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Spontaneous imbibition of three leading shale formations in the Middle Yangtze Platform, South China Rui Yang, Xusheng Guo, Jizheng Yi, Zhixiong Fang, Qinhong Hu, and Sheng He Energy Fuels, Just Accepted Manuscript • Publication Date (Web): 07 Jun 2017 Downloaded from http://pubs.acs.org on June 10, 2017
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Spontaneous imbibition of three leading shale formations in the Middle
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Yangtze Platform, South China Rui Yang †, Xusheng Guo ‡, Jizheng Yi #, Zhixiong Fang &, Qinhong Hu †, a, Sheng He †, b
3 4
†
5
of Geosciences, Wuhan 430074, China.
6
‡
Exploration Company, Sinopec, Chengdu 610064, China.
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#
Jianghan Oilfield Branch Company, Sinopec, Qianjiang, Hubei 433124, China.
8
&
SINOPEC East China, Nanjing, Jiangsu 210000, China.
Key Laboratory of Tectonics and Petroleum Resources, Ministry of Education, China University
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ABSTRACT
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Widely distributed in the Middle Yangtze Platform, Longmaxi, Dalong and
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Dongyuemiao Shales are the most potential target zones for shale gas development in
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South China. In this study, samples from these main shale gas-producing intervals,
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with a range of TOC content, mineral compositions, and thermal maturities (from
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mature to overmature), were selected from three shale gas wells in the Middle
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Yangtze Platform to investigate their pore structures and spontaneous imbibition
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characteristics. MICP results show the pore throats in these organic shales are mainly
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within nanometer range, and the pores with pore-throat diameter of 3-50 nm account
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for 56.7-73.1% of the total pore volume in mature Dongyuemiao Shale, which is
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comparative to 51.4-82.7% for Dalong Shale but smaller than 68.1-86.5% for
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overmature Longmaxi Shale, which is probably associated with abundance of organic
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matter-hosted pores in Longmaxi Shale.
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According to the different imbibition behaviors towards deionized (DI) water (a
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hydrophilic fluid) and n-decane (a hydrophobic fluid), the pore connectivity and 1
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wettability characteristics were qualitatively assessed. Most of the shales exhibit a
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better pore connectivity towards n-decane, while a few samples with high brittle
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minerals and clay minerals contents have a high imbibition rate for DI water.
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Imbibition tests also suggest that Longmaxi Shale is mixed-wet, while Dalong and
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Dongyuemiao Shales are oil-wet or weakly water-wet, which is generally consistent
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with the contact angle measurement. Sorptivity obtained from the imbibition tests of
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wetting n-decane shows positive relationships with porosity and clay contents, but a
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negative correlation towards TOC content. In addition, a lower-bound of the
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estimated permeability from wetting n-decane imbibition tests ranges from 135 to 528
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nD, and matches well with reported measured matrix permeability.
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Key words: Yangtze Platform; Sichuan Basin; Organic shale; MICP; Wettability;
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Imbibition
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1. INTRODUCTION
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As a relatively clean fossil fuel, shale gas has evolved to be the focus of
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exploration and development in North American and other countries over the past
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several decades 1. In order to meet the increasing energy demand, petroleum industry
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have greatly advanced the drilling completion technologies, such as horizontal drilling
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and hydraulic fracturing, leading to a dramatic rise of gas production from mudrock
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(commonly referred as shale) formations in the United States, from 0.39 tcf in 2000 to
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9.96 tcf in 2015 1.
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Shale gas is mainly stored in three forms: free gas in pores and fractures with a
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multi-scale size range, adsorbed gas on the surfaces of inorganic minerals and organic
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matter, and to a less extent dissolved gas within water, oil and bitumen 2. Even with
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the ongoing shale revolution, petroleum industry has gradually recognized that natural
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gas extraction and commercial exploitation from shale reservoirs are still technically
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challenging
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environmental consequences (such as groundwater quality) in the application of
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massive and multistage hydraulic fracturing technologies
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decline and low overall recovery can constrain shale revolution 4; there are doubts
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about whether natural gas extraction and production from deep shale formations will
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be profitable 3. The sustainable shale gas development is strongly related to the
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complex shale geology, especially the nanometer scale pore system in shale matrix 4,
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8-10
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reservoirs and their ultimate profitability mainly depends on how the flow rate of
3, 4
. Furthermore, considerable attention has been drawn to the potential
5-7
. In addition, steep initial
. The cumulative gas production obtained from the hydro-fractured wells in shale
3
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gases varies over production time 11, 12.
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Gas production from shale reservoirs around the world faces both scientific and
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engineering challenges. Recent shale gas exploration and production data reported
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that the flowback efficiency is often very low
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Haynesville shale after fracturing treatments, and a significant fraction of injected
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fluid is retained in the porous shale reservoir 18. Particularly, during the period of well
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shut-in, the volume of fluid loss and low flowback efficiency become more
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pronounced.
13-17
; for example, only 5% for
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The interaction between fracturing fluids and created fracture surfaces causes the
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injected fluid to invade into the shale matrix through certain mechanism, which is
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closely related to fluid imbibition, a relatively slow process
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imbibition not only leads to the fluid uptake (or loss) of huge volumes to the
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formation, but also results in capillary blockages and a decrease of gas relative
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permeability, which have attracted extensive attentions in petroleum industry
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Obviously, a better understanding of fluid imbibition behavior is beneficial to
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understand the retention of fracturing fluid and the potential formation damage, as
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well as the wettability properties of the rock surfaces
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imbibition process can enhance the rate of initial gas production after extended shut-in
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of a hydraulically fractured well
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been considered to be an enhanced recovery method in shale gas reservoirs, which is
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important for the sustainable development of shale gas 20, 25, 29.
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14, 19
. Spontaneous fluid
14, 20-22
.
20, 23-26
. Studies also show that
27, 28
; therefore, spontaneous fluid imbibition has
Fluid imbibition has been widely investigated in the academic and petroleum 4
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industry. The quantity and rate of water intake can be reduced by the addition of
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surfactants, which can effectively change the wettability characteristics of shale
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Dehghanpour et al.
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additional driving forces, and induce some (micro)fractures to enhance the
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spontaneous permeability. Imbibition rate is also related to the shale bedding with a
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much higher imbibed volume in the direction parallel to the bedding direction, which
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is related to effects of anisotropy
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saturation on the rate of spontaneous imbibition has been widely studied on different
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rocks, and the initial water saturation can influence the capillary pressure and relative
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permeability
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low-permeability porous rocks are often deeply buried with relatively high water
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saturations, which will greatly reduce the imbibition rate in terms of sorptivity 33, 38-40.
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Furthermore, the complex pore structure and heterogeneous mineral composition in
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shale reservoirs can result in various imbibition rates among shales 26.
29
14, 30
.
discovered that water uptake by clay minerals can provide
26, 31, 32
. In addition, the effect of initial water
33-37
. Under geological conditions, it can be expected that
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With an estimated shale gas resource of 886.4 tcf, since 2008 Chinese
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government has been embarking on an ambitious shale gas exploration and
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development program
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Platform from South China, with various depositional environments of marine
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(Precambrian Sinian to Middle Permian), transitional marine (Permian to Middle
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Trassic) and lacustrine setting (Late Triassic to Jurassic)
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announced the 1st commercial success of shale gas development in the Upper
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Ordovician Wufeng and Lower Silurian Longmaxi Shales in the Fuling area of
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. Organic shales are widely distributed in the Yangtze
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. In 2014, China
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46
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Sichuan Basin
. Since then, marine shales in the Yangtze Platform have been
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regarded as main target zones for shale gas exploration and development in South
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China, and many publications focus on these two units of marine shales in terms of
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depositional environment
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characterization 50-52, and gas enrichment mechanism 42, 53, 54.
47, 48
, shale gas resource potential
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, pore system
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In contrast, due to the clay-rich nature and relatively low shale gas production,
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transitional and lacustrine shales have been considered to be less prospective and are
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often neglected to some extent. Compared with Longmaxi Shale, Dalong and
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Dongyuemiao Shales in Yangtze Platform have different geological settings and
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associated attributes such as mineral composition, thermal maturity, kerogen type and
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organic richness. Recent exploration of shale gas resource from Dalong and
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Dongyuemiao Shales in Yangtze Platform leads the petroleum industry in China to
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realize that these two units of organic shales also have great resource potential
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However, reported production data of several shale gas wells from these three leading
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shales shows a rapid decline of gas production within few years (e.g., gas production
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from JY#1 Well declines from 20×104 m3/d to 6.6×104 m3/d within one year)
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Underlying reason for such a steep decline and low gas recovery could be better
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assessed with improved understanding of pore structure and imbibition characteristics
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of shale matrix. However, a comparative study on the spontaneous imbibition
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characteristics for these three leading shale formations (Longmaxi, Dalong and
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Dongyuemiao) with different sedimentary environments from the Yangtze Platform is
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not available in the literature. Furthermore, although it is accepted that shale 6
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.
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.
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properties (TOC, porosity, and mineral composition) can affect the imbibition process,
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few studies have been carried out to investigate the effect of such properties on
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sorptivity and calculate the permeability from imbibition tests.
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In this study, several core samples from three leading shale formations with
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different mineral compositions, thermal maturities (from mature to overmature) and
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sedimentary facies (marine, transitional and lacustrine) were selected from shale
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gas-producing wells in the Middle Yangtze Platform. In combination with the mercury
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injection capillary pressure (MICP) tests for pore structure characterization, this study
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is the first attempt to comparatively investigate the spontaneous imbibition
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characteristics on organic-rich Longmaxi, Dalong and Dongyuemiao Shales in South
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China, discuss the effects of shale properties (TOC, mineral composition and pore
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structure) on the spontaneous imbibition rates, and estimate permeability from the
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imbibition of wetting n-decane fluid to be compared with published matrix
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permeability obtained from pulse-decay permeameter with helium. This work is
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beneficial to understanding the fluid imbibition rate in organic-rich shales, which
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could also provide important reference to the low flowback efficiency and enhanced
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the gas recovery.
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2. GEOLOGICAL SETTING AND SAMPLES
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2.1 Geological setting. Distributed in the south China, Yangtze Platform includes the
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eastern part of Southern China, Eastern of Sichuan province, Yangtze River Basin and
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its southern regions, which can generally be divided into Upper, Middle and Lower
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Yangtze Platform (Figure 1)
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. Since the development of Yangtze craton, Yangtze 7
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Platform region experienced five large-scale tectonic movements, in the order of,
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Caledonian (Late Sinian-Silurian), Hercynian (Devonian-Permian), Indosinian
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(Triassic), Yanshanian (Jurassic-Cretaceous), and Himalayan (Tertiary-Quaternary),
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leading to a relatively complex geological settings in and around Yangtze Platform
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region 55, 56. During the period of Late Ordovician to Early Silurian, global relative sea
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level rose rapidly in the relative confined paleogeography
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low-energy and anoxic sedimentary and the vast deposition of the marine Wufeng and
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Longmaxi Shales in most areas of Upper-Middle Yangtze Platform (Figure 2).
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Longmaxi Formation mainly consists of siliceous shale, carbonaceous shale,
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argillaceous siltstone and carbonaceous mudstone with abundant radiolarian,
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graptolite fossils, and authigenic pyrite
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mainly deposited in deep-water continental shelf, has now been regarded as not only
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excellent source rock but also potential reservoirs for shale gas production 58.
47, 55, 57
, resulting in a
47, 50
. This set of black organic-rich shale,
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From Late Carboniferous to Middle Triassic, affected by the Hercynian orogeny
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and Indosinian tectonic movements, the sedimentary environment in Upper-Middle
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Yangtze Platform evolved to transitional facies and was dominated by an open
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platform with a thick deposition of limestone, dolomite interbedded with clastic rocks
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and some thin coal seam
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tectonic movement, ancient sea in Upper-Middle Yangtze Platform region regressed in
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southern and southwestern direction, developing in a platform edge facies and
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deposition of Dalong Formation
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secession of calcareous shale, marlstone and dolomite interbedded with thin
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. During the Late Permian, affected by the Dongwu
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. Dalong Formation is characterized by a thick
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mudstones. The average TOC content in Dalong Formation is about 4.69%
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indicating an excellent hydrocarbon source rock and shale gas reservoir.
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,
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During the period of Late Triassic and Middle Jurassic, Yangtze Platform regions
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experienced multi-scale and multi-stage uplift and deformation, and the predominant
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depositional setting was delta, semi-deep lake and deep lake facies 55. At a thickness
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of 70-120 m, Dongyuemiao Member from Ziliujing Formation mainly consists of
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gray mudstone, argillaceous limestone and silty shale (Figure 2). Compared to
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Longmaxi and Dalong Shales, organic shales from Dongyuemiao Member are
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characterized by a moderate thermal maturity (at the peak of oil generation) and
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shallow burial depths (< 2000 m).
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In summary, these three organic-rich shales from marine to transitional to
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lacustrine settings, spanning in age from Early Silurian, Upper Permian to Early
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Jurassic, are widely distributed in the Yangtze Platform region and are now being
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targeted as the main potential targets for shale gas exploration and production in
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China.
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2.2 Samples. Recent production data and investigations of lithofacies characteristics on
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these three leading shale formations show that the lithology of the main shale
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gas-producing intervals are carbonaceous shale and siliceous shale at the bottom of
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Longmaxi Formation, calcareous shale for Dalong Formation, and silty shale and
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interbedded argillaceous limestone for Dongyuemaio Member
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total of six core samples from these typical lithofacies were collected from the above
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leading shale formations in three shale gas-producing wells from the Middle Yangtze 9
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. In this work, a
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Platform, South China (Figure 1). This set of shale samples can generally provide a
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snapshot of the main productive layers for these shale gas-producing formations. The
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basic information for these analyzed samples (e.g., age, depth, formation, lithology,
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TOC content, thermal maturity and mineral composition) is listed in Table 1.
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In
this study, shales from different sedimentary environments were
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comparatively investigated, including the lacustrine shales (samples DY-1 and DY-2)
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in Dongyuemiao Member of Lower Jurassic Ziliujing Formation from Hubei Province,
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transitional shales (samples DL-1 and DL-2) in the Late Permian Dalong Formation
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from Hunan Province, and marine shales (samples LM-1 and LM-2) in the Lower
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Silurian Longmaxi Formation from Chongqing Province. These samples have a wide
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range of thermal maturity (from mature [1.1-1.3 %Ro] in lacustrine shales to highly
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mature or overmature [3.1 %Ro] in marine shale), TOC content (0.6-8.1 wt.%) and
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mineral composition, thus the potential variation of spontaneous imbibition
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characteristics with different TOC contents, thermal maturity and mineral composition
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can be studied.
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3. METHODS
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3.1. Mercury Injection Capillary Pressure (MICP). Core samples were first dry-cut to
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obtain 1cm-sized cubic samples. Using an AutoPore IV 9510 automatic pressure
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mercury from Micromeritics Instrument Corporation, pore structure parameters (e.g.,
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pore volume, porosity and pore-throat distribution) were determined to assess the pore
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systems. Before the MICP test, cubic samples were oven-dried at 60 oC for more than
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2 days to remove any possible moisture (mainly free water) from the samples, and 10
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cooled to room temperature of about 23±0.5 oC. According to the Washburn equation
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63
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pressure is inversely proportional to pore-throat size, but directly proportional to the
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volume of mercury intruded into the sample. For example, our MICP instrument can
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reach a maximum pressure of 60,000 psia (414 MPa); thus, a correspondingly
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measurable pore-throat diameter to be about 3 nm. In this study, the surface tension
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was adopted as 485 dyne/cm, and 130° for the mercury’s contact angle. Equilibration
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time (minimum elapsed time for
