Cronkwright, David (University of Calgary) | Ghanizadeh, Amin (University of Calgary) | DeBuhr, Chris (University of Calgary) | Song, Chengyao (University of Calgary) | Deglint, Hanford (University of Calgary) | Clarkson, Chris (University of Calgary) | Ardakani, Omid (Geological Survey of Canada)
This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Denver, Colorado, USA, 22-24 July 2019. The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted by the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk. The information herein does not necessarily reflect any position of URTeC. Any reproduction, distribution, or storage of any part of this paper by anyone other than the author without the written consent of URTeC is prohibited. Abstract Fluid distribution and fluid-rock interactions within the nano-/macro-porous pore network of tight oil reservoirs will affect both primary and enhanced oil recovery (EOR) processes. Focusing on selected samples obtained from the liquids-rich reservoirs within the Montney Formation (Canada), the primary objective of this work is to evaluate the impact of mineralogical composition on micro-scale fluid distribution at different saturation states: 1) "partially-preserved" and 2) after a series of core-flooding experiments using reservoir fluids (oil, brine) under "in-situ" stress conditions. Small rock chips (cm-sized), sub-sampled from "partially-preserved" (using dry ice) core plugs, were cryogenically frozen and analyzed using an environmental field emission scanning electron microscope (E-FESEM) equipped with X-ray mapping capability (EDS).
Relative permeability (kr) functions are among the essential data required for the simulation of multiphase flow in hydrocarbon reservoirs. These functions can be measured in the laboratory using different techniques including the steady state displacement technique. However, relative permeability measurement of shale rocks is extremely difficult mainly because of the low/ultralow matrix permeability and porosity, dominant capillary pressure and stress-dependent permeability of these formations.
In this study, the impacts of stress and capillary end effects (CEE) on the measured relative permeability data were investigated. The steady state relative permeability (SS-kr) measurements were performed on Eagle Ford and Pierre shale samples. To overcome the difficulties regarding the kr measurements of shale rocks, a special setup equipped with a high-pressure visual separator (with an accuracy of 0.07 cc) was used. The kr data were measured at different total injection rates and liquid gas ratios (LGR). In addition, to evaluate the impacts of effective stress, the kr data of an Eagle Ford shale sample were measured at two different effective stresses of 1000 and 3000 psi.
From the experimental data, it was observed that the measured SS-kr data of the shale samples have been influenced by the capillary end effects as the data showed significant variation when measured at different injection rates (with the same LGR). This suggested that the liquid hold-up (i.e. capillary end effects) depends on the competition of capillary and viscous forces. In addition, it was shown that it is more necessary to correct the experimental kr data measured at the lower LGRs. Furthermore, different relative permeability curves were obtained when the kr data were measured at different effective stresses. This behavior was explained as the capillary pressure was expected to be more dominant at the higher effective stress.
The results from this study improve our understanding of unconventional mechanisms in shale reservoirs. It is evident that the behavior of unconventional reservoirs can be better predicted when more reliable and accurate relative permeability data are available. The outcomes of this study will be useful for accurate determination of such kr data.
This is the second of a three-part tutorial describing a workflow for evaluating unconventional resources including organic mudstones and tight siltstones. Part 1 reviewed the unique challenges and provided an overview of the proposed workflow (Newsham et al., 2019). Part 2 describes in detail the many components of the workflow and how they come together to determine the storage capacity of the reservoir. Part 3 links the petrophysical results to the production potential in terms of fractional flow and water cut and will present alternate cross-checks of the storage properties to validate the results.
As stated in Part 1, one of the most important functions that the petrophysicist provides is the estimation of accurate storage properties. However, when the authors survey the range of workflows used to estimate the storage capacity of these complex systems, we find a wide range of options. Solutions can vary from simple deterministic to more complex probabilistic approaches. Whatever the method, the objective should be the same: to provide consistent, portable hence reliable estimation of hydrocarbon storage capacity, also known as “Petrophysics CPR.” As mentioned in Part 1, estimation of hydrocarbon storage is more than just the calculation of porosity and water saturation. In this tutorial, we will describe a workflow that has been successfully used to evaluate thousands of wells in the Permian Basin with great consistency. The authors have nearly 100 wells with core data to calibrate the workflow. We will show examples of the workflow’s portability by highlighting examples from the Midland Basin, the Texas Delaware Basin and the New Mexico Delaware Basin. We will show how every property measured in core matches to log-based profiles using a combination of deterministic and the constrained simultaneous solution methods. The workflow also is found to be reliable in other basins throughout the world, however, the examples will be confined to the Permian Basins.
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. Enhanced-oil-recovery studies in tight formations through surfactant and gas injection and acid treatment are among the recent research directions toward improving the ultimate recovery of tight formations or shales (Teklu et al. 2017a, 2018).
A hybrid-hydraulic-fracture (HHF) model composed of (1) complex discrete fracture networks (DFNs) and (2) planar fractures is proposed for modeling the stimulated reservoir volume (SRV). Modeling the SRV is complex and requires a synergetic approach between geophysics, petrophysics, and reservoir engineering. The objective of this paper is to characterize and evaluate the SRV in nine horizontal multilaterals covering the Muskwa, Otter Park, and Evie Formations in the Horn River Shale in Canada, with a view to match their production histories and to evaluate the effectiveness and potential problems of the multistage hydraulic-fracturing jobs performed in the nine laterals.
To accomplish this goal, the HHF model is run in a numerical-simulation model to evaluate the SRV performance in planar and complex fracture networks using good-quality microseismicity data collected during 75 stages of hydraulic fracturing (out of 145 stages performed in nine laterals). The fracture-network geometry for each hydraulic-fracture (HF) stage is developed on the basis of microseismicity observations and the limits obtained in the fracture-propagation modeling. Post-fracturing production is appraised with rate-transient analysis (RTA) for determining effective permeability under flowing conditions. Results are compared with the HHF simulation and the hydraulic-fracturing design.
The HHF modeling of the SRV leads to a good match of the post-fracturing production history. The HHF simulation indicates interference between stages. The vertical connectivity in the reservoir is larger than the horizontal connectivity. This is interpreted to be the result of the large height achieved by HFs, and the absence of barriers between the formations.
It is concluded that the HHF model is a valuable tool for evaluating hydraulic-fracturing jobs and the SRV in shales of the Horn River Basin in Canada. Because of the generality of the Horn River application, the same approach might have application in other shale gas reservoirs around the world.
The Beetaloo Sub-basin in the Northern Territory is one of Australia's most prospective basins for shale gas production. The Beetaloo gas shales are unique in that they could become some of the oldest producing source rocks in the world, if commercialized successfully. In this work we characterise gas shales from two target reservoirs in the Beetaloo Sub-basin and compare them to other shales from around the globe to improve the current understanding of what controls gas adsorption on shales.
We characterise the methane adsorption capacity of two sets of Beetaloo shale samples: middle Velkerri B shale (8 samples, ~2450 m depth) and lower Kyalla shale (10 samples, ~1300 m depth). Measurements are performed at reservoir conditions, i.e. up to 110°C and 30 MPa, using CSIRO's gravimetric isotherm rig. The samples’ mineralogy is analysed using X-ray powder diffraction (XRD) and the total organic carbon (TOC) is determined using a LECO machine.
Our experiments demonstrate that the gravimetric rig is capable of obtaining fast and reliable measurements on low adsorbing shales at high pressures and high temperatures for sample quantities of around 90 g. The results highlight that the adsorption capacity of middle Velkerri B shale is significantly higher than of lower Kyalla shale (average Langmuir volume 3.23 m3/t compared to 2.27 m3/t) and that the isotherms can be represented using a Langmuir relationship. In spite of their age, the Beetaloo shales exhibit adsorption behaviour comparable to that of other shales with similar TOC.
Two global shale data sets, which include the Beetaloo samples, demonstrate that there is a strong relationship between TOC and a shale's adsorption capacity. However, the TOC alone cannot account for the differences in adsorbed amount observed within the two sets of Beetaloo shale samples.
Bulk clay content appears to control the adsorption capacity of shales with low TOC (< 2%), such as the lower Kyalla shale. Analysis assessing the contribution of individual clay minerals to the CH4 adsorption capacity indicates that it is the high illite/muscovite content (30-40%) that controls adsorption on the lower Kyalla shale samples. For the high TOC/low clay middle Velkerri B samples (3.7-6.3% TOC, 20-23% clay) clay content cannot account for the differences observed in adsorbed gas between the samples, even as a secondary control. Further investigation is required to understand what controls gas adsorption on this shale.
Kettlety, Tom (School of Earth Sciences, University of Bristol) | Verdon, James P. (School of Earth Sciences, University of Bristol) | Werner, Maximilian (School of Earth Sciences, University of Bristol) | Kendall, J Michael (School of Earth Sciences, University of Bristol)
In this study we investigate the potential driving mechanisms that lead to induced seismicity during hydraulic fracturing. Fluid processes (pore-pressure changes and poroelastic effects) are often considered to be the primary driver. However, some studies have suggested that elastic deformation, and the resulting stress interactions, may contribute to further seismicity. In this paper we use a dataset acquired during hydraulic fracturing to calculate elastic stress transfer during a period of fault activation and induced seismicity. We find that elastic stresses may have weakly promoted failure during the initial phase of activity. However, at later times, stress changes generally acted to inhibit further slip. These signals are further weakened once uncertainties in source mechanisms and other geomechanical parameters are taken into account. Given the estimated
Presentation Date: Tuesday, October 16, 2018
Start Time: 1:50:00 PM
Location: 208A (Anaheim Convention Center)
Presentation Type: Oral
Unconventional reservoirs have high initial production rates followed by a steep decline as compared to conventional reservoirs. The increase in the net stress with the production results in matrix and fissure permeability reduction and hydraulic fracture compaction and conductivity impairment due to proppant embedment. At the same time, the pressure decline will result in gas slippage and matrix permeability enhancement. The impact of the net stress and pore pressure changes are often neglected when evaluating the production performance of the shale wells. The objectives of this study are to investigate the impacts of net stress changes (geomechanical) and pore pressure changes (gas slippage) on the gas production from horizontal wells with multiple hydraulic fractures completed in the Marcellus Shale. Laboratory measurements on Marcellus shale core plugs provided the foundation for evaluating the impact of pore pressure and net stress changes on the matrix permeability. Additionally, these laboratory measurements on Marcellus shale core plugs provided the fissure closure stress. The results of the published studies on Marcellus shale core plugs were also utilized to develop relationships for hydraulic fracture conductivity and the fissure permeability as a function of the net stress in the shale. Core, log, completion, stimulation, and production data from the wells located at the Marcellus Shale Energy and Environment Laboratory (MSEEL) were utilized to generate the formation and completion properties for the base model for a horizontal well completed in Marcellus Shale. The results of the laboratory measurements and published studies were then incorporated into the base model to account for the impact of the stress on the matrix, fissure, and hydraulic fracture permeability (conductivity), and consequently on the production performance.
The model was utilized to determine the effective properties of the hydraulic fractures by history matching the production data from two horizontal wells at MSEEL site. For the comparison purposes, the geomechanical effects were excluded from the model, individually and all combined, to history match the same production data from the horizontal wells. The results indicated that the geomechanical effects for fissure permeability have a significant impact on gas production as compared to geomechanical effect for matrix permeability and hydraulic fracture conductivity. The gas slippage was found to have an insignificant impact on the production. The base model was finally used to perform a number of parametric studies to investigate the impact of fracture half-length, initial fracture conductivity, and fracture stages spacing on the stress-dependent fissure permeability.
Imbibition of water into the shale matrix is known as the primary reason for inefficient water recovery after hydraulic fracturing treatments. The hydration of clay minerals may induce microfractures in clay-rich shale samples. The increased porosity and permeability due to induced microfractures has been considered to be partly responsible for 1) excessive water uptake of gas shales, and 2) increase in hydrocarbon production rate after prolonged shut-in periods. To test this hypothesis, it is necessary to measure imbibition-induced strain and stress under representative laboratory conditions. In this study, we conduct laboratory tests to 1) measure the strain and stress induced by water imbibition in gas shales and 2) investigate the effect of confining load on the rate of water imbibition. We conduct a three-phase study on rock samples from the Horn River Basin (HRB) and the Duvernay (DUV) Formation, located in the Western Canadian Sedimentary Basin.
Students from SPE Suez University Student Chapter (Egypt) take a selfie together with a member of SPE Gubkin University Student Chapter (Russia) during ATCE 2014. Chevron will be the sole sponsor of the student dues program, which provides support for college students to join SPE’s global network of student chapters. SPE has nearly 69,000 student members in 130 countries. Also, Chevron will support the Energy4me program in which teachers and students gain invaluable knowledge about the oil and gas industry. Students learn skills on how to think, problem solve and adapt to changing conditions – competencies required to be a successful engineer.