Nano-petrophysics of Avalon Shale of the Delaware Basin of West Texas & Southeastern New Mexico, USA PDF Download
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Author: Arinze Collins Adon
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Languages : en
Pages : 78
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Author: Arinze Collins Adon
Publisher:
ISBN:
Category :
Languages : en
Pages : 78
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Author: Ryan Jones
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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: Ashley Chang
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Category :
Languages : en
Pages : 78
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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.
Author: Nabil Mzee
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Languages : en
Pages : 71
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Technological advances in hydraulic fracturing and horizontal drilling have led to a surge in oil and gas production in unconventional shale reservoirs over the past several decades. The Permian Basin of Northwest Texas and Southeast New Mexico is no exception to this. Since 2009, when the application of these technologies went into full scale, the production in the Permian Basin has more than doubled. Despite the enormous advances in production in the Permian Basin, operators are plagued by rapid decline rates in producing wells. The root cause of the rapid production decline rates is not well understood but there is consensus that the predominance of nanopores in these unconventional reservoirs plays a significant role in the sharp production declines. In order to develop a better understanding of the production behavior in unconventional reservoirs, the nano-petrophysical properties of these reservoirs must be investigated. This study investigates the nano-petrophysics of the Wolfcamp B, Wolfcamp A, Dean, and Spraberry Formations of the Midland sub-basin in the Permian Basin by Mercury Injection Capillary Pressure (MICP) analysis, spontaneous fluid imbibition tests, vacuum saturation and liquid displacement tests, x-ray diffraction (XRD), and pyrolysis. Most samples exhibit significant pore size distribution in pore throat diameter ranges associated with intra-clay grain space, organic matter hosted pores, and intragranular pores. Thermal maturation is found to play a significant role in the generation of pores within these pore throat ranges. The hydrophobic pore networks of the samples exhibit a better connectivity than the hydrophilic pore networks of the samples. Lastly, pore size distribution is found to be a significant controlling factor on permeability as the significant presence of pores within the 2.8-50 nm range correlates with lower permeabilities and higher tortuosities in the sample set.
Author: Jordan Bevers
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Languages : en
Pages : 103
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Despite the increased hydrocarbon production in hydraulically stimulated unconventional reservoirs, how fluid flows through the rock matrix in these reservoirs is still not well understood. It has been shown that much of the porosity in unconventional mudrocks is nanometer in size, making research challenging as analyzing these pores requires specialized methodologies. These pore networks affect fluid flow by their pore sizes, pore throats, and topology (pore connectivity). The Bone Spring Formation is one of the fastest growing unconventional plays in the world. It is a hybrid shale-oil system with high total organic carbon (TOC) source rocks juxtaposed against organic-lean reservoir layers such as sandstone and carbonate. However, there are very limited studies of nano-petrophysics (the interaction of fluids with porous media with a strong presence of nano-sized pore spaces) of organic-rich and organic-lean facies of Bone Spring Formation, which is the focus of this research. To achieve this objective, several core samples of both organic-rich and organic-lean facies in the Bone Spring Formation were taken from two nearby wells (both vertical and conventional wells with one being productive during 1984-2016 and the other dry). The nanopetrohysics were investigated by mercury intrusion capillary pressure (MICP), contact angle (wettability) tests, spontaneous imbibition and vapor absorption. Pyrolysis was conducted to analyze maturity and TOC while X-ray diffraction (XRD) was carried out for determining mineral composition Porosity in the study samples varied from 0.3-3.2% with the majority of pore throats being 5-50 nm, which are likely organic or intraparticle types. Connectivity of the pore systems is very low for water (hydrophilic fluid) but high for n-decane (hydrophobic fluid). An integrated analysis of MICP, imbibition, wettability, and well logging results suggests that there is isolated porosity that is water-wet. No difference between the nano-petrophysics, in regards to porosity, pore-throat size, wettability, and permeability, of the different organic-rich and organic-lean facies in the two wells was observed. Our results from this area go against previous SEM studies which suggest TOC would be the main driver of porosity in the Bone Spring Formation but still supports that the reservoir intervals contain a higher percentage of non-organic hosted porosity.
Author: Ryan P. Quintero
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Languages : en
Pages : 66
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With the rise in interest of unconventional plays, efforts have moved to understand these formations across 12 orders of magnitude through nm-km scale. Recent work by others has shown the importance of the nanometer range due to the fact this is the predominant pore size within shales. In attempt to understand nanopore structure and production behavior within a shale unconventional reservoir, a number of complementary experimental methods must be employed. This research involves the use of wettability droplet analysis for micron scale assessment of wetting properties and Mercury Intrusion Capillary Pressure (MICP) analysis for pore structure characterization within the Spraberry and Wolfcamp Formations of the Permian Basin in west Texas. In conjunction with pyrolysis and X-ray diffraction data from two wells, total organic carbon (TOC), thermal maturation, and mineralogy are considered for the development of the pore system. The Spraberry Formation was found to contain a larger porosity, higher permeability, and lower tortuosity than the Wolfcamp. The two formations also showed different pore size distributions, with the Spraberry containing more intra- and inter-pores (10-100 nm) while the Wolfcamp containing more organic sized pores (predominantly at 5-10 nm). Mineralogy differences between these shales showed no strong relationship with pore sizes distribution nor maturation. Values of S1 (volatile hydrocarbon content) from pyrolysis analyses showed the strongest relationship with pore sizes. As S1 values increased, the higher porosity increased; this rise in porosity is seen predominantly within organic pore sizes. Production data from the Rogers #3804 and Wright #44 are compared to Jarvie's oil generation crossover line (S1 vs. TOC). This crossover line accurately predicts the historical trend of these two wells.
Author: Qiming Wang (Ph.D.)
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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: Christina Marie Muñoz
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Languages : en
Pages : 100
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Characterizing unconventional shale reservoirs consisting of nano-size pores and pore networks are complicated due to their complex geometric structure and restrictive fluid transport abilities. Technological advancements with the use of multiple laboratory techniques for unconventional shale characterization has played key roles in determining their petrophysical properties with greater understanding and accuracy. Successful assessment of reservoir properties can be achieved by the measurement of porosity, permeability, pore size distribution, total organic carbon content, mineralogy, thermal maturity, wettability, tortuosity, with an understanding of the dispositional environments. The Marcellus covers as much as six states and occurs as deep as 9000 feet below the surface indicating a large potential and storage capacity for natural gas. Despite the Marcellus being the top shale gas producer in the United States it's also characterized by low porosity and permeability resulting in low-yields with declining production rates in some wells. In efforts to increase production or higher-yielding well completions in the shale, a greater understanding of the reservoir's petrophysical properties are essential for evaluation. This study will focus on the evaluation of nano-petrophysical properties of the Marcellus and underlying Utica that will provide additional information to the behavior of unconventional shale formations of the Appalachian basin, Pennsylvania. A series of experimental methodologies will be performed on samples gathered from five wells and two outcrops of the Marcellus and Utica formations in Pennsylvania. Analyses to be performed on samples include vacuum saturation, wettability/contact angle, x-ray diffraction (XRD), geochemistry, liquid pycnometry, mercury injection capillary pressure (MICP), imbibition and vapor absorption, and well-log analyses. Observations are then used to determine pore geometry and connectivity, migration, and storage characteristics within the Marcellus and Utica formations in the Appalachian basin, Pennsylvania. This will contribute to a better understanding of reservoir properties leading to the enhancement of well stimulation and completion methodologies for increased fluid migration and potentially increased production.
Author: Chad Larsen
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Languages : en
Pages : 89
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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: Richard Kalteyer
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Languages : en
Pages : 104
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The Mancos Shale of the San Juan Basin is no stranger to the drilling of oil and gas, but traditional exploration within the region has predominately been limited to the use of conventional vertical wells. Due to the recent advances in drilling and completion technologies, a large focus of oil and gas exploration has shifted towards the development of unconventional reservoirs. Because of these significant breakthroughs, it comes as no surprise that an increased interest in further developing the Mancos Shale has taken place. However, like most unconventional plays, low porosity and extremely low permeability characterize the Mancos Shale. These characteristics typically result in large production declines of oil and natural gas in the first couple years of production, sometimes up to 90% (Hughes, 2014). One of these issues involves the hindrance in diffusive hydrocarbon transport from the rock matrix to the fracture network (Hu and Ewing, 2014). In order to improve the production of hydrocarbons in these tight reservoirs, it is important to first understand the petrophysical properties of the reservoir itself so that an assessment can be made on the quality of the reservoir. This study will provide a better glimpse on the nano-petrophysical properties of pore structure and fluid-rock interactions that implicate hydrocarbon production in tight reservoirs. A suite of tests are performed on core samples from three wells within the Tocito Marine Bar play and the Offshore Mancos Shale play in order to address the relationship between pore structure and the flow and migration of hydrocarbons within the rock matrix. Some of the tests include mercury intrusion porosimetry (MICP), low-pressure gas physisorption, wettability/contact angle, and fluid imbibition. Various attributes of the core samples including TOC, XRD and pyrolysis data are also used to supplement test results to further evaluate reservoir quality. Results obtained from XRD indicate the Tocito Marine Bar samples are siliceous in nature, compared to the more calcareous Offshore Mancos Shale samples. Tocito Marine Bar samples are found at shallower depths, and were therefore found to be less mature than samples from the deeper, Offshore Mancos Shale play. Contact angle measurements demonstrate that all samples are oil-wet, as n-decane spread readily on to the surface. Imbibition tests show good connectivity within the inner pore network with respect to n-decane. Porosity and permeability from various testing methods including MICP, core plugs, and low-pressure gas physisorption show that the Mancos Shale is an organic-rich rock with low porosity and low permeability. The Tocito Marine Bar samples display the largest porosity of tested samples ranging from 1.77 to 7.14%, compared to the 1.15% Offshore Mancos sample. Total porosity is influenced primarily by inter-clay platelet pores, organic matter-hosted pores, intragranular pores, and intergranular pores. Porosity and permeability was found to be consistent with results obtained from previous studies, further validating our testing methods.
