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RESEARCH PAPER
PETROLEUM EXPLORATION AND DEVELOPMENT
Volume 47, Issue 4, August 2020
Online English edition of the Chinese language journal
Cite this article as: PETROL. EXPLOR. DEVELOP., 2020, 47(4): 791–802.
Received date: 17 Feb. 2020; Revised date: 26 Jun. 2020.
* Corresponding author. E-mail: luok@petrochina.com.cn
Foundation item: Supported by the Key Intergovernmental Special Project on International Science and Technology Innovation Cooperation (2016YFE0102400).
https://doi.org/10.1016/S1876-3804(20)60094-5
Copyright © 2020, Research Institute of Petroleum Exploration & Development, PetroChina. Publishing Services provided by Elsevier B.V. on behalf of KeAi Com-
munications Co., Ltd. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/).
Key technologies, engineering management and important
suggestions of shale oil/gas development: Case study of a
Duvernay shale project in Western Canada Sedimentary
Basin
LI Guoxin1, LUO Kai2,*, SHI Deqin3
1. PetroChina Exploration & Production Company, Beijing 100007, China;
2. CNPC S & T Department, Beijing 100007, China;
3. CNPC Oilfield Service Company Limited, Beijing 100007, China
Abstract: The Duvernay project in Canada was taken as an example to summarize the advanced technology and engineering manage-
ment model of shale oil and gas development in North America. Preliminary suggestions were put forward to accelerate the commercial
development of domestic continental shale oil and gas. The advanced technologies, valuable knowledge and rich experience were intro-
duced, including the evaluation of geological target area of the project, rapid long horizontal drilling and completion, high-intensity frac-
turing, and well spacing optimization. In particular, the concept and connotation of the full-life cycle management of North American
unconventional resource projects were analyzed. Its emphasis on early evaluation and risk management, and a highly competitive market
environment have played an important role in promoting technological innovation and management innovation. In addition, the low-cost
sharing system of industry-wide knowledge and experience and the management mode were applied. These management approaches are
of great significance for reference in accelerating the exploration and development of unconventional resources in China. China possesses
abundant shale oil and gas resources, which are an important replacement to guarantee the national oil and gas energy supply. However,
due to the late start and special geological characteristics and engineering difficulties in China, there is a large gap in technology level and
management mode compared with North America. According to the advanced experience and enlightenment of the shale oil and gas de-
velopment in North America, a preliminary proposal to accelerate the development of shale oil and gas in China was made.
Key words: shale oil and gas; long horizontal well; high-intensity hydraulic fracturing; full-life cycle management; large scale exploitation
Introduction
According to the forecast of the international energy agency,
the global demand on oil and gas will continue increasing
until the middle of the 21st century[12]. In recent years, the
shale gas revolution, firstly, has made the United States be-
come a net oil and gas exporter in 2020[2]; secondly, is con-
tinuously strengthening the influence of the United States on
the global oil and gas market, which has changed the global
gas supply pattern; and thirdly, will has a profound impact on
global energy development and geopolitics. In the past 20
years, oil and gas demand has grown rapidly in China, and the
dependence on oil and gas import has been rising. In 2019,
China’s dependence on the import of crude oil and natural gas
has reached 72.5% and 45.2%, respectively[3]. The future de-
mand will continue growing. China's oil and gas exploration
and development has gone through more than half a century,
and some of the major oil and gas bearing basins have entered
the mid-to-late stage of conventional oil and gas exploration
and development. Therefore, unconventional oil and gas have
become the main force for increasing reserves and production.
However, new discoveries are significantly degraded, and this
trend is increasing year by year. In order to ensure the safety
of China's oil and gas supply, it is necessary to increase efforts
to domestic exploration and development, especially to accel-
erate the development of unconventional resources. China is
rich in shale oil and gas resources. In recent years, it has made
major breakthroughs in some basins, such as the Junggar Ba-
sin, the Bohai Bay Basin, the Ordos Basin, and the Sichuan
Basin. After preliminary exploration and development, im-
LI Guoxin et al. / Petroleum Exploration and Development, 2020, 47(4): 791–802
792
portant understandings have been achieved on the shale oil
and gas characteristics in these major basins[45]. However, to
realize a shale oil and gas revolution, major innovations in
theory, technology and management are needed urgently[4].
Shale oil and gas development in North America has achieved
a great success and a wealth of theoretical knowledge and key
technologies have been accumulated, as well as excellent
management concepts and advanced management models.
The experience is of great guiding significance to promote a
shale oil and gas revolution in China and accelerate the effi-
cient development and utilization of resources. By referring to
previous studies[620], this paper takes the Duvernay project in
Canada as a case to systematically summarize the advanced
technologies and engineering management models of shale oil
and gas development in North America, and puts forward
preliminary suggestions to accelerate the commercial devel-
opment of continental shale oil and gas resources in China
according to their features and progresses made in exploration
and development.
1. Introduction to the Duvernay project
The Duvernay project is located in the West Canadian
Sediment Basin (briefly called WCSB). The basin has rich
unconventional oil and gas resources (Fig. 1). It is a typical
foreland basin with an area of 140104 km2. Located between
the Canadian Shield and the Rocky Mountains, it goes
through Northwest Canada, British Columbia, Alberta, Sas-
katchewan and Manitoba, and then extends southward to
Montana, North Dakota, and South Dakota in the United
States. From the western edge of the Canadian shield to the
front of the Rocky Mountains, the WCSB looks like a wedge
structure thinning northeast. The Mesoproterozoic-Cenozoic
formations in the northeast near the Canadian shield have
been completely eroded, and the thickness of the formations
Fig. 1. Location of the Duvernay project.
on one side of the Cordillera mountain is up to 20 km. Cam-
brian clastic rocks are developed in the lower part of the
wedge body, but only in the Rocky Mountains. Ordovi-
cian-Lower Carboniferous carbonate rocks are developed in
the middle. Upper Triassic-Tertiary formations are developed
too. Bordered by the Ththlina High in the north and the Sweet
Grass Arch in the south, the WCSB is divided into three sec-
ondary basins, namely Mackenzie, Alberta and Williston, re-
spectively. The Duvernay project is located in the deep part of
the Alberta Basin.
In December 2012, PetroChina entered the Duvernay pro-
ject. As of the end of 2018, the Duvernay project covered
1555 km2 on four blocks (Simonette, Pinto, Edson and
Willesden Green) according to their geographic locations, and
the total resources were about 1829106 m3 and oil equivalent
was 11.5109 BOE (Fig. 2). Among the four blocks, Simon-
ette is the main development target with a "sweet spot" area of
about 400 km2, natural gas resources of 440.9109 m
3 and
condensate oil of 397106 t. As one of the primary source
rocks in the WCSB, shale in the Devonian Duvernay Forma-
tion is the main formation developed by the Duvernay project.
It is a kind of dark asphalt-rich shale developed during the
maximum transgression period. In the Simonette block, the
shale is buried from 3000 m to 4200 m, and contains effective
reservoirs from 30 m to 45 m (39 m on average) thick. The
effective porosity ranges from 3% to 6%, the permeability
ranges from 0.0001×103 μm2 to 0.0003×103 μm2, the TOC is
2% to 6% (3.5% on average), the Ro is 0.6% to 2.9% (1.2% on
average), the adsorbed gas content ranges from 0.5 m3/t to 2.5
m3/t, and the condensate content ranges from 252 g/m3 to
2028 g/m3.
When PetroChina entered into the Duvernay project in De-
cember 2012, the annual oil and gas equivalent was only
17.7×103 t. As of 2018, the annual natural gas production of
the project had increased from 13×106 m3 to 1440×106 m3, the
annual condensate production had increased from 7.5×103 t to
Fig. 2. Blocks distribution of the Duvernay project.
LI Guoxin et al. / Petroleum Exploration and Development, 2020, 47(4): 791–802
793
730×103 t, and the annual oil and gas equivalent production
had reached 1.88×106 t. The production had increased signifi-
cantly. This is firstly attributed to the close cooperation be-
tween PetroChina and Encana in capacity evaluation and
production construction, constant research and regular sys-
tematic exchanges. In the capacity evaluation stage of the
project (2012–2014), the concept of multi-round evaluation
was adopted to optimize the "sweet spot intervals". In the
stage of large-scale production construction (2015–2018),
after continuous verification and adjustment, progressive de-
velopment was realized. Secondly, thanks to the service com-
panies with advanced technologies selected by the joint ven-
ture. More than 14 international and local drilling providers
and more than 12 international and local completion providers
participated in the project. Continuous optimization of tech-
nologies brought "higher efficiency with a fewer wells".
2. Key technologies
2.1. Geological valuation for selecting blocks
Geological evaluation for selecting blocks for the Duvernay
project is a process of continuous recognition, verification,
re-recognition, re-verification, deepening, optimization and
adjustment. In the early days, capacity evaluation was being
carried out in several blocks to improve evaluation and selec-
tion of "sweet spot intervals". Since starting large-scale pro-
duction, the principle that’s to effectively use reserves with
minimum efforts was followed to achieve “higher efficiency
with a fewer wells".
From 2012 to 2014, the Duvernay project adopted the con-
cept of multi-round evaluation, and three rounds of capacity
evaluation were carried out. Based on 3D seismic data, four
blocks (Simonette, Willesden Green, Pinto and Edson) were
evaluated through drilling wells.
The first round was before the end of 2012. The project had
put into operation with four staged fractured horizontal wells,
and the yearly oil and gas equivalent production was 17.7×103
t. Among the four horizontal wells, three wells were drilled
into the Duvernay Formation in the Willesden Green block
and one well into the Duvernay Formation in the Simonette
block. But the production effect of the Willesden Green block
is worse than that of the Simonette block. In addition, a verti-
cal well was drilled in the Pinto block, but it was confirmed to
be dry gas and not put into production. At this stage, a tech-
nology for predicting the condensate content based on the
hydrogen index was developed -- according to the geochemi-
cal data from cores or cuttings, it was found that the hydrogen
index and the condensate content had a good correlation, and
the hydrogen index can be determined by the ratios of δ13C2,
δ13C3, to Butane isomers. Using the technology, the distribu-
tion of condensate oil can be predicted preliminarily.
The second round was run in 2013. Since the Pinto block
has been confirmed to be with dry gas, it was proposed not to
develop at that time. Meanwhile, the evaluation on the
Willesden Green block was strengthened. In 2013, the project
put 17 new wells into operation, including 9 in the Willesden
Green block and 8 in the Simonette block, with yearly oil and
gas equivalent production of 126.6×103 t. In the Willesden
Green block, the average peak gas production per well was
53.8×103 m3/d (1.9 MMscf/d), the peak production of con-
densate oil was 43.0 m3/d (270.6 bbl/d), and the EUR of natu-
ral gas was 33.9804×106 m3 (1.2 bcf) and the EUR of conden-
sate oil was 15264.0 m3 (96 Mbbl). In the Simonette block,
the average peak gas production per well was 82.1×103 m3/d
(2.9 MMscf/d), the peak production of condensate oil was
119.9 m3/d (754 bbl/d), the EUR of natural gas was
50.9706×106 m3 (1.8 bcf), the EUR of condensate oil was
51.404.7×103 m3 (323.3 Mbbl). It was further confirmed that
the single-well production effect of the Willesden Green block
was far worse than that of the Simonette block, which had not
met expectations.
The third round was in 2014. The project put 19 new wells
into operation, with yearly oil and gas equivalent production
of 391.8×103 t. Among the 19 new wells, 16 were in the Si-
monette block. In view of the unsatisfactory drilling results in
the Willesden Green block, 3 wells were fractured, but the
post-fracturing production still did not meet expectations. At
the same time, a horizontal well was drilled in the Edson
block, which proved that the Edson block had dry gas. There-
fore, it was proposed temporarily not to develop and suspend
the development of the Willesden Green block. At that stage,
dynamic production data were collected from staged fractured
horizontal wells and geochemical data from cuttings taken in
different positions of the horizontal sections (1 horizontal well
can quantitatively characterize the condensate content at mul-
tiple different positions on the horizontal section), to enrich
the understanding of the plane distribution of condensate and
to improve the prediction accuracy. On this basis, the zone
with condensate content of 540 to 1125 g/m3 was classified
into the ultra or locally high condensate zone. It laid a founda-
tion for large-scale development.
Starting in 2015, the project entered into the stage of
large-scale production construction. And the following strate-
gies were formed: from 2015 to 2016, the Duvernay Forma-
tion of the Simonette block would be developed as the pri-
mary target, namely, first the ultra or locally high condensate
oil zones, then the volatile oil zones in order, but slowing
down the development of condensate oil zones. Another 96
wells were put into production, and all of them were located
in the Duvernay Formation of the Simonette block. By the end
of 2016, the production capacity reached 1.7936×106 t. In
2017, based on the key development of the Duvernay Forma-
tion in the Simonette block, the potential of the shallow Nor-
degg Formation and Montney Formation was evaluated. 27
wells were put into production, with a production capacity of
more than 2.00×106 t. Among them, in the Montney Formation,
the peak gas production was 180×103 m3/d and the condensate
production was 40 t/d, and in the Nordegg Formation, the
peak gas production was 40×103 m3/d and the condensate
LI Guoxin et al. / Petroleum Exploration and Development, 2020, 47(4): 791–802
794
production was 50 t/d. The test results of the evaluation wells
were good, which revealed that the shallow Montney Forma-
tion and the Nordegg Formation possessed a certain develop-
ment potential. They were expected to become the capacity
replacement of the Duvernay Formation. By the end of 2018,
a total of 180 horizontal wells had been drilled and 172 had
been put into production. The yearly oil and gas equivalent
production in 2018 was 1.88×106 t.
2.2. Fast drilling technologies for ultra-long horizontal
wells
The important experience and understanding of the Duver-
nay project are that long horizontal section is the core to im-
prove well-controlled reserves and EUR. Through a series of
measures such as slimming the wellbore, optimizing the drill
bit, optimizing the drilling fluid, and strengthening drilling
parameters, the horizontal section should be extended as long
as possible to ensure more well-controlled reserves and higher
EUR. At the same time, extending the length of the horizontal
section as much as possible through the integration of geology
and engineering laid the foundation for benefit development.
From 2012 to 2018, the length of the horizontal section in-
creased from 1300 m to more than 3000 m (Fig. 3), which was
more than doubled in 6 years; the well depth increased from
5000 m to over 7000 m (Fig. 3); and the average completion
depth increased by 40%. The well-controlled available re-
serves of equivalent oil were up to 215×103 t, and the
well-controlled reserves increased by 2 to 3 times compared
with the initial period. According to the progress in the drill-
ing technology, the following points are worth learning.
(1) Optimized well structure. The well is a three-casing
structure. For the first casing string, the size of the borehole is
349.3 mm ( 34
13 ), and the surface casing was reduced from
273.1 mm ( 34
10 ) to 244.5 mm ( 58
9 ), which is economi-
cal, safe and practical. For the second casing string, the bore-
hole size was reduced from 250.8 mm ( 78
9 ) to 222.3 mm
(34
8 ). The 193.7 mm ( 58
7 ) technical casing greatly in-
creased the drilling speed. According to the statistics, the
drilling cycle for the second spud-in was shortened by 6.7
days on average. For the third spud-in, the borehole size of the
horizontal section increased from 155.6 mm ( 18
6 ) to 171.5
Fig. 3. Statistics of drilling depth and horizontal section length
of the Duvernay project over years.
mm ( 34
6
), and the production casing was optimized from
114.3 mm ( 12
4
) (casing/tailpipe) to 139.7 mm ( 12
5
)
+114.3 mm ( 12
4
) (composite casing). The wellbore expan-
sion of the horizontal section and the application of the com-
posite string were more conducive to the safe running of the
production casing along the long horizontal section. In addi-
tion, the thickness of the cement ring was increased from 21
mm to 28 mm, which reduced the risk of casing change while
improving cementing quality.
(2) Advanced rigs. The Duvernay project used advanced
drilling equipment and tools, with a high degree of automation.
The rigs are mainly AC-driven, accounting for more than 70%.
The advantage of these rigs is the changeable drilling pa-
rameters, which can meet the requirements of various proc-
esses during the construction. For example, when the columns
of the drilling derrick transiting from 3 to 2, the length of the
drill rod was increased from 9.55 m to 14.30 m, which saved
time of connection and rejection. Time for running drillpipe
decreased from 4.6 min/rod to 2.7 min/rod, and time for run-
ning casing decreased from 5.1 min/piece to 1.9 min/piece,
which greatly shortened the drilling cycle. In addition, all
parts of the AC70 rig are almost skid-mounted, and the mov-
ing and installation time was also reduced from the original 4
days to 2 days, and half the time was saved.
(3) Optimal bits and drilling parameters. The bits used were
all PDC bits. The advantage is that they aim at the surface
gravel interlayers, soft/hard interlayers and strong abrasive
layers. And the blade-shaped wing structure -- inclined blade
wing and spiral distributed teeth ensured one PDC bit to finish
the first spud-in section (the first casing program). During the
second spud-in, only one PDC bit can drill through the less
abrasive layers, and 2 to 3 PDC bits can finish the
high-abrasive layers. Before reaching the kickoff point, the
PDC bit can not only meet the requirements of orientation, but
also maximize the penetration of highly abrasive layers, and
reduce the damage to the drill bit from the dolomite and an-
hydrite layers. Choosing PDC bits for the third spud-in can
meet the requirements of strong steering ability, small drift
tendency and high axial efficiency. And after bit optimization,
it can achieve penetration of 30003500 m with a bit. At the
same time, in terms of parameter optimization, based on the
size of the screw in different spud-ins, the parameters were
optimized by referencing to the maximum screw parameters.
For example, the displacement of the horizontal section was
increased from 0.9 m3/min to 1.2 m3/min, the pump pressure
was increased from 27 MPa to 41 MPa, the weight on bit was
increased from 8 t to 14 t, the rotatory speed was increased
from 50 r/min to 100 r/min, and the drilling speed in the hori-
zontal section was increased from 15 m/h to 49 m/h. The pur-
pose of all the changes is to increase the displacement and
sand carrying capacity, and ensure safe and fast drilling.
(4) Optimized bottom hole assembly. Due to the homoge-
neous lithology and relatively thicker target reservoir, the
Duvernay project is more economical and cost-effective to use
LI Guoxin et al. / Petroleum Exploration and Development, 2020, 47(4): 791–802
795
MWD (Measurement While Drilling) over rotating geosteer-
ing tools. However, due to the longer horizontal section, in
order to ensure smooth borehole and prevent complicated
situation, priority is given to using rotary geosteering tools.
Judging from the actual application of rotating geosteering
tools by PetroChina GreatWall Drilling Company in the Mi-
wan Lake Project in Alberta, Canada, if the ROP (rate of
penetration) increased from 20 m/h to 40 m/h, the drilling
cycle would be shortened by 3.5 d. It seems economically
unsatisfactory, but from a long-term view, the use of rotary
steering tools can generate a smooth and flat borehole, which
is more beneficial for subsequent running casing, cementing
quality and long-term safety of the well.
(5) More stable and suitable drilling fluid. After the second
spud-in, all the drilling fluids used in the Duvernay project
were oil-based. The performance of the drilling fluids was
stable and their inhibition was strong. They could solve the
problems like shale expansion, shrinkage and collapse when
encountering water. Furthermore, they could decrease the
friction in the inclined section and the horizontal section, and
reduce complex accidents such as stuck tools in the horizontal
section. In addition, oil-based drilling fluids are easier to
make and easy to maintain on site, and have good sand-carry-
ing effects. The performance of the oil-based drilling fluid
system can fully meet the requirements for safe drilling of
long open-hole sections, and can be reused to reduce costs.
2.3. Well spacing and well pattern
Optimization of well pattern and spacing is the basis for ef-
ficient development of oil and gas resources. It is for increas-
ing well-controlled reserves, producing resources, recovery
and project economic benefits. In order to develop shale oil
and gas formations with extremely low permeability, the Du-
vernay project conducted a series of pilot tests with different
well spacing. Through continuous optimization of well spac-
ing and well pattern, rich experiences were accumulated, and
facilitated to form the optimization technology of well spacing
and well pattern for staged fractured horizontal wells drilled
in shale reservoirs. The technology not only ensures that a
well can control enough economically recoverable reserves,
but also can avoid the waste of resources caused by inter-well
interference or excessive well spacing caused by manual
fracture communication. The present horizontal well spacing
in North America is 100500 m.
After analyzing the interference from three adjacent wells
with a well spacing of 150 m, it was found that the pressure
fluctuations of side wells would seriously affect the produc-
tion of the intermediate well, indicating that there was inter-
ference among the wells. And it was clear that the well spac-
ing of 150 m is too small. At the same time, the production
data with well spacing of 150, 200, and 400 m, which are
basically equivalent to the previous fracturing process, were
selected for comparative analysis (Fig. 4), and it was found
that the boundary feedback time was greatly delayed with the
Fig. 4. Boundary feedback vs. well spacing.
increase of well spacing, further indicating that interwell in-
terference existed at the 150 m and 200 m well spacing. Tak-
ing well-controlled reserves into account, to enlarge the well
spacing to 300 m was proposed in 20172018, and pilot tests
with well spacing of 300 m were conducted. The test data
showed that the production at 300 m and 400 m well spacing
was similar (Fig. 5). Under current technical conditions, the
300 m well spacing is more reasonable, and the 400 m well
spacing may be too large to control reserves. Compared with
the original 200 m well spacing, the cumulative production
per well at 300 m well spacing could be increased by about
40% in the first year (Fig. 5). The Duvernay project adopted
the plan, and as a result, the number of wells was reduced by
243, realizing efficient development with a fewer wells.
2.4. Dense-perforation hydraulic fracturing technology
In recent years, large-scale dense-perforation volume frac-
turing is a core technology commonly used in North America
to increase production and development efficiency[1314]. This
technology follows the concept of dense-perforation volume
fracturing, shortens stage/cluster spacing, enhances displace-
ment, increases sand/fluid volume, and finally increases
well-controlled stimulated reservoir volume (SRV). By opti-
mizing fracturing materials, using quartz sand instead of ce-
ramsite, etc., fracturing costs could be reduced greatly, and
development benefits could be improved significantly.
The Duvernay project used a process of degradable bridge
plug + cluster perforation fracturing. From 2012 to 2018, the
fracturing stage spacing had been reducing, from 89 m in
2012 to 49 m in 2018 (Fig. 6), namely shortened by 45%,
while the production kept increasing. Comparing with the
adjacent block with the same developing layer and the nearby
other operator’s block (Fig. 7), the fracturing stage spacing of
the Duvernay project is mainly between 50 and 100 m, while
that of the adjacent block with the same developing layer is
mainly between 70 and 150 m, and that of the nearby other
operator’s block is mainly between 100 and 250 m. By com-
paring the cumulative production over the past two years, the
LI Guoxin et al. / Petroleum Exploration and Development, 2020, 47(4): 791–802
796
Fig. 5. Cumulative oil and gas equivalent vs. well spacing.
Fig. 6. Fracturing stages and stage spacing.
Fig. 7. Variation of production with stage spacing.
production from high to low is the Duvernay project, the ad-
jacent block and the nearby other operator’s block in turn,
indicating that narrow fracturing stage spacing mean higher
cumulative production.
While shortening the staging spacing, the Duvernay project
continued to increase the number of fracturing clusters per
stage, from the initial 3–4 clusters to 7 clusters, and the cluster
interval gradually decreased from the initial 15 m to 7 m (Fig.
8). By comparing the output vs. the number of clusters per 50
m (Fig. 9), it was found that the Duvernay project has 4–8
clusters per 50 m, while the adjacent block with the same de-
veloping layer and the nearby other operator’s block have
only 2–6 clusters per 50 m. In terms of the cumulative pro-
duction over the past two years, the cumulative production
from high to low is the Duvernay project, the adjacent block
Fig. 8. Optimization of stage/cluster spacing.
Fig. 9. Production vs. the number of clusters.
with the same developing layer and the nearby other operator’s
block in turn, indicating that more narrow stage spacing and
more clusters can result in higher cumulative production.
Like the current general understanding of the industry in
North America, the Duvernay project is based on the concept
that "sand means oil, and sand volume equals oil volume".
The project used fracturing fluid composed of slick water and
a new high-viscosity polymer. And the sand volume increased
from 1.69 t/m in 2012 to 3.90 t/m in 2018 (Fig. 10), so the
highest proppant concentration in the sand-carrying section
reached 600 kg/m3. In addition, quartz sand with 100 mesh +
40/70 mesh (0.150 mm + 0.380/0.212 mm) was used instead of
ceramsite proppants, which reduced the fracturing cost greatly.
By comparing the production of the Duvernay project, the
adjacent block with the same developing layer, and the nearby
other operator’s block, it’s found that more proppants added is
beneficial to increase the cumulative production (Fig. 11).
Fig. 10. Proppant volume added.
LI Guoxin et al. / Petroleum Exploration and Development, 2020, 47(4): 791–802
797
Fig. 11. Production vs. proppant volume.
In addition, the Duvernay project promoted the concept of
“carrying more proppants into formation with less fluid”. This
reduces fracturing costs and is helpful to environmental pro-
tection. The fluid used for carrying unit sand volume de-
creased from 11.2 m3/t in 2012 to 5.1 m3/t in 2018. The liquid
used for a cluster reduced from 509 m3 to 139 m3. In other
words, it reduced by more than 70% (Fig. 12). The results are
references and should be paid attention to by China, especially
in the area where water resources are relatively scarce such as
in western China. In such areas, it is particularly important to
reduce liquid use, improve water use, and take into account
environmental protection.
2.5. Development effect
After the Duvernay project applied the above technologies,
both the single-well peak production and the EUR increased
by a large margin. Since 2012, with the determination of the
"sweet point", the development scope has changed from two
blocks (Willesden Green and Simonette) to the ultra or locally
high condensate oil zones with "sweet spots" in the Simonette
block. At the same time, with the advancement of drilling and
completion technology, the single-well peak production and
EUR of staged fractured horizontal wells were increasing year
by year (Figs. 13 and 14). The peak natural gas production of
a staged fractured horizontal well increased from 80.8103
m3/d in 2012 to 170.9103 m3/d in 2018, and EUR increased
from 40106 m3 in 2012 to 90106 m3 in 2018. The peak con-
densate oil production of a staged fractured horizontal well
increased from 70.93 t/d in 2012 to
Fig. 12. Fracturing cost and fluid volume per stage.
Fig. 13. Peak production per staged fractured horizontal well.
Fig. 14. Recoverable reserves per staged fractured horizontal
wells.
196.36 t/d in 2018, and EUR increased from 26103 t in 2012
to 69103 t in 2018.
3. Advanced project management
3.1. Full-life cycle management
Full-life cycle management is the most effective organiza-
tional model for the efficient utilization of unconventional
resources. Reasonable risk setting and management are the
core of the entire management system. The decision-making
principles and procedures of unconventional oil and gas pro-
jects in North America implement full-life cycle management,
including six stages, namely initial exploration, evaluation,
optimization, determination, implementation (planning, op-
eration), and execution (evaluation, adjustment). "Integrated"
management was implemented, and realized efficient opera-
tion. Especially for those stages that bear the major risks, in-
cluding exploration, evaluation, optimization, and determina-
tion, the corresponding floating range of investment cost was
set. (1) In the early stage of exploration, due to the lack of
regional geological knowledge and other factors, there are
many uncertainties in project exploration and development, so
greater risks are allowable, and the affordable cost fluctuation
is expected to be 20% to +50%. That is in the exploration
stage, it is acceptable that the budget exceeds 50% of the plan.
(2) The main purpose of the evaluation stage is to obtain the
LI Guoxin et al. / Petroleum Exploration and Development, 2020, 47(4): 791–802
798
static parameters of the target area, fully evaluate any possible
risks, and carry out preliminary design and test for well loca-
tion. In this stage, it is still allowed to withstand greater risks,
and the affordable cost fluctuation is expected to be 20% to
+40%. (3) In the optimization stage, through previous re-
search and evaluation, experience and lessons analysis, it is
necessary to further optimize technical solutions and invest-
ment management and control, and calculate economic bene-
fits. Since static recognition has been basically completed in
this stage, uncertainties should have been reduced. Therefore,
the affordable cost fluctuation is designed to be 15% to
+25%. (4) The determination stage is before the large-scale
development, during which various plans should be estab-
lished, such as pre-feasibility plan, overall development plan,
drilling and completion plan, investment and cost recovery
plan. Before determining the final plan, some errors and risks
are allowable and acceptable. The tolerable cost fluctuation is
set between 10% and +10%. After continuous evaluation,
optimization, and adjustment, all understanding issues should
be resolved before implementing the final plan. (5) During the
implementation stage, the final plan must be strictly imple-
mented. In theory, no error is allowed in this stage. (6) During
the execution stage, wells that have been completed should be
evaluated for geology, safety and economic benefits, etc., and
the results should be referred to by new wells. By optimizing
well locations and engineering parameters and technologies,
engineering efficiency has been improved and operating costs
have been reduced. All stages require scientific demonstration
and continuous improvement to ensure successive, systematic,
untied and synergic results.
3.2. Early integrated evaluation and learning curve
management
Preliminary evaluation and research are the key to the
high-quality development and construction of the project,
which can not only greatly reduce risks, but also lay a solid
foundation for the high-quality construction in the later stages.
Design optimization, design determination and well construc-
tion almost run through the entire project cycle. Design opti-
mization plays a core role in inheriting the past and inspiring
the future. It is a process of deepening understanding, im-
proving technology and reducing risks. High costs and some
non-subversive mistakes are allowable in the early days. The
first several stages last longer, so it is necessary to reasonably
control the project process, and at the same time, a learning
curve should be built to collect experiences, learn lessons, and
iteratively reduce development risks. In addition, because of
rapid production decline and almost without a stable produc-
tion period, the concept of plan preparation, approval system
and engineering construction model, etc. for conventional oil
and gas development may no longer meet the needs of rapid
response and adjustment in exploration and development of
unconventional oil and gas resources.
The importance of early research can be seen more clearly
Fig. 15. Investment costs and value influence in different stages.
from Fig. 15. According to the practice in North America, the
project values and investment costs of different stages are
different. The preliminary research, optimization and deci-
sion-making stages lasted longer, and the total costs were
lower, but their contribution to the final value of the project
was larger. After all project elements are determined, the in-
vestment in large-scale production construction will rise
sharply once it enters the stage of implementation. The con-
tribution to the project’s cash flow by the gradual increase in
production is gradually increasing, which fully shows that
early evaluation before final investment decision has the
greatest impact on the overall value of the project. Therefore,
Canada’s unconventional oil and gas exploration and devel-
opment attaches great importance to preliminary project eval-
uation, and prefers to be “slow” in the early stage and spend
more time to do detailed and practical work. Once the plan is
determined to enter the implementation stage, the de-
velopment plan will be hardly adjusted during the construc-
tion process. This can as a whole ensure the development
quality and production rates, guarantee the final development
effect, and achieve rapid exploration and development.
3.3. Information sharing from big data
North America attaches great importance to information
sharing and platform construction in the process of explora-
tion and development of unconventional oil and gas. The Ca-
nadian energy authority has led the establishment of a special
oil and gas exploration and development information platform
by formulating a complete management system, and has is-
sued data sharing regulations. The regulations stipulate that
any operator should upload all documents, data and informa-
tion involving well drilling, completion, test, and production
to the management platform within a specified time. Opera-
tors can directly review and use the data with a very little
money cost to access the field cases. Through this sharing
method, many small companies can even compile their own
plans by referring to the data, design cases and work plans of
neighboring blocks, so as to avoid repetitive research and save
cost. In other words, service companies including operators,
contractors, well drilling and completions companies, etc.,
have their own research and development capabilities. They
can often use the comprehensive and rich database storing
exploration and development information, and make full use
LI Guoxin et al. / Petroleum Exploration and Development, 2020, 47(4): 791–802
799
of big data and other means. By studying a large number of
practical cases, they can formulate and improve various engi-
neering and development plans for single wells, well groups,
blocks and even oilfields. Especially for designing drilling
and completion plans, process improvement, tool optimization,
etc., repeated trial and error can be avoided, operating costs
can be reduced significantly, and operating efficiency and
engineering quality can be improved greatly.
3.4. Lean management and precise incentives for
market-oriented competition
Shale oil and gas drilling and completion in North America
adopts a market-oriented model and implements a "day rate
system" for fine management. Drilling, cementing and com-
pletion services are clearly defined and separated. Oil com-
pany as Party A is responsible for the construction of well
sites, roads and other infrastructure, as well as the design of
drilling, cementing, and drilling fluids. Oil companies should
sign separate contracts with professional service companies
providing services like drilling, logging, cementing, bits, ori-
entation, and drilling fluid, and send a drilling director as its
representative to be responsible for wellsite construction, and
solely responsible for the production organization and man-
agement of all service companies, and give construction in-
struction to them. Service companies (Party B) are only re-
sponsible for the management of equipment and personnel.
The advanced practices of the market-oriented organiza-
tional model in North America include the following aspects:
(1) Party A and Party B strictly implemented the contract to
ensure seamless connections among all aspects of the project,
and effectively controlled non-production time. (2) Expanded
the market scale of technical services, and fully introduced
competition mechanism. Party A signed contracts with companies
providing the best services by investigating the performance
of the companies, and could terminate the contract with the
non-compliance company. (3) To achieve cost reduction and
profit increase, a perfect system of quota, settlement, evalua-
tion, and incentive was established. The first is reward for drill-
in ratio. Taking 80% as the lowest drill-in ratio, design two
lines (over 10% and 20% respectively) as bases to reward on-
site operators. This measure greatly stimulated the operators.
The second is reward for construction days. The average his-
torical construction days from the drilled wells in the same block
is used as the reward baseline. If the drilling cycle is shortened,
the operator will be rewarded by money or additional drilling
service. The above-mentioned market-oriented advanced con-
cepts and practices forced service companies to strengthen
technological innovation, reduce costs, and improve competi-
tiveness. Finally, a coordinative, risk-sharing and benefit-shar-
ing management model was built to jointly promote cost re-
duction and benefit development of unconventional resources.
4. Enlightenment and suggestions
4.1. Enlightenment from North America
The Duvernay project is a star project in recent years. The
enlightenment from the project is as follows.
(1) A reasonable development strategy is the foundation of
the success of the project. Unconventional resources are spe-
cial, their development methods are significantly different
from conventional resources, and their development strategies
are also completely different[2126]. Especially from the per-
spective of the overall utilization of oil and gas resources, the
starting point of conventional oil and gas reservoir develop-
ment is usually to avoid inter-well interference as much as
possible, while it is just opposite for the development of un-
conventional oil and gas resources -- the latter’s starting point
is to create the largest SRV in tight formations by effective
fracturing stimulation (even ultra-dense fracturing stimulation
in recent years). This is for making inter-well interference,
enhancing inter-well communication and reserves control, and
consequently driving oil and gas that is difficult to freely flow
in nanoscale pores and throats. On the other hand, it is neces-
sary to make full use of well pattern data to avoid serious in-
ter-well interference[2728], to get the highest EUR, and best
development effect and benefit. For example, the Duvernay
project expanded the well spacing by 100 m through field
tests and inter-well interference analysis at different well
spacings. As a result, the single-well cumulative production
increased by 40% in the first year.
(2) Applicable technical evaluation is the guarantee of the
project success. In recent years, dense-perforation fracturing
stimulation has become the most popular technology for the
development of unconventional resources at home and
abroad[67]. The effect of such dense fracturing stimulation
was often evaluated by micro-seismic survey in the early days.
But more monitoring methods indicate that the actual stimu-
lated scope of unconventional oil and gas reservoirs is much
smaller than the SRV monitored by micro seismic data[21]. In
particular, as to whether high-strength fracturing has really
fractured the rock and how effective its stimulation is, they are
not only an important engineering problem, but also an im-
portant scientific issue worthy of in-depth study. ConocoPhil-
lips’ latest field tests and studies have shown that[2123], unlike
the conventional assumption that laterally propagating frac-
tures will be induced at the beginning of fracturing stimula-
tion, in actual formations dense fracture clusters will be in-
duced on different scales and their distribution is extremely
uneven along the horizontal section. However, pressure inter-
ference tests along the horizontal section show that from the
flow point of view, only some large fractures contribute to the
single-well production[21]. Increasing fracture density is to
increase the number of larger fractures, thereby increasing the
flowing scope. When there is greater interference between the
flowing fractures, further increasing fracturing density will
reduce fracturing efficiency (that is, the production contribu-
tion per meter of horizontal section) is reduced[13]. The re-
search and development of new technologies, which is de-
signed to conduct low-cost test and scientific evaluation on
fracturing effect of each section or even each cluster, have
become the current hot spot issues in the field of unconven-
LI Guoxin et al. / Petroleum Exploration and Development, 2020, 47(4): 791–802
800
tional oil and gas research in North America[2931].
(3) The change of concept is the prerequisite for the success
of the project. The highly active marketization system and
competition mechanism in North America have bred highly
innovative unconventional concepts, technologies and man-
agement models, and formed systematic and cutting-edge
equipment, tools, products and core software, etc., which are
available for optimal application. In particular, an engineering
management and decision-making platform based on geo-
logical-engineering integration has been built for low-cost
data sharing throughout the industry, project development
planning and optimization[24], timely monitoring, optimization
and adjustment of drilling and fracturing operation[2930], and
full-chain connection among seismic survey, logging, mathe-
matical modeling and oil production, as well as an under-
ground and aboveground automated monitoring and optimiza-
tion system. It can be said that the basic software platform and
system have supported the efficient management of uncon-
ventional projects in North America. Together with advanced
equipment, tools and products, they have jointly promoted the
continuous reduction of the development cost of unconven-
tional oil and gas resources in North America, and improved
the developing effect. As shown in Fig. 16, the production per
new well in major basins in the United States has continued
increasing in recent years[2], the cost of crude oil production
has dropped significantly, and the cost of barrel oil has long
been below US$50[6]. At present, 80% of new wells drilled but
not completed have a breakeven cost of less than $25. In re-
cent years, emerging technologies such as artificial intelli-
gence, cloud computing, machine learning, and digital twins
are rapidly infiltrating and applying in the field of unconven-
tional resource exploration and development in North Amer-
ica[3233], which will definitely promote the revolution of new
technologies and management models for unconventional oil
and gas exploration and development. In China the integration
of geology and engineering has been advocated for many
years, but the overall progress is not outstanding and the re-
sults are not significant. One of the important causes is the
lack of independent basic platforms, core software and appli-
cation tools, which greatly restricts the effective promotion of
technology and management model on geological and engi-
neering integration. Especially the massive data from geology,
reservoir, seismic survey, drilling, production and downhole
operation, cannot effectively form seamless data flow, smooth
information flow, and high-value knowledge flow, so that it is
difficult to timely solidify and concretize the valuable knowl-
edge, experience and ideas formed in various fields, to inherit
and promote them on a large scale, and even more difficult to
effectively solve the problems encountered in engineering and
project management in real time. As some experts in the in-
dustry believe, what we currently have is "a huge amount of
data ", but not real "big data"[34].
(4) It is an eternal pursuit to improve ultimate recovery.
Significantly increasing recovery is a major challenge faced
Fig. 16. The average daily production per new well in different
basins of the United States.
by oil companies[3537]. In North America, from economic
considerations, the production is basically organized by means
of “quickly recovering investment at the high initial produc-
tion stage, stabilizing production at the low production stage
for a long period or displacing blocks with insufficient capac-
ity at late stages”. At present, field tests such as repeated frac-
turing and gas injection have also been carried out, and a cer-
tain progress has been made. Domestic shale oil and gas de-
velopment has just started. Especially in view of the current
domestic situation of "limited area with mineral rights and
small resource latitude", the concept of "striving to develop
every hydrocarbon molecule underground" must be estab-
lished. Even if the initial production is limited to a certain
amount, efforts must be made to increase the recovery fatcor.
It should be pointed out that for China’s unconventional oil
and gas exploration and development, the mind should be
further expanded, the traditional management model should
be broken[3839], and “unconventional oil and gas, unconven-
tional concept, unconventional technology and unconven-
tional management” should be followed. A full-life cycle
management and technical system should be built for uncon-
ventional oil and gas projects. By this way, China's continen-
tal shale oil and gas revolution will be accelerated. Unconven-
tional resources should be strictly treated as unconventional,
even if the cost is reduced as low as, even lower than that of
conventional resource occasionally.
4.2. Suggestions for speeding up the development of
unconventional resources in China
On the basis of learning from advanced technologies and
management concepts of shale oil and gas development in
North America, especially from the Duvernay project, the
following suggestions are made for actual shale oil and gas
exploration and development in China.
(1) To ensure the national oil and gas energy security, or-
ganize and carry out evaluation on the national shale oil and
gas resource as soon as possible, find out the resource base,
formulate shale oil and gas development strategies and plans
at national/company level, provide fiscal and tax supporting
policies, and create a good external environment for large-
scale development and utilization of shale oil and gas re-
sources.
LI Guoxin et al. / Petroleum Exploration and Development, 2020, 47(4): 791–802
801
(2) Build a full-life cycle management system for uncon-
ventional oil and gas projects as soon as possible. Establish
independent project departments in Junggar, Ordos, Bohai
Bay, Songliao and other basins to carry out full-life cycle
management experiments. Implement independent investment,
independent production measurement, independent economic
evaluation, full-life cycle assessment, and fully integrated
operation. Clarify responsibilities, rights, and interests. Im-
plement the engineering management of "unconventional con-
tinuous integration"[39]. Create model projects. Realize six
integrations of “exploration and development, geology and
engineering, aboveground and underground, research and
production, production and operation, and design and supervi-
sion". Improve the development efficiency of unconventional
projects to the largest extent.
(3) On the basis of introduction, digestion and absorption,
focus on the research of core technologies. Accelerate the
platform construction of integrated geological engineering
system. Optimize unconventional fracturing design. Develop
and test high-end equipment, tools, and products such as nu-
merical simulation software and rotatory steering tools. Focus
on breaking technology bottlenecks such as "sweet spot" pre-
diction of continental shale oil and gas, low-cost fracture con-
trol fracturing for ultra-long horizontal wells, and production
monitoring. Speed up application of new technologies such as
big data, machine learning, and artificial intelligence. Quickly
adapt to the urgent requirements of full-life cycle management,
speed improvement, quality improvement and efficient im-
provement for unconventional oil and gas projects.
(4) Accelerate the deployment of pilot test in typical areas
with different reservoirs, different horizontal section lengths,
different well spacings, different well patterns, and different
development models such as repeated fracturing, sidetracking,
water huff and puff, CO2 huff and puff, and shut-in. Carry out
field tests to improve the recovery factor of unconventional
oil and gas as soon as possible and provide scientific guidance
and lay a solid foundation for rapid development of large-
scale commercial development of unconventional resources,
5. Conclusions
This paper takes the Duvernay project as a case to introduce
new concepts, advanced technologies and experience in the
full-life cycle management of unconventional resource pro-
jects in North America. Shale oil and gas in China is buried in
continental sediments. Shale oil and gas resources are abun-
dant in China, and they are important replacement energy to
ensure the safety of national oil and gas supply. However,
China’s shale oil and gas development is still at the beginning
and testing stage. The practical experience, engineering op-
eration efficiency, operating costs and single-well production
are far from North America. In particular, the high-end
equipment and tools should be accelerated to localization. The
software systems supporting full-life cycle management and
geological engineering integration urgently need to be devel-
oped. In general, China's shale oil and gas exploration and
development depends on own features of resource and envi-
ronmental conditions. On the basis of scientific introduction,
digestion and absorption of advanced technology and man-
agement concepts from North American, China should further
broaden the mind, explore new development models, and
speed up the continental shale oil and gas revolution.
Acknowledgements
The authors extend thanks to Academician Liu He, Petro-
China Research Institute of Exploration & Development;
Professor Wang Hongjun, Professor Xia Chaohui, Professor
Wu Zhiyu, Professor Jiang Tao, Senior Engineer Yu Rongze,
Senior Engineer Wang Ping, Senior Engineer Kong Xiangwen,
Senior Engineer Liang Chong, Senior Engineer Zhao Wen-
guang, and Dr. Su Jian for providing valuable comments and
suggestions in writing of this paper.
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