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Shale gas exploitation: Status, problems and prospect

Fig. 2. Annual production of major shale gas plays in the world. Note: The data abroad are sourced from Refs. [14], [15], and the domestic data from Ref. [1]. Except for the Monteney and Muskwa shale gas plays in Canada of which the production data are shale gas production from 2011 to 2012, those of other plays are the data in 2015.


Over the past five years, great progress has been made in shale gas exploitation, which has become the most driving force for global gas output growth. Hydrocarbon extraction from shale helps drive the USA on the road to energy independence. Besides, shale oil & gas production has been kept in a sustained growth by continuous improvement in drilling efficiency and well productivity in the case of tumbling oil prices and rig counts.

Wang Shiqian

Research Institute of Petroleum Exploration and Development, PetroChina Southwest Oil & Gas Field Company, Chengdu 610051, China

Received 8 May 2017; accepted 25 June 2017

Shale gas reserves and production have been in a rapid growth in China owing to the Lower Paleozoic Wufeng and Longmaxi shale gas exploitation in the Sichuan Basin, which has become an important sector for the future increment of gas reserves and output in China. However, substantial progress has been made neither in non-marine shale gas exploitation as previously expected nor in the broad complicated tectonic areas in South China for which a considerable investment was made.

Analysis of the basic situation and issues in domestic shale gas development shows that shale gas exploitation prospects are constrained by many problems in terms of resources endowment, horizontal well fracturing technology, etc. especially in non-marine shale deposits and complicated tectonic areas in South China where hot shales are widely distributed but geological structures are found severely deformed and over matured.

Discussion on the prospects shows that the sustained and steady growth in shale gas reserves and production capacity in the coming years lies in the discovery and supersession of new shale plays in addition to Wufeng and Longmaxi shale plays, and that a technological breakthrough in ultra-high-pressure and ultra-deep (over 3500 m buried in the Sichuan Basin) marine shale gas exploitation is the key and hope.


During the “12th Five-Year Plan” period, China learned successful experiences in “shale gas revolution” of North America and made great progress in the shale gas exploitation through sustained endeavor and field tests on the technologies to recover the Lower Paleozoic marine shale gas in the Sichuan Basin. Along with the successive discovery and confirmation of the Upper Oligocene Wufeng–Lower Silurian Longmaxi shale gas in the blocks such as Fuling, Weiyuan, Changning, and Fushun–Yongchuan in the Sichuan Basin, China’s shale gas reserves and production have grown vigorously from zero.

Up to the end of “12th Five-Year Plan” period, the cumulative proved marine shale gas reserves in China amounted to 5441 × 108 m3, and the production of marine shale gas in 2015 was 45 × 108 m3[1]. Shale gas has gradually become an important sector for the future increment of gas reserves and output in China, and made China one of the only four countries that have realized commercial development of shale gas around the world (Fig. 1) [1], [2], [3], [4].

Fig. 1. Shale gas production of four shale gas producing countries in 2015. Note: The data are sourced from Refs. [1], [2], [3], [4], and the data of USA refer to dry gas production.
Fig. 1. Shale gas production of four shale gas producing countries in 2015. Note: The data are sourced from Refs. [1], [2], [3], [4], and the data of USA refer to dry gas production.

However, continental and marine–continental transitional shale gas, which was believed to have a great potential in the shale gas investigation in the early “12th Five-Year Plan” period, was not satisfactorily explored and was deemed to be limited in potential. The continental and marine–continental transitional shale gas resources predicted in 2015 were much less than that in the early “12th Five-Year Plan” period, suggesting an uncertain prospect [5], [6].

During the “12th Five-Year Plan” period, marine shale gas exploitation in the Sichuan Basin gained a significant breakthrough and the commercial productivity was realized soon after commissioning. Accordingly, the future shale gas exploitation in the periphery of the Sichuan Basin and even in the whole South China is highly expected. On one hand, the National Energy Administration (NEA) adjusts shale gas production in China at the end of “13th Five-Year Plan” period from (300–600) × 108 m3 to 300 × 108 m3, while some scholars propose that a target of 200 × 108 m3 by 2020 is more rational [5], [7].

On the other hand, an optimistic opinion considers a production of 300 × 108 m3 a little conservative and suggests defining the 45 × 104 km2 range covering Sichuan, Chongqing, Yunnan, Guizhou, Hunan and Hubei, including the Sichuan Basin, as a “Special Shale Gas Zone”. If so, China’s shale gas production by 2020 is expected to reach 1000 × 108 m3[8].

Anyway, all of these viewpoints are based on an optimistic prediction on shale gas in the whole South China, although exploration practices and research achievements in shale gas licenses during the “12th Five-Year Plan” period have revealed that shale gas exploitation in many complex structural areas in the South China, other than the Sichuan Basin, is susceptible to huge geologic risks and engineering challenges, and the economy of commercial shale gas development is also uncertain [5], [6], [9], [10].

However, it seems that some departments are too optimistic about marine shale gas exploitation in South China, especially in complex structural areas, when they make shale gas development planning, being less aware of the problems therein. Under this background, for the sake of orderly development of shale gas in the future, it is necessary to comprehensively review the current status of shale gas exploitation in China and abroad and identify the problems therein.

Basic situation and characteristics of shale gas development abroad

Shale gas exploitation has become the main driving force of global natural gas production growth

According to the EIA evaluation in 2013, globally, shale gas was extremely rich, and technically recoverable shale gas resources were up to 206.56 × 1012 m3[11]. Thus abundant shale gas resources laid a solid material foundation for the “shale gas revolution” in the North America. Although only four countries have realized the commercial shale gas exploitation (Fig. 1), it is believed that more and more countries will join the sector along with the technical progress and the constant improvement of policies, markets and infrastructures.

EIA’s prediction in 2016 [2] showed that the global daily natural gas production would increase from 97 × 108 m3 in 2015 to nearly 157 × 108 m3 in 2040, among which shale gas would make the greatest contribution – being tripled from 2015 to 2040, when shale gas production would account for 30% of global natural gas production, and China would rank as the second largest shale gas producer only after the USA. Besides the four countries producing shale gas, Algeria and Mexico will cooperate with IOCs to produce shale gas commercially around 2020 and 2030 respectively. By 2040, these six countries will totally contribute 70% to global shale gas production. Clearly, future natural gas production growth mainly relies on shale gas, and global shale gas production growth mainly depends on China and the USA. In China, key shale gas production and breakthrough are expected in the marine shale areas in the southern part of the country [1].

Shale oil/gas exploitation has led the USA towards energy independence

In the USA, since the discovery of Barnett shale gas play in the early 1980s, 13 shale oil/gas plays have been put into commercial development [12], and shale gas development has grown swiftly especially from the beginning of the 21st century. The substantial growth of natural gas production in the country is mainly contributed by shale oil/gas. The annual production of shale gas (only dry gas) increased quickly from nearly 100 × 108 m3 in 2000 to nearly 4000 × 108 m3 in 2015, accounting for 50% of the total annual natural gas production in the USA [13].

The Annual Energy Outlook 2016 of EIA [3] shows that the imported natural gas of USA was 283 × 108 m3 in 2015, and the supply and demand were basically in balance, with a difference of only 3%; it is anticipated that in 2018 the USA will become a net exporter of natural gas for the first time since the 1950s, and in 2040 the gap between the oil production and consumption in the USA is only 7%, and the daily import only is 1.5 million barrels. Therefore, the USA is now realizing energy independence by virtue of scale exploitation of shale oil/gas. In the past years, under the circumstance of tumbling oil prices, some new characteristics are observed in shale gas exploitation in the USA.

1)   Shale gas production in the USA can still increase stably year by year under the circumstance of tumbling oil price, and will keep the trend of stable growth in the following years (2016–2040) [3]. This is benefited from the unique and unduplicated resource and market conditions in the USA as well as the constant progress of the low-cost high-efficient shale oil/gas development technologies [13], rather than the so-called industrial policy guidance, support or stimulation highlighted by the domestic opinions.

2)   Since the beginning of the 21st century, especially in the low oil price period, the rapid and sustained development of shale gas in the USA firstly benefited from the rich and highly endowed shale gas resources. Due to the development technology and practices in the Barnett shale gas play which was first developed, “shale gas revolution” spreads quickly throughout the USA, resulting in more and more shale gas discoveries in the petroliferous basins. In 2014, the technically recoverable shale gas resources exceeded 17 × 1012 m3, and the proved reserves reached 5.65 × 1012 m3[6].

According to the EIA data announced in 2016, there are seven shale gas plays (namely the first seven gas plays from left to right in Fig. 2) with an annual production exceeding 200 × 108 m3 in the USA, among which four large shale gas plays (i.e. Marcellus, Eagle Ford, Haynesville and Barnett) delivered an annual production more than 300 × 108 m3, accounting for 70% of the total shale gas production in the USA.

Fig. 2. Annual production of major shale gas plays in the world. Note: The data abroad are sourced from Refs. [14], [15], and the domestic data from Ref. [1]. Except for the Monteney and Muskwa shale gas plays in Canada of which the production data are shale gas production from 2011 to 2012, those of other plays are the data in 2015.

Fig. 2. Annual production of major shale gas plays in the world. Note: The data abroad are sourced from Refs. [14], [15], and the domestic data from Ref. [1]. Except for the Monteney and Muskwa shale gas plays in Canada of which the production data are shale gas production from 2011 to 2012, those of other plays are the data in 2015.

In addition, owing to the sharing of shale gas exploitation experiences among oil companies and the duplication of advanced technologies, the period that shale gas play can be put into scale production is greatly shortened. The horizontal drilling and completion technology and gas reservoir management experience developed in the Barnett shale gas play are copied in other plays successfully with better results.

The data statistics show that the Fayetteville shale gas play in the Arkoma Basin commissioning in 2007 reaches a daily production of 2700 × 104 m3 that takes 22 years in the Barnett shale gas play. The Haynesville and Marcellus shale gas plays developed after Barnett have exceeded the highest annual production of 500 × 108 m3 of Barnett in 2011 and 2012 respectively, and replaced the overlord of Barnett that yields the highest production in the first decade of the 21st century.

3)   Hughes analyzed 65000 shale gas production wells and found that the shale gas production decline rate ranged from 23% to 49% on average in the first year of production in seven shale gas plays including Barnett, and from 80% to 90% in the first three years [16]. Therefore, in order to keep shale gas production stability, it is required to drill new wells to make up the rapid production decline of old wells. However, when the oil price goes down, oil companies will inevitably lessen the rigs to reduce the shale oil/gas development cost. According to the data published by Baker Hughes, the number of rigs in the USA decreased from 1859 in November 2014 to 951 in April 2015, while shale oil/gas production didn’t descend but ascended [17].

Under the situation of falling oil price and reducing rigs, oil companies took some effective measures to realize stable production growth and low cost of commercial development. First, they focused the development on the high-quality resources in the “core plays”. Through integrated geological-engineering evaluation on shale gas, they selected the “core plays” with higher production and better profit for exploitation. They deployed the limited rigs in the “core plays”, so as to avoid a great decline of shale oil/gas production because of less drilling workload. Second, they reduced expenditure and improved operation efficiency. Some oil companies reduced the quantity of staff and rigs, and allocated the remaining staff and rigs to high-quality projects, so drilling time-efficiency was greatly enhanced.

According to the statistics [17], the drilling time in the Eagle Ford and Permian Basin shale gas plays was shortened by 5–10% and 20% respectively. The rigs in the Heynesville shale gas play in 2015 was less than the oddments in 2011, and the production declined by 40%, but the shale gas production efficiency in 2015 was higher than that in 2011. What’s more, the drilling time-efficiency in the major shale gas plays, such as Bakken, Marcellus and Eagle Ford, improved greatly in recent years, with the exploitation cost declining year by year [18]. In the Marcellus shale gas play, the rig number dropped from 144 in 2012 to 98 in 2015, but the production was more than doubled.

Third, they effectively reduced the production cost by technical innovation. Under the situation of tumbling oil price, many oil companies devoted to realizing higher production with less wells by virtue of new technologies and new methods. The enhancement of shale oil/gas production per well brought the improvement of economic profit. In terms of drilling operation, a platform well-plant mode was adopted with the support of intelligent rigs with a dual fuel translation system, which greatly shortened the drilling period and reduced the drilling cost. In terms of stimulation treatment, the technologies of horizontal well “zipper” fracturing and re-fracturing were usually adopted; with optimized well track and completion techniques, single-well EUR increased distinctively.

Production practices demonstrate that these measures are effective in the low oil price era and can reduce the break-even price year by year for a majority of shale oil/gas plays in the USA [18]. For example, the single well cost in the Heynesville shale gas play ranks the highest (almost USD10 million [12]) in the large shale gas plays in the USA, but the operation cost reduced by about 25% through technical innovation. The statistics show that the gas price at the break-even point in the Heynesville shale gas play generally declined by USD0.3–0.4/1000 ft3 (1 ft3 = 0.0283168 m3, the same below) from 2014 to 2015, or even by USD0.5/1000 ft3 in some plays.

4)   According to the 2016 outlook of EIA [3], the rising tendency of shale gas production in the USA will continue to 2040. Shale gas production growth in the USA at present and in the future is mainly contributed by two shale gas zones in the eastern Appalachian Basin, i.e. Marcellus and Utica, which produced shale gas of about 1650 × 108 m3 in 2015, accounting for 43% of the total shale gas production in the USA, and will exceed 50% in 2040, when daily production reaches 11.32 × 108 m3.

5)   When it comes to the future of shale gas, some independent agencies in the USA hold the opinions quite different from the prediction of EIA. A research team consisting of 12 geologists, reservoir engineers and economists from the University of Texas at Austin conducted a systematic research on four shale gas plays (Marcellus, Heynesville, Fayetteville and Barnett) for three years.

The team adopted a production prediction method with a precision at least twenty times that of EIA prediction, and concluded that the gross shale gas production of these four plays will reach a peak in 2020 and then decline rapidly, and only half of the EIA predicted production in 2030 [19]. This is apparently pessimistic in comparison with the predictions of EIA and Goldman Sachs etc. The Post-Carbon Institute also analyzed the production decline in five shale gas plays including Marcellus and concluded that the prediction of EIA is over optimistic [16] and that the prediction of the Institute on shale gas production in the USA from 2014 to 2040 is 46% lower than that of EIA.

Although there are shale gas resource discoveries in some host countries, commercialization is still a long way to go

In the early 21st century, the commercial triumph of shale gas exploitation in the North America rapidly spread to other countries with rich shale gas resources, such as Poland with special geo-politic meaning in Europe, Mexico and Argentina in Americas, South Africa in Africa, China and India in Asia, and Australia etc. [11] except a few countries like China and Argentina where commercial development of shale gas has been initiated, other countries are just slow and even stagnant in the development of shale gas, although they have obtained discoveries in shale gas exploration [20].

According to shale gas drilling and evaluation, the predicted shale gas resources are very rich in some countries, but their shale gas resource endowment is far less than USA. In addition to complex geological conditions, these countries lack shale gas exploitation technologies and experiences, well-trained and qualified professionals, drilling/fracturing facilities and surface facilities. Furthermore, there are no competitive service markets.

As a result, shale gas development effect is not up to the expectations and the drilling cost is too high. In such countries as Mexico and Australia, the commercial development of shale gas has not been initiated even after shale gas discoveries are made. Because the anxiety about the wastewater treatment and environmental impact as well as earthquake induced by fracturing cannot be eliminated, some European countries, such as France and Sweden, don’t support shale gas development or limit the application of shale gas fracturing with laws and regulations.

As is known, the predication of shale gas resources or production is controlled by prediction methods, precision and assumptions etc. As mentioned above, the global shale gas resources published by EIA from 2011 to 2013 are doubted to some extent [9], [16], [19]. Some countries that were deemed with rich shale gas resources in the evaluation of EIA sharply lowered their expectations of shale gas exploration after preliminary drilling and evaluation. Poland is one of the most active countries developing shale gas in the world, and it launched five shale gas projects including the Baltic Basin early in 2010, attracting the participation of many IOCs. After the IOCs, such as Chevron and Exxon Mobile, drilled many exploratory wells, the testing productivity was low and could not reach the industrial standard, hence shale gas development in Poland was suspended. Considering the shale gas development effect lower than the expectation and the lower limit of TOC > 2%, EIA reduced the technically recoverable shale gas resources in the Lubin Basin of Poland from 1.25 × 1012 m3 in 2011 to 0.25 × 1012 m3 in 2013 [11] (Fig. 3).

Fig. 3. Shale gas resource evaluation by EIA from 2011 to 2013. Note: Data in the histogram are sourced from Ref. [11].

Fig. 3. Shale gas resource evaluation by EIA from 2011 to 2013. Note: Data in the histogram are sourced from Ref. [11].

Shale gas resources in Poland predicted by Polish Geological Institute were not up to 1/10 of EIA’s prediction in 2011 [19]. According to the prediction of EIA in 2011, the technically recoverable resources of Alum shale gas in Norway were 2.35 × 1012 m3. Shell drilled three exploration wells in the Alum shale with better geologic conditions in Sweden, but failed to get any gas. It is thus inferred that the commercial success upon the complicated Alum shale gas in Norway is not as good as the previous prediction, and in the global shale gas resource evaluation report published by EIA in 2013, the technically recoverable shale gas resources in Norway were cut down to none (Fig. 3).

Therefore, the results of shale gas resource evaluation conducted in the play evaluation and selection period will be ultimately verified by drilling and dynamically adjusted or revised with the E&D progress to suit the E&D practice. Overestimate on shale gas resources will possibly bring about an over-high expectation on the shale gas future. Thus the exploration commitment and investment as well as the E&D index will be increased, resulting in a giant waste of human resources and materials. The evaluation result of shale gas resources in Poland by EIA is a typical example, and there is the same problem in China (to be elaborated later).

Basic situation and problems of domestic shale gas development

Remarkable shale gas progress in the “12th five-year plan” period and a long-way-to-go future development

Shale gas exploitation in China started from the Lower Paleozoic marine shale in the Sichuan Basin in 2009, and rapidly spread to marine, continental and marine–continental resources in South China and even the whole country in the “12th Five-Year Plan” period. Especially, under the guidance of many shale gas policies issued by the government, an upsurge of shale gas exploitation emerged with the guidance of governments at all levels, participation of multiple investors, and engagement of non-oil enterprises like power and coal enterprises, thereby a rapid development of shale gas industry in China has been promoted.

In the 44 shale gas exploration license blocks (including 21 bidding blocks) covering an area of 14.4 × 104 km2, triggered by the exploration evaluation in the “12th Five-Year Plan” period, breakthroughs have been made in terms of marine shale geologic evaluation method, drilling/completion and fracturing technology, and shale gas reserves and production management [1]. Some departments and scholars have summarized the major achievements in China [1], [5], [6], [21], which will not be repeated herein. The authors proposed the following remarkable characteristics from different aspects.

Multiple policies, quick implementation and great investment

Since shale gas was listed as an independent mineral category at the end of 2011, relevant authorities have issued some policies successively, such as Shale Gas Development Program, Shale Gas Development and Utilization Subsidy Policy, and Shale Gas Industry Policy, in order to encourage and speed up domestic shale gas development. Some local governments owning shale gas resources also have issued documents related to shale gas exploitation and industry development in the “12th Five-Year Plan” period and the “13th Five-Year Plan” period, where shale gas is regarded as an important industry to promote the local economic development and boost GDP growth, and they set up shale gas development companies.

In addition to CNPC, Sinopec, CNOOC, and Yanchang Oil, more than 10 investors including some private enterprises are attracted in shale gas exploitation through two rounds of shale gas license bidding. Compared with other countries and conventional oil/gas or coalbed methane (CBM), the Chinese government provides a really grand support to the shale gas industry. The main possible factors controlling shale gas development in the future are not related to policy or mechanism.

Up to the end of 2015, the national cumulative investment was RMB36.5 billion, including RMB1 billion from central and local finances as well as RMB2 billion from the bid-winning enterprises, and the remaining is all from oil companies. However, in terms of the input–output, all investments were not recovered with shale gas production, expect for the oil companies’ RMB33 billion which corresponded to a cumulative shale gas of 60 × 108 m3[21]. Under the current technical and market conditions, domestic shale gas exploitation is featured by large input, high risk, long return period, slow effect and low profit; some local governments or non-oil companies regard shale gas as an important industry to gain commercial profit, which isn’t a smart choice.

Rapid production of marine shale gas within the basin, and successful “testing ignition” outside the basin

During the “12th Five-Year Plan” period, petroleum and petrochemical enterprises closely followed the progress of shale gas exploitation technology in the USA, and actively developed unconventional oil/gas business. They quickly initiated and increased the investment in the Paleozoic marine shale gas exploration and development in the Sichuan Basin, and finished the construction of three national marine shale gas demonstration areas (Changning–Weiyuan, Fuling and Zhaotong) with an annual productivity of 75 × 108 m3.

The great growth of shale gas reserves and production brought about the exploration and development technologies for marine shale gas below 3500 m and the profitable exploitation of marine shale gas. Nevertheless, in some deeply buried shale gas strata (below 3500 m) inside or around the Sichuan Basin or in the complicated tectonic areas, exploitation faces dual challenges of both technology and economy.

According to the national shale gas resource investigation results [22], the central finance, local governments and bid-winning enterprises have invested more than RMB 3 billion in shale gas exploration and development in South China with rich resources, in addition to the Sichuan Basin, including over 50 exploration wells. Unfortunately, there is no commercial discovery made, except for the lately reported Well Anye 1 [23] in northern Guizhou and a few exploration wells which delivered a little shale gas flow (not up to the standard of industrial gas well).

Over 3–4 years, the efforts in many shale gas blocks remained to demonstrate “whether there is hot shale or not” and “whether the shale contains gas or not”, but no recoverable shale gas resources under the current technical and economic conditions were confirmed and no block of shale gas with commercial value was found. Facing the huge financial pressure and investment risk as well as “crop failure”, many shale gas enterprises were impaled in a dilemma and difficult to take a step.

No substantial breakthrough in the exploration of continental and marine–continental shale gas

When marine shale gas in South China advances intensively, the Geological Survey of China (GSC) and some prospecting and oil companies actively conduct shale gas exploitation in favorable zones of continental and marine–continental facies with a great potential, which lives up to great expectations. In recent years, the drilling results in the Carboniferous–Permian and Triassic–Jurassic coal beds as well as lacustrine sand-mudstone in the southern North China, the Ordos Basin and the Sichuan Basin show that except some exploration wells with low-yield shale gas flow after fracturing, a great majority of wells only reveal “good gas shows in testing”, “high desorption gas or gas content” and “successful flaming or ignition” [21], with no substantial breakthrough.

The Jurassic and Upper Triassic formations are key targets for continental shale gas exploitation in China. The Jurassic is dominant among all the formations with recoverable shale gas resources up to 5.54 × 1012 m3[22], mainly in the northwestern China and the Sichuan Basin. In the Yan’an National Continental Shale Gas Demonstration Area, for example, there are tens of wells, but only half of them have obtained gas after fracturing; horizontal well production is generally only (0.4–0.8) × 104 m3/d in testing, and the wells can’t be put into formal development due to unstable production and quick decline; at present, only one gas well is producing for power generation [6], [21].

This can be proved by the fact that this area is classified as an “evaluation breakthrough region” rather than a “key productivity building region” in the “13th Five-Year Plan” [1]. Well Chaiye 1, one of the important shale gas discoveries in 2014, is the first well drilled to develop continental shale gas in Jurassic in the Qaidam Basin [21], and it reveals three sets of shale interval with high gas content and cumulative thickness of 141 m, of which the site desorption gas content is up to 2–5 m3/t, the highest shale gas content is about 9m3/t, and the core desorption gas is successfully “ignited”.

According to the data of GSC, sand fracturing was carried out in two sets of gas-bearing shale with a total thickness of 60 m and the highest gas content, but there was no gas flow during the flowback. Some discoveries even found some wells (mostly unstimulated vertical wells) widely reported domestically with high yield of shale gas in continental or marine–continental formations, which should be assigned to tight carbonate gas or tight sandstone gas, are collectively incorporated into the achievements of shale gas, since sandstone (or carbonate rock) and shale are interbedded or superimposed in continental or marine–continental formations [9].

Although there were attempts on the shale gas exploitation in the Upper Triassic Xujiahe Fm and Lower Jurassic Ziliujing Fm in the Sichuan Basin during the “12th Five-Year Plan” period, and even the Jurassic continental shale gas exploitation in the Fuling block was earlier than that of the Longmaxi marine shale gas, no breakthrough has been made or no scale productivity has been built due to shale gas resource endowment, horizontal well fracturing, and production testing performance in continental formations.

Shale gas exploitation in the complex tectonic areas in South China

During the “12th Five-Year Plan” period, 17 coal-fired power-dominated winners in the first and second rounds of bidding for shale gas licenses conducted shale gas exploration in 21 blocks covering an area of 2.4 × 104 km2. Particularly, 19 of these blocks were marine shale gas blocks in the complex tectonic areas in South China, outside the Sichuan Basin. Under the “13th Five-Year Plan”, key substituting blocks for future shale gas exploitation are concentrated in marine shale gas blocks in the complex tectonic areas in South China, with the target being unexceptionally the Wufeng–Longmaxi [1].

All these blocks are beyond their three-year exploration period, but no enterprise has completed (and actually cannot complete) its original exploration obligations, and two winners in the first round were even penalized economically. Practices show that these shale gas blocks are basically featured by presence of shale without gas, or no gas flow, or no commercial flowrate, and investment without return, making the enterprises impaled in the dilemma. In order to better arrange the work during the “13th Five-Year Plan” period and thereafter, it is necessary to review the exploitation operations over the past years and figure out the problems.

“Rich shale” meaning no “rich shale gas”

One of the achievements in drilling geological information wells, reference wells and exploration wells in the shale gas blocks in South China lies in the wide distribution of black hot shale in the Wufeng–Longmaxi and Lower Cambrian Niutitang formations. In fact, such distribution was previously confirmed in field geological surveys and hydrocarbon prospecting, and a lot of research results in relation to black graptolite shale and source rocks were accumulated [24], [25].

According to the drilling results in the “12th Five-Year Plan” period, the black hot shale (TOC ≥ 2%) in the Wufeng–Longmaxi and Lower Cambrian Niutitang formations in the complicated tectonic areas in South China is characterized by great thickness, high organic abundance, high evolution degree, and good reservoir physical properties, brittleness and gas-bearing potential. Therefore, these areas have good shale gas exploitation conditions and prospects [26], [27], [28].

Undoubtedly, some blocks are even comparable to the producing shale gas demonstration zones in the Sichuan Basin (e.g. Jiaoshiba in Fuling, Changning and Weiyuan) in terms of static geologic indexes, especially the high-quality Niutitang/Shuijingtuo shale which has remarkable thickness and organic abundance (Table 1). However, rich shale doesn’t mean rich shale gas. Numerous drilling results in the Youyang, Xiushan, Baojing, Fenggang and Zheng’an blocks show that the gas in the Niutitang hot shale is not methane but nitrogen. In the drilled blocks, the nitrogen content of almost 70% of Lower Cambrian black shale is more than 90%. Because of the complicated tectonic conditions in South China, gas presence in black shale is complicated.

For example, Well Tianxing 1 in the Cengong block revealed a low-yield gas flow (with methane content ranging from 76% to 81%) through liquid nitrogen drainage and swabbing after vertical well fracturing in the Niutitang formation, while Well Tianma 1 about several kilometers away demonstrated a dominance of nitrogen (more than 95%) in the Niutitang formation. Furthermore, in some wells in Zhantong and Changning blocks, the Niutitang black shale has a low gas content (<0.5 m3/t) although it has a large thickness (40–50 m) and high organic content (TOC > 3% on average); the gas is mainly nitrogen, and no gas flows out after fracturing.

Table 1. Characteristics of hot shale in marine shale gas blocks in South China.a
aThis table is compiled with references [26], [27], [28], [29] and other data. bQuartz + feldspar content. cChangning/Weiyuan.

Table 1. Characteristics of hot shale in marine shale gas blocks in South China.a

General existence of gas in shale but with limited recoverable resources

According to the petroleum geologic theory, shale gas is the residual in-place gas after natural gas generated in source rocks under temperature and pressure conditions is expulsed and migrated (Fig. 4). Therefore, conventional oil/gas is also called “outside-source oil/gas”, and shale oil/gas is called “inside-source oil/gas”. Once source rocks reach a certain maturity, some residual gas always exists, no matter what the expulsion and transport conditions are.

Fig. 4. Pattern of hydrocarbon generation, expulsion and evolution and formation of shale oil/gas (according to the technical communication with Conoco Phillips, 2013).

Accordingly, during the drilling operations of all shale gas wells, both inside and outside the basin, there are always oil/gas shows in the high GR black shale intervals, such as anomaly in gas logging, increased gas content and even well kicking, and other common phenomena such as gas flow-out when cores are taken out, bubbling in the water and ignition of gas desorbed on site. However, these ubiquitous “shale gas shows” are widely reported as great discovery or breakthrough that can prove the “presence of shale gas”. Theoretically, the “presence of shale gas” is not necessarily proved by wells consistently, but can be confirmed with basic oil/gas geology. The “presence of shale gas” should not be deemed as an indicator for success of shale gas exploration.

The practices of marine shale gas exploitation in South China have proved that either good shows, or high gas content, or “successful ignition” doesn’t mean industrial gas flow after fracturing. By far, many enterprises have carried out hydraulic fracturing tests in the target intervals with high shale gas parameters and good gas presence (Table 2), but haven’t obtained industrial shale gas flow from either vertical wells or horizontal wells. The drilling of Well Wuxi 2 in the Dabashan arc fold thrust zone shows that hot black shale with TOC > 2% is nearly 90 m thick, including 51 m shale with TOC > 3%, and 59 m shale with gas content > 2 m3/t, and the highest gas content exceeds 8 m3/t [30].

Moreover, water boiling is observed after the core is soaked in water, and the gas-bearing potential is even better than that in the developed blocks (Table 1). However, the exploration wells deployed near Well Wuxi 2 by oil companies in recent years suffered geological complexities during drilling and failed to obtain any commercial discovery after horizontal well fracturing. In Well Qianye 1 drilled earlier near the Qianjiang block, “successful ignition” after fracturing was realized, but many wells drilled in this block and the adjacent Youyang block showed “outcrop failure”.

Emanuel Martin
Emanuel Martin is a Petroleum Engineer graduate from the Faculty of Engineering and a musician educate in the Arts Faculty at National University of Cuyo. In an independent way he’s researching about shale gas & tight oil and building this website to spread the scientist knowledge of the shale industry.

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