Nano-petrophysical Characterization of the Oil Window of Eagle Ford Shale from Southwestern to Central Texas, U.S.A. PDF Download
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Author: Chad Larsen
Publisher:
ISBN:
Category :
Languages : en
Pages : 89
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Book Description
Eagle Ford Shale and the overlying Austin Chalk are the main producing plays throughout Central Texas. Due to the high clastic nature of Eagle Ford Shale and its ability to produce and maintain fractures from hydraulic fracturing, this formation quickly became the favored target over Austin Chalk for unconventional hydrocarbon production. The purpose of this study is to gain an understanding of nano-petrophysical properties of Eagle Ford Shale,which is still lacking.Drilling cores from three wells within the oil window of Eagle Ford Shale were examined at the Bureau of Economic Geology in Austin, TX. Multiple plug samples were taken of three wells and analyzed using various tests of XRD, pyrolysis, TOC, mercury intrusion porosimetry (MIP), pycnometry, (DI water and n-decane) vacuum saturation, low-pressure nitrogen gas physisorption, and fluid (DI water and n-decane) imbibition. These experiments will shed light on the nano-petrophysical properties of the reservoir regarding porosity, pore throat distribution, permeability, and flow patterns. MIP results from this study show that Eagle Ford Shale has a wide range of pore structure parameters with porosity values varying from 0.11 to 7.25% and permeability from 0.005 to 11.6 mD; all samples are dominated by two pore types: micro fractures (1-50 μm) and inter-granular(0.01-1 uμ) pores. TOC % showed an increase when quartz % increased as minerology has a direct influence on TOC %. Bulk density averages 2.54% while the grain density is slightly increased with an average of 2.64%. Kerogen values plot between group II and III indicating a hydrocarbon potential. Based on the nano-petrophysical analysis of Eagle Ford Shale, the results of this thesis are beneficial to further the understanding of the pore structure and fluid migration within the shale, and to better facilitate increased production.
Author: Chad Larsen
Publisher:
ISBN:
Category :
Languages : en
Pages : 89
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Book Description
Eagle Ford Shale and the overlying Austin Chalk are the main producing plays throughout Central Texas. Due to the high clastic nature of Eagle Ford Shale and its ability to produce and maintain fractures from hydraulic fracturing, this formation quickly became the favored target over Austin Chalk for unconventional hydrocarbon production. The purpose of this study is to gain an understanding of nano-petrophysical properties of Eagle Ford Shale,which is still lacking.Drilling cores from three wells within the oil window of Eagle Ford Shale were examined at the Bureau of Economic Geology in Austin, TX. Multiple plug samples were taken of three wells and analyzed using various tests of XRD, pyrolysis, TOC, mercury intrusion porosimetry (MIP), pycnometry, (DI water and n-decane) vacuum saturation, low-pressure nitrogen gas physisorption, and fluid (DI water and n-decane) imbibition. These experiments will shed light on the nano-petrophysical properties of the reservoir regarding porosity, pore throat distribution, permeability, and flow patterns. MIP results from this study show that Eagle Ford Shale has a wide range of pore structure parameters with porosity values varying from 0.11 to 7.25% and permeability from 0.005 to 11.6 mD; all samples are dominated by two pore types: micro fractures (1-50 μm) and inter-granular(0.01-1 uμ) pores. TOC % showed an increase when quartz % increased as minerology has a direct influence on TOC %. Bulk density averages 2.54% while the grain density is slightly increased with an average of 2.64%. Kerogen values plot between group II and III indicating a hydrocarbon potential. Based on the nano-petrophysical analysis of Eagle Ford Shale, the results of this thesis are beneficial to further the understanding of the pore structure and fluid migration within the shale, and to better facilitate increased production.
Author: Namrita Sondhi
Publisher:
ISBN:
Category : Gas reservoirs
Languages : en
Pages : 352
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Author: Austin Pourciau Cardneaux
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ISBN:
Category :
Languages : en
Pages :
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Author: Sebastian Ramiro-Ramirez
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ISBN:
Category : Facies (Geology)
Languages : en
Pages : 126
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Author:
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ISBN:
Category :
Languages : en
Pages :
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We report that porosity and permeability are key variables that link the thermal-hydrologic, geomechanical and geochemical behavior in rock systems and are thus important input parameters for transport models. Recent neutron scattering studies have indicated that the scales of pore sizes in rocks extend over many orders of magnitude from nanometer pores with huge amounts of total surface area to large open fracture systems (multiscale porosity, cf. Anovitz et al., 2009, 2011, 2013a, b, Wang et al., 2013; Swift et al., in press). However, despite considerable effort combining conventional petrophysics, neutron scattering and electron microscopy, the quantitative nature of this porosity in tight gas shales, especially at smaller scales and over larger rock volumes, remains largely unknown (Clarkson, 2011). Nor is it well understood how porosity is affected by regional variation, thermal changes across the oil window and, most critically, hydraulic fracturing operations. To begin providing this understanding we have used a combination of small and ultrasmall angle neutron scattering from the GP-SANS instrument at ORNL/HFIR, and the NG3-SANS (Glinka et al., 1998) and BT5-USANS instruments at NIST/NCNR (Barker et al., 2005), with SEM/BSE imaging to analyze the pore structure of clay and carbonate-rich samples of the Eagle Ford Shale. The Eagle Ford Shale is a late Cretaceous unit underlying much of southeast Texas and probably adjacent sections of Mexico. It outcrops in an arc from north of Austin, through San Antonio and then west towards Kinney County. It is hydrocarbon rich, straddles the oil window, and is one of the most actively drilled oil and gas targets in the US. The first successful horizontal well was drilled in 2008, and 2522 permits were recorded by Sept 1, 2011. While the oil and gas reserves in the Eagle Ford have been known since the 1970's, prior to the invention of horizontal drilling/hydraulic fracturing it was not considered economic. Several important trends in the rock pore structure have been identified using our approach. Pore distributions are clearly fractal but, as was observed for the St. Peter sandstone (Anovitz et al., 2013a), are composed of several size distributions. Initial porosity is strongly anisotropic, as expected for shale. However, this decreases for shale, and disappears for carbonates with maturity. In both cases significant reduction occurs in total porosity, with most of the change coming at the finest scales (
Author: Qiming Wang (Ph.D.)
Publisher:
ISBN:
Category :
Languages : en
Pages : 97
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As one of the most productive shale gas plays, the Haynesville Shale has a high geopressure gradient and high temperature, but with a lack of petrophysical understanding. To analyze the poregeometry and wettability related connectivity of this formation, multiple methods such as total organic carbon content (TOC), X-ray diffraction (XRD), vacuum saturation, mercury intrusion capillary pressure (MICP), contact angle, fluid imbibition, and helium pycnometry were used on 10 Haynesville Shale core samples from a single well over a vertical distance of 123 ft. The results from those tests show that the Haynesville Shale is calcareous shale with 2.26~5.28% of TOC. The porosities range from 3 to 8%, and the pore-throat sizes are concentrated at the nanoscale (2.8~50 nm). Moreover, the permeability and effective tortuosity of the pore network controlled by 2.8 to 50 nm pore-throat size are 3.7 to 23.4 nD and 1413 to 3433, respectively. All ten samples show strong oil-wet characteristics and only three samples exhibit mixed wettability (both oil-wet and water-wet). In general oil-wet samples show higher pore connectivity when they imbibe hydrophobic (a mixture of n-decane: toluene at 2:1, as an oil analog) than hydrophilic (deionizedwater) fluids.
Author: Okwuosa Francis Chukwuma
Publisher:
ISBN:
Category :
Languages : en
Pages : 68
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The introduction of horizontal drilling combined with the ability to perform multiple stage hydraulic fracture treatment has enabled the oil and gas industry to explore previously unexploitable source formations, where it is estimated that 85% of the original reserves still resides. The application of these techniques provides economic gas and oil flow in extremely low porosity and permeability reservoirs. The Utica play, like the Bakken, Eagle ford, Marcellus, Haynesville, Permian and Niobrara plays are the current focus for unconventional reservoir exploration in the United States where it is estimated that shale gas and oil production from these plays would reach 80 billion cubic feet per day and 9.6 million barrels per day, respectively, by the year 2020 (EIA, 2014). However, despite these recent advances in production techniques used in stimulating tight shale reservoirs, most shale wells are still characterized by overall low recovery and steady steep decline in production typical to unconventional plays. The Utica Shale is not excluded from this, with production from this play showing an initial decline rate of 65% after its first year of production. This may be as a result of the low pore connectivity and very narrow pores that affects movement of hydrocarbon from the shale matrix to the well bore. A number of factors such as pressure volume and temperature (pvt), pore grain composition, multiphase fluid flow have been attributed to this observed phenomenon in shale reservoirs. However, researchers have not investigated the pore structure of the nanopores storing and transporting hydrocarbon.This study will evaluate pore-size distribution and pore connectivity of Utica Shale samples obtained from J. Goins (GS-3), Prudential (1-A) and Fred Barth (#3) wells in Ohio. Using mercury intrusion porosimetry, fluid (DI water, API brine and n-decane) and trace rimbibition, and edge-only accessible porosity tests, we were able to investigate the pore structure, edge accessible porosity, and the degree to which wettability is associated with mineral and organic kerogen phases. The MICP tests gave us initial sample characterization of basic petrophysical properties (porosity, permeability, pore-size distribution, and tortuosity). We examined imbibition behavior and imbibed tracer distribution for fluids (API brine or n-decane) to examine the association of tracers with mineral or kerogen phases using LA-ICP-MS mapping to measure the presence of tracersin each fluid. Mercury intrusion capillary pressure analyses shows that the Utica pores are predominantly in the nanometer size range, with measured average pore-throat diameter of 4 nm to 6 nm across the study location. Imbibition slopes shows an evidence of low pore connectivity which is consistent with percolation theory interpretation of low connectivity and may be due to the observed small pore-throat distribution. These innovative approaches are significant because they may hold the key to understanding fluid flow and pore structure in the nanopores by stipulating the limited accessibility and connectivity in the Utica Shale.
Author: Ryan Jones
Publisher:
ISBN:
Category :
Languages : en
Pages : 81
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The Permian Basin has been producing oil and gas for over a century, but the production has increased rapidly in recent years due to new completion methods such as hydraulic fracturing and horizontal drilling. The Wolfcamp Shale is a large producer of oil and gas that is found within both the Delaware and Midland sub-basins of the Permian. This study focuses on the Wolfcamp A section in the Delaware Basin which lies within southeastern New Mexico and west Texas. The most recent study performed to estimate continuous (unconventional) oil within the Delaware Basin was conducted in November 2018 by the USGS. They found that the Wolfcamp and overlying Bone Spring formations have an amount of continuous oil that more than doubles the amount found in the Wolfcamp of the Midland Basin in 2016. However, to ensure a high rate of recovery of this oil and gas it is important to understand the nano-petrophysical properties of the Wolfcamp Shale. This study aims to obtain the nano-petrophysical properties of the Wolfcamp A shale formation in Eddy County, NM. To determine petrophysical properties such as density, porosity,permeability, pore connectivity, pore-size distribution, and wettability, various testing procedures were used on a total of 10 samples from 3 different wells in the Wolfcamp A formation. These procedures include vacuum-assisted liquid saturation, mercury intrusion porosimetry (MIP), liquid pycnometry, contact angle/wettability, and imbibition, along with XRD, TOC, and pyrolysis evaluations. Results show that samples from two wells are carbonate dominated and contain 0.08-0.25% TOC, while the third well shows higher amounts of quartz/clay with 1.56-4.76% TOC. All samples show a high concentration of intergranular pores, and two dominant pore-throat sizes of 2.8-50 nm and >100 nm are discovered. Permeability and tortuosity values in the 2.8-50 nm pore network range from 2.75-21.6 nD and 375-2083, as compared to 8.85103-5.44×105 nD and 5.49-295 in the >100 nm pore network. Average porosity values range from 0.891-9.98% from several approaches, and overall wettable pore connectivity is considered intermediate towards deionized water (hydrophilic fluid) and high towards DT2 (n-decane:toluene=1:1, a hydrophobic fluid).
Author: Arinze Collins Adon
Publisher:
ISBN:
Category :
Languages : en
Pages : 78
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Author: Ashley Chang
Publisher:
ISBN:
Category :
Languages : en
Pages : 78
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Book Description
The Permian Basin is one of the largest oil producing basins in the United States. The Permian Basin is 260 miles by 300 miles in area and encompasses 52 counties in southeast New Mexico and West Texas. In the past decade, the Permian Basin has exceeded its previous peak from the early 1970s (EIA, 2018). Now, the basin has generated more than 33.4 billion barrels of oil and roughly 118 trillion cubic feet of natural gas (EIA, 2018). The Permian Basin is a very complex sedimentary system, with three main sub-divisions that are geologically and stratigraphically different from one another. These three sub-divisions are the Midland Basin, Central Basin Platform and the Delaware Basin. The Delaware Basin, specifically the Bone Spring and Wolfcamp Formations, will be the focus of this study.Although the production in the Permian Basin has been accelerating, the steep decline rate in the production of the basin is a realistic concern. To better understand the factors contributing to the production decline rate, this study will investigate the pore structure and fluid migration within the Bone Spring and Wolfcamp Formations. Seven samples from the Wolfcamp are studied, along with two samples from the First Bone Spring unit and one sample from the Second Bone Spring unit. The methods used in this investigation include: total organic carbon (TOC) analysis and pyrolysis for the geochemistry, x-ray diffraction (XRD) to determine the mineralogy, vacuum saturation and liquid displacement, mercury intrusion capillary pressure (MICP) measurements of the sample's petrophysical properties (such as porosity, pore size distribution, tortuosity and permeability), and spontaneous imbibition to determine the pore connectivity in DI water and DT2 (n-decane: toluene= 2:1 in volume) fluids.The results from the methods stated above show that samples from the Wolfcamp and Bone Spring Formations are quartz or carbonate rich and have TOC values that range from 0.08-1.96%. The porosity of all samples range between 0.36-7.65%. Most samples have pores that are in the micro-fracture and intergranular pore range (>100 nm), with only three samples falling within the intragranular, organic matter, and inter-clay platelet pore range (2.5-50 nm). The samples with a predominant pore-throat network interval of 2.8-50 nm have a permeability that ranges from 0.55 nD to 294 nD, and a geometrical tortuosity that ranges from 2.7-85.2. Samples that have a predominant pore-throat network of >100 nm have a range of 2.55×104 nD to 6.02×109 nD in permeability, and a geometrical tortuosity range of 0.2-5.3. Three out of the 10 samples display a good pore connectivity towards DT2 fluid, and all samples show poor pore connectivity with DI water.
