Shale Gas Basins Research Articles

Predictive Modeling of Energy and Emissions from Shale Gas Development.

Contributions of individual preproduction activities to overall energy use and greenhouse gas (GHG) emissions during shale gas development are not well understood nor quantified. This paper uses predictive modeling combining the physics of reservoir development operations with depositional attributes of shale gas basins to account for energy requirements and GHG emissions during shale gas well development. We focus on shale gas development from the Montney basin in Canada and account for the energy use during drilling and fluid pumping for reservoir stimulation, in addition to preproduction emissions arising from energy use and potential gas releases during operations. Detailed modeling of activities and events that take place during each stage of development is described. Relative to the hydraulic fracturing activity, we observe significantly higher energy intensity for the well drilling and mud circulation activities. Well completion flowback gas is found to be the predominant potential source of GHG emission. When these results are expressed on an annual basis, consistent with the convention of most climate policy goals and directives, environmental impacts of our growing natural gas economy are better appreciated. Estimated likely GHG emission from new development wells in 2017 in the Montney Formation alone is 2.68 Mt CO2e. However, on a preproduction requirements basis and dependent on mean estimated ultimate recovery (EUR), energy return on invested energy for shale gas from the Montney Formation in Canada is estimated to be about 3400. The approach described here can be reliably extended to areas, globally, where natural gas development is becoming prominent.

Thomsen anisotropy parameters calculation in the Baltic Basin shale gas formations based on the measurement of well logging data, some attempts

Thomsen anisotropy parameters calculation in the Baltic Basin shale gas formations based on the measurement of well logging data, some attempts

4D multi-physical stress modelling during shale gas production: A case study of Sichuan Basin shale gas reservoir, China

To investigate the time-lapse, three-dimensional (4D) stress during shale gas production, a multi-physical modeling method is proposed. This model enfranchises multiple years' scale dynamic production data. A finite difference method (FDM) reservoir simulator is used to couple thermal-hydrological-chemical (THC) processes, while a finite element method (FEM) geomechanical simulator takes on the role of a thermal-hydrological-mechanical (THM) coupling calculator. In order to couple the flow model with the geomechanical model, an interface (coupling) Python code is provided to communicate data between the finite difference (FD) and finite element (FE) grids. A set of FORTRAN routines are assigned to interpolate initial stress field and mechanical parameters into the geomechanical model based on field and experimental data. Ultimately, a 4D multi-physical model of Sichuan Basin shale gas reservoir (China) is proposed and analyzed. Based on the simulation results, the continuous reduction in reservoir pore pressure leads to evolving changes in the stress state and reservoir properties beyond the pre-consolidation pressure. Transversely isotropic characteristics have a considerable effect on the changes in the reservoir stresses and poro-elastic parameters. The results provide some fundamental insights for optimizing well patterns, ensuring wellbore stability, re-fracturing design and locating, drilling and completing infill wells.

Paleozoic shale gas resources in the Sichuan Basin, China

The Sichuan Basin, China, is commonly considered to contain the world’s most abundant shale gas resources. Although its Paleozoic marine shales share many basic characteristics with successful United States gas shales, numerous geologic uncertainties exist, and Sichuan Basin shale gas production is nascent. Gas retention was likely compromised by the age of the shale reservoirs, multiple uplifts and orogenies, and migration pathways along unconformities. High thermal maturities raise questions about gas storage potential in lower Paleozoic shales. Given these uncertainties, a new look at Sichuan Basin shale gas resources is advantageous. As part of a systematic effort to quantitatively assess continuous oil and gas resources in priority basins worldwide, the US Geological Survey (USGS) completed an assessment of Paleozoic shale gas in the Sichuan Basin in 2015. Three organic-rich marine Paleozoic shale intervals meet the USGS geologic criteria for quantitative assessment of shale gas resources: the lower Cambrian Qiongzhusi Formation, the uppermost Ordovician Wufeng through lowermost Silurian Longmaxi Formations (currently producing shale gas), and the upper Permian Longtan and Dalong Formations. This study defined geologically based assessment units and calculated probabilistic distributions of technically recoverable shale gas resources using the USGS well productivity–based method. For six assessment units evaluated in 2015, the USGS estimated a mean value of 23.9 tcf (677 billion cubic meters) of undiscovered, technically recoverable shale gas. This result is considerably lower than volumes calculated in previous shale gas assessments of the Sichuan Basin, highlighting a need for caution in this geologically challenging setting.

Improved Mechanistic Understanding of Natural Gas Methane Emissions from Spatially Resolved Aircraft Measurements.

Divergence in recent oil and gas related methane emission estimates between aircraft studies (basin total for a midday window) and emissions inventories (annualized regional and national statistics) indicate the need for better understanding the experimental design, including temporal and spatial alignment and interpretation of results. Our aircraft-based methane emission estimates in a major U.S. shale gas basin resolved from west to east show (i) similar spatial distributions for 2 days, (ii) strong spatial correlations with reported NG production (R2 = 0.75) and active gas well pad count (R2 = 0.81), and (iii) 2× higher emissions in the western half (normalized by gas production) despite relatively homogeneous dry gas and well characteristics. Operator reported hourly activity data show that midday episodic emissions from manual liquid unloadings (a routine operation in this basin and elsewhere) could explain ∼1/3 of the total emissions detected midday by the aircraft and ∼2/3 of the west-east difference in emissions. The 22% emission difference between both days further emphasizes that episodic sources can substantially impact midday methane emissions and that aircraft may detect daily peak emissions rather than daily averages that are generally employed in emissions inventories. While the aircraft approach is valid, quantitative, and independent, our study sheds new light on the interpretation of previous basin scale aircraft studies, and provides an improved mechanistic understanding of oil and gas related methane emissions.

Spatial variability of tight oil well productivity and the impact of technology

New well productivity levels have increased steadily across the major shale gas and tight oil basins of North America since large-scale development began a decade ago. These gains have come about through a combination of improved well and hydraulic fracturing design, and a greater concentration of drilling activity in higher quality acreage, the so called “sweets spots.” Accurate assessment of the future potential of shale and tight resources depends on properly disentangling the influence of technology from that of well location and the associated geology, but this remains a challenge. This paper describes how regression analysis of the impact of design choices on well productivity can yield highly erroneous estimates if spatial dependence is not controlled for at a sufficiently high resolution. Two regression approaches, the spatial error model and regression-kriging, are advanced as appropriate methods and compared to simpler but widely used regression models with limited spatial fidelity. A case study in which these methods are applied to a large contemporary well dataset from the Williston Basin in North Dakota reveals that only about half of the improvement in well productivity is associated with technology changes, but the simpler regression models substantially overestimate the impact of technology by attributing location-driven improvement to design changes. Because of the widespread reliance on these less spatially resolved regression models, including by the U.S. Energy Information Administration to project shale gas and tight oil resource potential, the overestimate of technology’s role in well productivity has important implications for future resource availability and economics, and the development choices of individual operators.

Assessing the fugitive emission of CH4 via migration along fault zones - Comparing potential shale gas basins to non-shale basins in the UK.

This study considered whether faults bounding hydrocarbon-bearing basins could be conduits for methane release to the atmosphere. Five basin bounding faults in the UK were considered: two which bounded potential shale gas basins; two faults that bounded coal basins; and one that bounded a basin with no known hydrocarbon deposits. In each basin, two mobile methane surveys were conducted, one along the surface expression of the basin bounding fault and one along a line of similar length but not intersecting the fault. All survey data was corrected for wind direction, the ambient CH4 concentration and the distance to the possible source. The survey design allowed for Analysis of Variance and this showed that there was a significant difference between the fault and control survey lines though a significant flux from the fault was not found in all basins and there was no apparent link to the presence, or absence, of hydrocarbons. As such, shale basins did not have a significantly different CH4 flux to non-shale hydrocarbon basins and non-hydrocarbon basins. These results could have implications for CH4 emissions from faults both in the UK and globally. Including all the corrected fault data, we estimate faults have an emissions factor of 11.5±6.3tCH4/km/yr, while the most conservative estimate of the flux from faults is 0.7±0.3tCH4/km/yr. The use of isotopes meant that at least one site of thermogenic flux from a fault could be identified. However, the total length of faults that penetrate through-basins and go from the surface to hydrocarbon reservoirs at depth in the UK is not known; as such, the emissions factor could not be multiplied by an activity level to estimate a total UK CH4 flux.

Apparent Permeability and Gas Flow Behavior in Carboniferous Shale from the Qaidam Basin, China: An Experimental Study

Shale can act as an unconventional gas reservoir with low permeability and complex seepage characteristics. Study of the apparent permeability and percolation behavior of shale gas is important in understanding the permeability of shale reservoirs, to evaluate formation damage, to develop gas reservoirs, and to design wells. This study simulated methane percolation at 298.15 K under inlet pressures ranging from 0.2 to 4 MPa and a constant outlet pressure of 0.1 MPa to investigate shale gas percolation behavior and apparent permeability. Five representative shale cores from the Carboniferous Hurleg and Huitoutala formations in the eastern Qaidam Basin, China, were analyzed. Each experiment measured the volume flow rate of methane and the inlet pressure. Pseudopressure approach was used to analyze high-velocity flow in shale samples, and apparent permeability at different pressures was calculated using the traditional method. A nonlinear apparent permeability model that considers diffusion and slippage is established from theory and experimental data fitting, and the shale gas flow characteristics affected by slippage and diffusion are analyzed. The results indicate that the pseudopressure formulation that considers the effect of gas properties on high-velocity flow produces a more accurate linear representation of the experimental data. The apparent gas permeability of shale consists of contributions from Darcy permeability, slippage, and diffusion. The apparent permeability and gas flow behavior in the studied shales strongly depended on pressure. The diffusion contribution increased greatly as pressure decreased from 2 to 0.2 MPa, and the smaller the shale permeability, the greater the relative contribution of diffusion flow. At pressures greater than 2 MPa, slip flow contributes $$\sim $$ 20% of the total flux, Darcy flow contributes up to 70%, and diffusion makes only a minor contribution. This study provides useful information for future studies of the mechanism of shale gas percolation and the exploration and development of Qaidam Basin shale gas specifically.

Water Availability for Shale Gas Development in Sichuan Basin, China.

Unconventional shale gas development holds promise for reducing the predominant consumption of coal and increasing the utilization of natural gas in China. While China possesses some of the most abundant technically recoverable shale gas resources in the world, water availability could still be a limiting factor for hydraulic fracturing operations, in addition to geological, infrastructural, and technological barriers. Here, we project the baseline water availability for the next 15 years in Sichuan Basin, one of the most promising shale gas basins in China. Our projection shows that continued water demand for the domestic sector in Sichuan Basin could result in high to extremely high water stress in certain areas. By simulating shale gas development and using information from current water use for hydraulic fracturing in Sichuan Basin (20,000-30,000 m(3) per well), we project that during the next decade water use for shale gas development could reach 20-30 million m(3)/year, when shale gas well development is projected to be most active. While this volume is negligible relative to the projected overall domestic water use of ∼36 billion m(3)/year, we posit that intensification of hydraulic fracturing and water use might compete with other water utilization in local water-stress areas in Sichuan Basin.

Sweet spot identification in underexplored shales using multidisciplinary reservoir characterization and key performance indicators: Example of the Posidonia Shale Formation in the Netherlands

Sweet spot identification in underexplored shale gas basins needs to be based on a limited amount of data on shale properties in combination with upfront geological characterization and modelling, because actual production data is usually absent. Multidisciplinary reservoir characterization and integration of modelling approaches can aid initial site selection for exploratory drilling and de-risk exploration efforts. In this study, the potential of hydrocarbon production across underexplored shale basins is analyzed using key performance indicators. A mean indicator is defined as the harmonic mean of three performance indicators that describe the potential for hydrocarbon generation, storage, and flow stimulation. The performance indicators are based on a limited number of local shale properties, i.e. vitrinite reflectance, porosity, depth, thickness, sorbed gas content and brittleness index. Values for the indicators are calculated relative to prospective North American shales (Marcellus, Bakken, Haynesville and Barnett), so that the mean indicator can be used to rank the prospectivity of an underexplored shale relative to hydrocarbon producing shales. The mean performance indicator is also used to map out the potential for gas production in the underexplored Posidonia Shale Formation in the West Netherlands Basin. The analysis shows that the performance indicator is lower for the Posidonia than for the North American Shales, mainly due to low maturity and brittleness. Local maxima of the indicator correlate with local maxima in vitrinite reflectance and depth. Besides the low potential for flow stimulation, the potential for hydrocarbon generation and storage capacity of the Posidonia are comparable to oil-window thermal-maturity Barnett Shale. Upfront simulations of hydraulic fracture properties and gas production in the Posidonia Shale Formation are in rough agreement with observed average gas flow for Barnett wells in non-core areas that are oil mature. It shows that key performance indicators can be applied to underexplored shales to quantify prospectivity and map out sweet spots across shale basins.

An Identified Method for Lacustrine Shale Gas Reservoir Lithofacies Using Logs: A Case Study for No. 7 Section in Yanchang Formation in Ordos Basin

Unconventional reservoirs are keys to oil and gas exploration and development, especially shale gas reservoirs. Discriminated shale gas reservoir lithofacies are, in particular, a primary problem in shale gas reservoir engineering. The mineral composition will affect both absorbed and free gas contents, therefore their identification is important. The mineral composition is one part of lithofacies. The shale content has always been used in previous lithological identifications: this method is effective in sand reservoirs; however, it is not suitable for use in shale gas reservoirs. This paper takes No.7 section in Yanchang formation in Ordos basin as an example. Through a lithological analysis, it was concluded that overlap method and cross-plot method are not also inappropriate for shale gas reservoirs. The Ordos basin shale gas reservoir is divided into seven lithofacies. We form a mathematical method and apply it to shale gas reservoirs using the shale volume and ΔlgR which are available from conventional well logging and reflect organic matter in the processed dataset. Decision tree is used here. However, there were too many parameters to discriminate all lithofacies precisely. Principal component analysis (PCA) is a technique used to reduce multidimensional data sets to lower dimensions for analysis. This technique can be useful in petro-physics and geology as a preliminary method of combining multiple logs into a single entity or two logs without losing information. Combining PCA and a decision tree algorithm, the lithofacies of a shale gas reservoir were accurately discriminated.

The impact of engineering parameters on shale oil and gas production: theory and practice

Production performance of shale oil and gas wells is complicated due to the uncertainty of fracture geometry and heterogeneity of reservoir properties, et al. Especially, it is difficult to link the engineer parameters such as stage, cluster, proppant, fracture fluid to well production, which is significant for fracturing design and optimization. The purpose of this study is trying to find out this link and reveal the production performance and influence factors for shale oil and gas reservoirs. A large number of analytical modeling has done and the sensitivity of production influence factors has studied. Moreover, a field case of shale oil and gas basin in US is analyzed and compared with the theoretic study results. Sensitivity study showed that the production rate increases with fracture half-length, conductivity and horizontal well length increase, while declines with the fracture spacing increases. All of the engineering parameters have optimal values. Field case stated that the influence rules of engineering parameters on production are consistent with the theoretical modeling results, but it is more complicated. It is shown that production has positive correlation with horizontal well length, and has ascending trend with stage, cluster, fracture fluid, proppant increase although it is not obvious. However, the production contribution per increment of their values will decline when they increase. In most cases, the increase of engineering parameters could not lead to production decline, and will only add the operation cost and difficulty. So in order to design the engineering parameters, the optimal value should be determined based on economic indexes. The link between fracturing parameters and fracture characteristics is significant. Fracturing monitoring or fracture propagation modeling is required and necessary to understand well performance for shale oil and gas reservoirs.

Geologic Characteristics and Development Trend of North China Shale Gas Basins

Geologic Characteristics and Development Trend of North China Shale Gas Basins

Geologic Characteristics and Development Trend of South China Shale Gas Basins

Geologic Characteristics and Development Trend of South China Shale Gas Basins

Reply to comment by Flewelling and Sharma on “Hydraulic fracturing in faulted sedimentary basins: Numerical simulation of potential contamination of shallow aquifers over long time scales”

We welcome and appreciate the comments of Flewelling and Sharma [2015, hereafter referred to as FS] which give us the opportunity to clarify and discuss important aspects of our study [Gassiat et al., 2013, hereafter referred to as G13]. FS discuss some important details of the model development and implementation of G13. The main thrust of FS is that parts of the model geometry, parameters and boundary conditions are inappropriate, and model calibration is insufficient for a specific shale gas basin, the St. Lawrence basin. However, the work of G13 was fundamentally a parametric study, using data from multiple shale gas basins to define model geometry, parameters and boundary conditions, and the objective was not to robustly calibrate results to a specific shale gas basin. Below we systematically address the specific comments of FS about the limitations of G13, which provide us an opportunity to further elaborate on the already extensive discussion of such limitations in G13 [paragraphs 36–47].

Effects of composition and pore structure on the reservoir gas capacity of Carboniferous shale from Qaidam Basin, China

Shale adsorption and breakthrough pressure are important indicators of shale gas development and key factors in evaluating the reservoir capacities of shales. In this study, geochemical tests, pore-structure tests, methane adsorption tests, and breakthrough-pressure tests were conducted on shales from the Carboniferous Hurleg Formation in eastern Qaidam Basin. The effects of the shale compositions and pore structures on the adsorption and breakthrough pressures were studied, and the reservoir capacities of the shales were evaluated by analyzing the shale adsorptions and sealing effects. The results indicate that the organic carbon content was only one of factors in affecting the adsorption capacity of the shale samples while the effect of the clay minerals was limited. Based on the positive correlation between the adsorption capacity and specific surface area of the shale, the specific surface area of the micropores can be used as an indicator to determine the adsorption capacity of shale. The micro-fracturing of brittle minerals, such as quartz, create a primary path for shale gas breakthrough, whereas the expansion of clay minerals with water greatly increases the breakthrough pressure in the shale samples. Methane adsorption tests showed that maximum methane adsorption for shale samples Z045 and S039 WAS 0.107 and 0.09655 mmol/g, respectively. The breakthrough pressure was 39.36 MPa for sample S039, maintained for 13 days throughout the experiment; however, no breakthrough was observed in sample Z045 when subjected to an injected pressure of 40 MPa for 26 days. This indicates that sample Z045, corresponding to a depth of 846.24 m, exhibited higher adsorption capacity and a better reservoir-sealing effect than sample S039 (498.4 m depth). This study provides useful information for future studies of Qaidam Basin shale gas exploration and development and for evaluation of shale quality.

Evaluation on Shale Gas Potential in the Sheling Group Yitong Basin

Yitong Basin is a Tertiary depression bas in Jilin Province , and from north to south were Chaluhe , Luxiang and Moliqing depression. As the depth is larger , high maturity of organic matter , more than 1% , mainly shale gas. Based on the geochemical parameters of sheling group , using chemical kinetics method study the birth hydrocarbon volume, using the sum of the largest shale gas tolerance capabilities , based on the adsorption isotherm experiments, combined hydrocarbon volume , calculated the shale gas resources in the region , the results showed that the total amount of resources sheling group Yitong Basin shale gas level was 238.215 billion square . Indicates that the area has huge shale gas resource potential

Productivity of blast-fractured wells in liquid-rich shale gas formations

The explosive stimulation by blast-fracturing was first used in well stimulation with pronounced results in the booming Pennsylvania oil field in 1865. The advent of hydraulic fracturing in the 1950's caused explosive stimulation of oil wells to decline dramatically. Because the hydraulic fracturing process consumes a huge amount of water and imposes a threat to the ground water resources, it is highly desirable to revisit the feasibility of replacing hydraulic fracturing with blast-fracturing in the oil and gas well completion processes. This paper presents an analysis of well productivity of different types of well architectures to be completed with the blast-fracturing stimulation in liquid-rich shale gas formations.Compared to the hydraulic fracturing, blast-fracturing creates radial fractures with fracture-orientations independent of formation stress anisotropy. This eliminates the requirement of in-situ stress orientation that is necessary for designing multi-hydraulic fracturing horizontal wells. An analytical model was developed in this investigation to predict the initial productivity of vertical wells, horizontal wells, and radial-lateral drain holes. Case studies indicate a good agreement between the result given by the models and field observation. Sensitivity analyses with the analytical model indicate that the initial productivity of blast-fractured wells increases non-linearly with the number of radial fractures and fracture penetration. The benefit of increasing fracture depth levels out as the amount of explosives increases. This paper presents well completion engineers a theoretical base and useful data for revolutionizing their well completion technology in developing liquid-rich shale gas basins.

Life cycle greenhouse gas footprint of shale gas: a probabilistic approach

With the increase in natural gas (NG) production in recent years, primarily from shale gas, some sources, including the US Environmental Protection Agency (EPA), have suggested that upstream methane emissions are increasing. Much of the recent controversy has centered on emissions during well drilling, testing, and completion even though emissions downstream of the wellhead are also of concern. The study critically assessed the current state of knowledge about the life cycle GHG footprint of NG, analyzed the assumptions, data and analysis methodologies used in the existing literature. This study comprehensively analyzed the emission of methane from different stage of the life of well for conventional and unconventional NG using the EPA’s revised 2011 estimates as well as other existing literature and publicly available government data. The study proposed a probabilistic model to estimate the range of total GHG footprint of NG with varying probabilities. Through the bottom up approach starting from the well construction to the delivery of NG to the small user and using Monte Carlo simulation, the study identified the critical sources of fugitive emissions from the NG. As expected, emissions from well completion and periodic emissions (e.g. liquid unloading in the case of onshore conventional wells and workovers in the case of unconventional wells) are significant contributors to the overall GHG footprint of NG, and possess large opportunity for reduction. Finally the application of probabilistic model is demonstrated through a case study using the data from the Montney and Horn River shale gas basins in the Northern British Columbia to estimate the range of total GHG footprint of shale gas with varying probabilities. The study found that the GHG footprint of Montney and Horn River wells are much smaller than that of Barnett shale (which is representative of US shale gas) due to strict flaring regulations followed in BC. The study also undercuts the outcome of Howarth et al. (Clim Chang Lett 106:679–690, 2011), which states that the GHG footprint of shale gas is at least 20 % greater than coal.

Special Issue on Environmental Impacts of Shale Gas Development

Shale oil and gas holds great promise as a newly accessible domestic source of energy. Shale gas is expected to grow from 23% of total U.S. dry gas production (in 2010) to more than 49% in 2035 [U.S. Energy Information Administration (U.S. EIA) 2012]. Many shale gas basins in the United States have great potential, including the Fayetteville in Arkansas, the Haynesville in Louisiana and Texas, and the Marcellus in Pennsylvania and West Virginia. Similarly, shale oil basins including the Bakken (North Dakota) and the Eagle Ford (Texas) will contribute to the U.S. oil supply over the coming decades. The potential economic benefits are significant, with estimates of $5.1 trillion in capital expenditures related to the industry between 2012 and 2035 (IHS Global Insight 2012). Engineering and technological development has paved the way for this shale energy transformation through the use of directional drilling and high volume hydraulic fracturing. Similarly, research into the potential adverse impacts of shale development has increased significantly over the past few years. Research has focused on impacts on water (Vidic et al. 2013; Olmstead et al. 2013), air (Pacsi et al. 2013; Roy et al. 2014), human health (Korfmacher et al. 2013; Finkel and Law 2011), and ecology (Entrekin et al. 2011; Drohan et al. 2012). This special issue includes six papers covering important aspects of environmental issues associated with shale development. Geng et al. present results of simulation of migration of pressurized air during drilling of a well. They report that compressed air is capable of creating a high-pressure gradient in groundwater at hundreds of meters from the drill hole in a confined aquifer. Their work suggests observational wells placed prior to drilling could alert drillers to pressure buildup. Gilmore et al. evaluated the potential effect of water and wastewater truck transport associated with development of Marcellus shale gas. Their work highlights the importance of including all truck trips (including empty returns) when evaluating impacts and also suggests policy changes that could reduce impacts by improving planning. He et al. considered the formation of barium and strontium sulfate in produced water from Marcellus shale development. Formation of precipitates can interfere with reuse of produced water, and equilibrium predictions are not always reliable due to the presence of organic matter. Mauter and Palmer describe an expert elicitation related to current practices and future trends in wastewater management, focused on the Marcellus shale gas formation in Pennsylvania. Their work concludes that long-term water reuse is a viable strategy for management of produced water from shale development for companies with ongoing activity. Strong et al. evaluated the biodegradability of produced water from shale development in the Marcellus and Bakken regions. A wide range of organic compounds were found, as were many halophilic bacterial species capable of biodegradation of these organics. Wilson et al. consider shale-produced waters in comparison with other fossil fuel wastewaters to develop an anion ratio-based source identification method. Applying this method to data collected in Pennsylvania allowed identification of sources of changes in surface water quality. We would like to thank the ASCE Journal of Environmental Engineering Special Issues Editor, Dionysios D. Dionysiou, and the ASCE publishing office personnel for their support during the development of this special section. Further, we are grateful to the important contributions of the reviewers during this process.