1. 2575150
Significant Production Improvement of UltraLow Permeability Granitic
Reservoirs to Develop Heavy Black Oil, Utilizing Channel Fracturing Technique
Authors; Mostafa Mahmoud Kortam1
; Samir Siso1
; Nelly Mohamed Abbas2
; Ahmed Salah1
;
Atef Hesam1
; Andrea.Cilli1
; Ahmad Kamar2
; Fatmaelzahraa Khafagy2
.
1
Petrobel, Egypt;
2
Schlumberger Egypt;
ABSTRACT
The development of low quality reservoirs such as; low permeability, marginal assets, and
unconventional resources has a several cost challenges pushing the industry toward maximizing the
potentiality and optimizing the strategies of such high risk plays.
Petrobel has a discovered one of such challenged asset and successfully conducted a comprehensive
study to set the best development strategy to unleash this potential. SIDRI Area is a relatively new
settlement with a reasonable hydrocarbon potential according to petrophysical analysis. The target
formation of SIDRI wells is a sedimentary rock with granitic facies that consist of a series of tight
conglomerates over an oil/water column of more than 900m. The pore system of this rigid and stiff
formation consists of a micro natural fractures network with secondary cemented porosity. The
production is mainly governed these tiny natural fractures that have a permeability as low as 0.1-0.5
md. Despite this tightness these series are separated by nonporous sections that occasionally exhibit
as barrier and may introduce layering or subdivision of pay, however in sometimes permit a vertical
communication between productive sections. Performed Cuttings analysis such as XRD, thin-sections
showed a variety of minerals composition representing different lithology which in turn complicates
the characterization of such reservoir.
On top of the unique mineralogy, the executions of fracturing treatment of SIDRI wells include
multiple other challenges. The higher reservoir temperature and the formation depth cause a great
constraint in terms of pumping rate and pressure. Besides, the non-availability of pumping equipment
of high Horsepower restricts the pump rates and also limits the utilization of slick water frac. Even
the nature and the quality of crude oil is quite challenged since it is a heavy black oil type and its
composition contains high number of asphaltenic compounds accordingly the opportunity of creating
sludge with treatment fluids is highly likely. The oil water viscosity ratio at reservoir condition
represents a weighted obstacle for oil recovery that should be overcome.

2. The basic concept of applying hydraulic fracturing for these kinds of reservoirs is very simple,
however the execution to get much more production improvement is quite difficult. Particularly the
main idea here is to conduct a cost effective fracturing treatment with economical wisdom principle
that can lead to achieve a greater oil recovery with best profitable model.
This paper presents the details of formation characterization and reservoir quality assessment, as well
as a detailed discussion about wettability alteration and how adversely complicates the process of
determining initial saturation. The implemented application including designing, experimental works,
and execution of the channel fracture treatment job will be reviewed. The work sequence of this
project that led to commercialize such asset will be addressed too.
INTRODUCTION
Abu Rudeis-Sidri Field is located in the western border of Sinai Peninsula, in the Gulf of Suez
Region. The Gulf of Suez is a Cainozoic rift with about 300 km wide and 80 km long. This field is a
mature oil land field and has been discovered back to 1948. The operator of this field is Belayim
Petroleum Company (PETROBEL) which is one of the biggest petroleum companies in Egypt
working in domain of hydrocarbons production and Exploration. PETROBEL is a joint venture
company between (EGPC-ENI) that has many oil and gas fields in Mediterranean Sea, Sinai, and
Nile Delta.
The production has started in the beginning of 1959 with total field oil production about 350 bpd.
Then after increasing the development wells and commencing water injection as secondary recovery
mechanism; the maximum production has been peaked in 2004 with total field production
approached 8,000 bpd. Later on the field has subjected to decline although the program of
development was still running till reached 6,000 bpd in 2014.
Fig. 1: Abu Rudeis-Sidri Field, Gulf of Suez, and its offset fields; geographic Location map
After performing the final history match and calibrating reservoir model the total field potential has
been estimated with indicating huge original oil in place STOOIP split over all reservoirs belong to

3. Fig. 2: field Structure Map with proposed well locations.
this field. Although the actual recovered reserves were only 13 % of to date of study (Jan 2014), the
ultimate recoverable reserves were not that big. Since the output of this study with the existing well
constraints without adding new wells or increasing the current off take will recover around 78 , and
88 MMSTB cumulative oil productions till 2030 , 2050 respectively, representing 19 % , 21 %
recovery factor. With such obtained results an optimized plan was generated to develop this field on a
commercial way taking into considerations all expected problem starting from drilling till production.
So that with the current existing wells and adding another 12 new infill wells, and another 4
Appraisal wells, 4 Exploratory wells, 9 Contingent Wells, will recover around a reasonable
cumulative oil productions till 2050 representing 31 % as an ultimate recovery factor. Finally the
proposed new wells to be drilled are 29 wells.
The new development strategy has been boosted and a spots were turned to ARM & SIDRI areas in
particular the last two years when the
company announced about results of Res.
study. Since a good discovery of a commercial
oil volumes in a basaltic intrusion in the first
well of this campaign, as well as the
remaining volume that was predicted from
Study output an additional 12 wells have been
drilled in ARM area, 3 new wells in ARMW
area, 4 new wells in Sidri area searching for
the oil in both of the basaltic intrusion as
secondary target and in Nukhul formation as a
primary target. As it is illustrated in (Fig.2)
which shows the distribution of well locations
in SIDRI area (the eastern side of the field),
and also in ARM area (that covers the western
side).
The development plan has been implemented immediately in the middle of 2014, and the drilling
activities were commenced to support the field production profile. Apparently in no time the
production has revered again and increased greatly achieving new record with a higher peak that was
almost 16,000 bpd in 2015.
This remarkable achievement is thanks to the execution of a comprehensive reservoir study in
addition to an optimization and improvement that was applied in the drilling operations. Such
combination led to such accomplished success in short time.

4. In the next discussion a brief description about geological background of whole region, and also
reservoir aspects will be addressed just to figure out the overall field conditions and circumstances.
AR Field Geological Set Up
Abu Rudeis-Sidri Field is located partly offshore Sinai. All of the wells are being drilled from shore
land as vertical and deviated wells. The first reservoir from surface or the shallowest reservoir in the
field is Nukhul formation. (Oligocene age), represented by conglomerates and beach deposits. The
number of wells that were produced or completed are 55 wells, out of a total of 85 wells drilled in the
area, representing 64 % of total drilled wells up to date (Aug-2016).
The evolution of the Gulf of Suez was characterized in pre-Miocene time, by a quite homogeneous
sedimentation history with no big areal thickness variation. Then, starting from Late Oligocene, a
strong tectonic activity began as a consequence of the extension induced by rifting; this resulted in
the tilting of the rift borders with a huge sedimentation in the deepest part. The presence of “clysmic
alignments” (NW-SE) along the rift axis interrupted its continuity with a series of highs and lows.
Fig. 3: Total A/R oil field production charts (gross rate, water cut, oil daily rate, Cum oil) showing that a peak at
the last period starting from mid of 2014

5. The stratigraphic sequence comprises Palaeozoic to Oligocene as pre-rift deposits, then from Lower
to Middle Miocene as syn-rift deposits, and ended with Late Miocene to Recent post-rift sediments.
The field contains several fault bounded blocks tilted toward the main Coastal Fault. The
geomorphology of areas undergoing lithospheric extension show a strong relationship to the
underlying structural geometry This relationship is most clearly displayed along major normal faults,
where footwall blocks act as sediment sources for subsiding hanging-wall basins. In these areas,
emergent of stream channels into the basins commonly results in the development of alluvial fans in
subaerial settings or fan deltas where the basin is marine or lacustrine. In the area, three main tectono-
stratigraphic units can be recognized: the Precambrian Basement, a pre-rifi sequence represented by
Nubian sandstones and Cretaceous to Eocene clastics and carbonates, and a Late Oligocene to
Holocene synrift sequence. Marine conditions were established sooner.
Accordingly the Gulf of Suez corresponds to a NW-SE elongate rift basin of Miocene age with
transversal accommodation zones separating three segments with opposite asymmetry. The master
fault of the central segment is situated at the north-eastern margin of the basin, while for the northern
and southern segments it is at the south-western basin margin. It is worth to mention that of the
challenged aspects of this field is the complexity of its geometry, since reservoirs topography have a
different structure elements that would make the formation tops vary in unpredictable way.
As it is shown in (Fig. 5), the main reservoirs by which the production is obtained are the following:
 Nukhul Formation (Oligocene to Early-Miocene); which is basically sandstone reservoir
locates in the form of conglomerate facieses with clay interbeds.
 Matulla Formation (Lower Senonian); mixed lithology: sandstone, limestone and dolomite
with clay interbeds.
Fig. 4: Gulf of Suez lateral cross section showing all blocks resulted from tectonic activities.

6.  Wata Formation (Turonian); mixed lithology: sandstone, limestone and dolomite with clay
interbeds.
 Nubia Formation (Cambrian to Apatian); Pure Sandstone reservoir with well-rounded and
sorted sizes and good porosity representing high quality facies.
 Igneous Rock (igneous intrusion); basaltic rocks that was created during igneous activities
and exist in form of sill and dyke. It is fractured set up with non-uniform thickness distribution.
Newly Discovered Unconventional Asset
Focusing here on the new asset that has been discovered recently and consequently it opened a new
horizon.
Upon the above discussion, and after defining the proposal of new wells, one of SIDRI wells that
penetrated section of Pre-Miocene, has encountered a different formation lithology with a challenged
logging responses by which a great effort was exerted in order to evaluate and characterize such new
formation.
Fig.5: Gulf of Suez Schematic Stratigraphic Record

7. In the below map Fig.6 shows the position of well SID-18 that targeted Nukhul formation and was
planned to intercept the zone in a separate block. The well position locates closer to the basement line
where a great sealing fault that defined the trap of the reservoir.
The well is planned to be drilled with a maximum inclination of 17 degree, then after passing Nukhul
formation, the well has crossed a new formation with anomalous response in terms of drilling
performance, and logging data. This new section formation which was encountered is basically
deposited grains of conglomerate facies of basal Miocene section. The lithology was identified as
granitic & basaltic fragments that were driven from nearby Basement.
The Mud-log descriptions were carefully looked at to determine possible mineralogy, which was key
during lithology modeling the cuttings analysis suggest the basement lithology consists of fragments
of the following: Silica (Quartz) , Feldspar (Orthoclase/K-Feldspar), and Mica (Biotite).
As displayed in Fig 6 the gas reading has been detected in the bottom part of drilled section, and low
rate of penetration was experienced during drilling of such complicated formation.
Fig.6: Structure map of Nukhul formations with well location.

8. Going deeply through reviewing the performed analysis that has been utilized a several Thin Section
(TS) Analysis Petrographic over collected drilling cuttings. Two samples is addressed here to give an
idea about the nature of this new formation
1. Analysis of First Sample;
Lithology: representing ≈ 100% by volume.
Textural Description: Coarse-grained size, equigranular texture, with presence of plutonic acidic
igneous rock (Intrusive).
Components: - The rock composed of dominant amounts of plagioclase and K-feldspars.
- Minor to common amounts of quartz grains and few grains are slightly bended
800 m
interval
height
Fig.7: Mud logging data of well SID-18

9. - Pyroxenes are locally observed.
- Rare quantities chlorite, hornblende, secondary silica, calcite and epidote
- Some fractures are completely filled with calcite.
Porosity diagnosis: Rare amounts of secondary intraparticle and fracture porosity, with poor
reservoir quality.
2. Analysis of Second Sample;
Lithology: The sample consists of different lithologies including:
• Granite, representing ≈ 75% by volume.
• Microgranite, representing ≈ 15% by volume.
• Metagranite, representing ≈ 10% by volume.
Textural Description: Coarse-grained size, equigranular texture and plutonic acidic igneous rock
(Intrusive).
Fig.8: Photo of Thin section analysis that collected from drilled Cuttings (Sample No.1)

10. Components: - The rock in composed of dominant amounts of plagioclase and K-feldspars.
- Minor to common amounts of quartz grains and few grains are slightly bended due to high
pressure.
- Rare quantities chlorite, hornblende, secondary silica, calcite and epidote.
Porosity diagnosis: Rare to minor amounts of fracture porosity, with poor to moderate reservoir
quality. With rare amounts of fracture porosity, that indicates poor reservoir quality. The rock is
metamorphosed granite showing foliation texture.
Another investigation was made over the cuttings by applying Analysis obtained by X-Ray
diffraction for whole rock samples in order to evaluate the formation properly. Table.2 shows the
mineralogy that forms the lithology of this new formation.
Interval Composition (wt%) Total
[wt%]
Smectite Chlorite Quartz Plagioclase
Feldspars
Mica Amphibole Fayalite Augite Magnetite
Upper - 7.22 27.65 22.21 21.66 9.03 3.40 6.93 1.90 100
Middle - 6.95 24.60 23.45 16.41 6.22 3.90 18.47 - 100
Bottom 4.31 - 27.17 27.25 23.93 7.72 4.19 5.43 - 100
Fig.9: Photo of Thin section analysis that collected from drilled Cuttings (Sample No.2)
Fig.9: Photo of Thin section analysis that collected from drilled Cuttings (Sample No.2)
Table 1: XRD data of Cuttings

11. Formation Evaluation utilizing wireline formation tester
Several points were tested through using
wireline formation tester, with oil-base mud
filtered that has relatively acceptable viscosity,
yet measured mobility values were quite low.
Also there is no Valid points were acquired
across the upper zone of pay as it showed in
table no. 2. Few valid points were acquired in
the lower interval showed a water gradient of
0.4492 psi/ft. Only mobility range above 0.1
mD/cP is considered for further analysis.
Conclusively the formation showed an ultra-low
permeability.
M psia (psia) (F) md/cp
x740.5 4261 N/A 211 TIGHT TEST
x906.7 4457 N/A 216 TIGHT TEST
x519.2 4694 N/A TIGHT TEST
x048.1 4703 4435.3 200 0.009 Normal Test
x115.4 4815 4533.5 207 0.009 Normal Test
x151.3 4860 4593.3 212 0.002 Normal Test
x196.7 4940 4657 219 0.022 Normal Test
x213.6 4970 4813.5 221
NOT
STABILIZED
x250.0 5020 N/A 222 TIGHT TEST
x282.4 5070 N/A 223 TIGHT TEST
x292.4 5077 4825.8 224 0.013 Normal Test
x302.4 5092 N/A 225 TIGHT TEST
Comments
x172.8 4876 4608.7 216 0.373
Sample grad.=0.933=
0.4PSI/FT
Depth ssl
Hydrostatic
Press.
F. Press. Temp. Mobility Zone
Fig.10: Recorded pressure points in well SID-18
Table 2: measured Pressure points of well SID-18 in the granitic section

12. Down hole sable was acquired but due to the tightness of formation the sample showed a high content
of mud invasion by which no much valuable information is added.
Logging processing
Different logging tools were run for adequatly analysing the formation in order to define the most
evaluate the oil content (check appendix fig. ). Starting from nulcuar magnetic resonance log where
T2 cutoff were characterized for basement lithology, but here were some difficults to accurately
differentiate between bound and free fluid , the caluclated permeabilities are qualitatively
comparable, but difficult to calibrate due to low number of valid formation tester points and their
spacing (Fig.11)
The resistivity image log along with dipole sonic were analyzed to chracterize the formation features
and to define sedmintological enviroment and the following is the observed points were challenged
and affected on formation chracterization process;
1. Generally, image resolution ranged from fair to good with borehole coverage < 60% due to
drilling with oil base mud.
2. Some localized washouts and pads mismatch/overlapping affected the confidence of the manual
dip picking of features (i.e. fractures) within those intervals.
3. The drilling environment where OBM was used affected the ability to identify breakouts and
drilling induced fractures.
4. There was no obvious signature as they were filled with resistive OBM from Borehole
radius/calipers which support this picking were not conclusive & showed minimal separation.
Permeability obtained from
mobility value that was
measured during pressure
point records of formation
tester tool.
Calc. permeability
matching with RDT points
and T2 distribution “free
fluid” present corresponds
to increase in permeability.
A decent match between
NMR and Calc. porosities
also present.
Fig.11: Section of integrated logs & Processed log of well SID-18

13. From a Geomechanics point of view the mechanical aspects of formation were assessed too, the
stresses in the wellbore were almost homogeneous, the
following points were considered in
- When Hydraulic fracturing is being applied, it is
better to choose a zone where both good completion
quality and good reservoir quality exist. Natural
fractures (blue in the color map Flag of Fig.13) may
have an effect the hydraulic fracturing geometry and
breakdown pressures so it was important to consider
them in determining the perforation intervals
- As there was extensional/normal (green in the
color map Flag) and strike slip stress regimes (yellow in
in the color map Flag), it was preferred to place fracture
in areas with an extensional/normal regime. In strike
slip regime, the fracturing may experience tortuosity
and post fracturing production problems
- In order to calculate more accurate stresses and
stress barrier magnitudes, 3D sonic anisotropy was
necessary; such data was not available for Sidri-18.
Some
localized
washout
Overlapping
Image
Fig.12: Section of resistivity image logs that was recorded in water base mud showing some issues
during the logging operations due to formation nature and well hole profile
Fig.13: Stress evaluation model of well SID-18

14. Fig.14: integrated formation evaluation of well SID-18, showing the selected interval that bounded with black box.

15. Choosing Suitable Perforation
After conducting a deep analysis exploiting all available data and after performing integration with
mud logging, drilling parameters, pressure point data, and so on. A preliminary prof about
hydrocarbon presence was suggested, since over 800 m TV height, 450 m were sorted out to be oil
pay as it illustrated in Fig.14. So that a decision was taking to start testing part of this new pay and in
case of the results were positive, stimulation job using hydraulic fracturing will be executed to bring
the production at economical limits. The perforated interval selection process was challenged since it
was considered to support further stimulation via Hydraulic fracturing which necessitate to
minimizing perforation interval as low as possible with the limits allow for pumping fracturing
treatment in a suitable way. At the same time, as the longer perf interval as preferred situation, that
sufficiently enables for adequate testing and give much more coverage than shorter interval. At the
end a 30 m of perforation was decided as compromised length.
The chosen interval as it depicted in Fig.13, were perforated first and a great drawdown were applied
in order to confirm oil presence. With about 80 % differential pressure only some traces of oil were
able to be produced. Such poor influx indicates the low quality reservoir and supporting the idea of
ultra-low permeability rook.
Accordingly a great effort has to be exerted in order to put the well on production within the
economic margin.
Meeting Technical Challenges With Novel Approaches
This section is challenging the original concept of hydraulic fracturing by reviewing the proposed
techniques and technologies that was tested before and became a field proven, with an explanation
about working mechanism of these innovative solutions.
1). Channel Fracturing Technique
Now the proposed state-of-the-art fracturing practice is to crate void areas inside the fracture
while filling the rest of fracture with a multilayer pack of spherical or cylindrical particles and form
such voids in continuous symmetric profile to form channel like shape. By which in the dynamic
conditions the flow will be throughput channels instead of proppant interparticles space “proppant
Pack” that known as proppant pack, that maximize total fracture conductivity, that what is so-called
"Flow Channel Fracturing".
This concept had changed by developing and applying the flow channel hydraulic fracturing
technique instead of flowing entirely through a proppant pack, hydrocarbons flow through these
channels increasing conductivity by orders of magnitude.
Channel fracturing is a hydraulic fracturing stimulation technique that relies on the intermittent
pumping of proppant-laden and proppant-free gelled fluid at a high frequency to promote
heterogeneous placement of proppant and generation of open channels throughout the proppant pack
(Gillard et al., 2010; Medvedev et al., 2010; Valenzuela et al., 2012).
The new fracturing method fundamentally include the of placing a mixture of fibrous bundles mixed
with proppant in the fracture fluids slurry and being injected intermittently in pulsed manner of

16. crosslinkable proppant-free spacer fluid to generate a conglomerate of proppant masses surrounded or
suspended by proppant-free gel slugs. This achieved by pumping with high frequency of alternating
of paroppant slurry cycle "dirty" and proppant free slurry cycle "clean" in a repeated sequence for
different proppant concentration stages, then with continuing pumping the proppant conglomerates
sequence discharge into the created fracture. These spaced proppant conglomerates pods are
distributed over the fracture face in a pattern of irregularly shaped pillars. Ending the treatment by
pumping continuous proppant stage before flush without pulsation which is acting as proppant bank
and defined as "tail-in" meanwhile the fracture is propagating and expanded in the formation.
Once the mixture of fibrous bundles and proppant conglomerates is placed in the fractures, The
spacer fluid containing fiber should remain crosslinked to support the proppant patches until the
fracture is allowed to close on the mixture by the termination of the fracturing fluid flow and pressure
exerted on the formation along With the breaking of the viscous fracturing fluids is caused to be
reverted into thinner viscous fluids gel slugs were broken and removed from the propped channeled
fracture and returned to the surface. Following this, the fibers also decouple and degrade
subsequently leave their places empty which is creating voids and flow channels within propped
fracture and this accompanied with gathered proppant particles in the interior of fracture to form
bonds and connect in response to closure act and since proppant material has higher strength than
applied stress resulted from formation walls the fracture will stop closing on formed beds of proppant
pods that are trapped in place and supporting fracture faces from being collapsed.
Upon this the closure load the fracture are not in contact with each other for some distance away from
the edge of the proppant bed because of the support given by the proppant pods, thus it acts as a
width pivotal that what is so-called "pillars".
Hence relaying on the presence of these pillars which is scattered within created fracture in
discontinuous profile having capability to prevent the fractures from closing, besides formation
stiffness tends to keep fracture open for limited critical length at caused by absence of proppant
between each surrounding pillar, a highly conductive channels are created and permanently formed
through which produced fluids can readily flow.
It is highly recommended to ensure pumping of a continuous proppant “tail-in" stage towards the end
of the job before the flush stage
this tail-in guarantees the existence
of propping agent at the near
wellbore region against the in-situ
stress mounted in disjointed
formation walls which were
cracked as a result of hydraulic
fracturing. This tail-in ascertain
good connectivity between
wellbore and the channel space
created. This stage is normally
longer duration and pumped as
high as proppant concentration of
previous proppant PPA stage.
As explained by in order to ensure
that the fracture stay opened and the distance between pillars do not pinch in between when fluid
pressure decline during leak-off period the duration of pulse “cycle time steps” must be chosen
Fig.15 Approximated perception of Conventional fracturing shape vs
Flow Channel fracturing technology. (Coursterytesy of Schlumberger)

17. carefully based on rock mechanical properties and geomechanics of formation. The time cycling
governs the separation between created proppant pillars that as a result define space between each
pillar and drew the distance of channel paths. It was desired that the formation has high value of
Young’s modulus and low minimum horizontal in situ stress by which it can bear exerted formation
load, however this rule became might be less weighty, since channel fracture has been applied for all
formation categories. Formation stiffness withstands bending stress on the rock avoid pinching or
closing of open channels after frac fluids in these channels has leaked off and this compensates
nonexistence of proppant against the formation walls. As constant as time period or time steps of
each cycle “Equal Pulsation” as getting smoothed and uniform channel paths. Normally this is
optimum for hard rock and in case of dealing with soft formations this cycling time should be adapted
and increase pulsing frequency of pulses must be applied.
Stressing again about the importance of rule particularly for treating high perm reservoirs, while
some modification might be happened for low perm or tight reservoirs that utilize channel fracturing
for increasing frac half-length and design the perforation of entire pay totally leading to deliver final
channel fracture structure to be on different regime as the alignment of pillars will be formed as
parallel stripes or columns like-hood which is so-called “Zippra Frac”. However, such modification
does not provide the highest conductivity, this kinde of channel structure will not affect for fracture
performance since it is not required for low perm formations to target greater conductivity.
This technique is less risky in execution since the proppant-free spacer sweeps and mitigates the
proppant buildup in the near-wellbore (NWB) area. The presence of clean pulses around proppant
structures and fibers inside the slurry provide bridging effect that eliminate accumulation of proppant
in the perforation tunnels in addition to a reduction in the use of proppant leading to the elimination
of the occurrence of screen-outs during placement.
The applicability of this technology from operation side does not have any complexity the blender’s
components, hardware devices, and software programs are capable to handle the pulsing process,
which is accomplished Operationally this can be achieved due to the modifications done to the
blender gate at which the blender’s gate is controlled in a manner to open and close during the
treatment.
In summary, the mechanism of this technology is basically comprised of many steps; pumping a
mixture of fibrous bundles and proppant, then placing a mixture of fibrous bundles and proppant in a
fracture while maintaining the fracture open, and after that allowing the fracture to close on the
mixture. The last step is the fibers decouple from the mixture and degrade creating permanent opened
channels within the proppant pack with surrounding pillars that hold channel structure.
2). Degradable Fiber Technology
The deformable fibrous bundles are commonly used in oil field application such as diversion
fluid agents in matrix acidizing treatments, fluid-loss material to cure lost circulation caused by the
presence of natural fractures in drilling fluids and The fiber system is deployed either in a spacer
ahead of cementing slurries.
The employment of such products started for hydraulic fracturing as proppant flow-back inhibiting
material till the idea of channel fracturing emerged and since this it was subjected to a modification

18. Fig16. Schematic effect of fiber in stabilizing
proppant conglomerates while transporting into
formation reflecting deliverability function of
fiber.
and developed properly by altering it to its nature of thermal degradation with time and it has been
utilized in highly effective purpose.
The main basic functions of degradable Fiber are;
 Banding of proppant conglomerates during transportation.
 Temporary Filling material.
 Controlling fracturing fluid loss.
1. Banding of proppant conglomerates during transportation
Primarily it is used as proppant conglomerates
transporting agent in conjunction with fluid viscosity
to maintain slurry stability during the transportation of
the proppant particles thru increasing suspension of
pumped proppant specially before crosslinking of
slurry in case of delayed crosslinker is used which
normally is happened at the well-topside. This product
possess a higher carring capacity thus reduces
proppant settlement in the bottom of well, eliminating
proppant lost in the sump hole “below bottom
perforation”.
Self-degradable fiber can also be used as part of
the spacer fluid to help ensure the separation of
conglomerates of proppant- pods “slugs” or "patches"
during their movements in the wellbore in turn this
avoids gravity segregation effect between proppant
patch and clean spacer patch in turn prevents
communication "coming together" of each proppant
pod patch. Accordingly proppant patches are being
transmitted safely upon the function of fibers that
prevents the dispersion of the proppant pulses while they are being conveyed through the treating
equipment, along the well completion and into the fracture, as well as resist settling down inside frac
geometry therefore segregation in the wellbore and proppant pillar distortion are overcame.
Fibers usually are connected together and form a lattice which is a fiber-based network within the
fracturing fluid surrounding the proppant providing cohesive forces by which increase
conglomeration of proppant particles without affecting stability of these Proppant particles patches
and avoiding them from coalescence without affecting pulses stability. Exclusively this material
offers a mechanical means to transport, suspend, and place the
proppant in effective way.
2. Temporary Filling material
The employment of fibrous bundles involves placing a significantly
reduced volume of proppants in a fracture to create a propped
fracture having high porosity, fracture permeability, or
conductivity. The reduced volume of proppants may be
consolidated, in certain conditions, to form individual
Fig17. Real photo of Cellulose
acetate fiber.

19. conglomerates group of particles (proppant pillars structures) that keep the fracture open.
After placing proppant and being deposited in the formation followed by ceasing the pumping,
fibrous bundles fills the created fracture and occupy voids or channels located within the proppant
patches "pillars and provides a cohesion force in order to maintains the fracture open and hold it until
fracture closes on a propped patches "pillars" owing to applied horizontal stress. Then after reaching
the maturation of closure and by equalizing forces a stabilization in fracture dimensions occur, these
fibers start to degrade and dissolve gradually over sufficient time by converting into micro particles
that can be flown easily during flow back cleanup, or during production of the well leaving their
place inside the fracture wings clear and empty without any significant residue that can make a flow
impedance leading to deliver highly conductive open channels. . 6, 32, 33, 34
3. Controlling fracturing fluid loss
Has a great impact in reducing the effect of formation damage in highly permeable by decreasing
amount of fluid losses. Fluid loss Generally are fluid Leak-off, and Spurt loss and it is property of
both the rock and the fluid however major effect is dominated from rock permeability. Spurt is
usually defined as fluid volume that leaks off rapidly as the fracturing fluid first contacts the fracture
face, before a filter cake forms to improve fluid-loss control. Since the recent analysis applied for
high-permeability wells showed massive damaged resulted from very large volumes of spurt loss
with longer spurt times that came from nonwall-building “filter cake” fluids.
Upon that the fiber material bridge over formation faces in the frac edges providing an excellent
control over fracturing fluid losses saving the formation permeability. The employment of fiber
exceeded pulsing stages and recently it has been involved in pad stage for extremely low fracturing
fluid efficiency instead of increasing gel loading to increase fluid viscosity which may encounters
formation damage.
The fiber material has various cross sectional shapes such as circular, rectangular or other shape. In
addition, the fibers must have a reasonable degree of stiffness hold the fracture open during closure
period. Generally, individual fibers have lengths in the range of from about 0.33 to about 1 inch and
diameters in the range of from about 10 to about 1,000 micrometers.
This Present degradable fiber usually disperses readily in most of fracturing fluid systems include
gelled Water or oil base liquids, foams and emulsions. It is fully compatible with standard surface
mixing in the blender, and pumping equipment. The suspension of the mixture of fibrous bundles
accomplished by Fibers are pumped on the fly they are not batch mixed they are pumped through the
dry additive screw fiber of the blender.
Approximately all types of proppant are compatible with this fibers and it should not be any
constraint for proppant size since it has been used for a broadband of a particle size in the range of
from 2 to 400 U.S mesh scale.
3) Rod-shaped proppants
A sintered rod-shaped proppant is a needle of cylindrical
geometry and possesses the following features;
 Higher conductivity
 Proppant Flowback preventer
 Higher compressional strength
Fig18: photo of Rod-shaped proppant

20. i. Higher conductivity
The shape of the proppant has a significant impact on how it packs with other proppant particles and
the surrounding area. Thus, the shape of the proppant can significantly alter the permeability and
conductivity of a proppant pack in a fracture. Different shapes of the same material offer different
strengths and resistance to closure stress. proppant particles become too tightly packed, they may
actually inhibit the flow of the oil or natural gas rather than increase it, as described by Alary, and
Jean Adre in European patent No 2,500,395 A2.
The conventional wisdom in the industry is that spherical pellets of uniform size are the most
effective proppant body shape to maximize the permeability of the fracture according to evaluation of
roundness and sphericity as measured on the Krumbein scale. However, other shapes have been
suggested in the art. For example, as claimed in U.S. Patent No. 3,497,008 to Graham et al. disclose
the use of particles having linear, parallel, opposite surface elements including cylinders, rods,
paralellepipeds, prisms, cubes, plates, and various other solids of both regular and irregular
configuration.
The degree of success of a fracturing operation depends upon the resultant fracture porosity hence
conductivity, and the porosity of the resultant packed, propped fracture is then at least partially
related to the interconnected interstitial spaces between the adjoining proppant particulates.
Nevertheless the geometric character of grains permeable pore space is in reality quite complicated,
and may vary greatly from one proppant type to another.
It is obvious that such kind of particles packing gives the highest porosity value. This model may
though, be used in the situation of rod shape proppant. Depending on this interparticles porosity the
greater permeability can be obtained for propping agents have elongated shape. The isotropic shape
of spherical pellets, identical in every direction will naturally reach high compaction leaving little
space between the pellets. While in the case of cylinder, the anisotropic shape the shape not being the
same on each axis generates naturally large no of possible packing of interior pores even after
compression.
Furthermore the direction along the long axes of grains will have larger pathways and therefore
greater permeability than the direction that is parallel to the long axes. Because of The impact of
cylindrical shape pellets on the pore size distribution can be assessed in similar way cylindrical
shaped pellets with similar diameter like spheres having length over diameter ratio about 3 will have
equivalent volume of spherical pellet that is 40% larger in diameter, that what is so-called “Native
Interstitial permeability”.
Lucky the arrangement of the rod shape proppant particles inside the fracture is in disorder manner
and generally the packing is random and by definition this yields to provide more porosity and
consequently higher conductivity
As shown below comparison between geometric packing and random packing in both 2D and 3 D
views which illustrates the great effect of proppant shape on fluid flow paths.

21. This function is extremely important and optimum for high perm formations since any attempts to
increase propped fracture portion will tremendously rise up conductivity and support fracturing
potential in high permeability reservoirs.
ii. Proppant Flowback preventer
The non-ability to flow the proppant attributes to its rod structure; therefore the grains do not fit
together very well and makes interlocking mechanism depending on mechanical interference between
particles and each other (based on Edelman et al., 2013).
Flow back control “anti-flowback gent” property of rod-shaped proppants is a primary consequence
of changing the particle shape its inherent characterizes and impacting its packing behavior and the
interaction between pellets. The configuration of pellets with random alignment of rod shape reduces
the ability on the pack when compression is increased as an expected response for the unique
interlocking of the rod-shaped particles. This configuration reduces ability of pellets to move relative
to one other to minimize applied stress on the pack. By increasing compression stress at the case of
random alignment of rod packing and this acting on lowering mobility of rod proppant to move and
resist dragging forces exerted by fluid flow.
This function is strongly preferred for low stresses formations since they frequently suffer from
flowing Proppant back to the well bore despite diminishing fracture efficiency it cause artificial lift
failure.
Fig.20: 3D packing of different types of proppant, left: spherical proppant of same particle sizes .Middle:
spherical proppant with different sizes, Left: Rod-shape proppant arrangement
Fig19: 2D showing differences in porosity resulted from arrangement of spherical and elongated
proppant. Right side: is the packing in side view, while Left: packing in top view

22. iii. Higher strength
The most crucial prosperity of this proppant type the high compressive strength that capable of a
withstanding high compressive forces often greater than 10,000 psi with a little effect on the fracture
conductivity comparable with spherical intermediate strength proppant.
According to E.Patent No 2500 395A2 of Alary, Jean Adre, the designed sintered rod has a parallel
bounding planes that are substantially circular, where the circular planes have an average diameter of
between about 0.5 mm and 1.5 mm. Sintered rods have a length of up to about 20 mm, preferably up
to 10 mm.
Rods particles have "substantially semi uniform length,” plus or minus 20%. Sintered rod dimensions
may have a length to width ratio (this term is also intended to encompass the length to diameter ratio,
if the rod has a circular cross-section) between about (1.5:1 to 7:1). However, it is preferable to
restrict the length to width
ratio from about (2:1 to 4:1),
at any case, the rod must
have a length to width ratio
of greater than 1:1. This
because the elongated shape
inherently introduces more
disorder into the proppant
pack, which increases void
spaces between the proppants
and in turn increases the
conductivity of the proppant
pack.
The required Perforation scheme to accommodate rod shape proppant can be any gun size has
Perforation density of 5 SPF with any phasing degree and entrance hole of 0.465" without any
limitation for tunnel penetration, such perforation profile can be utilized to house this kind of
proppant up to 10 ppg as tail-in in channel flow fracturing.
Field Implementation& Execution of technology
As it stated in the earlier section, after perforating 30 m in the conglomerate section and during the
lifting of well; it was found a traces of oil and very low permability has been indicated.
The decision of performing channel fracturing technology accompanied with rod shape proppant was
made. A new test was conducted post frac job to assess the improvement of channel fracturing
technology. The results is showing in Fig.22 where the performance of lifting was very poor (green
line) while a better performance was obtained during lifting time after frac job (red line). The applied
drawdown post frac job was less than it was before frac, in addition to the influx was greater than it
Fig.21: comparison of retained conductivity for rod shape, ISP 8/14, and ISP 12/18
Under test condition of; gel loading 40 gpt Without breaker , proppant laod of 2
ibm/ft2, proppant concentration 8 ppg, 4,000 psi applied closure stress at temp of 176
°F between Ohio sandstone cores with 2% KCL. (Courtesy of Schlumberger)
Rod shape ISP 8/14 ISP 12/18

23. was before frac. Also the buildup was faster and stabilized in quicker time than it happened before frac
job.
Accordingly the performed channel hydraulic fracture job was successful, depending on post frac
lifting test where good results were obtained and improved productivity was gained. The estimated
fold of increase is about 10 times.
As per charts of Fig.23&24 the well was put on production with a stabilized performance except the
water production which behaves in anomalous trends. The average parameters are as the following;
• Gross Rate = 70 - 45 m3
/d
• Water Cut: 20% (blue line in Fig 22)
• Net Oil Rate: = 55-35 m3
/d
• produced Water Salinity: 70,000 ppm
• Initial Res Press: 3910 psia at ESP setting depth
• Pwf = 1000 psia at ESP setting depth (blue line in Fig 23)
• Delta P = 2910 psi (76%)
• Estimated Productivity index before stimulation= 0.018 b/d/psia
• Estimated Productivity index after stimulation= 0.16 b/d/psia
Fig.22: Comparison of drawdown and buildup tests at two different conditions; before fracturing (green
curve), post fracturing (red curve)

24. Fig.23: The upper chart is a Cartesian plot of percentage water cut (blue clor)also the salinity is being displayed in
red color, while the lower chart is the daily gross fluid production
Fig.23: The chart of ESP performance that measured at downhole conditions contains intake pressure& temp. of
pump, as well as discharge pressure& temp. of pump

25. The story didn’t finish yet, based on the stabilized production of the conglomerate reservoir in
SIDRI-18 and in order to further appraise and evaluate the conglomeratic reservoir by acquiring more
reservoir information, PETROBEL decided to develop such newly challenged area and apply all
recent technology to unleash the discovered potential. As a results of this many wells were proposed
to be drilled in the same block of well SIDRI-18.
Ways Forward
• Petrel Mangrove model is being built for all upcoming Sidri wells with the findings from this
study and Integrated Fracturing design log
• With the help of this model different completion scenarios will be tested for the optimized
field development model
• Punch of vertical wells with multi-stage fracturing will be designed across granitic
conglomerate pay for the best production response
• In order to thoroughly analyze natural fracture network, the below is required Spectroscopy
logs would provide continuous mineralogical composition and might be able to resolve for trace
elements that could potentially affect the total porosity; this could also be used for better calibration
with XRD data
• 3D Sonic Anisotropy is essential in modeling anisotropic stresses in a Mechanical Earth Model
• Discrete Fracture Network (DFN) integrated with 3D Reservoir and Geomechanics stress
model is essential in characterizing the dynamic behavior of the natural network and predicting
performance of hydraulic fractures. This can be supported by imaging, interpretation, and integration
of hydraulic fracture monitoring (HFM)
Conclusion
A number of primary conclusions may be drawn from the foregoing analysis obtained results:
1. Basement mineral composition consists of silica, mica and feldspar fragments (based on mudlog
descriptions, and XRD).
2. Total porosity in the basement zone of interest ranges from 2 – 8 pu with water saturation ranging
from 30-60 percent and net pay of approximately 450 m.
3. Granitic Conglomerate pay is mostly a fractured basement reservoir where higher fracture density
was detected above and below the zone of interest. Identification of fractures within the zone of
interest (hydrocarbon zone) was hindered due to image quality/coverage which could be attributed to
presence of different formations fluids.
4. Higher stress regions are potentially present surrounding the perforation which could possibly
contain the hydraulic fracture. However, if open fractures exist, the 1D MEM approach is no longer
valid which increases the uncertainty of stress barriers.

26. 5. Pre-fracturing pressure analysis suggested a naturally fractured reservoir system (closed system
signature).
6. Post fracturing pressure analysis did not match a homogeneous model with a realistic well bore
storage coefficient, thereby suggesting an actively producing network of natural fractures.
7. The important design criterion for a conventional fracture is choosing a proppant with the desired
conductivity and a carrier fluid with the desired clean up characteristics that will meet production
goals.
8. Channel HF for high perm reservoirs is used to increase permeability contrast between created frac
and formation and this improves fracture dimensionless conductivity. While for low perm reservoirs
for the same amount of proppant it is used to increase fracture half-length.
9. The channel a fracturing using fiber combined with rod shape proppant is became an attractive
technique for high permeability pay even though a complex reservoir as described case.
10.Practically channel Hydraulic-fracturing increases the ultimate recovery factor that corresponds to
the economic cutoff of production, upon this all wells can benefit from hydraulic fracturing.
Nomenclature
P.I. = Productivity index
OOIP = Original Oil in Place
WC = Water cut
HSD = High shot density
MD = Measured Depth
WOB = weight on bit
Ppb = Part per Billion
PDC = Polycrystalline diamond
LWD = Logging While Drilling
BOPD = Barrel oil per day
PPM = part per million
BFPD = barrels of fluid per day
BOPD = barrels of oil per day
Ft = feet
C.F. = Completion factor
OBM = Oil Base Mud
GOR = Gas oil ratio
WC = Water cut
HSD = High shot density
W.I. = Water injection
E = Young’s modulus
BHFP = bottom hole flowing pressure
ESP = electrical submersible pump
S = skin factor
K = Permeability
BOPD = Barrel oil per day
PPM = part per million
BFPD = barrels of fluid per day
BOPD = barrels of oil per day
Ft = feet

27. Acknowledgement
The authors wish to thank the management of Eni and Petrobel for the permission and encouragement
to publish this paper. The assistance provided from Eng. Gabriele Carpineta, Eng. Simona Grifantini,
Eng. Claudia Porretta, Ibrahiem Awny, and Hany Raafat, is gratefully acknowledged. Special
appreciations for Eng. Doaa Musa for his motivation and his continuous support that led to produce
this work.
References
1. Philip d. Nguyen, duncan, ok (us); jmmie d. Weaver,; ron a. Gibson, Nguyen et al us patent 7,281,581 b2;
methods of hydraulic fracturing and of propping fractures in subterranean formations
2. Worley et al. US patent 2014/0048262 A1 Methods For Pillar Placement In Fracturing
3. Alary, Jean Adre Imerys Rod-shaped proppants and anti-flowback additives, methods of manufacturing, and
methods of use European patent application EP 2 500 395 A2.
4. Medvedev et al. Heterogeneous Proppant Placement In A Fracture With Removable channeling Fill US
2011/0083849
5. Hartman et al. System And Method For Low Damage Fracturing US Patent 7,784,541 B2
6. Nguyen et al. Preventing Well Fracturing Proppant Flow Back US Patent 5,908,073
7. Ali Daneshy Daneshy Consultants Internationa lectures
8. Andreas Reinicke, Erik Rybacki, Sergei Stanchits, Ernst Huenges, Germany sandstone-proppant systems
"Hydraulic fracturing stimulation techniques and formation damage mechanisms—Implications from laboratory testing "
9. P. Nguyen, J.Weaver, and R. Rickman, Halliburton Prevention of Geochemical Scaling in Hydraulically Created
Fractures: Laboratory and Field Studies SPE 118175
10. Alvin Wing-Ka Chan , PHD STANFORD UNIVERSITY "Production-Induced Reservoir Compaction,
Permeability Loss And Land Surface Subsidence" December 2004
11. P.M.T.M. Schutjens,/SINTEF Petroleum Research; T.H. Hanssen, M.H.H. Hettema,, and J. Merour; P. de Bree
and J.W.A. Coremans,; and G. Helliesen, "Compaction-Induced Porosity/ Permeability Reduction in Sandstone
Reservoirs: Data and Model for Elasticity-Dominated Deformation" spe_88441.
12. R.M. Ostermeier “Compaction Effects on Porosity and Permeability: Deep water GOM Turbidites” SPE66479.
13. Finkbeiner, T., Barton, C.A. & Zoback, M.D.1998.Relationship between in-situ stress, fractures and faults, and
fluid flow in the Monterey formation, Santa Maria Basin, California, AAPG Bull,81, 1975-1999.
14. M.C. Vincent, SPE, Insight Consulting Examining Our Assumptions - Have Oversimplifications Jeopardized Our
Ability To Design Optimal Fracture Treatments, SPE 119143.
15. Blauch, M., Weaver, J., Parker, M., Todd, B., and Glover, M. 1999. New Insights Into Proppant-Pack
Damage Due to Infiltration of Formation Fines. Paper SPE 56833.
16. McDaniel, B.W. 1986. Conductivity Testing of Proppants at High Temperature and Stress. Paper SPE 15067
presented at the SPE California Regional Meeting, Oakland, California, 2-4 April.
17. Adegbola, K., Boney, C., 2002. Effect of fracture face damage on well productivity. SPE 73759.
18. Aggour, T.M., Economides, M.J., 1999.Impact of fluid selection o high-permeability fracturing. SPE 36902.
19. Formation damage vs. solid particles deposition profile during laboratory simulated PWRI .SPE 82235.
20. Anderson, R.W., Cooke, C.E., Wendorff, C.L., 1989. Propping agents and fracture conductivity in recent
advances in hydraulic fracturing. SPE Monograph Series 12, 109-130.
21. Wattenberg Field, Colorado. Paper SPE 5624 presented at the SPE-AIME Annual Fall Technical Conference.
22. Cikes, M. 2000. Long-Term Hydraulic-Fracture Conductivities Under Extreme Conditions. SPEPF 15 (4): 255-
261. SPE- 66549-PA..Cobb, S.L. and Farrell, J.J.. Evaluation of Long-Term Proppant Stability. Paper SPE 14133.
23. Dewprashad, B.T., Weaver, J.D., Nguyen, P.D., Parker, M., and Blauch, M. 1999. Modifying the
Proppant Surface to Enhance Fracture Conductivity. Paper SPE 50733.
24. Smith, M.B., Miller, W.K, and Haga, J.:"Tip Screen-out Fracturing: A Technique for Soft, Unstable Formations,"
paper SPE 13273 presented·at the 59th Annual SPE Technical Conference and Exhibition, Houston, Texas Sept,1984.
25. Niemeyer, B.L and Reinart, M.R.:"Hydraulic Fracturing of a Moderate Permeability Reservoir, Kuparuk River

28. Unit," paper SPE 15507 presented at the 61st SPE Annual Technical Conference and Exhibition, New Orleans, Oct.1986.
26. Blount, C. G., Brady, J., L.. Fife, D. M., Gantt, L. L., Heusser, J. M., and Hightower C. M.: "HC1/HF Acid-
Resistant Cement Blend: Model Study and Field Application," SPE 19541 presented at the 1989 Annual Tech Conf.
27. McGuire, W, J. and Sikora, V.J."The Effect of Vertical Fractures on Well Productivity," Trans., AIME (1960)
28. S. Ai-Haddad, R. Arbaugh, and D. McKnight,"Hydraulic Fracturing in High Permeability Wells", SPE 40008.
29. D.R. Reimers and R.A. Clausen,"High-Permeability Fracturing at Prudhoe Bay, Alaska", SPE 22835.
30. Edelman, J., Maghrabia, K., Mathur, A., Semary, M., et al, 2013: Rod-shaped Proppant Provides Superior
Proppant Flowback Control in the Egyptian Eastern Desert, Paper SPE 164014.
31. Gillard, M., Medvedev, O., Pena, A., et al, 2010: A New Approach to Generating Fracture Conductivity, Paper
SPE 135034, presented at the SPE Annual Technical Conference & Exhibition, Florence, Italy
32. Technical recommendation of Eni reservoir simulation team conducted 2009.
Appendix
Fig.24: The raw data of different logging tools over a particular section of well SID-18