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Unlike conventional reservoirs, coal seams are the source, trap, and reservoir for CBM. A comparison of the two reservoir types shows profound differences in reservoir properties, storage mechanisms, flow mechanisms, and production profiles. CBM reservoirs are layered and contain an orthogonal fracture set called cleats, which are perpendicular to bedding. Because the coal matrix has essentially no permeability, CBM can be produced economically only if there is sufficient fracture permeability. Relative to conventional gas reservoirs, coal seam permeabilities are generally low and may vary by three orders of magnitude in wells separated by distances of less than 500 m.
This one-day training event introduces completion, production, surveillance and reservoir engineers to the design of fiber-optic DTS (distributed temperature sensing) and DAS (distributed acoustic sensing) well installations. A basic understanding of the principles and benefits of DTS, DAS and surveillance monitoring technology, in general, is assumed. This course provides both an overview of water management and an in-depth look at critical issues related to sourcing (acquiring), reusing, recycling, and disposing of water in hydraulic fracturing operations. The course starts with a background of hydraulic fracturing operations and the different plays around North America. Options being used for transport, storage, reuse, and disposal are described for each of the different regions.
Temizel, Cenk (Saudi Aramco) | Canbaz, Celal Hakan (Ege University) | Gok, Ihsan Murat (NESR) | Roshankhah, Shahrzad (California Institute of Technology) | Palabiyik, Yildiray (Istanbul Technical University) | Deniz-Paker, Melek (Independent Consultant) | Hosgor, Fatma Bahar (Petroleum Software LLC) | Ozyurtkan, Mustafa Hakan (Istanbul Technical University) | Aksahan, Firat (Ege University) | Gormez, Ender (Middle East Technical University)
As major oil and gas companies have been investing in shale oil and gas resources, even though has been part of the oil and gas industry for long time, shale oil and gas has gained its popularity back with increasing oil prices. Oil and gas industry has adapted to the low-cost operations and has started investing in and utilizing the shale oil sources significantly. In this perspective, this study investigates and outlines the latest advances, technologies, potential of shale oil and gas reservoirs as a significant source of energy in the current supply and demand dynamics of oil and gas resources. A comprehensive literature review focusing on the recent developments and findings in the shale oil and gas resources along with the availability and locations are outlined and discussed under the current dynamics of the oil and gas market and resources. Literature review includes a broad spectrum that spans from technical petroleum literature with very comprehensive research using SCOPUS database to other renowned resources including journals and other publications. All gathered information and data are summarized.Not only the facts and information are outlined for the individual type of energy resource but also the relationship between shale oil/gas and other unconventional resources are discussed from a perspective of their roles either as a competing or a complementary source in the industry. In this sense, this study goes beyond only providing raw data or facts about the energy resources but also a thorough publication that provides the oil and gas industry professional with a clear image of the past, present and the expected near future of the shale oil/gas as it stands with respect to other energy resources. Among the few existing studies that shed light on the current status of the oil and gas industry facing the rise of the shale oil are up-to-date and the existing studies within SPE domain focus on facts only lacking the interrelationship between heavy and light oil as a complementary and a competitor but harder-to-recover form of hydrocarbon energy within the era of rise of renewables and other unconventionals. This study closes the gap and serves as an up-to-date reference for industry professionals. 2 SPE-198994-MS
There is a very extensive amount of information and learnings from naturally fractured reservoirs (NFRs) around the world collected throughout several decades. This paper demonstrates how the information and learnings can be linked with tight and shale reservoirs (TSRs) with the objective of maximizing hydrocarbon recovery from TSRs.
A classic definition indicates that a natural fracture is a macroscopic planar discontinuity that results from stresses that exceed the rupture strength of the rock (
Actual observations in TSRs indicate that micro and nano natural fractures do not flow significant volumes of oil or gas toward horizontal wells. Thus, the wells must be hydraulically fractured in multiple stages to achieve commercial production. Once the wells are hydraulically fractured, the area exposed to the shale reservoir is enlarged and the natural micro and nano fractures flow hydrocarbons toward the hydraulic fracture, which in turn based on the values of hydraulic fracture permeability, feeds those hydrocarbons to the wellbore. In TSRs there are also completely cemented macroscopic fractures that are breakable by hydraulic fracturing and can become very effective conduits of hydrocarbons toward the wellbore.
The link that exists between natural fractures at significantly different scales established in this paper is a valuable observation. This is so because the larger tectonic, regional and contractional (diagenetic) fractures that exist in NFRs have been studied extensively for several decades, for example in carbonates, sandstones, and basement rocks. Those learnings from NFRs have not been used to full potential in TSRs for maximizing oil and gas recoveries. This paper provides the necessary tools for remediating that situation.
The established link between NFRs and TSRs permits determining how to drill and complete wells in TSRs. It is concluded that this link will lead to (1) improvements in gas production performance, and (2) maximizing economic oil rates and recoveries under primary, improved oil recovery (IOR) and enhanced oil recovery (EOR) production schemes.
Blood, David R. (DRB Geological Consulting) | McCallum, Scott D. (McCallum Petrophysics and Data Analytics) | Jalali, Jalal (SRN Petroleum Consulting) | Douds, Ashley S. B. (Parsley Energy) | Stypula, Merril J. (Deloitte)
The highly productive nature of the Marcellus Shale has led to an interesting observation where individual well estimated ultimate recoveries (EURs) often exceed the calculated gas-in-place (GIP). These observations have led us to question our understanding of GIP, vertical and horizontal drainage, and our understanding of downhole pressure measurements. This paper presents our modification of the GIP estimate in an effort to achieve more accurate values which can lead to a better understanding of future Marcellus production and development. Here we focus on three aspects to improve GIP calculations: 1) implementation of the Ambrose-Hartman correction to account for pore space occupied by adsorbed gas; 2) we provide evidence that measured pore water is mostly of anthropogenic origin and should not be considered in effective porosity calculations, 3) we provide evidence from outcrop observations for considering a dynamic pore pressure throughout the rock.
Pressurized rotary sidewall cores were collected on a Marcellus well drilled under slightly overbalanced conditions to minimize the escape of gas. After measuring total gas evacuated from the cores, total uptake experiments were conducted to determine the storage capacity of the samples at varying pressures. Isotopic analysis of core water was used to determine the source of the water. Finally, field analysis of the occurrence of natural hydraulic fractures compared to total organic carbon (TOC) was used to estimate the variation of overpressure development at a bed scale.
Total uptake experiments confirm the necessity of the Ambrose-Hartman correction to quantify the free GIP component. Analysis of core water indicates that the majority of water encountered in the Marcellus Shale results from the drilling and completion process with minimal evidence of mobile in situ water. Finally, the increased density of natural hydraulic fractures (NHFs) associated with increasing TOC indicates a strong relationship between overpressure development and TOC at the bed scale, suggesting the need to treat pore pressure as a dynamic value across the stratigraphic interval. When these three aspects are considered, GIP values increase substantially.
Unconventional reservoirs, such as Permian Basin, have fundamentally different production behaviors than that of the conventional reservoirs because of the low permeability of formations away from the stimulated volume. Thus, it is difficult to run full-field reservoir simulation to generate a full-field development plan. Even though satisfactory history matching for completion and production data can be achieved for wells at one location, it is difficult to directly apply the results to other areas in the same region. This is especially true in complex thick pay zone reservoirs, such as Permian Basin, where the complex geology, geomechanical properties, and resource properties all make the solution of frac hit (optimal well spacing) very challenging. To our best knowledge, this study is the first to integrate the detailed physics-based simulation, including fracturing simulation, coupled reservoir and geomechanics simulation, with machine learning (ML) to generate a sound workflow for well spacing optimization. In this workflow, a large field is first divided into several representative regions according to geology, geomechanical properties, and reservoir properties; and a typical well is selected for each region. High-quality physics simulation (including fracturing simulation, coupled reservoir simulation and geomechanics simulation) and history matching are then performed for a pair of parent and child wells. Additional well completion scenarios are built upon the base case, which serve as input to the following ML study. Various ensemble regression methods are applied to generate production predictions for unexplored reservoir locations in this field.
In recent years, many fracture simulation models have been developed to represent the complex geomechanical processes involved in hydraulic fracturing (F. Ajisafe, Shan, Alimahomed, Lati, & Ejofodomi, 2017; Morales et al., 2016; Pankaj, 2018b). Among them, well interference or well spacing optimization is a critical issue to solve in energy sector, especially during the current industrial downturn (F. O. Ajisafe, Solovyeva, Morales, Ejofodomi, & Porcu, 2017; Pankaj, 2018a; L. Wang & Yu, 2019; M. Wang, Wang, Zhou, & Yu, 2019). Detailed mechanistic study of integrated fracturing simulation and reservoir simulation have made significant progress during the recent years, which greatly helps to unlock unconventional resources and assist the industry to achieve economic goals (Alimahomed et al., 2017; Lashgari, Sun, Zhang, Pope, & Lake, 2019; Min, Sen, Ji, & Sullivan, 2018; Rodriguez, 2019). Nevertheless, when applying these technologies in unconventional field development and production, major uncertainties remain, including geology aspects such as stress orientation, stress anisotropy and natural fracture distribution, and completion aspects such as discrepancy between different completion strategies (Pankaj, Shukla, Kavousi, & Carr, 2018; Xiong, Liu, Feng, Liu, & Yue, 2019). A common concern is that even though current physics-based modeling and simulation could match the completion and historical production of a single well or multiple wells, it is still difficult to successfully transfer or scale up one small-area’s knowledge and experience to another area, because of the complexity and uncertainty of unconventional reservoirs (Xiong, Ramanathan, & Nguyen, 2019; Yeh et al., 2018).
Hill, A. D. (Texas A&M University) | Laprea-Bigott, M. (Texas A&M University) | Zhu, D. (Texas A&M University) | Moridis, G. (Texas A&M University) | Schechter, D. S. (Texas A&M University) | Datta-Gupta, A. (Texas A&M University) | Abedi, S. (Texas A&M University) | Correa, J. (Lawrence Berkeley National Laboratory) | Birkholzer, J. (Lawrence Berkeley National Laboratory) | Friefeld, B. M. (Class VI Solutions, Inc.) | Zoback, M. D. (Stanford University) | Rasouli, F. (Stanford University) | Cheng, F. (Rice University) | Ajo-Franklin, J. (Rice University / Lawrence Berkeley National Laboratory) | Renk, J. (Department of Energy) | Ogunsola, O. (Department of Energy) | Selvan, K. (INPEX Eagle Ford LLC)
The Eagle Ford Shale Laboratory is a DOE and industry-sponsored multi-disciplinary field experiment aimed at applying advanced diagnostic methods to map hydraulic fractures, proppant distribution, and the stimulated reservoir volume. The field site is an Inpex Eagle Ford, LLC lease in LaSalle county, Texas that has a legacy Eagle Ford producing well and that will be developed with 5 new producers. Utilizing newly-developed monitoring technologies, the project team will deliver unprecedented comprehensive high-quality field data to improve scientific knowledge of three important processes in unconventional oil production from shales: (1) a re-fracturing treatment in which the previously fractured legacy well will be re-stimulated for improved production, (2) a new stimulation stage where the most advanced hydraulic fracturing and geosteering technology will be applied during zipper-fracturing of 3 new producers, and (3) a Gas-Injection Enhanced Oil Recovery (EOR) Phase where one of the wells will be later tested for the efficiency of Huff and Puff gas injection as an EOR method. Field monitoring is being complemented with laboratory testing on cores and drill cuttings, and coupled modeling for design, prediction, calibration, optimization, and code validation. The multi-disciplinary team consists of researchers from Texas A&M University, Lawrence Berkeley National Laboratory, Stanford University, Rice University, and Inpex Eagle Ford, LLC.
The ultimate objective of the Eagle Ford Shale Laboratory Project is to help improve the effectiveness of shale oil production by providing new scientific knowledge and new monitoring technology for both initial stimulation/production as well as enhanced recovery via re-fracturing and EOR. The main scientific/technical objectives of the project are:
Build and test active seismic monitoring with fiber optics in an observation well to conduct: (1) real-time monitoring of fracture propagation and stimulated volume, and (2) 4D seismic monitoring of reservoir changes during initial production and during an EOR pilot.
Test distributed temperature sensing (DTS), distributed acoustic sensing (DAS) and distributed strain sensing (DSS) with fiber optic technology and develop protocols for field application.
Assess spatially and temporally resolved production characteristics and explore relationships with stimulated fracture characteristics by open hole logging, cased hole logging, production logging, and tracer technology.
Understand rock mechanical properties and reservoir fluid properties and their effect of stimulation efficiency through coring and core analysis.
Evaluate suitability of re-fracturing to achieve dramatic improvements in stimulated volume and per well resource recovery.
Develop understanding of gas-based EOR Huff and Puff methods to increase per well resource recovery by lab tests and field test.
Paronish, T. J. (National Energy Technology Laboratory / Leidos Research Support Team) | Toth, R. (West Virginia University) | Carr, T. R. (West Virginia University) | Agrawal, V. (West Virginia University) | Crandall, D. (National Energy Technology Laboratory) | Moore, J. (National Energy Technology Laboratory / Leidos Research Support Team)
The Marcellus Shale Energy and Environmental Laboratory (MSEEL) consists of two project areas within the dry gas producing region of the Marcellus shale play in Monongalia County, West Virginia. MSEEL is a collaborative field project led by West Virginia University, with Northeast Natural Energy LLC, several industrial partners, and sponsored by the US Department of Energy National Energy Technology Laboratory. The study areas are drilled approximately 8.5 miles apart to better understand the vertical and lateral changes in stratigraphy over a short distance. Two vertical pilot wells, MIP-3H and Boggess 17H were drilled in the fall of 2015 and spring of 2019, respectively. Core was recovered from the MIP-3H (API: 47-061-01707-00-00) 112 feet (34m) between depths of 7445 to 7557 feet, and from the Boggess 17H (API: 47-061-01812-00-00) 139 feet (42m) between depths of 7908 and 8012 ft. A full suite of triple combo (gamma ray, neutron, density logs), image logs, and advanced logging tools were run in both wells and calibrated to core analysis. Core analysis includes medical computed tomography (CT) scans, mineralogy and chemostratigraphy determined from handheld X-Ray fluorescence (hhXRF) and X-Ray powder diffraction (XRD) measurements, and determination of total organic content (TOC).
Lithofacies were determined at core-scale using traditional core description techniques and medical CT-scan images. Log-scale facies are based on mineralogy and TOC data and developed using petrophysical logging data calibrated to core data (XRD and pyrolysis data). Chemostratigraphic analysis utilized hhXRF data to determine the major and trace element trends in the cores.
In the two wells six shale lithofacies were recognized at the core and log scale. Both wells show organic-rich facies (TOC > 6.5%) primarily in the middle and lower Marcellus, with a slight decrease in thickness of this interval in the Boggess 17H. This interval is interpreted as an increase in paleo-productivity (increased Ni, Zn, and V), decreased sedimentation (decreased detrital proxies), and anoxic to euxinic conditions (increased Mo and chalcophile elements). Paleo-redox conditions in both wells are dynamic throughout deposition transitioning between euxinic/anoxic to dysoxic/oxic. This trend is seen through elemental proxies and calcite/pyrite concretion distributions.
Eltaleb, I. (University of Houston) | Rezaei, A. (University of Houston) | Siddiqui, F. (University of Houston) | Awad, M. M. (University of Houston) | Mansi, M. (University of Houston) | Dindoruk, B. (University of Houston) | Soliman, M. Y. (University of Houston)
The fracture injection fall-off test is a common technique for determining rock properties and fracture closure pressure. Conventional methods for analyzing DFIT are formulated based on the assumption of a vertical well and have shortcomings in horizontal wells drilled in ultra-low permeability reservoirs with potential multiple closures. In this study, an alternate technique using the signal processing approach is proposed. In the proposed method, we analyze the energy of the noise in the signal using a wavelet transform to identify the closure moment and pressure. We hypothesize that after the complete fracture closure moment, the noise in the recorded pressure will begin to vanish. To determine this closure moment, we decompose the pressure fall-off (signal) into multiple levels with different frequencies using the wavelet transform. Multiresolution wavelet decomposition breaks the (pressure) signal into high pass (noise) and low pass (approximation) components at various levels. The energy distribution plot is then constructed by plotting the energy of the high pass (noise) component versus the corresponding decomposition level.
Our results show that the noise energy reduces by several orders of magnitude at a specific time, which may identify the moment of fracture closure. Four field cases are analyzed using the proposed approach for demonstration. Also, we show an example where identifying the closure pressure using G-function is challenging, and our method still works reasonably well. Plots of the noise energy distribution versus time indicated multiple decreasing levels of energy. We also observed that the energy of the recorded noise in the signal could stay constant, or it can decrease gradually until the closure moment. In both cases, we observed that the signal energy drops to a minimum level at closure, and stays at that lowest level, thereby confirming our hypothesis. We also noted that the closure points that are found using this approach could happen before or after the closure from the conventional G-function method.
The main advantage of our proposed approach is that, unlike other physics-based techniques, it does not have any pre-assumption about the geometry of fracture or type of the well. It solely relies on the pressure signal that is recorded during the fall-off period. This advantage makes our approach unique since it is not limited to any specific formation, rock, or well type.
Acid fracturing is a promising technique to stimulate the induced unpropped (IU) fractures which are created in shales during hydraulic fracturing. These fractures have enormous surface area, but close during production due to their inability to accommodate proppants. The use of acid has been proposed as a way to keep these IU fractures open after pumping has ceased. A successful acid fracturing treatment requires the acid to effectively etch the shale fracture surfaces to create a connected flow pathway that will remain open when stress is applied. This requires the acid etching to be non-uniform. Changes in fracture surface topography and mechanical properties are critical in determining how the fracture conductivity will change with stress.
In this study, 55 preserved shale samples from Barnett, Eagle Ford, Haynesville and Utica shale covering a wide range of mineralogy (with clay 3.4 - 75.6 wt% and carbonate 1.9 - 83.7 wt%) were used to systematically investigate the effect of acid treatment on their fracture surface topography, mechanical properties and fracture conductivities. The mechanical properties of the fracture surface were measured using indentation tests. Fracture conductivities were computed with a numerical model that simulates unpropped fracture closure.
The results showed that the roughness of all the fracture samples increased after acid etching, but to different extents. The roughness was initially 1.58 ± 0.29 µm and developed into two groups: the low roughness group for roughness within 6 µm, and the high roughness group with roughness over 10 µm and up to 43.71 µm. Although carbonate-rich samples were more likely to produce high roughness, high carbonate content did not necessarily always lead to rougher surfaces. The amount and the distribution pattern of carbonate minerals affected the etched surface topography. On surfaces of low etched roughness, isolated pits with diameter of 10-30 um were formed, while profile valleys at millimeter scale were developed on surfaces of high roughness, and some of these valleys were connected to form channels. Acid caused additional shale softening than brine exposure, mainly by removal of carbonate minerals. Acid fracturing was found to improve fracture conductivities under reservoir pressure mostly in cases of high etched roughness; while fractures with low etched roughness, conductivities were lower than or close to factures treated by brine.
Experimental results on surface topography, mechanical properties and the modeled fracture conductivities of acid-fractured shales of a wide range of mineralogy are presented. The results are important in selecting candidate shale plays for acid fracturing, and also provide useful parameters for modeling and field design.