Microseismic Monitoring of the B-Sand Hydraulic Fracture Experiment at the DOE/GRI Multi-Site Project

Warpinski, N.R.; Wright, Tom; Uhl, J.E.; Engler, B.P.; Drozda, P.M.; Peterson, R.E.; Branagan, P.T.

doi:10.2118/36450-ms

“…Also, since microseisms do not necessarily occur on the hydraulic fracture itself (but can in fact be some distance to the side and/or ahead of fracture), it is difficult to determine completely accurate geometries of the fracture. According to Warpinski et al (1999) Other factors that can contribute to microseismic event location uncertainty are the distance from microseism to receiver and the azimuth of microseismic signals. From the same study done by Warpinski et al (1999), accuracy of the azimuth to the microseism is about ±5 o whereas uncertainty in the distance from the receiver to the microseism varies considerably depending upon the number of levels on which the S-wave arrival is accurately detected, but it is approximately on the order of ±50 ft.…”

Section: Downhole Methodology Vs Surface Methodologymentioning

confidence: 99%

A Comparison of Hydraulic-Fracture Modeling With Downhole and Surface Microseismic Data in a Stacked Fluvial Pay System

Mohammad

¹

,

Miskimins

²

2012

SPE Production &Amp; Operations

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The work in this project concentrates on comparing the results of hydraulic fracture mapping and modeling using two microseismic monitoring techniques: downhole and surface arrays. There were three objectives achieved in this project in order to obtain the resulting comparisons. The first objective was to develop detailed posttreatment models of the hydraulic fracturing treatments in the subject well, Well D1, which was monitored with downhole microseismic data. The second objective was to develop detailed post-treatment models of the hydraulic fracturing treatments in the subject well, Well S1, which was monitored with surface microseismic data. The final objective of this project was to determine the match characteristics of the downhole and surface microseismic data to hydraulic fracture models developed for both Wells D1 and S1. Comparisons of the match characteristics of the multiple inputs were then developed.In this study, GOHFER™, a fully three-dimensional fracture simulator was used to build hydraulic fracture stimulation models that were integrated with microseismic events detected during actual hydraulic fracture treatments on Wells D1 and S1.GOHFER™ uses data from actual hydraulic fracturing treatments (pressure, slurry rate, and proppant concentration) and log-derived data to supplement reservoir and mechanical iv Input data for this project were obtained from five wells in the Greater Natural Buttes, Uinta basin, Utah. Two wells, Wells D1 and S1, were stimulated with hydraulic fracturing treatments where each well was monitored by geophone arrays that were placed at different locations. Downhole geophone receivers were employed in an observation well, Well D2, to monitor microseismic activities in the treatment well, Well D1. For the other treated well, Well S1, geophone receivers were placed on the ground surface surrounding the treatment well to monitor microseismic events in the subsurface.Multiple log data were provided for the treated wells including the sonic log from which rock mechanical properties were calculated.Ten fracture models were built using GOHFER™ for five stages each from Wells D1 and S1. Pressure matching procedures were performed to achieve the final simulated fracture geometries. The integration process took place by utilizing data from two sources: microseismic mapping during actual hydraulic fracturing treatment; and fracture profiles from simulated fracture models. Results from the integration process show good agreement for most stages in the downhole-monitored well, whereas comparisons of surface microseismic mapping measurements with the simulated fracture geometries yield questionable results especially regarding microseismic event locations with respect to depth.

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“…According to Warpinski et al (1999) Other factors that can contribute to microseismic event location uncertainty are the distance from microseism to receiver and the azimuth of microseismic signals. From the same study done by Warpinski et al (1999), accuracy of the azimuth to the microseism is about ±5 o whereas uncertainty in the distance from the receiver to the microseism varies considerably depending upon the number of levels on which the S-wave arrival is accurately detected, but it is approximately on the order of ±50 ft. Given the uncertainties in microseism locations, the microseismic results in this research and other situations should be considered as an envelope that "surrounds" the fracture.…”

Section: Downhole Methodology Vs Surface Methodologymentioning

confidence: 99%

A Comparison of Hydraulic Fracture Modeling With Downhole and Surface Microseismic Data in a Stacked Fluvial Pay System

Mohammad

¹

,

Miskimins

²

2010

SPE Annual Technical Conference and Exhibition

0

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The work in this project concentrates on comparing the results of hydraulic fracture mapping and modeling using two microseismic monitoring techniques: downhole and surface arrays. There were three objectives achieved in this project in order to obtain the resulting comparisons. The first objective was to develop detailed posttreatment models of the hydraulic fracturing treatments in the subject well, Well D1, which was monitored with downhole microseismic data. The second objective was to develop detailed post-treatment models of the hydraulic fracturing treatments in the subject well, Well S1, which was monitored with surface microseismic data. The final objective of this project was to determine the match characteristics of the downhole and surface microseismic data to hydraulic fracture models developed for both Wells D1 and S1. Comparisons of the match characteristics of the multiple inputs were then developed.In this study, GOHFER™, a fully three-dimensional fracture simulator was used to build hydraulic fracture stimulation models that were integrated with microseismic events detected during actual hydraulic fracture treatments on Wells D1 and S1.GOHFER™ uses data from actual hydraulic fracturing treatments (pressure, slurry rate, and proppant concentration) and log-derived data to supplement reservoir and mechanical iv Input data for this project were obtained from five wells in the Greater Natural Buttes, Uinta basin, Utah. Two wells, Wells D1 and S1, were stimulated with hydraulic fracturing treatments where each well was monitored by geophone arrays that were placed at different locations. Downhole geophone receivers were employed in an observation well, Well D2, to monitor microseismic activities in the treatment well, Well D1. For the other treated well, Well S1, geophone receivers were placed on the ground surface surrounding the treatment well to monitor microseismic events in the subsurface.Multiple log data were provided for the treated wells including the sonic log from which rock mechanical properties were calculated.Ten fracture models were built using GOHFER™ for five stages each from Wells D1 and S1. Pressure matching procedures were performed to achieve the final simulated fracture geometries. The integration process took place by utilizing data from two sources: microseismic mapping during actual hydraulic fracturing treatment; and fracture profiles from simulated fracture models. Results from the integration process show good agreement for most stages in the downhole-monitored well, whereas comparisons of surface microseismic mapping measurements with the simulated fracture geometries yield questionable results especially regarding microseismic event locations with respect to depth.

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“…In the adjacent Rulison field, the combined impact of permeability, anisotropy, and depositional direction result in reservoir drainage taking a preferential east-west direction (Kuuskraa and Ammer, 2004). Studies of the stress field at the MWX site found the preferred fracture orientation in that area to be N74 to 80°W (azimuth of 106 to 111°) (Myal et al, 1989;Koepsell et al, 2003;Warpinski et al, 1996). Few fractures are found with orientations other than a general eastwest direction; outcrop studies indicate fracture strikes are within +/-25 degrees of east-west, implying only one fracture set (Nelson, 2003).…”

Section: Conceptual Flow Modelmentioning

confidence: 99%

“…Warpinski et al (1996) evaluated six hydrofrac operations in the B-sand fluvial sandstone (Williams Fork) at the MWX site, identifying a range in length from 53.3 to 106.7 m and a range in height of 12.2 to 41.1 m. They note that the length changes only slightly from tests of small-volume, low-viscosity fluids pumped at slow rates to larger volumes of high-viscosity fluids pumped at high rates, with the height being more affected. Another six hydrofrac operations were performed in the C-sand, resulting in fractures extending 121.9 to 152.4 m. However, diagnostics at an intersection well located at a distance of 87.5 m showed that the fractures were not conductive connections.…”

Section: Hydraulic Fracture Lengthmentioning

confidence: 99%

Tritium Transport at the Rulison Site, a Nuclear-stimulated Low-permeability Natural Gas Reservoir

Cooper¹,

Ye²,

Chapman³

2008

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EXECUTIVE SUMMARYThe U.S. Department of Energy (DOE) and its predecessor agencies conducted a program in the 1960s and 1970s that evaluated technology for the nuclear stimulation of lowpermeability natural gas reservoirs. The second project in the program, Project Rulison, was located in west-central Colorado. A 40-kiltoton nuclear device was detonated 2,568 m below the land surface in the Williams Fork Formation on September 10, 1969. The natural gas reservoirs in the Williams Fork Formation occur in low permeability, fractured sandstone lenses interbedded with shale. Radionuclides derived from residual fuel products, nuclear reactions, and activation products were generated as a result of the detonation. Most of the radionuclides are contained in a cooled, solidified melt glass phase created from vaporized and melted rock that re-condensed after the test. Of the mobile gas-phase radionuclides released, tritium ( 3 H or T) migration is of most concern. The other gas-phase radionuclides ( 85 Kr, 14 C) were largely removed during production testing in 1969 and 1970 and are no longer present in appreciable amounts. Substantial tritium remained because it is part of the water molecule, which is present in both the gas and liquid (aqueous) phases.The objectives of this work are to calculate the nature and extent of tritium contamination in the subsurface from the Rulison test from the time of the test to present day (2007), and to evaluate tritium migration under natural-gas production conditions to a hypothetical gas production well in the most vulnerable location outside the DOE drilling restriction. The natural-gas production scenario involves a hypothetical production well located 258 m horizontally away from the detonation point, outside the edge of the current drilling exclusion area. The production interval in the hypothetical well is at the same elevation as the nuclear chimney created by the detonation, in order to evaluate the location most vulnerable to tritium migration.A three-dimensional geologic model was developed of the local Williams Fork Formation at the Rulison site that includes a sequence of sandstone and shale lenses conditioned on observations at two site wells. The dominant flow and transport direction is east-west, in agreement with the direction of regional fractures in the area. The average sandstone lens length is approximately 161 m, and mean thickness is 7.5 m. The sandstone lenses are characterized by very low intrinsic permeability in core measurements (on the order of 10 -18 m 2 ), while reservoir tests often indicate higher permeabilities (up to 10 -16 m 2 ) presumably as a result of fractures encountered at the field scale. Porosity of Williams Fork sandstone units is generally reported as being between 0.01 and 0.1. Shale units are considered barriers to flow, with intrinsic permeability of 10 -20 m 2 .A conceptual flow and transport model for the area around the emplacement well (where the nuclear device was located) was developed to investigate the rates of tritium transport in...

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Microseismic Monitoring of the B-Sand Hydraulic Fracture Experiment at the DOE/GRI Multi-Site Project

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A Comparison of Hydraulic-Fracture Modeling With Downhole and Surface Microseismic Data in a Stacked Fluvial Pay System

A Comparison of Hydraulic-Fracture Modeling With Downhole and Surface Microseismic Data in a Stacked Fluvial Pay System

A Comparison of Hydraulic Fracture Modeling With Downhole and Surface Microseismic Data in a Stacked Fluvial Pay System

Tritium Transport at the Rulison Site, a Nuclear-stimulated Low-permeability Natural Gas Reservoir

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