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Key technologies, engineering management and important suggestions of shale oil/gas development: Case study of a Duvernay shale project in Western Canada Sedimentary Basin


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The Duvernay project in Canada was taken as an example to summarize the advanced technology and engineering management 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 introduced, including the evaluation of geological target area of the project, rapid long horizontal drilling and completion, high-intensity fracturing, 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 development in North America, a preliminary proposal to accelerate the development of shale oil and gas in China was made.
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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:
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Key technologies, engineering management and important
suggestions of shale oil/gas development: Case study of a
Duvernay shale project in Western Canada Sedimentary
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
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
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
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
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
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
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
), and the production casing was optimized from
114.3 mm ( 12
) (casing/tailpipe) to 139.7 mm ( 12
+114.3 mm ( 12
) (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
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 operators 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
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 operators
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
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
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
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
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
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
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-
LI Guoxin et al. / Petroleum Exploration and Development, 2020, 47(4): 791–802
(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.
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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... The resource of Duvernay shale oil and gas is abundant, with natural gas, liquid hydrocarbon, and crude oil resources of 23.22×10 12 m 3 , 115.54×10 8 t, and 250.5×10 8 t, respectively (Lyster et al., 2017). Because of the low matrix permeability of the Duvernay shale reservoir, hydraulic fracturing operations are performed on horizontal wells targeting the Duvernay formation, which achieved well field applications and made Duvernay shale become a world-famous shale resource (Rokosh et al., 2012;Li et al., 2020). ...
Conference Paper
Unconventional shale resources are widely distributed in the Western Canadian Sedimentary Basin and have great potential for development. However, due to the complex distribution of shale sweet spots and the high drilling and fracturing costs of horizontal wells, the petroleum industry faces great challenges in the efficient and economic development of shale resources. This paper proposes an integrated geological-engineering method to characterize the Duvernay shale reservoir near the Fox Creek region. First, reservoir petrophysics is characterized based on core experiments. Second, based on geomechanical experiments and acoustic logging, we characterize elastic parameters and in-situ stress tensors to establish a geomechanical model. Next, focal mechanisms of microseismicity are employed to identify large-scale natural fractures and faults. Then, based on the aforementioned models, as well as the perforation and treatment data, the propagation of full 3D hydraulic fracture networks for horizontal wells is simulated to construct the unconventional fracture model (UFM) via Petrel Kinetix. Finally, numerical simulations of horizontal wells are conducted, which are further corroborated by the production performance of fractured wells. It is found that the core analysis of the key well suggests that reservoir porosity, permeability, and gas saturation are averaged to be 5.3% and 404 nD, respectively. The rock mechanical parameters, including Poisson's ratio, and Young's modulus, are derived from the triaxial compression tests, with both average values of 0.21 and 36.2 GPa, respectively. The natural fractures in the examined region have been demonstrated to be governed by two-period tectonic activities and hence developed with mean dip azimuths of NE21° and SE111°, respectively. Real-time fracturing parameters of four horizontal wells are used to simulate the complex propagation of hydraulic fracture networks, considering the reservoir heterogeneity and stress shadows among different stages. Numerical simulations of well production are conducted based on the geological and geomechanical models. The agreement between simulation results and production performance reaches more than 90%, indicating the effectiveness of this integrated method for shale gas development. This work provides a solid foundation for site selection and fracturing job size optimization of new horizontal wells in the future.
... Canada is now the second country after the United States to successfully explore and extract shale gas, making it an essential part of the unconventional energy sector in North America [1][2][3]. In 2021, Canada produced 184 billion cubic meters of natural gas, with 29.9 % of those coming from unconventional formations producing shale gas [4,5]. ...
The integration of multi-technology and multi-scale evaluation techniques is quite important in the development of shale resources. To assess the high-quality shale in the West Duvernay Shale Basin, an integrated experiment-logging-based strategy is proposed. The investigation of core measurements and logging interpretations is first carried out to ascertain a geographic distribution of high-quality shales. The relationships between shale productivity and reservoir characteristics are then quantified, and the distribution of high-quality shales in space is predicted using machine learning techniques. The Duvernay shale is discovered to be separated into four sub-layers, with the D2 and D3 sublayers being considered high-quality shales based on a comprehensive analysis. Shale thickness, effective porosity, a brittleness index, and formation pressure are found to be crucial factors that greatly influence the production of high-quality shale. This strategy can be used to evaluate high-quality shale comprehensively in other shale resources and achieve the effective development of unconventional shale resources.
... Since 2011, concerns have been increasingly raised about the exploration and development of tight oil (Guoxin Li et al., 2020;Zhang et al., 2021). The Lucaogou Formation in the Jimsar Sag of the Junggar Basin is the priority to explore and develop tight oil in the Jimsar Sag (Kuang et al., 2015;Wang 2021;Zhi et al., 2019). ...
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Over the years, shale oil has been at the leading edge of oil exploration and also become the hotspot of reserve increases for various oil fields. The Permian Lucaogou Formation in the Jimsar Sag has been less extensively researched in terms of, among others, lithologic interpretation of fine-grained mixosedimentite, identification and classification of sedimentary microfacies, and sweet spot evaluation. The present study identifies the classification of sedimentary microfacies, characteristic distribution of sedimentary reservoir, and spatial configuration distribution of facies-controlled sweet spot body based on core logging, cutting logging, and data while drilling, combined with logging information, experimental analysis data, and production data with respect to formation test and production test and through the lithology identification based on element logging. This study indicated the following: 1) Microfacies of the reservoir body include a shallow lacustrine sand bar, mixing beach, and dolomitic flat. Different microfacies are adapted to different lithologies or lithological associations. 2) The lower sweet spots P2 l 1 2−3, P2 l 1 2−2, and P2 l 1 2−1 evolved into the dolomitic flat from mixing beach from NE to W. Also, the dolomitic flat is mostly developed in the west of the work area, and the mixing beach is better developed in the east. The shallow lacustrine sand bar is highly developed in the middle location, and the mixing beach and shallow lacustrine sand bar are highly developed on the northern and southern sides. 3) Sedimentary microfacies have evident controls over sweet spots. The upper sweet spots P2 l 2 2−3 and P2 l 2 2−2 are dominated by Class I sweet spots followed by Class II and IV sweet spots, which are major sweet spot reservoirs. The upper sweet spot P2 l 2 2−1 is mainly suffused with Class IV sweet spots, and the Class I reservoir is feldspathic litharenite (shallow lacustrine sand bar microfacies accordingly).
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Shale oil has become a global hotspot of unconventional exploration and development. In this study, the latest drill core and experiment analyses of the Qingshankou Formation in the northern Songliao Basin were used to evaluate its lithofacies classification, sedimentary environment, pore types, pore-throat structure characterization, and shale oil potential. Lithofacies classification was determined according to the total organic carbon (TOC) content, sedimentary structure, and rock mineral content. Laminae genesis and micro-sedimentary structures indicate the deposition of fine-grained sedimentary rocks (FGSRs) in a semi-deep to deep lacustrine environment; however, evidence also suggests partial reworking by storm events and bottom current flows. FGSRs mostly comprise type I kerogen, with small amounts of type II1. The average vitrinite reflectance of the FGSRs was 1.37%, indicating middle to high stages of thermal maturation within the oil generation window. The N2 adsorption experiment indicated that silty mudstone (SM), silty fine mixed sedimentary rock (SFMR), and argillaceous fine mixed sedimentary rock (AFMR) had ink-bottle-shaped and slit-shaped pores, and the lithofacies were dominated by mesopores, accounting for 77.4%, 71.9%, and 80.8% of the total pore volume, respectively. Mercury injection capillary pressure analysis indicated that SM and SFMR had an average pore-throat radius of 0.01–0.04 μm, whereas AFMR and CM were dominated by nanopores, mainly distributed in the range of 0.004–0.0063 μm. Based on the comprehensive studies of TOC content, pore development, and brittleness, we concluded that organic-rich laminated SM and SFMR should be the focus of shale oil exploration of the Qingshankou Formation in the northern Songliao Basin, followed by organic-rich or organic-moderate laminated and layered AFMR, as well as calcareous fine mixed sedimentary rocks.
To develop dissolvable packer rubber barrel is a key technology for realization of green oil drill engineering. During this experiment, a novel degradable rubber sealing material from MPUR/HNBR composite was prepared by physical mixing and chemical cross-linking with different parts of HNBR. The effect of blending ratio on the vulcanization characteristics, mechanical properties, compatibility, thermal stability, and dissolution characteristics of the composites were investigated. The results showed that when the MPUR/HNBR blend ratio changed from 80/20 to 60/40, the cross-linking degree of composites decreased gradually and the mechanical properties decreased. MPUR and HNBR have compatibility properties in a certain blending range, and the addition of HNBR led to an improvement in the thermal stability of composites. When immersed in a water medium at 100 °C, the tensile strength of pure MPUR decreased sharply in 12 h from 30 MPa to 3 MPa, its short service life time didn’t meet the need of engineering. After composed by HNBR, the tensile strength retention increased from 27.0% to 52.1% immersion for 24 hours. In addition, the composite can maintain high tensile strength between 48 and 168 h, its superior long service life time fully meet the sealing requirements. The possible degradable mechanism in water medium was offered.
The production efficiency of shale gas is affected by the interaction between hydraulic fractures and natural fractures. This study presents a simulation of natural fractures in shale reservoirs based on a discrete fracture network (DFN) method for hydraulic fracturing engineering. Fracture properties of the model are calculated from core fracture data according to statistical mathematical analysis. The calculation results make full use of the quantitative information of core fracture orientation, density, opening and length, which is the direct and extensive data of mining engineering. The reliability and applicability of the model are analyzed considering the model size and density, and the calculation method of dominant size and density is proposed. Then, finite element analysis is applied to hydraulic fracturing numerical simulation of shale fractured reservoir in southeastern Chongqing. The hydraulic pressure distribution, fracture propagation, acoustic emission information, and in‐situ stress change during fracturing are analyzed. The results show the application of fracture statistics in fracture modeling and the influence of fracture distribution on hydraulic fracturing engineering. The present analysis may provide a reference for shale gas exploitation.
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In the development of unconventional shale resources, production forecasts are fraught with uncertainty, especially in the absence of a full, multi-data study of reservoir characterization. To forecast Duvernay shale gas production in the vicinity of Fox Creek, Alberta, the multi-scale experimental findings are thoroughly evaluated. The relationship between shale gas production and reservoir parameters is assessed using multiple linear regression (MLR). Three hundred and five core samples from fifteen wells were later examined using the MLR technique to discover the fundamental controlling characteristics of shale potential. Quartz, clay, and calcite were found to comprise the bulk of the Duvernay shale. The average values for the effective porosity and permeability were 3.96% and 137.2 nD, respectively, whereas the average amount of total organic carbon (TOC) was 3.86%. The examined Duvernay shale was predominantly deposited in a gas-generating timeframe. As input parameters, the MLR method calculated the components governing shale productivity, including the production index (PI), gas saturation (Sg), clay content (Vcl), effective porosity (F), total organic carbon (TOC), brittleness index (BI), and brittle mineral content (BMC) (BMC). Shale gas output was accurately predicted using the MLR-based prediction model. This research may be extended to other shale reservoirs to aid in the selection of optimal well sites, resulting in the effective development of shale resources.
Conference Paper
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This work aims to address a challenge posed by recent observations of tightly-spaced hydraulic fractures in core samples from the Hydraulic Fracturing Test Site (HFTS). Many fractures in retrieved cores have sub-foot spacing, which is at odds with conventional models where usually one fracture is initiated per cluster. Since it is unrealistic to explicitly model all densely-spaced fractures, we develop a new upscaling law that enables existing simulation tools to predict reservoir responses to fracture swarms. The upscaling law is derived based on an energy argument and validated through multiscale simulations using a high-fidelity code, GEOS. The swarming fractures are first modeled with a spacing that is much smaller than the cluster spacing; these fractures are then approximated by an upscaled, single fracture based on the proposed upscaling law. The upscaled fracture is shown to successfully match the energy input rate and produce the total fracture aperture and average propagation length of the explicitly simulated swarm. Afterwards, the upscaling approach is further implemented in 3D field-scale simulations and validated against the HFTS microseismic data of a horizontal well in the Middle Wolfcamp Formation. Our results show that hydraulic fracture swarming can significantly affect fracture propagation behaviors compared with the propagation of single fractures as assumed by conventional modeling approaches. Under the considered situations, the conventional case entails fast propagation speed that far exceeds that indicated by the microseismic data. We also illustrate this discrepancy can be reduced readily through the implementation of the upscaling law. Our results demonstrate the importance of accounting for the fracture swarming effect in field-scale simulations and the efficacy of this approach to enable realistic predictions of reservoir responses to fracture swarms, without explicit modeling all tightly-spaced fractures observed in the field.
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Shale gas resource in China is greatly different from that in the North America in term of natural endowment, so North America's experience and practice of shale gas revolution shall not be copied blindly in China. In order to realize scale effective development of shale gas resource in China, we analyzed and summarized the status quo of domestic shale gas stimulation technologies referring to the advanced concepts of shale gas development in the North America, considering the actual situations of shale gas resource in China. Then, some suggestions were proposed on the development direction of key shale gas fracturing technologies and the enhancement of engineering management. First, a data volume that integrates geological, engineering and production information is the base for designing and optimizing all segments of shale gas exploration, development and production. Therefore, it is necessary to break the “data isolated island”, strengthen data mining and improve the data application efficiency, so as to promote the integration of geo-engineering data fusion. Second, the geomechanics test & evaluation method and technology suitable for shale reservoirs shall be developed and improved by taking into consideration the anisotropic mechanical behaviors and ground stress characteristics of shale reservoirs, so as to increase the design level of geo-engineering integration program. Third, it is necessary to develop the dissolvable bridge plug, improve operation the efficiency of staged fracturing and reduce the operation risk, so as to achieve cost reduction and benefit increase of shale gas development. Fourth, there is still great room for the improvement of the engineering management system, which is worth exploring and studying further. Therefore, oil & gas industry and companies shall seize this critical strategic opportunity to actively optimize the current engineering management pattern and seek the optimal approach to quality improving and benefit increasing. In conclusion, the exploration and development of shale gas in China is currently in the early stage and there is an obvious gap compared with foreign countries in terms of technology & equipment, production management, exploration and development achievement and policy & regulation. Therefore, it is in an urgent need to innovatively explore a way feasible for the actual shale gas development in China based on the resource conditions of its own after referring, digesting and absorbing the hydraulic fracturing experience and management concept of shale gas revolution in the United States. Keywords: China, North America, Shale gas, Hydraulic fracturing, Geo-engineering integration, Geomechanics, Dissolvable bridge plug, Engineering management, Big data
Conference Paper
A proven and tested method for helping improve completion design during well stimulation is formally presented. Systematic changes in terms of cluster spacing, fluid design, proppant design, and perforating scheme were evaluated and implemented in real time. Post completion evaluation led to a series of design improvements applied to active and future projects. The ultimate goal of the project was to identify an improved completion design both in terms of productivity and economic efficiency in real time. A formal approach of beginning at the cluster level and expanding to the asset level was followed. The project focus progressed from the optimal stage completion to well completion and then section. For stage and well optimization, the target was to meet or exceed the type curve for the area while maintaining economic discipline. This paper will focus on the near wellbore aspect of asset optimization. The diagnostic pad consisted of six wells configured in a wine rack spacing design. A single diagnostic well "Wildcat No. 1" was completed individually and included a fiber-optic cable installed on casing. During completion downhole, microseismic monitoring and tilt were recorded from nearby vertical wellbores. The cluster-level flow profiles were recorded at each stage using fiber-optics. This data, provided in real time, enabled a dynamic workflow to test, assess, and immediately apply learnings. For example, stage length was tested, evaluated, and adjusted until a favorable length was identified. Improvements in the completion design around the fluid system, cluster spacing, shots per foot (spf), injection rate, and execution parameters were identified based on the Uniformity Index (UI). Temporal changes to the completion design were also reviewed and identified. This approach is as significant as the technologies that enable it and is discussed in detail.
Conference Paper
Frac Driven Interactions (FDI) have gained much attention, but like many past challenges in our industry, a solution is not far behind. The ability and willingness of operators to share information is at the core of advancing this solution. Not content to just shut-in our wells and "hope for the best" during nearby frac ops, we decided to pro-actively learn about FDIs and to apply the learnings to frac defense. Frac defense not only protects the primary well, it also helps to prevent asymmetrical fractures in the infill well. We provide methodology used to design and implement FDI defense. Additionally, we also show how we analyzed the results of the FDI defense to determine its success. In 2018, we had an opportunity to learn about FDI and documented those interactions, along with the analysis, in SPE 194349-MS. The original study was initiated to understand FDI and to ultimately determine appropriate mitigation. In this case study, we used the findings from the initial study to select suitable mitigation: pre-loading the primary well with water prior to offset fraccing operations. The study location is one that had previously experienced FDI from offset development wells. The primary wells had recovered quickly from the past FDI but due to an additional year of depletion, our research showed that recovery would probably be longer. The workflow covers well candidate selection, necessary personnel and equipment on location, and the risk analysis of the overall project. To monitor the effectiveness of mitigation after pre-loading, the team placed wellhead pressure sensors on pre-loaded primary wells, and primary wells in the adjacent pad. Sensors were installed on select vertical wells perforated through the target zones. In addition, wirelessy connected, high-pressure sensors were deployed on actively fraccing wells. All sensors were time-synced and monitored in real-time. Pressure results indicated that mitigation using the water pre-load method dampened FDIs. A successful application would manifest in pressure dampening and a reduction of recovery time. At the time of this writing, flowback operations are ongoing and one primary well recovered to pre-frac rates within one week. We anticipate a corresponding reduction of recovery time in the other wells. Most importantly, the infill well immediately offset from the primary is performing as good or better than the other infills in the same interval. This paper presents methods ad processes that offer a potential solution to identify candidates for fracture mitigation, and optimize project economics in a full section, multi-bench development. A novel aspect to the data is that all wells were wirelessly connected to the internet, time-synced with the atomic clock, and monitored in real-time. Time-synched pressure indicators immediately reveal the earliest signs of well-to-well communication across the entire field of active and passive wells. Pressure readings are reflective of FDIs allowing the operator to monitor, and proactively apply mitigation techniques in real-time. This process is known as "active well defense." However, due to certain limitations, we deployed a "passive well defense" where we injected water into the primary wells prior to frac operations.
Conference Paper
The unconventional Shale and Tight play concept has grown to dominate the North American energy landscape, now accounting for the vast majority of onshore activity levels. However, not all Shale or Tight reservoir plays are created equal and what works for one play/Formation may not work for another. How should you design your stimulation, where to begin, what parameters are most impactful and what are some of the large economic leavers that can either make your project successful, or potentially cause it to fail. The Duvernay is an Upper Devonian mudrock, with significant quartz, carbonate and total organic carbon content, making it an attractive Shale gas target. Total Organic Carbon (TOC) varies from 2-17 wt.% and porosity ranges from 3-8% (averaging approximately 5%). The Formation is approximately 2,800 – 3,800 meters deep in the project area and is approximately 35-60m thick. Importantly, the target is significantly overpressured, with nearly double normal hydrostatic reservoir pressure (15-21 Kpa/m gradient). The native permeability of the Duvernay Formation is extremely tight, measuring in the 70-150 nano Darcy range, thus the formation requires horizontal wells with multi stage hydraulic fracturing, to be economically productive. The natural fracture density of the formation partially explains how a rock with such low matrix permeability can be so prolific, background tectonic fracturing is significantly greater than most other low permeability reservoirs being exploited in North America. Fracture densities have been measured in core and image logs at up to 8 fractures per meter, with average open fracture density's approximating 1-2 per meter. These fractures are steeply dipping (75-85 degrees) and created during tectonic events, both open and healed/calcite filled fractures are present. While the presence of natural fractures aid in the productive stage of the well's life, it can complicate the stimulation design and challenge the placement of a wellbore treatment. During the initial planning stages of an unconventional hydraulic stimulation program, the first step is to examine what other operators in the play are already utilizing. Early due diligence into what design elements are successful and almost as important, not successful, can save significant amounts of capital early in the evolution of a project. An example of this within the Duvernay project were uncemented ball drop liner completion systems. Due to the high-pressure pumping requirements of the Duvernay (up to 90 Mpa), these systems were not able to adequately stimulate the reservoir and were prone to install and isolation challenges. Limited entry Plug and Perf design dominates the Canadian unconventional energy landscape, this is where Chevron Canada Limited and KUFPEC Canada ("The JV") began its journey. The next critical stimulation parameters to decide on are proppant and water intensities, these will govern the duration of the stimulation and are key economic drivers (proppant intensity is typically the most significant variable in terms of cost and well productivity). Other major inputs into the frac program center around cluster design; number of clusters to be treated as part of a single frac stage, the spacing between the clusters and the number and orientation of perforations within a cluster/stage are key parameters. The treatment pressure is usually dictated by the breakdown and fracture extension pressure inherent to the reservoir, where the target treatment rate is a selection made by the operator (typically 10-15 m3/min for most unconventional reservoirs). Stimulation fluid design also varies by play type, Slickwater designs are some of the most popular in use today with hybrids, reverse hybrids and high viscosity friction reducer (VFR), also used in various quantities across play types. Connected to the stimulation design, is the interwell spacing distance, usually the wider wells are spaced from one another, the higher the proppant intensity. The key premise of limited entry design assumes that all the clusters within a fracture stage are taking fluid and sand equally and thus, have equal fracture half lengths, this is not the case (concept known as cluster efficiency), more discussion on that topic to follow later in the manuscript.
Conference Paper
Descriptive Analytics is the first step of a three-step data-driven analytics workflow used for managing and optimizing completion, production and recovery of shale wells. The comprehensive data-driven analytics workflow for the unconventional resources is called Shale Analytics (Mohaghegh 2017). The key behind Shale Analytics is the incorporation of all field measurements that contribute to the productivity of shale wells. There are workflows in the market that claim to be data analytics related but do not make use of all the available field measurements when performing their analyses. These workflows are mainly based on traditional statistical algorithms rather than Artificial Intelligence and Machine Learning. Such approaches represent different versions of Decline Curve Analysis. Shale Descriptive Analytics takes into account seven categories of field measurements; (i) well construction and trajectory, (ii) well spacing and stacking, (iii) reservoir characteristics, (iv) completion design, (v) hydraulic fracturing implementation, (vi) operational constraints, and (vii) well productivity. Each of the above categories of field measurements include several parameters. Shale Descriptive Analytics provides two types of insight on the contribution of all the field measurements to well productivity. The first type of insight compares and quantifies the contribution of the different categories of field measurements to well productivity. The second, more detail type of insight compares and quantifies the contribution of each of the parameters of the first six categories to the final category that is well productivity and then compares all the parameters to one another. The Shale Descriptive Analytics presented in this article demonstrate the results of more than 800 shale wells in one of the most productive shale plays in Texas. Two conclusions have been achieved as the result of this study. (a) In the early life of a shale asset, when the wells are NOT too close to one another (when Frac-Hit is not an issue), using well productivity indices (such as initial production, initial decline rate, first 30, 60, 90, 120, 180 and 365 days of cumulative production, etc.) can provide realistic insight for completion optimization, well productivity and recovery. (b) Once the number of wells in a given asset increases, resulting in the reduction of the distances between parent and child wells (Frac-Hit impacts production and recovery), well productivity indices will no longer be able to provide the required insight for modeling and analysis of field measurements. This is because as the number of wells increases in a given shale asset, the fracture-driven interaction between wells (also known as Frac-Hit) takes over the overall productivity of all the wells in the field. Frac-Hit not only negatively influences parent and child wells productivity and recovery, it completely undermines all the existing techniques (traditional techniques such as RTA and numerical simulation as well as all the existing techniques based on Data Analytics) for completion and production optimization of shale wells. At the conclusion of this article, a new approach to overcome this specific problem is introduced.