Most of the shale reservoirs in US land are naturally fractured. The fracture intensity and types vary from one shale to another. Even within the same shale in the same field, the heterogeneity of fracture intensity can be often expected to be high in a horizontal well. The current popular geometrical completion design can potentially ignore the existence of natural fractures. Hence, maximizing stimulation efficiency without understanding existing natural fractures can be a challenge. In this paper, study was made of the majority of the published case studies related to natural fractures in the US shales in the last 20 years. The evidence of natural fractures from either outcrops or subsurface data, i.e. core, borehole images, or other data is summarized for each studied shale. The latest studies show that the hydraulic fracture propagation can be strongly influenced by existing natural fractures regardless of whether they are open or closed. The roles of existing fractures in the shales include: 1) providing enhanced reservoir permeability for improved productivity if they are open and effectively connected by hydraulic fractures; 2) promoting much better fracturing network complexity regardless of whether they are open or closed prior to the stimulation; 3) giving possible negative impact sometimes, i.e. high water cut, if they are connected with wet zones below or above the reservoirs. It can be concluded that engineered completion designs that employ accurate knowledge of natural fracture data, in-situ stresses, and other reservoir and completion quality indicators as inputs can provide opportunities for enhancing stimulation efficiency and fracturing network complexity. This in turn can lead to better connectivity to a larger reservoir volume and access to more drainage area in the shales.
The electrochemical performance is significantly influenced by the structure and surface morphology of the electrode materials used in supercapacitors. Using the floating catalytic chemical vapor deposition (FCCVD) technique, a self-supporting, flexible layer of continuously reinforced carbon nanotube woven film (CNWF) was developed. Then, polyaniline (PANI) was formed in the conductive network of CNWF using cyclic voltammetry electrochemical polymerization (CVEP) in various aqueous electrolytes to produce a series of flexible CNWF/PANI composite films. The impacts of the CVEP period, electrolyte type, and electrolyte concentration on the surface morphology, doping degree, and hydrophilicity of CNWF/PANI composite films were thoroughly examined. The CNWF/PANI1-15C composite electrode, which was created using 15 cycles of CVEP in a solution of 1 M sodium bisulfate, displayed a distinctive coral-like PANI layer with a well-defined sharp nanoprotuberance structure, a 48% doping degree, and a quick reversible pseudocapacitive storage mechanism. At a current density of 1 A g–1, the energy density and specific capacitance reached 54.9 Wh kg–1 and 1098.0 F g–1, respectively, with a specific capacitance retention rate of 75.9% maintained at 10 A g–1. Both the specific capacitance and coulomb efficiency were maintained at 96.9% and more than 98.1% of their initial values after being subjected to 2000 cycles of galvanostatic charge and discharge, demonstrating excellent electrochemical cycling stability. The CNWF/PANI1-15C composite film, an ideal electrode material, offers a promising future in the field of flexible energy storage due to its exceptional mechanical properties (127.9 MPa tensile strength and 16.2% elongation at break).
Granitic basement reservoirs have been the focus of increasing attention in the Asia Pacific region in recent years, following several new oil and gas discoveries in this complex reservoir type. Accurate formation evaluation in fractured, crystalline, granitic reservoirs is notoriously difficult. Furthermore relatively little research has gone into understanding logging tool response or pressure transient behavior in these reservoir types, and developing suitable workflows for formation evaluation. In this paper the authors propose an improved methodology for integrating various open-hole logs, production logs and well test data to better evaluate the reservoir potential of a fractured granitic formation. Since the wells are either horizontal or highly deviated, the framework also serves as one of the primary methods to asses the lateral extent of the reservoir. A case study from the region is used to illustrate the workflow. Image log interpretation, advanced acoustic measurements, nuclear logs and production logs with distributed local sensors are combined with well test data to derive the best possible evaluation of the fracture network around the borehole and the degree of connectivity with the reservoir at large. The advantages and limitations of the proposed workflow are also discussed and the stage set for further work in this complex environment. Background Fractured granitic reservoirs differ from other types of fractured reservoirs in that they are generally considered to have no primary porosity. All the pore space in the rock is formed through fracturing and diagenetic processes. The resulting pore structure heterogeneity makes formation evaluation extremely challenging. Another complicating factor is the lithology, where the granite composition can vary and sub-vertical extrusive dykes cause abrupt lateral variations in matrix properties. This paper deals specifically with granitic oil bearing formations from southern offshore Vietnam. The typical basement reservoir consists of a faulted basement high. The majority of the porosity is thought to be associated with fractures and fault zones. High fracture density enhanced by hydrothermal alteration forms the majority of the effective pore space. Unlike basement plays in other regions the weathered zone at the top of the structure and the dykes are usually not productive, though the interface between dykes and host rock can be (Le Ngoc 2007, Nguyen 2003, Tandom 1999). In this environment the majority of new wells drilled are highly deviated or horizontal, and drilled to intersect sub-vertical fault zones. Most of the fractures are small and form the storage capacity of the reservoir. To be productive, a well should also encounter enough larger, permeable, fractures which are sufficiently connected to the storage capacity of the reservoir. The objective of the following interpretation methodology is partly to quantify as much as possible the total fracture porosity, but mainly to identify the large permeable fractures which are necessary for the well to be productive.
Summary In recent years, energy companies in the Asia Pacific region have focused increasing attention on granitic basement reservoirs, following several new oil and gas discoveries in these complex reservoirs. However, accurate formation evaluation in fractured, crystalline, granitic reservoirs is notoriously difficult. Furthermore, relatively little research has been conducted to understand loggingtool response or pressure-transient behavior, or to develop suitable workflows for formation evaluation in these types of reservoirs. In this paper, we propose a method for integrating various openhole logs, production logs, and well-test data to better evaluate the reservoir potential of fractured granitic formations. Because the wells are either horizontal or highly deviated, this workflow also serves as a primary method of assessing the lateral extent of a reservoir. We include a case study from the region to illustrate the workflow. Image-log interpretation, advanced acoustic measurements, nuclear logs, and production logs with distributed local sensors are combined with well-test data to derive the best possible evaluation of the fracture network around the borehole and the degree of connectivity with the reservoir at large. We also discuss the advantages and limitations of the proposed workflow and set the stage for further work in this complex environment.
Permeability is one of the major controls for production in fractured basement. It is critical to be able to identify and characterize permeable zones in the basement reservoirs not only for evaluating well producing potential but also for designing perforation, well completion and injection. Even though geoscientists and reservoir engineers have made considerable effort over the years to better characterize the permeability profile in fractured basement, it is still very challenging to achieve this objective. This paper presents a newly developed approach aimed at better understanding the permeability profile. The technique was developed based on case studies from wells in two different basement fields located offshore in the south of Vietnam. Traditionally, fractures have been characterized using core and borehole image data. In this study, borehole image data were integrated with other open-hole logs to derive a permeability curve. The result was calibrated with core data and then validated with dynamic data i.e. production log data, well testing data, mud losses, gas shows. As demonstrated in the case studies, it is believed that the permeability in the basement could be reasonably evaluated using this method. However, in a zone where fractures are cemented or partially cemented with conductive minerals, the log-derived permeability needs to be calibrated with the degree of cementation. Introduction Permeability is one of the most difficult parameters to assess in a reservoir and it is even more challenging when the reservoir is fractured. There is no proved mean for directly measuring the permeability in fractured basement except for well testing and coring, which imply high cost. In addition, well testing only provides permeability height product KH based on many "best guess" assumptions and can lead to unclear range of contacted hydrocarbon volumes. Core analysis usually focuses on the worse portion of the reservoir due to the fact that core recovery has rarely been good in a highly fractured zone. Therefore the permeability measured from the core sample is often not representative. Reservoir modeling could provide critical insights to the permeability system in fractured basement. However, the model is stochastic or based on fault line objects, and is grossly constrained by dynamic pressure data but rarely by well data. This paper focuses on new techniques that allow multiple sources of information to be incorporated into the estimation of permeability along the path of a wellbore in the reservoir. These permeability properties can then be incorporated and upscaled into reservoir models to provide more accurate representations of the fractured reservoir. Fracture Basement Reservoir of the CuuLong Basin The fractured basement reservoirs of CuuLong Basin are prolific hydrocarbon bearing and naturally fractured. Individual wells in these fractured basement reservoirs are capable of sustained production in excess of 20,000 bbls/d. The fracture systems are present in 4-way dip closed structures and have been reviewed by Long(1), Guttormsen(2), Schmidt(3), Cuong(4), and Olson(5). The productive CuuLong basement structures are oriented NE-SW with range of structural styles from large flat horst blocks to half horst structures (Figure 1, map of CuuLong Basin). These structures are typically bounded by strike slip faults that exhibit positive and negative elements along their strike. The largest structural complex in the block is the Bach Ho (White Tiger) structural complex and particularly its prolific central dome (Figure 2, Map of major producers in CuuLong Basin). The individual structures exhibit a variety of internal structural complexities as they accommodated stress during the complex structural history of the basin. The horst reservoir is a granitiod body with a history of poly-phased intrusives. Post emplacement tectonic events related to the intrusives can be summarized into seven episodes(3). These are from oldest to youngest:Pre-Rift Magmatic upwelling and Paleozoic metasediments deformationPre-Rift active poly-phased intrusive and cooling phasePre-Rift Pre-basin compressional phase (deformation cycle 1 - D1, D2)
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