As exciting as it is to finish university, it can also be overwhelming! The plethora of opportunities or the lack of them, the hazy picture of what you would like to do versus what you are being offered. This article reviews a few key locations where graduates can enter into the industry and the variety of options that the oil and gas industry offers them. Let's see what the US, Canada, and the UK have to offer. The cap and gown have been doffed and the diploma ink is still drying.
Teklu, Tadesse Weldu (Colorado School of Mines) | Park, Daejin (Korea Gas Corporation and Colorado School of Mines) | Jung, Hoiseok (Korea Gas Corporation and Colorado School of Mines) | Amini, Kaveh (Colorado School of Mines) | Abass, Hazim (Halliburton and Colorado School of Mines)
Tadesse Weldu Teklu, Colorado School of Mines; Daejin Park and Hoiseok Jung, Korea Gas Corporation, and Colorado School of Mines; Kaveh Amini, Colorado School of Mines; and Hazim Abass, Halliburton and Colorado School of Mines Summary Matrix and fracture permeability of carbonate-rich tight cores from Horn River Basin, Muskwa, Otter Park, and Evie Shale formations, were measured before and after exposing the core samples to spontaneous imbibition using dilute acid [1-or 3-wt% hydrochloric acid (HCl) diluted in 10-wt% potassium chloride (KCl) brine]. Permeability and porosity were measured at net stress between 1,000 and 5,000 psia. Brine and dilute-acid imbibition effect on proppant embedment, rock softening/weakening, and fracture roughness were assessed. The following are some of the experiment observations: (a) Formation damage caused by water blockage of water-wet shales can be improved by adding dilute HCl or by using hydrocarbon-based fracturing fluids; (b) matrix permeability of clay-rich or calcite-poor shale samples is usually impaired/damaged by dilute-acid imbibition; (c) matrix permeability and porosity of calcite-rich shales usually improved with dilute-acid imbibition; (d) effective fracture permeability of unpropped calcite-rich shales is reduced by dilute-acid imbibition; the latter is because of "rock softening" and "etching/smoothing" of fracture roughness on the "fracture faces." Nevertheless, dilute-acid imbibition is less damaging than brine (slickwater) imbibition; and (e) proppant embedment was observed during both brine (slickwater) and diluteacid imbibition. Introduction A statistical report in EIA (2016) shows that, in the United States, oil and gas production from tight formations have become increasingly significant since 2007. This is mainly because of the advancement of multistage hydraulic-fracture stimulation in horizontal wells. Even with multistage hydraulic-fracture stimulation horizontal-well technology, oil recovery from tight formations such as the Bakken is usually less than 10% (Alharthy et al. 2015; Sheng 2015; Teklu et al. 2017a). Hence, many researchers are devoted to improving this low oil recovery.
Liang, Feng (Aramco Services Company: Aramco Research Center—Houston) | Lai, Bitao (Aramco Services Company: Aramco Research Center—Houston) | Zhang, Jilin (Aramco Services Company: Aramco Research Center—Houston) | Liu, Hui-Hai (Aramco Services Company: Aramco Research Center—Houston) | Li, Weichang (Aramco Services Company: Aramco Research Center—Houston)
Carbonate reservoirs dominate oil (70%) and gas (90%) reserves in the Middle East, and imbibition is the main mechanism for fracturing-fluid uptake during the hydraulic-fracturing stimulation process. Because of the highly heterogeneous nature of tight carbonate source rocks, it is crucial to understand the effects of imbibed fluid on the mechanical, morphological, and flow properties of carbonate rocks. Although the influence of imbibed fluids on the wettability of carbonate reservoir has been studied extensively, research regarding the effects of imbibed fluids on the texture and mineralogy of carbonate rocks is still very limited. This paper aims to provide a conceptual approach and work flow to characterize and quantify microstructure and mineralogy changes in carbonate rocks caused by imbibed fluids.
A thin section of a low-permeability organic-rich carbonate-rock sample [7×7×0.3 mm (length×width×thickness)] was used in the study. The sample was submerged into 2%-KCl (pH = 7.1) fluid from one end to simulate the spontaneous-imbibition process. A scanning electron microscope (SEM) was used to capture the sample’s morphological changes before and after spontaneous imbibition. Energy-dispersive-spectroscopy (EDS) maps were measured before and after fluid treatment to investigate changes in various elemental distribution. In addition, inductively coupled plasma (ICP) equipped with an optical-emission-spectrometer (OES) detector was used to quantify dissolved-ion concentration in the treatment fluid. Permeability and porosity were measured using core plugs with dimensions of 1.0×1.5 in. (diameter×length) before and after fluid treatment. During the imbibition process, approximately one-half of the sample was submerged in the treatment fluid.
The SEM images for the thin-section sample showed three zones with distinct fluid-uptake characteristics. In Zone I, which was fully submerged in the testing fluid, a significant amount of mineral dissolution was observed. In Zone III, which was above the testing-fluid level, considerable mineral precipitation was detected. While in the transition zone just above the water/air interface (Zone II between the previous two zones), only a minor level of mineral dissolution was observed. Elemental-distribution changes resulting from the fluid treatment were identified by EDS analysis in all three zones. Gypsum and calcite crystals dissolved into imbibed fluids upon reaction. Gypsum was found reprecipitated on the rock surface in the zones above fluid level. The observed gypsum formation likely resulted from the dissolution of the gypsum from the rock matrix, then reprecipitation later from the imbibition experiment caused by water evaporation. Absolute-permeability and porosity measurements for core-plug samples have shown that both were increased after the imbibition process.
Teklu, Tadesse Weldu (Colorado School of Mines) | Park, Daejin (KOGAS, Daegu and Colorado School of Mines) | Jung, Hoiseok (KOGAS, Daegu and Colorado School of Mines) | Miskimins, Jennifer L. (Colorado School of Mines)
The geomechanics of a shale play: what makes a shale prospective.
ABSTRACT: Fractures play an essential role in many unconventional reservoirs, yet our ability to see and characterize them is often limited. It is common to observe few vertical fractures in vertical image logs and many in horizontal or inclined well images. Core gives the highest resolution and the best characterization but has limited application because of the time and cost involved. Image logs are acquired more frequently and can be obtained from wells of all orientations and over long intervals. After de-biasing and comparing fracture intensities between vertical cores, vertical image logs and inclined/horizontal images there is a noticeable difference in the ability to detect/resolve fractures from the three data sources. Many fractures that are visible to the eye in core are not resolved in a wellbore image. There is clearly better visibility of fractures in the horizontal images than in the vertical images. In addition to the effect of well orientation on sampled fracture density, the effects of image coverage, obscuring features and altered stress at the wellbore wall influence the visibility of fractures. This paper examines these effects and compares the observed fracture abundance to a minimum size-intensity relationship derived from core observations.
In this study, experiments were done on samples from the Marcellus, Woodford, and Eagle Ford shales. The experiments showed that samples from these formations were grossly water-wet, mixed-wet and oil-wet, respectively. The correlation of average wettability index with total organic carbon (TOC) showed that 5 wt% is the critical TOC content required to achieve connectivity and generate oil-wet pathways. Similarly, correlation of average wettability index with clay content showed that <10 wt% clay, samples are oil-wet and >65 wt%, they are predominantly water-wet, and between 10 and 65 wt% clay content, samples exhibited mixed wettability. The threshold values of 5 wt% TOC and 10 wt% clays represent the same volumetric fraction (~10%) of the rock. The figure of 10% can be thought of as percolation threshold for connectivity in shale rocks.
Scanning electron microscope (SEM) imaging done on representative samples (one per formation) was used to quantitatively assess the fraction of different pore types. The fractions of different pore types were in agreement with the observations from the macroscopic imbibition experiments. For instance, oil-wet Eagle Ford samples had a higher fraction of organic pores (22.5%) while water-wet Marcellus samples had a higher fraction of inorganic pores (40%). The samples from all the three shales had a high fraction of mixed-wet pores (Marcellus 57%, Eagle Ford 69%, and Woodford 68%). This knowledge of fractions of different pore types can be instrumental in modeling connectivity pathways.
Uneven proppant distribution is often encountered in hydraulic fracturing. Despite propped and unpropped fractures exhibiting different closure behavior during shut-in and early-flowback periods as a result of changes in effective stress, modeling of the geometry and closure behavior of a partially propped fracture is rarely performed. Numerical simulation is used in this study to simulate the closure behavior of a partially propped fracture and to examine its effects on water flowback and gas production.
Explicit finite-difference geomechanical simulation is used to simulate the change in effective stress and the corresponding closure geometry of a partially propped fracture. Parameters including rock strength, in-situ stress condition, proppant compaction, and propped-fracture height and aperture are considered to understand their effects on the fracture-closure geometry. This partially propped fracture is then represented explicitly in the computational domain in a flow simulation to model fluid flow during the shut-in and flowback periods. Fracture volume and fracture conductivity are adjusted as a function of effective stress to represent the fracture-closure process. The effect of coupling of partially propped fracture closure and multiphase flow on water recovery and gas production is investigated. Implications of ignoring the physical process of fracture closure and complex partially propped fracture geometry are examined.
Geomechanical-simulation results reveal the potential formation of a residual opening above the proppant pack in a partially propped fracture. Three distinct parts are identified within a partially propped fracture: a propped region, an unpropped region, and a residual opening (arch). The size of the residual opening is most sensitive to the initial fracture aperture. Stress concentrations occur at the top of the proppant pack and lead to potential proppant crushing or embedment. In addition to water uptake into the matrix because of forced (large pressure differential across the matrix/fracture interface) and spontaneous (high capillary pressure in the matrix) imbibition, fracture closure during the shut-in and flowback periods could displace more water into the nearby matrix and reduce the final water recovery. The residual opening would exaggerate the effects of gravity segregation and hamper water recovery by providing a highly conductive flow path to gas flow, such that the water would accumulate near the bottom of the fracture. The implication is that more-aggressive drawdown should be implemented to recover the fracturing fluid.
This study offers a quantitative analysis of the geometry of a partially propped fracture and highlights its effects on water flowback and gas production. The existence of the residual opening, which is commonly ignored in most analysis, would indeed play a crucial role in the subsequent well performance and in-situ fluid distribution. A number of insights pertinent to practical fracture design and operational strategy are discussed.
Sheng Yang, University of Calgary; Nicholas B. Harris and Tian Dong, University of Alberta; and Wei Wu and Zhangxin Chen, University of Calgary Summary This paper documents the formation of natural fractures in the Horn River Group, a major Canadian shale gas play, and addresses relationships between natural-fracture development and rock-mechanical properties derived from cores and well logs. Most natural fractures in the Horn River Shale are narrow vertical fractures, sealed with carbonate minerals. In this study, the formation of observed fractures is primarily determined by a lithology type, mineral composition, and rock-mechanical properties at the timing of fracturing. Brittleness is an important geomechanical property controlling the formation of fractures, because brittle shale is more easily fractured than ductile shale, and fractures in brittle shale tend to persist when the fracturing pressure is released. In this study, a hardness value measured by a commercial hardness tester is found to be a good proxy for the brittleness of shale layers. On the basis of a statistical analysis, the threshold values of both hardness and brittleness are estimated to predict the distribution of natural fractures, assuming that the mechanical properties of the host rock were relatively stable from at least the time at which fractures formed. Hardness values are shown to be more reliable than brittleness. Introduction Researchers have conducted many studies on different aspects of natural fractures and fractured reservoirs (Lorenz et al. 1991; Laubach et al. 2004) [e.g., the characterization and effects of fractures in the carbonate and siliciclastic reservoirs of the Middle East (Ameen et al. 2009, 2010, 2014)]. In recent years, natural fractures in shale reservoirs have become a key focus of research (Curtis 2002; Kresse et al. 2011; Gale et al. 2014) [e.g., the comprehensive study of natural fractures in the Qusaiba shale conducted to evaluate shale reservoir proceptivity by Ameen (2016)].
Qinghai, Yang (Research Institute of Petroleum Exploration & Development) | Siwei, Meng (Research Institute of Petroleum Exploration & Development) | Tao, Fu (Research Institute of Petroleum Exploration & Development) | Yongwei, Duan (Oil and Gas Engineering Research Institute) | Shi, Chen (Oil and Gas Engineering Research Institute)
CO2 waterless fracturing is a novel waterless fracturing technology. CO2 exists in the reservoir with supercritical state, and its fracturing stimulation mechanism is very different from that of water-based fracturing. This paper studies the physical and chemical properties of supercritical CO2 and reservoir adaptability of CO2 waterless fracturing.
Supercritical CO2 has the advantages of good fluidity and strong penetrability, which avail to form a complex network fractures. Through miscible phase with crude oil, absorption gas displacement, and reservoir energy enhancement, production and ultimate recovery are further improved. While the liquid CO2 has the disadvantages of poor proppant carrying capacity, high friction and low fracture opening. Based on CO2 waterless fracturing practices in Jilin oilfield, this paper summarizes physical parameters, operation effect and production situation of all wells, analyzes the main factors influencing productivity, and puts forward a set of well and layer selection methods of waterless CO2 fracturing.
Under the condition of existing CO2 thickening and resistance reducing technology, the selection of wells and layers is mainly carried out in 6 aspects. (1) Because the filtration of CO2 fracturing fluid is strong, the permeability of target reservoir should be lower than 5md in order to ensure stimulation effect of remote area. (2) CO2 can react with water and divalent metal ions to produce carbonate sediments to block existing pores and reduce reservoir permeability, so it is better for low water-bearing reservoirs. (3) Frictional resistance of CO2 is 1.9 times as that of conventional guar gum, so the target layer should be 3000m or shallower to reduce frictional pressure drop. (4) Energy increasing effectiveness of unit volume of CO2 is 1.9 times as that of slick-water, which is more suitable for stimulating undercompacted reservoirs. (5) There is no water phase in CO2 fracturing fluid, suitable for stimulating strong water-sensitive reservoirs. (6) CO2 is easy to dissolve in crude oil and greatly reduces its viscosity, which is suitable to stimulate heavy hydrocarbon reservoir.
Adopting above well and layer selection principles, CO2 waterless fracturing were implemented in 6 wells in 2017, and the key parameters, such as success ratio, sand adding amount, production capacity post-fracturing were comprehensively promoted, which effectively supported CO2 waterless fracturing development practices of unconventional reservoirs.
The CO2 waterless fracturing, just as its name implies, is a fracturing technique using CO2 as the fracturing fluid. During the operation, proppants are mixed with liquid CO2 under pressurized conditions, with the help of the customized blending apparatus, and the mixture is then injected into the wellbore to break the reservoir formation, create artificial fractures, and place proppants to avoid fracture closure after depressurization. The CO2 blending apparatus is a high-pressure sealed container, in which proppants are put inside prior to the fracturing operation. The blender connects the piping system, and is capable of mixing the proppant and CO2 liquid stream, and driving the mixture into the high-pressure fracturing pump.
The objective of this paper is to improve the evaluation and characterization of the fracture network as well as the production matching in the Horn River Shale of Canada. The task is carried out by extending the hybrid hydraulic fracture (HHF) model introduced by
In this paper, the fracture network is discretized using microseismic observations, when available. However, microseismic data may be limited in some of the fractured stages, or like in the case of most hydraulically fractured wells it might be non-existent. The fully coupled HHF model is developed to (1) improve the shale characterization and the simulation history matching, (2) study the fracture closure and permeability change in the fracture network due to gas production, and (3) alleviate microseismic data scarcity by generating a representative fracture network of those stages where microseismic data are unavailable.
The stress change from the initial hydraulic fracturing is evaluated in nine paths multi-level horizontal wells that penetrated the Horn River Shale. The stress shadow is corroborated with microseismic observations and exhibited areas with high fracture density and productivity.
The HHF model further evaluates the reservoir response to pore pressure depletion stemming from production, which leads to stress and permeability changes, fracture closure, and fracture reorientation. The procedure improves the simulation history matching by improving reservoir characterization, especially in stages closer to the toe where an understanding of fracture network geometry is problematic due to the cloud dispersion and scarcity of the microseismicity. The model also evaluates interference between well-paths and helps to determinate the optimum well, fracture and stage spacing.
The HHF model was used to observe changes in volume, permeability and fracture connectivity in undepleted areas close to the fracture network. These areas reveal possible candidates for refracturing. A refracturing scenario that restores fracture conductivity and increases the drainage area of the fracture network is analyzed economically for evaluating the viability of that type of operation in the Horn River Shale.
The HHF simulation model improves the shale reservoir understanding and simplifies the use of a highly complex fracture network for evaluating history matching, fracture closure and permeability changes during gas production. Furthermore, it provides a viable methodology to optimize well and stage spacing, and to evaluate potential refracturing candidates, where microseismic data is unavailable and a fracture network needs to be developed.