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.
Flashback 10 years ago to 2008: the North American hydraulic fracturing industry utilized a then record breaking 21.41 Billion pounds and experienced exponential growth year-over-year (excluding 2015 and 2016). Prior to 2008, proppant demand grew at a relatively modest pace and overwhelmingly consisted of 20/40 mesh high quality natural sands and synthetic proppants. Fundamental changes in drilling and completion practices has given rise to a significant increase in the application of smaller mesh proppants, most notably 40/70, 30/50 and various forms of what is generically referred to as 100 mesh sand (i.e., sands that are predominantly smaller than 70 mesh) in natural gas and liquid applications. Proppant demand has now soared, increasing significantly as a result of the new high-intensity completions practices in horizontal wells. In 2018, an estimated 200 Billion pounds will be used for the first time in history (or 10 times that used in 2008).
The proppant supply industry responded well to the increased demand in the past decade, but the industry is increasingly concerned about future supply limitations and the potential impact on completion practices subject to high volume, quality and mesh size availability.
This paper summarizes the historical supply of proppant by type and source, and the driver for each proppant type based on the authors’ current and prior research. The paper will further clarify the basics of proppant by type and size (e.g., what is 100 mesh?) and will address some of the challenges that both the proppant supplier and end-user may face subject to current or desired completion practices. Key observations will be: 1) Potential limitations in the amount of proppant size and type, 2) The impact that specific proppant shortages may have on both supplier and end-user, and 3) Risk factors the proppant supply base may experience subject to future changes in completion design.
The objective of this effort is to encourage the need to study alternative completion designs subject to proppant availability. It is specifically not the intent of this paper to propose one form of completion practice or proppant type over the other.
Although infill drilling and tighter well spacing have improved the production and economic return for North American Shale leases, these practices have intensified a problematic side effect often referred to as Frac Hits (
Frac hits are not a new phenomenon in the development of North America's Shale fields. Usually first encountered by operators during the progression from Hold By Production (HBP) to infill drilling, they have been widely documented and studied over the past 6+ years. However, apart from avoiding frac hits entirely through a fully integrated field development plan, the existing industry literature does not provide a flexible, repeatable, cost effective solution to mitigating frac hits. Refracs have been discussed for parent wells next to the new infills, but economics have been difficult to justify on more recently completed wells with larger completion designs, and refracs do not address the challenge of third or higher generation infill activities where several wells are at risk of being frac hit.
This document will cover the development of the frac hit mitigation technique that the authors developed in their company's Eagle Ford acreage and which is now employed as standard practice for all infill completion campaigns in both the Eagle Ford and Permian.
He, Yong (PetroChina Zhejiang Oilfield Company) | Jiang, Liwei (PetroChina Zhejiang Oilfield Company) | Chi, Lu (iRock Technologies) | Wang, Xin (Independent Consultant) | Chen, Qiang (iRock Technologies) | Roth, Sven (iRock Technologies) | Dong, Hu (iRock Technologies)
To reliably evaluate the petrophysical, geochemical, and geomechanical properties of an organic-rich shale formation in China, we integrated digital rock analysis (DRA) with conventional core data and well log interpretation. The objectives of this paper included (a) to create a complete and accurate formation evaluation model for Wufeng-Longmaxi shale gas formation by combining pore-scale (digital rock), core-scale, and log-scale data; (b) to accurately characterize the micro-scale pore space, rock matrix, and organic matters in this formation, and create 3D pore network models from core samples; and (c) to identify the geological and engineering sweet-spot along vertical wellbore.
For well log interpretation, we obtained Gamma Ray (GR), spectral GR, neutron, density, resistivity, sonic logs, and elemental spectroscopy logs in the wells. For core measurements, we performed static and dynamic geomechanical experiments on core samples. For DRA, we obtained multi-scale images of the organic-rich shale samples, using three-dimensional (3D) micro-Computed Tomography (CT), 3D Focused-Ion-Beam Scanning Electron Microscope (FIB-SEM), and high-resolution Back-scattered Electron (BSE) imaging. Mineralogical and elemental analysis was also obtained by QEMSCAN. We then quantified various petrophysical properties from the digital rocks, including organic/inorganic porosity, Total Organic Carbon (TOC), elemental concentration and mineralogy. Most of the obtained properties were cross-validated with log data. Furthermore, we extracted pore network models from the digital rocks to quantify pore connectivity, pore throat size distribution, organic pore radius distribution, … etc, to provide more micro-scale information within the rock. Next, we determined the origin of quartz and the cause of high natural gamma-ray sections in the formation, based on point-by-point elemental analysis on SEM images and geochemical analysis. At last, we investigated various geomechanical properties using digital rock, core and log data. We compared geomechanical properties from core experiments and logs, then performed sensitivity study by DRA.
Two vertical wells in Wufeng-Longmaxi shale formation were studied by the introduced workflow. The DRA, core, and log data were mostly in good agreement, confirming the reliability of these methods. When multiple logs showed discrepancies in TOC, DRA provided additional key information for judgment. Based on the obtained petrophysical, geochemical, and geomechanical properties, we accurately characterized the Wufeng-Longmaxi formation, predicted the shale gas sweet-spot along the wellbore, and provided suggestions for future operations of horizontal drilling and fracking in this formation.
The exploration and development of shale gas formations in China attracted extensive interests among Chinese national oil companies and international operators. However, it was extremely challenging due to the complex geological features of organic-rich shale formations in China. Furthermore, conventional methods of core analysis and well log interpretation were usually unreliable in these complex formations, and unable to illustrate micro-scale information in shale. The integration of DRA with conventional core and log analysis significantly improved formation evaluation in organic-rich shale formations in China, and can provide basis for future development decisions.
Yanhua, Yao (Baker Hughes, a GE Company) | Ning, Zhang (Baker Hughes, a GE Company) | Qirong, Li (Changning Shale Gas Company, PetroChina) | Yang, Yang (Changning Shale Gas Company, PetroChina) | Jian, Zheng (Changning Shale Gas Company, PetroChina) | Man, Chen (Changning Shale Gas Company, PetroChina) | Li, Yang (Changning Shale Gas Company, PetroChina) | Hao, Zhou (Changning Shale Gas Company, PetroChina) | Zhou, Zhang (Changning Shale Gas Company, PetroChina)
Production in shale is higher related to the well placement in both sweetspot and fracable zone. Due both to market conditions and also shale property, geosteering in tight shale reservoirs have generally employed basic and economical steering tools, such as gamma ray; however, though the tool provides some data to steer the well, the data provided does not allow for predictions of fracability and production potential of the shale rock. This paper introduces a new geosteering approach, which augments existing techniques by providing data to also help well placement, then design stage and perforation location. This novel formation evaluation technique is essentially building a quantitative model of "sweetspot fracable window" for shale, which can help to land and target most prospective zones. The main quantitative data is obtained through measurement of cuttings samples at well-site in semi-realtime on a field portable SEM (
Case studies have shown that maintaining the well path in the sweetspot fracable window can result in better well production after fracturing. And thus, the goal for geosteering is to ensure as much as possible that the horizontal well trajectory is maintained within this window. Additionally, the cuttings data generated during the drilling process can also be used both during and after TD to generate optimized completion design, aiming to further maximize well productivity. The case study also shows that, compared with conventional wireline logging data, the on-location cutting based analysis is able to generate richer mineralogical and elemental data throughout lateral wells, providing a better understanding of geological heterogeneity. Meanwhile, the author also applies several strategies to calibrate the cutting depths and cuttings’ time lags.
This approach can provide a fast analysis for enhanced reservoir navigation, to keep the well trajectory within a predefined sweetspot fracable zone. The production analysis of the wells, hereafter, verifies the higher rate of intersecting into sweetspot fracable zone, the higher production the well receives. This then assist in generating cost-effective completion optimization of stage placement and perforation, with the ultimate goal of increasing the investment returns.
In conclusion, the production statistics of the wells verifies the higher rate of intersecting into sweetspot fracable zone, the higher production the well receives. The goal for geosteering is to ensure as much as possible that the horizontal well trajectory is maintained within this window.
The economic trade-off between overcapitalization and ineffective hydrocarbon recovery has forced operators in shale plays to focus their efforts on understanding optimal wellbore spacing, both in the vertical and horizontal sense. Matrix permeability has a significant impact on the reservoir modeling results that drive many of these development decisions. Despite incorporating modern crushed-rock pressure-decay permeability datasets, well production is commonly degraded at wellbore spacing schemes much wider than the models indicate. The overstatement of permeability is likely due to experimentally derived flow-regime effects inherent to the analysis. Large helium gas molecules at low pressures are used in crushed-rock permeability experiments, which allow individual gas molecules to be quite far apart (they have a large mean free path, λ). Since shale pores are often smaller than λ, it is more likely a gas molecule will hit a pore wall than another gas molecule. This creates flow-regime effects, which tend to overstate permeability up to several orders of magnitude. To test this hypothesis, several crushed-rock samples from the Devonian Duvernay and Jurassic Nordegg Formations in the Kaybob area in the Western Canadian Sedimentary Basin (WCSB), as well as the Late Cretaceous Eagle Ford Formation in South Texas were analyzed with a pressure-decay apparatus at various λs. This was accomplished by manipulating the gas molecule used and the equilibrium pressure of the test. Although significant differences were observed, conventional approaches for correcting flow-regime effects, including slip and double-slip plots, were not successful in deriving the true (intrinsic) matrix permeability. A new technique, referred to as the λ plot, enables a reasonable derivation of flow-regime corrected permeability and effective pore size for all the samples. This permeability, k1λ, corrects the λ to a typical plug permeability experiment value of 1 nm, which we believe is quite close to the true (intrinsic) permeability. The results indicate that the median matrix permeability for all samples is 5 nD, down from over 200 nD when no corrections are made. Steady-state permeability measurements trend towards k1λ as confining stress is applied on plugs where microfractures appear to be minimal. Crushed-rock pressure-decay permeability, when corrected for flow-regime effects, offers the best measure of matrix permeability in shales.
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.
Next to the Alaska Highway 97 north of Fort St. John in the thick forests of northern British Columbia natural gas is trucked out from the Highway Natural Gas Liquids Plant in the North Montney shale formation. Unconventional oil and gas have come to dominate the exploration and development scene in Western Canada since 2005, much as they have in the US. Both countries share essential elements needed to launch and sustain unconventionals: A long history of drilling, publicly available data, well-understood sedimentary basins, extensive infrastructure, a diverse corporate sector, and regulatory regimes supportive of innovative resource development. Following closely on developments in the US, the “tight gas” concept was a key component of the Canadian oil patch in the 1980s and 1990s. Horizontal drilling and hydraulic fracturing were employed in ever-tighter reservoirs, and in the early 2000s, Canadian operators began to appreciate the true potential of oil and gas from shales, tight reservoirs, and coal seams.
This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Houston, Texas, USA, 23-25 July 2018.