Papers by Svetlana Ikonnikova
Proceedings of the 8th Unconventional Resources Technology Conference
The URTeC Technical Program Committee accepted this presentation on the basis of information cont... more The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted by the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk. The information herein does not necessarily reflect any position of URTeC. Any reproduction, distribution, or storage of any part of this pap er by anyone other than the author without the written consent of URTeC is prohibited.
Oil & Gas Journal, 2013
Ken Medlock III Rice University Houston A comprehensive study of the reserve and production poten... more Ken Medlock III Rice University Houston A comprehensive study of the reserve and production potential of the Barnett Shale integrates engineering, geology, and economics into a numerical model that allows for scenario testing based on several technical and economic parameters. The study was conducted by the Bureau of Economic Geology (BEG) at The University of Texas at Austin and funded by the Alfred P. Sloan Foundation. In its base case, the study forecasts a cumulative 45 Tcf of economically recoverable reserves from the Barnett, with production declining predictably to about 900 Bcf/year by 2030 from the current peak of about 2 Tcf/year. The forecast falls in the mid to higher end of other known predictions for the Barnett and suggests that it will continue to be a major contributor to U.S. natural gas production through 2030. This study by geologists, engineers, and economists resulted in a cohesive model of the Barnett, linking geologic mapping, production analysis, well econom...
SPE Reservoir Evaluation & Engineering, 2020
Summary Machine learning provides powerful methods for inferential and predictive modeling of com... more Summary Machine learning provides powerful methods for inferential and predictive modeling of complicated multivariate relationships to support decision-making for spatial problems such as optimization of unconventional reservoir development. Current machine-learning methods have been widely used in exhaustive spatial data sets like satellite images. However, geological subsurface characterization is significantly different because it is conditioned by sparse, nonrepresentative sampling. These sparse spatial data sets are generally not sampled in a representative manner; therefore, they are biased. The critical questions are: first, does spatial bias in training data result in a bias for machine-learning-based predictive models; and if there is a bias, how can we mitigate the bias in these spatial machine-learning-based predictions? The presence and mitigation of prediction with spatial sampling bias is demonstrated with tree-based machine learning due to its high degree of interpre...
Proceedings of the 4th Unconventional Resources Technology Conference, 2016
Proceedings of the 5th Unconventional Resources Technology Conference, 2017
The URTeC Technical Program Committee accepted this presentation on the basis of information cont... more The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitt ed by the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does s o at their own risk. The information herein does not necessarily reflect any position of URTeC. Any reproduction, distribution, or storage of any part of this paper without the written consent of URTeC is prohibited.
Interpretation, 2019
An integrated workflow to estimate the hydrocarbon-in-place and recovery factor is applied in the... more An integrated workflow to estimate the hydrocarbon-in-place and recovery factor is applied in the Bakken-Three Forks petroleum system. Evaluating factors that control the generation and storage of hydrocarbon, such as the total organic carbon, maturity of shale, thickness, porosity, and permeability is a challenge in any shale play study. In addition, the hybrid nature of the Bakken petroleum system, where the source and reservoir rock are present within a short depth interval, adds complexity to the production interpretation and outlook of the play. One complexity is the contribution from Upper and Lower Bakken organic-rich shales to the production of horizontal wells completed in the Middle Bakken low-permeability laminated sandstone/siltstone and Upper Three Forks sandy/silty dolostone. We have performed geologic and petrophysical studies and calculate and map the hydrocarbon pore volume. For fluid characterization, we use three models to accurately cover a range of American Petr...
Journal of Natural Gas Science and Engineering, 2016
The Eagle Ford Shale presents a unique opportunity to assess the effect of wide-ranging fluid pro... more The Eagle Ford Shale presents a unique opportunity to assess the effect of wide-ranging fluid properties and pressure on well performance across a single shale play. Thermal maturity, depth, and pressure vary significantly across the Eagle Ford. Reservoir and fluid property variations impact production performance and complicate decline analysis. In addition, operational decisions and facilities limitations further complicate analysis of well performance. Numerous case studies have focused on local parameters for production analysis, such as geometry and conductivity of hydraulic fractures. Few have addressed field-wide parameters like fluid properties and pressure variations.
Environmental Management, 2018
Directional well drilling and hydraulic fracturing has enabled energy production from previously ... more Directional well drilling and hydraulic fracturing has enabled energy production from previously inaccessible resources, but caused vegetation conversion and landscape fragmentation, often in relatively undisturbed habitats. We improve forecasts of future ecological impacts from unconventional oil and gas play developments using a new, more spatially-explicit approach. We applied an energy production outlook model, which used geologic and economic data from thousands of wells and three oil price scenarios, to map future drilling patterns and evaluate the spatial distribution of vegetation conversion and habitat impacts. We forecast where future well pad construction may be most intense, illustrating with an example from the Eagle Ford Shale Play of Texas. We also illustrate the ecological utility of this approach using the Spot-tailed Earless Lizard (Holbrookia lacerata) as the focal species, which historically occupied much of the Eagle Ford and awaits a federal decision for possible Endangered Species Act protection. We found that~17,000-45,500 wells would be drilled 2017-2045 resulting in vegetation conversion of~26,485-70,623 ha (0.73-1.96% of pre-development vegetation), depending on price scenario ($40-$80/barrel). Grasslands and row crop habitats were most affected (2.30 and 2.82% areal vegetation reduction). Our approach improves forecasts of where and to what extent future energy development in unconventional plays may change land-use and ecosystem services, enabling natural resource managers to anticipate and direct on-the-ground conservation actions to places where they will most effectively mitigate ecological impacts of well pads and associated infrastructure.
SPE/IAEE Hydrocarbon Economics and Evaluation Symposium, 2016
We explore the comparative impacts of capital costs, price differentials, and state fiscal polici... more We explore the comparative impacts of capital costs, price differentials, and state fiscal policies on economic decision to drill, paying close attention to the decline of shale well production. We use a standard cash flow model for well economics and perform empirical analysis using actual production and completion data for Marcellus wells, cost and tax payments information from Pennsylvania, West Virginia and New York, and basis differentials in different parts of the play. Wells drilled in similar rock quality areas can have different economic value owing to completion choices and associated costs, state fiscal regimes, and market dynamics as reflected in prices realized by the producers at the wellhead.
SPE/IAEE Hydrocarbon Economics and Evaluation Symposium, 2016
Gradually increasing production of natural gas from shale formations has surpassed the production... more Gradually increasing production of natural gas from shale formations has surpassed the production from all other sources, including conventional, coal-bed, and tight formations in the U.S. (EIA, Monthly Energy Review, Jan. 2016). In fact, thanks to shale, natural gas production in the U.S. increased much faster than demand growth. Lower gas prices since 2010-11 owing to excess supply, has been encouraging more natural gas utilization in power generation and industrial sector, and exports via pipelines to Mexico and the rest of the world via liquefaction facilities. Many of these facilities are still under construction; and demand growth may not be fully felt until 2018 or later. In the meantime, shale drilling has slowed down considerably owing to low oil (and NGL) prices in addition to low natural gas prices. This situation raises concerns about the shale gas resource potential and future production capabilities. To address these concerns, the understanding of the two key resource ...
All Days, 2016
The advent of horizontal drilling technology and hydraulic fracture completions has fundamentally... more The advent of horizontal drilling technology and hydraulic fracture completions has fundamentally altered the geometry of flow in shale gas systems, requiring new decline curves to forecast production. In this work we perform automatic decline analysis on Marcellus gas shale wells, and predict ultimate recovery for each well. We use a minimal model that captures the basic physics and geometry of the extraction process. This model allows us to scale all individual wells' gas productions to fit upon a single, universal curve. This scaling curve predicts the production rate will decline as 1 divided by the square root of time early in the life of the well, and eventually rate declines exponentially. We fit cumulative production to the results of this model to determine time to boundary-dominated flow and ultimate recovery. For wells that have not entered boundary dominated flow, we use a new technique to estimate ultimate recovery, relying on early production. We find 404 wells tha...
Interpretation, 2016
A comprehensive regional investigation of the Eagle Ford Shale linking productivity to porosity-t... more A comprehensive regional investigation of the Eagle Ford Shale linking productivity to porosity-thickness (PHIH), lithology ([Formula: see text]), pore volume (PHIT), organic matter (TOC), and water-saturation ([Formula: see text]) variations has not been presented to date. Therefore, isopach maps across the Eagle Ford Shale play west of the San Marcos Arch were constructed using thickness and log-calculated attributes such as TOC, [Formula: see text], [Formula: see text], and porosity to identify sweet spots and spatial distribution of these geologic characteristics that influence productivity in shale plays. The Upper Cretaceous Eagle Ford Shale in South Texas is an organic-rich, calcareous mudrock deposited during a second-order transgression of global sea level on a carbonate-dominated shelf updip from the older Sligo and Edwards (Stuart City) reef margins. Lithology and organic-matter deposition were controlled by fluvial input from the Woodbine delta in the northeast, upwellin...
Economics of Energy & Environmental Policy, 2015
ABSTRACT This paper reviews major findings and insights from a series of integrated geologic, eng... more ABSTRACT This paper reviews major findings and insights from a series of integrated geologic, engineering, economic, and econometric analyses performed on the four largest U.S. shale gas plays. Developments in the Barnett Shale, Fayetteville Shale, Haynesville Shale, and Marcellus Shale plays are explained on the basis of a comprehensive data set, including existing wells production histories, drilling path data, geologic attributes and natural gas market parameters. The paper presents the data-driven methodology consistently applied to all four plays. The key insights discussed include the relationship between a play’s geology and well production; the impact of technological improvements of well productivity and inventory of future wells; and the dependence of well economics on geology, technology, and regulations.
AAPG Bulletin, 2015
ABSTRACT This study estimates reservoir quality and free-gas storage capacity of the Barnett Shal... more ABSTRACT This study estimates reservoir quality and free-gas storage capacity of the Barnett Shale in the main natural-gas producing area of the Fort Worth basin by mapping log-derived thickness, porosity, and porosity-feet. In the Barnett Shale, the density porosity (DPHI) log curve is a very useful tool to quantitatively assess shale gas resources, and gamma-ray (GR) and neutron porosity log curves are important factors in identifying the shale gas reservoir. The key data were digital logs from 146 wells selected based on the availability of GR and density log curves, log quality, and good spatial distribution. The Barnett Shale pay zone was determined on the basis of (1) DPHI >5%, (2) high GR values (commonly >similar to 90 API units), (3) no significant intercalated carbonate-rich beds, and (4) individual pay zones being thick enough to be commercially successful for the current design of horizontal wells. In the study area, the Barnett Shale pay zone varies from about 165 ft (50 m) to 420 ft (128 m) in thickness (H). Average DPHI values of individual wells for the pay zone vary from 8.5 to 14.0%. Porosity-feet maps of the pay zone show that areas of high DPHI-H values coincide with areas of high natural gas production, indicating that log-derived porosity-feet maps are a good method for evaluating reservoir quality and assessing natural gas resource in the Barnett Shale play. A limitation to this method is shown in the northwestern corner of the study area, which is located in the liquids-rich window with lower thermal maturity.
SPE Economics & Management, 2013
Summary We developed a production-outlook model on the basis of an interdisciplinary analysis of ... more Summary We developed a production-outlook model on the basis of an interdisciplinary analysis of production data from more than 15,000 wells and geologic data on the Barnett play. The model is the most granular to date because it incorporates 10 tiers of varying productivity and well economics of average wells by tier; it covers close to 8,000 square-mile blocks across partly drained and undrilled acreage, divided between low-Btu and high-Btu segments, and uses drillwell potential by tier for the total area; and it is unique in its use of production profiles on the basis of transient linear drainage. Drilling pace is adjusted to changes in natural-gas price relative to well economics, historical attrition rates, and logistical constraints. We analyze scenarios and conduct a simulation analysis on the basis of reasonable ranges for natural-gas price, remaining acreage developable in partly drained and undrilled blocks, improvement in technology and well cost performance, and economic...
SPE Unconventional Resources Conference, 2014
The Haynesville Shale is one of the largest unconventional gas fields in the US. It is also one o... more The Haynesville Shale is one of the largest unconventional gas fields in the US. It is also one of the deepest, with wells reaching more than 10,000 feet below ground. This uncommon depth and overpressure leads to initial reservoir pressures of up to 12,000 psi. These pressures are uniquely high among shale gas reservoirs, and require special treatment. We show that the methods developed by Patzek, et al., PNAS, 110, 19731-19736, can scale all individual wells' gas productions to fit upon a single, universal curve. Haynesville wells can take months or years for flowing tubing pressure to stabilize, so we modified the type curves to take this into account. Furthermore, we introduce a PVT solver in order to calculate gas properties at up to reservoir pressures. When we apply the scaling theory to 2,199 individual well productions in the Haynesville, we find 1,580 wells which have entered exponential decline due to pressure interference. We use a simple physical model to determine ...
We present a new methodology to study how upstream (e.g. producers) and downstream (e.g. transite... more We present a new methodology to study how upstream (e.g. producers) and downstream (e.g. transiters) players form coalitions, bargain over joint profit sharing and invest. Within coalitions players combine resources, coalitions compete on a market. Profit of each coalition depends on the cooperation among the outside players. Hence, we consider a game with externalities. To find the equilibrium coalition structure and the expected payoffs, we use the solution proposed by Maskin (2003). Payoffs reflect the bargaining power and depend on capacities of players. We show, how investment options available to players matter. We apply the study to analyze the Eurasian gas supply network. Russia and Turkmenistanproducers and Ukraine, Belorus, Azerbaijan, Iran-transiters form coalitions to supply gas and bargain over profit sharing. Besides, the players invest in pipelines. We derive the bargaining power of the countries from the architecture of the network and calculate the strategic value of the different pipeline projects.
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Papers by Svetlana Ikonnikova