2

ABSTRACT

Faced with poor production from a hydrocarbon reservoir, a petroleum engineer`s

first thought would be a stimulation technique. This normally involves the process
of pumping treating fluid into the near-wellbore vicinity to either dissolve
formation damage or create new pathways for production. The main target of this
report is to evaluate the state of the art of stimulation techniques and discuss in
what ways technical breakthroughs are helping to optimize stimulation jobs in oil
and gas wells. The stimulation techniques are one of the most widely used well
interventions performed on oil or gas wells by improving the flow of the
hydrocarbons from the drainage area into the wellbore. The history of problems,
trends, field applications with comprehensive analysis, and successful results of
solutions with both positive and negative sides are the crucial themes of this report.
 3

REFERAT
Karbohidrogen anbarından zəif hasilatla üzləşən neft mühəndisinin ilk fikri
stimullaşdırma texnikası olacaq. Bu, adətən ya lay zədəsini həll etmək, ya da hasilat
üçün yeni yollar yaratmaq üçün təmizləyici mayenin quyu çuxuruna yaxın əraziyə
vurulması prosesini əhatə edir. Bu hesabatın əsas məqsədi stimullaşdırma
texnikalarının vəziyyətini qiymətləndirmək və texniki nailiyyətlərin neft və qaz
quyularında stimullaşdırma işlərini optimallaşdırmağa hansı üsullarla kömək
etdiyini müzakirə etməkdir. Stimullaşdırma üsulları neft və ya qaz quyularında
karbohidrogenlərin drenaj sahəsindən quyu quyusuna axınının yaxşılaşdırılması
yolu ilə həyata keçirilən ən çox istifadə edilən quyu müdaxilələrindən biridir.
Problemlərin tarixi, tendensiyaları, hərtərəfli təhlili ilə sahə tətbiqləri və müsbət və
mənfi tərəfləri ilə həll yollarının uğurlu nəticələri bu hesabatın mühüm
mövzularıdır.
 4

РЕФЕРАТ

Столкнувшись с низкой добычей c углеводородного резервуара, инженер-

нефтяник первым делом подумал бы о методе стимулирования. Обычно это
включает в себя процесс закачки обрабатывающей жидкости в окрестности
ствола скважины, чтобы либо устранить повреждение пласта, либо создать
новые пути для добычи. Основными целями этой дипломной являются оценка
современных методов интенсификации и обсуждение влияния технических
продвижений на оптимизирование работы по интенсификации в нефтяных и
газовых скважинах. Методы интенсификации являются одним из наиболее
широко используемых внутрискважинных работ, выполняемых на нефтяных
или газовых скважинах, которые служат улучшению потока углеводородов из
зоны дренажа в ствол скважины. История о проблемах, тенденциях,
всесторонний анализ применения в полевых условиях и успешные результаты
решений как с положительными, так и с отрицательными сторонами
являются ключевыми темами этой дипломной.
 5

Table of Contents

ABSTRACT 2
REFERAT 3
РЕФЕРАТ 4
INTRODUCTION 7
THE FIELD CASE STUDIES OF MATRIX ACIDIZING 9
FIELD CASE: SAMARA FIELD IN RUSSIA 11
FIELD CASE: VDA APPLICATIONS 12
FIELD CASE: ACIDIZING OF HTHP CARBONATE RESERVOIRS IN
MEXICO 13
FIELD CASE: CHELANT-BASED ACID TREATMENT 15
FIELD CASE: ACIDIZING OF INJECTION WELLS IN CASPIAN SEA 16
FIELD CASE: HORIZONTAL GRAVEL-PACKED WELLS 17
THE FIELD CASE STUDIES OF HYDRAULIC FRACTURING 19
TIP SCREENOUT FRACTURING TECHNIQUE 20
FIELD CASE: KERN RIVER FIELD IN USA 21
FIELD CASE: MASSIVE FRACTURING IN OMAN 22
FIELD CASE STUDY: CHANNEL FRACTURING IN SHALE 23
FIELD CASE: FRAC-PACK IN WIDURI FIELD OF JAVA SEA 24
FIELD CASE: HYDRAULIC FRACTURING IN HTHP FIELD 24
FIELD CASE: HYDRAULIC FRACTURING IN HTHP CARBONATE FIELD
25
CONCLUSION 26
REFERENCES 28
APPENDIX 1: FIELD CASE STUDY OF JUJO-TECOMINOACAN FIELD IN
MEXICO 31
APPENDIX 2: FIELD CASE STUDY OF SOUTH GHAWAR FIELD IN SAUDI
ARABIA 32
 6

APPENDIX 3: FIELD CASE STUDY OF PIRAMBU FIELD OF BRAZIL 32

APPENDIX 4: FIELD CASE STUDY OF ACIDIZING OF HTHP CARBONATE
RESERVOIRS IN KAZAKHSTAN 32
APPENDIX 5: FIELD CASE STUDY OF PRUDHOE BAY FIELD IN USA 34
APPENDIX 6: HYDRAULIC FRACTURING 35
 7

INTRODUCTION

From the moment when the first drill bit enters the reservoir the formation damage
of near wellbore formation starts to be created which results in potential of the near
wellbore permeability to be reduced. This process decreases the well productivity.
When reservoir itself has naturally low permeability, this results in much lower
productivity. Well Stimulation is a type of well intervention job which is performed
on a petroleum well so as to enhance productivity by improving the hydrocarbon`s
flow from reservoir to tubing string. Fundamentally, the stimulation job opens new
channels or restore damaged zone in the formation to either fix or increase the
productivity of a well so that hydrocarbons can easily flow. The key reason, why
stimulation techniques are applied, is to fix this low productivity so that maximum
profitability can be achieved. Various types of stimulation techniques are aimed to
solve these issues as a means to recover or increase the permeability in near
wellbore vicinity, so productivity and ultimate recovery factor (Economides, et al.,
2013). Stimulation treatments are divided into 2 major classifications, matrix
stimulations, and hydraulic fracturing stimulations.
The simple purpose of the matric stimulation is to
enhance the productivity – reduce the skin factor in
reservoir area – by dissolving formation damage or
creating new pathways within several inches to a foot or
two around the wellbore. Matrix stimulations are carried
out below fracture pressure of formation and wellbore and
generally are aimed to restore the natural permeability of
the near wellbore zone by removing formation damage.
Compared with high-pressure fracturing, matrix acidizing
is a low-volume, low pressure, and low-budget operation.
However, the objective of applying matrix acidizing is
differed widely in sandstone than in carbonates. Although
this stimulation technique in sandstone is aimed to recover and improve formation
permeability near wellbore area as a means to remove formation damage, by
dissolving the material plugging pores and enlarging pore spaces, the aim of the
stimulation in carbonates is to increase conductivity that bypasses damage by
creating new wormholes (Figure 1). That being said, for the sandstone treatments,
the knowledge of the extent, type of damage, reservoir mineralogy, and
compatibility of acids with the formation are crucial factors while fluid type,
 8

temperature, and pumping rate are leading aspects in carbonates. (Nolte, et al.,
2010)
Hydraulic Fracturing involves pumping a high viscous fluid into the reservoir
interval to be treated at an adequately high pressure beyond a fracture initiation
pressure so as to create conductivity by breaking the rocks. These fractures are
subsequently needed to be filled with solids to maintain conductivity (keep fracture
open) after the fracturing process is finished. This stimulation method is mainly
applied to petroleum fields that have naturally low permeability. Therefore, the
basis of fracturing is quite straightforward – pump fluid at a high enough pressure
down the wellbore to force the rock to be opened. Basically, hydraulic fracturing
increases productivity by decreasing skin factor, increasing the wellbore radius, and
improving formation flow capacity - k o h values.
This technique has been applied for many decades by Figure 1:
Wormhole
offering a safer and more controlled well stimulation with
solid results. Half of all onshore wells have been applied
hydraulic fracturing in the United States of America. During the late 1970s,
considered the banner years of hydraulic fracturing advances, there was a saying
frequently used in jest: “When everything else fails, frac it!” These have been
proved to be true because a lot of “fracking 1” has been applied for well stimulation
in those days and since.
In some circumstances, a well stimulation technique is mainly applied in a
carbonate formation at a slightly higher pressure than those of the fracture initiation
pressure by injecting acid, usually hydrochloric (HCl). This method is named acid
fracturing, which is a special type of fracturing which involves acid treatment as
well.

THE FIELD CASE STUDIES OF MATRIX ACIDIZING

1
Fracking – Hydraulic fracturing is also called “fracking” in some western literature.
 9

The first matrix acidizing operation dates to 1896 when A Standard Oil managed to
acidize limestone with hydrochloric acid (HCl). Although the production increased
in oil wells by three times and in gas wells by four times, having severe corrosion
of casing led to a decline in popularity of this technique. Then, Dow Chemical
Company discovered that arsenic inhibited the action of hydrochloric acid on
casing (metal). This had resulted in the massive application of using arsenic as an
inhibitor, and commercial acidizing service had commenced to coming to
petroleum production industry.
The main challenge related to sandstone acidizing is a diversion. Since acid is
injected, it flows into a direction with less resistance, which means in the direction
of a high permeable zone. So, the acid is required to push into damaged or less
permeable zone so as to achieve the target. There are wide ranges of diversion
techniques that help to divert treatment fluid exclusively toward a low-permeable
zone. The core requirement of any diverting agents is to block high-permeable
pathways within the matrix, not to react with formation, fluid, acid, and to clean up
easily after the treatment so not as to impede further production. Currently, two
types of diverting are mostly used: 1) mechanical diversion with packers and coiled
tubing, 2) chemical diverting agents.
One of the best diverter agents is just simple foam, a stable mixture of liquid and
gas, in commercial name “FoamMAT” by service companies. It has been widely
applied in the matrix acidizing since it is cheap to produce, and it does a decent
diverting job. “FoamMAT” is produced by injecting nitrogen into soapy water with
the mixture of small amount of surfactant. The diversion of treatment fluid to the
damaged area takes place almost immediately and the diversion holds for at least
100 minutes. This technique has been successfully applied in fields of the Gulf of
Mexico and Africa (Zehrboub, et al., 1991).
Table 1 above indicates the results of the use of the “FoamMAT” method in 4
different wells. In the first example, the new technique had been applied in a high
water-cut oil well with a depth of 9600 ft. As this technique was successfully
applied in 51 ft interval, the oil production doubled, and water cut decreased by
3%. After the treatment, artificial lift – gas lift was not required to provide
economically beneficial results in this field. Since this tremendous achievement,
the new “FoamMAT” method has been proved to provide exceptional blockage of
water zones in wells with high water-cut percentage. The second and fourth field
studies reveal the application of it in gas wells in which both showed a tremendous
 10

increase in gas production. In the third example, the technique helped a high
temperature-high pressure oil well to back to production.

Table 1: Field Case Studies for "FoamMAT" technique in fields of Gulf Mexico and Africa
 11

FIELD CASE: SAMARA FIELD IN RUSSIA

Especially the application of this technique in Samara fields in the Volga-Ural

region of Russia can be considered the best example. The Samara field in the
Volga-Ural region is a carbonate formation with more than 60 billion barrels of
proven conventional reserves. About 70% of the production comes from this
region, the carbonate reservoirs, which commonly require matrix acidizing and acid
fracturing treatment. Although the stimulation operation is considered very
challenging in this area due to the fact that the field faced depleted reservoir
pressure, difficult flowback, formation heterogeneity, water cut up to 60%,
“FoamMAT” method was applied to overcoming extreme problems. An operator
company used a stable and nondamaging diverter agent at 65% nitrogen content.
The results were superb. The production was increased by nearly 450% with the
help of this technique associated. Figure 2 reveals the normalized productivity
index for four offset wells after acid treatments. Only in the well A of Samara
Field, Foam Acid Treatment had been used, and its result showed better and stable
productivity within the half of the year.
Furthermore, Figure 3 shows the differentiated results of application of both foam
acid treatment and conventional treatments in four different formation layers
(named as O2, DL, D3vor, and D3bur with similar geological and technical
conditions. As the figure shows clearly, Foam Acid Treatment demonstrated higher
productivity and better blockage of water coning within the analyzed production
period of 6 months in all four formations.

Figure 2: Normalized Productivity Index for four offset wells mentioned after treatment
 12

Figure 3 Comparison of average normalized PI, oil production (Qoil) and water cut after the treatments on
different formations (O2, DL, D3vor, D3bur)

FIELD CASE: VDA APPLICATIONS

However, in carbonate reservoirs, another problem is the wormhole network which

should be penetrated deeply and uniformly within the producing interval to achieve
sufficient stimulation result. The most challenging part of this process is to achieve
uniformity of the stimulation especially when there is huge permeability variation
throughout the producing interval. As the acid penetrates the reservoir, it flows
preferentially into the direction with less resistance, and that is why a high
permeable zone receives most of the treatment. To solve this issue in carbonate
reservoirs, again diverter acidizing fluids are applied. One of the most effective
techniques is to use viscoelastic (self) diverting acid (commercial name: VDA or
VSDA by Schlumberger). VDA is a self-diverting acidizing fluid with degradable
fibers (MaxC O3) mixture which can be applied alone or with other treatment fluid to
maximize zone coverage for carbonate reservoirs (Cohen, et al., 2010). One of the
best advantages using VDA with MaxC O3 fibers is related to its reduced cleanup
costs. Fundamentally, if fibers are left in wormholes after the treatment, it would
substantially decline the production from high permeable zones. For that reason,
degradable fibers seem perfect choice since they can be easily hydrolyzed and
degraded during the next couple of days. Basically, recovery and well cleanup are
quite easy since the fibers can be definitely broken or degraded by formation fluid
when production is restored (only low pressure is required to remove fibers).
Additionally, the fibers are made of an organic polymer chain which produces
acidic products once being degraded. These acidic products cause extra formation
 13

stimulation by maximizing productivity (Economides, 2000). Case histories from a

variety of fields in different parts of the world have proved this technique as a very
powerful system to achieve well productivity improvements.
Field Case Studies from the Northern Field of Qatar showed powerful results. Field
consisted of sequences of dolomite and limestone with 100/1 permeability
variations. As it has already discussed before, the main difficulties to achieve
effective acid placement were high permeability contrast which gave rise to poor
acid job. The matrix acidizing with VDA were successfully applied in 11 wells as a
part of the field test. The engineering team profitably achieved to stimulate
reservoirs as the posttreatment activities including production logging verified the
success of the treatment. This new technique offered operational efficiencies since
it can be efficiently batch mixes with existing equipment. That is why the
stimulation process took 2 – 4 days shorter than the conventional operations by
saving 480,000 $ to 950,000 $ per a well. As well as it offered a 72% reduction in
greenhouse gas emissions (Thabet, et al., 2009). Other Field Case Studies of VDA
technique from Jujo-Tecominoacan Field of Mexico (APPENDIX 1), South
Ghawar field in Saudi Arabia (APPENDIX 2) and Pirambu field of Brazil
(APPENDIX 3) showed a very great succession which was verified by
posttreatment activities including production logging.

FIELD CASE: ACIDIZING OF HTHP CARBONATE RESERVOIRS IN

MEXICO

Fields in the South Region of Mexico produce more than nearly half- million
barrels of oil per day from mature Cretaceous carbonate reservoirs which mainly
consist of calcium carbonate and dolomite formations being shallow-water
carbonates. The production is considered quite challenging due to the reservoirs`
varying degrees of permeability and wettability, presence of natural fractures and
extremely high temperature. This extremely high temperature up to 350-degree F
makes it even more challenging for the stimulation application with traditional
methods resulting in excessive corrosion and insufficient wormhole network. The
main reason, why stimulation was decided to apply, was related to an unforeseen
decline in the production during 2010 when the production declined from 172,000
to 158,000 bpd in four months. This 20% decrease urged to apply the stimulation
since the field had an annual oil production target of 200 KBOPD. The engineering
team needed to perform the most efficient stimulation operation with less delay.
 14

The engineering team decided to use the matrix acidizing technique. For the
specific case of the stimulation, they decided to use ethylenediaminetetraacetic acid
(EDTA-type) as primary dissolution agents provided by a service company. The
EDTA-type acid was chelating agents which were widely applied in the oil industry
as a means to remove scale. Another application of chelating agent was to avoid
solids precipitation from by-products of secondary reaction products as the acid
spends during reaction with the formation. The most important characteristic in
terms of the purpose of this project, was that the system with EDTA-type acid had
a pH of 4. This low pH value gave firstly rise to
1. Higher efficiency than a normal acid job in high-temperature reservoirs –
in which traditional matrix stimulation with HCl and other organic acids have a
longer reaction time and less capacity to produce an efficient wormhole network
at extreme conditions.
2. No need for post-treatment neutralization – the more acid reacts the more pH
increases. This means after the treatment, post-treatment fluid is needed to be
neutralized (need to have at least a pH of 5) before flow back to the surface,
however, this was avoided by use of EDTA-type acid.
3. Earlier production – this was related to previous factors which made the
stimulation to take less time.
The use of stimulation technique with EDTA-type acid, increased, and stable
production for a long time was achieved. The trend of the production rate decline
was completely changed. Roughly eightfold less cheap operation than traditional
matrix acidizing was accomplished. (Jimenez-Bueno, et al., 2012)

FIELD CASE: CHELANT-BASED ACID TREATMENT

 15

Another successful application of the stimulation using chelating-based agents was

observed in Pinda formations of the West Africa region in which consisted of
multi-layered formation by being carbonate content ranging from 2% to 100% with
300 ℉ temperature. A common type of formation damage in Pinda formation was
pore-lining and pore-clogging materials, such as calcite, chlorite, and dolomite.
In order to solve this problem, the field was initially stimulated by applying

Table 2: Well Pre-Job and 365-day Post-Job Production Results (BFPD – Barrels
fluid per day, BOPD-barrels of oil per day, BWPD – barrels of per day, and
MSCFD – thousand standard cubic feet per day)

conventional 7.5 % HCl acid fluid treatments which showed poor results by
causing deconsolidation of sand, clays` destabilization, and even corrosion to the
downhole tubular system. To both avoid these issues and ineffectiveness in
maintaining sustained improvement in the production, chelating-based agents with
a pH of 4 were used (Parkinson, et al., 2010).
The initial results for two wells were optimistic with a production increase of
roughly 1,000 barrels sustained nearly one year for each one before performing
other 6 wells in this offshore field which showed positive results sustained for a
long time. Table 2 shows the results for these wells with comparison of pre-
stimulation results. It can be easily seen that oil production has been nearly doubled
while gas production increased by 20% and water cut in % decreased from 12%
(371/3251*100=12%) to 8% (417/4948*100=8%) for a one-year period.

FIELD CASE: ACIDIZING OF INJECTION WELLS IN CASPIAN SEA

Another tremendous achievement related to matrix acidizing had been performed

between 2015 and 2018 in Yuri Korchagin Field which was situated in the largest
 16

condensate field of the Russian sector of the Caspian Sea. The hydrocarbon
reserves are confined to carbonate deposits. The most distinct characteristics of this
field are the effect of water and gas saturated layers on the total production. After
5-year production, a sharp increase in the volume of produced water had been
observed in the field, and two horizontal injection wells (Well 1`s horizontal
section=193m, Well 2=763m) had been drilled as a means to dispose of the
produced water. A decrease in the injectivity coefficient was witnessed as the total
volume of accumulated water increased. This was because heterogeneous reservoir
with natural fractures poses geological and technical complexity to perform
sufficient injection which urged to stimulating these wells annually. If a sufficient
injectivity index could not achieve, an operator company should have decreased the
total production to decrease the amount of disposed water.
Throughout 3 years, roughly 20 matrix treatments were applied; initially, HCl acid
system was used
before applying VDA,
OpenPath Sequence -
diverting pills with
multimodal particles,
and OpenPath Reach -
retarded acid system
for deep formation
penetration, a system
was used. (Golenkin,
et al., 2018)
Results were depicted in Figure
Figure 5. The
SEQ first\*3ARABIC
Figure results4:indicate HCl
The results (1, 2) and
for Injectivity Index after
Eltinoks-1K – stimulations

improved HCl system (3) acid systems. The difference in HCl results was related to
the volume of acid per meter used in the stimulation. Afterward, VDA (4) and
OpenPath Sequence (5) system were illustrated which showed a nearly threefold
rise in the average injectivity using less volume than conventional ones. The last
OpenPath Reach (5) system doubled the injectivity compared to 4 and 5 systems.
Significant improvement in the injectivity index which had been achieved by
adding the diversion systems together with hydrochloric acid, allowed operators to
increase production from the wells with high water cut, therefore improving total
production. These improvements also indicated the effectiveness of temporarily
blocking pills with both multimodal particles and retarded acid in carbonate
 17

reservoirs by introducing a new approach of solving an issue regarding a uniform

stimulation extent in long horizontal section and heterogeneous fractured
reservoirs. (Golenkin, et al., 2017). Another great application of the VDA system
had been conducted in HTHP Carbonate Reservoirs of Kazakhstan which showed
in APPENDIX 4.

FIELD CASE: HORIZONTAL GRAVEL-PACKED WELLS

As many gravel packs (PG) plug up, there plugging particles are required to
remove to prolong the effectiveness of GP as a means to improve productivity.
HV:HF acid system can be used to remove fine particles that have caused damage
out of GP and screens. This system (HV:HF) utilizes HF acid and organophosphate
(HV) acid which maintains the production of HF by reducing drastically damaging
further potential precipitates. That being considered, the process of this system can
be described: “an effort to remove more damage rather than the damage generated
by the stimulation itself” (Ross & Lullo, 1998). The key reason why acid
stimulation to remove damage in GP is the best solution could be related to the fact
that cleaning GP is much
cheaper process than replacing a GP which involves risks and expensive

procedures.
Figure 5: Data on existing wells treated with HF:HV Acid System

1. Case Histories: Champion Field, Well Champion 14 (Stanley, et al.,

2000)
 18

In Champion Field with stacked sand/shale sequences, GP has been frequently

applied, however over time, production decreases due to excessive sand production
which plugs GP. When the production from C-14 stopped, it was decided to use the
new matrix acidizing technique. 2 weeks after the job, oil production stood at 176
bopd by remaining at this level over 5 weeks.
2. Case Histories: YPX-Maxus, Indonesia
Another 2 case studies from YPX-Maxus Field from Indonesia consisted of fluvial
sandstone formation layers. The reservoir was Although the reservoir consisted of
relatively clean and poorly consolidated sandstone with 0.32 porosity (other
parameters in Figure 5), fines migration of clays in combination with the high fluid
rate with high water cut caused the problems, which urged to use HV:HF acid
stimulation to remove this damage. The stimulation handled with the problem by
doubling the production from 200 to 400 bopd with a fivefold productivity increase
in Aida A-9 well (1st case study). Further application in this field was operated in
Widuri D-17 well with similar completion data and production history, the
production increased by 2.5 times. In terms of economic discussion, costs of the
treatment in these wells were recovered less than a month with a production
increase 265 bopd in Widure D-17, and 200 bopd in Aida A-9 (Stanley, et al.,
2000).
Furthermore, EDTA amino acid system can be used to remove formation damage
around GP at HTHP conditions as it offers sufficient reaction time and rate at the
conditions (Bourgeois, 2000), and it also generates organic acids at a rate that can
be controlled (Terwogt, et al., 2006). However, slow-acting breakers, such as
enzymes, enzymes with chelating agents can be circulated into GP to remove
formation damage which can be applied at conditions up to 180 o F temperatures
(Parlar, et al., 2004).

THE FIELD CASE STUDIES OF HYDRAULIC FRACTURING

Although the idea of hydraulic fracturing was formed during the 20s year of XX
century, the first application of this stimulation treatment had to wait till 1947 when
Stanoild (now: Amoco Co.) used it for the first time in Klepper well in Kansas,
USA. The results of this first-ever application were a hit-or-miss proposition but
 19

exhibited the potential of the successful concept. In 1949, the first commercial
treatment was applied by increasing production outstandingly.
By the end of 1955, hydraulic fracturing reached roughly 3000 well per month, and
more than 0.5 million treatments by 1968 (Waters, 2002). Currently, 35 to 40% of
the total number of wells in the USA has been stimulated with this method, where
it has increased the oil revenues by up to 30% (Veatch, et al., 1989). Those results
indicate no signs of abating by expanding its application from low-permeability
reservoirs - mainly unconventional to medium-to-high permeability settings (NR,
1992). Figure 6 clearly shows the motivation for hydraulic fracturing by years. 3
parts of the chart with positive developments indicate 3 impulses; to remove
formation damage, then to enhance tenfold productivity of the tight gas reservoirs,
and to double up production of reservoirs with medium to high permeability,
nowadays.

Figure 6: History of hydraulic Fracturing

Fundamentally, it is considered by many petroleum engineers that much of today`s

thinking of fracking2 has been inspired by Sohoi Petroleum Co.`s field application
in the Prudhoe Bay in the middle of the XX century. The results and lessons
learned from this field application shaped hydraulic fracturing future. Detailed
information for the Prudhoe Bay case study is in APPENDIX 5.

2
Fracking – Hydraulic fracturing is also called “fracking” in some western literatures.
 20

TIP SCREENOUT FRACTURING TECHNIQUE

The Valhall field is located in the Norwegian sector of the North Sea. It has a soft
chalk reservoir with approximately 2 mD permeability (depth = 2400 m). Due to its
unstable formation, conventional stimulation techniques were difficult to apply
(Smith, et al., 1992). Firstly, acid fracturing was applied, however it failed since
acid-etched channels were rapidly collapsed by a reduction in pressure. Afterward,
proppant fracturing was utilized but failed. The proppant turned out to be
embedded in a weak rock by damaging fracture conductivity. From 1986, an
operator company decided to use the “tip screenout” technique (TSO) in which a
high concentration of proppant is pumped into a wide fracture. although the tip is
mainly the final step to be packed with proppant in normal fracturing operations,
the proppant builds a pack close to the end of the fracture early in the “tip
screenout” treatment (Figure 8: "Tip Fracturing"). That is why its length cannot be
grown but width when additional pressure is applied to the formation.
These techniques were successfully executed in Indonesia. More than 30 wells had
been stimulated by the TSO treatment either
coated proppant or gravel packing. The
permeability of the previously damaged zone
exceeded 100 mD after the treatment despite
still having a positive skin value. Yet, the
results were sufficient by producing adequately
higher than those of wells stimulated by
conventional fracturing techniques (Peters &
Cooper, 1989). Another successful field
application of the TSO treatment was carried
out in the USA sector of the Gulf of Mexico.
The production improvement was noted with
the excess of roughly threefold increase over
the first one-year period (Ayoup, et al., 1992).

FIELD CASE: KERN RIVER FIELD IN USA

Table 7: “Tip Fracturing”
 21

From 1999 to 2000, a screenless TSO fracture treatment was applied in the Kern
River field which was situated in Bakersfield, California with nearly 3.5 billion
barrels of oil revenues (4th largest oil field in the USA). It comprised the alternating
sequences of unconsolidated sand with considerable sand with silts and clays. The
reservoir had 0.3 porosity and from 500 to 3,000 mD permeability. Wells were
operated by cyclic steam flooding since oil viscosity constituted around 4,000 cp.
More than 500 treatments were operated in 200 wells by tripling the production.
Huge experience was gained during these operations as a means to assess the
economic return on investment based on Net Present Value (NPV) and key
parameters, for example how pad or slurry volume can have an influence on
productivity improvement. (Bybee & Karen, 2002)

FIELD CASE: MASSIVE FRACTURING IN OMAN

In 2009, multiple massive hydraulic fracturing treatments had been applied in Athel
reservoir formation on Oman field which was the silicilyte reservoir with the
average of 0.02 mD permeability. To start production, economically sufficient rate
was required which was achieved by applying proppant hydraulic fracturing. The
development started with the crestal but moved to flanks till oil-water contact had
been reached, and this required to be made more advanced well completion design
(multilateral, horizontal) and stimulation techniques. Although the crestal had
better reservoir properties, the move to flanks zone was related to the development
of unconventional reserves. Non-uniform depletion in the crest of the field required
2 massive hydraulic fracturing, because of more favorable reservoir properties,
while flank areas were designed to be stimulated by 3 multiple massive fracturing.
More than 15 wells were stimulated over a 2-year period, and economically
positive results had been obtained in both sectors.
Figure 8 (a) indicates the frac campaigns in 2 wells; Well-14 in the crest, and
Well-22 in the flank by clearly showing similar positive production history over a
one year. However, Figure 8 (b) shows relatively different results for Well-21 and
Well-22 despite their locations in the flanks. This difference was observed in
several wells in the flanks with poor reservoir properties. That being considered,
advanced and more detailed study, and understanding and advanced diagnostic of
the reservoir should be carried out so as to maximize productivity and vertical
 22

coverage. However, by applying additional hydraulic stages (multiple stages) to

increase interval coverage, the incremental production could be achieved in the
flanks of unconventional reservoirs despite having poor properties and higher stress
contrasts.

Figure 8: Production History of Wells in the field (a) - Well 22 and 14 comparison; (b) - Well 22 and 21
comparison

FIELD CASE STUDY: CHANNEL FRACTURING IN SHALE

Gas wells in the ultra-low permeability (mostly expressed in nanodarcies)

Marcellus Shale, which was situated in the USA, has been estimated to have
roughly 170 tcf gas in place. So as to economically produce this gas, hydraulic
fracturing operations have been required. Channel Hydraulic Fracturing stimulation
– a new novel method that creates a network of conductive channels has been
primarily applied in this kind of low permeable reservoir to increase well
productivity. Channel Hydraulic Fracturing involves integration of geomechanical
modelling, and distinctive pumping and perforation approach so as to generate
network of open channels by increasing productivity by severalfold. Figure 11:
Representation of Channel Fracturing reveals how this stimulation looks like.
Approximately 1400 successful treatments have been applied in the USA`s
ultralow permeable fields including Eagle Ford Shale of Texas (Rhein, et al.,
2011), Bakken Shale of North Dakota, and Almind and Lance formations of
Wyoming (Johnson, et al., 2011).
 23

This technique has proved several benefits that increase productivity by creating
longer propped fracture lengths, effectively stimulated reservoir volumes. As well
as it allows for better clean-up procedures than conventional ones. The sensitivity
analysis of 1400 stimulations concluded that an average productivity increase of
23% was achieved in initial gas production in Marcellous tight gas reservoirs and
51% in Eagle Ford Shale gas (Ajayi, et al., 2011).

FIELD CASE: FRAC-PACK IN WIDURI FIELD OF JAVA SEA

Frac-packing is one of the most popular sand control techniques which is

associated with the fracturing treatment and proved to be a highly productive and
reliable technique. in 2000, the frac-pack method had been applied in the Widuri oil
field in the Java Sea, offshore, Indonesia. The reservoir was immature fluvial
sandstone with low pressure (1350 psi between 3500ft and 3600ft of pay zone) 0.29
porosity and 2mD permeability being moderate consolidated and showing sand
production tendency. During the drilling phase, more than 4,000 bbl of drilling
fluid and 700 bbls of LCM pills had been lost to the formation, giving rise to
excessive formation damage. That being considered, Frac-pack was aimed to use in
this low pressure and high kh (100,000 md-ft) formation. The long-term results of
productivity with an excess of 13.4 bpd/psi were favorably compared to nearby
wells with cased hole gravel pack (average PI of 2.3) and wells with open-hole
gravel pack (average PI of 10), therefore it was proved to be operationally visible
despite having high permeable formations.
However, the main disadvantage of Frac-Packs is that they can poorly be suited to
intervals close to water or gas contacts or where cement quality is poor. In addition,
Frac-Packs require much higher pump rates and fluid associated mixing and
pumping equipment. For example, Frac-Pack operations in the Gulf of Mexico and
Brazil were quite beneficial where existing mixing equipment was available
(Furgier, et al., 2007) although experience in the offshore South Tapti field of India
resulted in profitability (J.Holmes, et al., 2006). That being said, advanced
economic analyses are required before the decision.
 24

FIELD CASE: HYDRAULIC FRACTURING IN HTHP FIELD

Krishna-Godavari condensate field was located on the eastern coast of India. The
reservoir was thick sequences of sediments with good prospects of both tight gas
and tight oil. The main challenge there was high temperature of 400 F, a high
pressure over 10,000 psi, fluid and proppant stability to sustain HTHP, and no prior
stimulation history. After laboratory analysis of mineralogy, rock mech, and fluid
stability and proppant pack conductivity at reservoir condition, it was decided to
use hydraulic fracturing with 20/40 high strength proppant which was to
compensate for the loss in fracture width during proppant embedment. 2 treatments
had been applied in 2 productive zone with post-treatment production results
increasing by nearly 6-fold from 0.7 MMscfd to 4MMscfd. The production rate
was stabilized at around 3.9 MMscfd.

FIELD CASE: HYDRAULIC FRACTURING IN HTHP

CARBONATE FIELD

Another hydraulic fracturing case study in HTHP condition was carried out in
Saudi Arabia`s carbonate field with permeability of 0.01 mD and temperature of
nearly 300 F. Although the low permeability of this rich gas reservoir required the
hydraulic fracturing, sustaining fluid stability and proppant pack conductivity at
reservoir condition was the primary issue. Majority of fracturing treatments in
Saudi Arabia were performed with the help of water&surfactant-based borate-
crosslinked gel fluids which was not optimum choice for this HTHP field due to its
thermal and shear degradation at HT conditions. To conduct fracture campaign,
new metal crosslinked fluid based on CarboxyMethylHydroxyPropyl Guar
(CMHPG) polymers with Zirconate crosslinker were decided to use after successful
tests in laboratory. The application of a CMHPG fracture fluid in Saudi Arabia
tight gas field showed very good performance in high temperature reservoirs by
enhancing conductivity and productivity (Malik, et al., 2015). Additionally, new
system provides significant cost savings when replacing surfactant-based fracture
fluid system (Azizov, et al., 2015).
 25

CONCLUSION

In this report, the main focus areas have been concentrated on types of stimulation
techniques that have been massively applied, their applications in different
reservoirs with comprehensive analysis, and positive results of solutions with both
encouraging and undesirable sides. We have analyzed the field case studies for
Matrix Stimulation at different conditions, therefore we can conclude:
● With the precise evaluation of reservoir, completion, treatment design, and
compatibility of acid&additive systems with any fluids that they may contact,
the matrix acidizing is quite beneficial in carbonate reservoirs to open new
pathways and in sandstone to remove formation damage at even high
temperature and high-pressure condition.
● Especially the effectiveness of chelating agents can be highlighted in HTHP
carbonate reservoirs at roughly 400o F by providing a sufficient wormhole
network.
● Furthermore, the new VDA technique has proved the operational efficiencies,
quite an easy recovery, and well cleanup since the fibers can be definitely
broken or degraded by formation fluid when production is restored (only low
pressure is required to remove fibers). Even it has provided additional because
of its organic polymer chain.
● The formation damage around Gravel Pack can also be removed in by means of
several acid systems at even HT conditions.
In terms of the application of Hydraulic Fracturing, we can conclude that:
● Fracturing treatment can be applied in those reservoirs in which advanced
matrix treatments failed to restore the productivity, therefore profitability of the
project increases., yet this process requires comprehensive NODAL analysis of
a reservoir, specific design including selection of pump rates, fluid properties,
fracture propagation model, and knowledge about how formation will respond
to this treatment.
 26

● Especially, this method can be applied in reservoirs with excessive formation

damage which appears to be deep formation damage that dramatically reduced
formation permeability.
● As well as hydraulic fracturing can be combined with advanced completion
techniques to provide increased productivity and a way to effectively bypass
near wellbore damage.
● Additionally, the hydraulic fracturing can be used in low permeability reservoirs
to create highly conductive pathways for the flow of hydrocarbons through
them.
● Hydraulic fracturing can be applied in ultra-low permeability HTHP fields with
the use of proper gel fluids which can be the optimum choice for HTHP fields
due to its resistance against thermal and shear degradation at HT conditions.
● However, advanced and more detailed study and advanced diagnostics of the
reservoir should be carried out before any hydraulic fracturing stimulation so as
to prove that maximum benefit can be achieved with this treatment.
● Finally, the application of acid fracturing, which is a special type of stimulation
techniques, can be quite beneficial in low-permeable carbonate reservoirs with
the proper selection of treatment fluid and diverting elements.
 27

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Economides, M., 2000. Formation Damage: Origin, Diagnosis and Treatment Strategy. In: Reservoir Stimulation.
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Economides, M. J., Hil, A. D., Ehlig-Economides, C. & Zhu, D., 2013. Petroleum Production Systems. Boston:
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Golenkin, M., Khaliullov, I., Vereschagin, S. & Ovsyannikov, D., 2018. Progression Through Technology: Results
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Golenkin, M. Y. et al., 2017. First Implementation of Diversion Stimulation Service with Multimodal Particles in
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 28

Jauregui, et al., 2011. Successful Application of Novel Fiber Laden Self-diverting Acid System During Fracturing
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Jimenez-Bueno, O., Jesus, T., Torres, R. & Tellez, F., 2012. Pushing the limits: High Temperature Carbonate
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Kalabayev, R. & Kruglov, R., 2020. Combining Technologies Optimises Acid Stimulation: Field Case Studies in
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 29

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 30

APPENDIX 1: FIELD CASE STUDY OF JUJO-

TECOMINOACAN FIELD IN MEXICO

This field with 48 producers and 19 injection wells is located near Southern Mexico
and operated by PEMEX (Petroleos Mexicanos). The average depth of producing
intervals is around 16,400 ft. with 160 ° of reservoir temperature. The reservoirs are
naturally fractured with high permeability contrast that sometimes reached 1000/1
in producing intervals, and it was difficult to stimulate uniformly. So, the target
was to achieve uniform zonal coverage of the matrix stimulation. One typical well
which was stimulated by this technique, had 3,300 psi pressure, 0.05 to 0.08
porosity and very low permeability (1000mD to 3mD with 333/1 contrast). The
reason why this technique was applied is related to the low production. In this well,
the production was started in 2005 with 1,278 bbl/day. However, the production
declined within the next 3 years. In 2009 when PEMEX performed traditional
matrix treatment there, they achieve to increase the flow rate immediately but failed
to stabilize and continue the production in the same high level. Then, VDA was
applied and showed very great succession by exceeding the PEMEX`s prediction
(3,000 bbl/day). And after 3 months, the average production had been stabilized
around 2000 bbl/day (Martin, et al., 2010).
 31

APPENDIX 2: FIELD CASE STUDY OF SOUTH GHAWAR

FIELD IN SAUDI ARABIA

Most of the gas production in Saudi Arabia comes from this field which has 0.05 to
0.15 porosity and 0.5 to 10 mD permeability. Saudi Aramco engineers applied
VDA technique in roughly 25 wells with average 7,500 psi reservoir pressure. One
treatment in a cemented and perforated well, in which 19 stages were used, has
showed huge success. The production was 8 MMcf/day prior to the treatment but
23 MMcf/day after the treatment (Jauregui, et al., 2011). The excellent results were
observed in the majority of other wells of the Ghawar field with the savings from
480,000 $ to 600,000 $). From this application, VDA has been the best choice of
Saudi Aramco (Rahim, et al., 2010).

APPENDIX 3: FIELD CASE STUDY OF PIRAMBU FIELD OF

BRAZIL

The reservoir, which is located near Rio de Janeiro, was stimulated with the aid of
this technique. These was carbonate reservoir with 0.05 to 0.18 porosities and less
than 0.001 mD permeability which lies below a thick layer of evaporite minerals,
mainly salt. These extreme conditions have limited the use of matrix acidizing in
this area. The operator company however decided to use VDA technique with
MaxC O3 acid fiber diversion. After the treatment, results by execution of the
production logging were again better than predicted by the stimulator. (Beasley, et
al., 2010)

APPENDIX 4: FIELD CASE STUDY OF ACIDIZING OF HTHP

CARBONATE RESERVOIRS IN KAZAKHSTAN

Another noticeable field study of matrix stimulation in HTHP carbonate reservoir is

acid stimulation campaign in several Triassic reservoirs of Kazakhstan. The main
target of the field study here was to find the most effective approach to address
challenges with acid placement and reservoir contact in long pay zones of HTHP
carbonate reservoirs in long-term perspective, hence improve return on investment.
 32

Deep onshore reservoirs with heterogeneous porosity, permeability and damage

profile were preferred as candidate for detailed implementation and case study.
As the first step, the matrix acidizing with 15% HCl as the main acid and 15% HCl-
based polymer-gelled acid (PGA) as the chemical diverter were applied in the
subject oil fields. The average normalized PI increase was about 1.92 ×10−4 after the
stimulation which can be considered very low (Figure 4).
Secondly, it was decided to evaluate further actions to reach desired level of PI
increase by improving the reservoir contact. The key reason why previous acid
system could not achieve desired PI levels was possibly because of the high
reaction rate of conventional HCl + PGA system resulting poor production
performance in long term. To increase the reservoir contact, the 15% HCl + single-
phase retarted acid (SPRA) was developed which had resulted in 2.53 ×10−4 of the
average normalized PI increase after the stimulation (Figure 4). Another success of
the HCl + SPRA was the decrease of the total volume of acid to achieve the same
wormhole network compare to previous one.
Afterwards, the engineering team
continued to investigation and
achieved to discover the ways to
improve diversion efficiency by
applying a viscoelastic self-
diverting acid (VSDA) in the
system of HCl + SPRA + VSDA.
This combination also aided to
achieve less pH of the acid system
by resulting in longer wormhole,
20% less time of the formation
Figure 9: Summary of offset versus pilot wells` normalized
clean-up, and the normalized PI Productivity Index after stimulations
of 2.84 × 10 with skin factor of -
−4

4.6 (Figure 4) (Kalabayev & Kruglov, 2020).

Although stimulation results were already satisfactory, the further investigation of
use of combination VSDA and a degradable particulate diverter (DPD) were
carried out. The average normalized PI of 3.28 ×10−4 was achieved by maximizing
the diversion efficiency and wormhole profile. Based on the results of field tests of
these various types of acid stimulation in heterogeneous and hot carbonate
 33

reservoirs, some improvements can be highlighted in hydrocarbon production as

well as technical and operational benefits:
● Application of SPRA system enabled optimization of the wormhole network,
which was confirmed by core flood tests, post-stimulation PLTs, and by the
treatment execution pressure behaviors.
● Implementation of VSDA has resulted in reduced post stimulation formation
clean-up time which was confirmed by stimulation pressure response and flow
profile within post-stimulation.
● Addition of DPD system to the stimulation schedule improved the diversion
efficiency by achieving roughly uniform profile of wormhole extent.
● All of above factors have resulted in a rise in an incremental oil production.
Furthermore, continuation of this comprehensive treatment process in several other
carbonate oil fields of West-Kazakhstan region had been carried out as a means to
determine well performance of these techniques after the stimulation. The main
investigation had focused on the “cleaner” displacement fluid selection and
optimized design and schedule of the treatment. As a result of the field tests,
instead of linear gel, the use of an oil based- displacement fluid have been proved
to play a critical role to accelerate the production startup and well flow back after
the treatment. (Kalabayev & Kruglov, 2020). The efficiency of new acid systems
was verified with the aid of core-flow tests and 3D microtomography after the
stimulation by confirming 30% more efficient within acid fracturing and up to 44%
more efficient within matrix stimulation than conventional acid treatments.
(Abdrazakov, et al., 2018)

APPENDIX 5: FIELD CASE STUDY OF PRUDHOE BAY FIELD

IN USA

Fundamentally, it is considered by many petroleum engineers that much of today`s

thinking of the fracking3 has been inspired by Sohoi Petroleum Co.`s field
application in Prudhoe Bay in the middle of XX century. It was highly permeable
sandstone reservoir with originally 25 million barrels oil reserves. Although it does
not sound much like an environment conducive to the treatment technique, the
hydraulic fracturing treatment had been applied due to the severe and what appears
3
Fracking – Hydraulic fracturing is also called “fracking” in some western literatures.
 34

to be deep formation damage which dramatically reduced formation permeability

by nearly 2 times from 100 mD to less than 5 mD. The damaged wellbore which
required deep penetrating was initially stimulated by matrix acidizing treatment but
showed poor effectiveness. Thus, engineers decided to apply the hydraulic
fracturing. The results from this sandstone reservoir were great. Highly conductive
fracture stimulations had been able to maximize productivity by bypassing drilling
and completion damage. The post treatment`s total production rate has exceeded
100,000 bbl/day over 100 wells that were stimulated. The heavily damaged wells
had reached around 7-fold productivity increase. Another key lesson that was
learned from this field was proppant concentration (Figure 10). The Sohio job was
designed to place 1 lbm/f t 2 (modest rate) by today`s standards which aspire to place
4 lbm/f t (EJ, 1985) (Reimers & Clausen, 1991)
2

APPENDIX 6: HYDRAULIC FRACTURING

F
 35

Figure 11: Representation of Channel Fracturing