO2 are measured at different equilibrium pressures. Second, a series of CO2 coreflood tests are performed to measure the CO2 EOR at different CO2 injection pore volumes, pressures, and rates. Each CO2 coreflood test is terminated after a total of 1.5 pore volume of CO2 is injected. The detailed experimental results sho...

Morteza Nobakht

Papers

Production Analysis of Tight-Gas and Shale-Gas Reservoirs Using the Dynamic-Slippage Concept

A New Analytical Method for Analyzing Linear Flow in Tight/Shale Gas Reservoirs: Constant-Flowing-Pressure Boundary Condition

Mutual interactions between crude oil and CO2 under different pressures

Effects of Viscous and Capillary Forces on CO2 Enhanced Oil Recovery under Reservoir Conditions

Incorporating Geomechanical and Dynamic Hydraulic-Fracture-Property Changes Into Rate-Transient Analysis: Example From the Haynesville Shale