Saudi Aramco
Spring 2016
A quarterly publication of the Saudi Arabian Oil Company
Contents
First Application of a Sequenced Fracturing Technique to
Divert Fractures in a Vertical Open Hole Completion: Case
2
Study from Saudi Arabia
Kirk M. Bartko, Roberto Tineo, Dr. Gallyam Aidagulov, Ziad Al-Jalal
and Andrew Boucher
Investigation of the Stability of Hollow Glass
Spheres in Fluids and Cement Slurries for Potential Field
Applications in Saudi Arabia
12
Dr. Abdullah S. Al-Yami, Mohammed B. Al-Awami and
Dr. Vikrant B. Wagle
Impact of Multistage Fracturing on Tight Gas
Recovery from High-Pressure/High Temperature
Carbonate Reservoirs
20
Dr. Zillur Rahim, Adnan A. Al-Kanaan, Dr. Hamoud A. Al-Anazi,
Rifat Kayumov and Ziad Al-Jalal
Development and Field Trial of the Well Lateral
Intervention Tool
28
Dr. Mohamed N. Noui-Mehidi, Abubaker S. Saeed,
Haider Al Khamees and Mohamed Farouk
Directional Casing while Drilling (DCwD) Reestablished
as Viable Technology in Saudi Arabia
36
Germán A. Muñoz, Bader N. Al-Dhafeeri, Hatem M. Al-Saggaf,
Hossam Shaaban, Delimar C. Herrera, Ahmed Osman and
Locus Otaremwa
Preliminary Test Results of an Eco-Friendly Fluid Loss
Additive Based on an Indigenous Raw Material
48
Dr. Md Amanullah, Dr. Jothibasu Ramasamy and
Mohammed K. Al-Arfaj
Pioneering Utilization of Fluid Cryogenics in Mimicking
Shutoff Barrier Characteristics
55
Nawaf D. Al-Otaibi, Nelson O. Pinero, Ibrahim A. Al-Obaidi and
Carlo Mazzella
Advancements in Well Conformance Technologies
Used in a Major Field in Saudi Arabia: Case Histories
Ahmed K. Al-Zain, Mohammed A. Al-Atwi, Ahmed A. Al-Jandal,
Rami A. Al-Abdulmohsen and Hashem A. Al-Ghafli
61
Journal of Technology
THE SAUDI ARAMCO JOURNAL OF TECHNOLOGY
First Application of a Sequenced Fracturing
Technique to Divert Fractures in a Vertical
Open Hole Completion: Case Study from
Saudi Arabia
Authors: Kirk M. Bartko, Roberto Tineo, Dr. Gallyam Aidagulov, Ziad Al-Jalal and Andrew Boucher
ABSTRACT
A unique sequenced fracturing technique using formation
notching and degradable diversion pills was applied for the
first time in a vertical open hole completion to stimulate multiple pay intervals in a well in the “Q” sandstone formation of
Saudi Arabia.
The challenge — to divert fractures in a vertical open hole
— is made more difficult by the large fracture surface area is in
contact with the wellbore. A robust, efficient and repeatable
two-step technique was implemented to provide the diversion
and controlled breakdown of higher stressed sections of the
interval. The first step used a specialized jetting nozzle to create
circular notches and weaken the formation at target depths.
The second step involved the pumping of a small volume of a
composite fluid made up of degradable non-damaging fiber
and multimodal particles that bridge at the fracture face,
which would divert the remainder of the treatment to understimulated sections of the interval.
The target for this well was a shallower formation, due to
completion pressure limitations while fracturing. This left six
pay intervals spread across the tight, heterogeneous sandstone
layers of the Q formation, spanning a single 552 ft vertical
open hole section. Previous experience showed large stress
variations in the layers with contained fractures, so fracturing
all pay intervals would require separate treatments for the
interval. After notching the pay intervals to reduce breakdown
pressures, each interval was fractured with three proppant
ramps separated by two diversion pills in the span of eight
hours, improving efficiency more than threefold. Diversion
was confirmed by: (1) Pressure increases of 380 psi and 500
psi, respectively, when the pills landed on formation, (2) Increasing the trend of the initial shut-in pressures (ISIPs)
throughout the treatment, resulting in 1,270 psi of net pressure
gain, and (3) Comparison of post-diagnostic injection test temperature log data with post-fracture neutron log data, showing
where nonradioactive traceable proppant was placed, including into at least three pay intervals not broken down during
the injection test. Post-treatment production expectations were
met and confirmed with a well test.
This article will present the design, execution and evaluation methodology, and challenges that were overcome to divert
2
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SAUDI ARAMCO JOURNAL OF TECHNOLOGY
hydraulic fractures in long vertical open hole intervals using
this two-step diversion process for sequenced fracturing. The
ability to do this consistently — and predictably — can provide a practical, efficient and cost-effective preferred solution
that does not exist today for completing and fracturing similar
zones that are traditionally bypassed, resulting in increased
production and reserves.
INTRODUCTION
The well that was considered for the first application of a sequenced fracturing technique in a vertical well was an exploration well located in the northern part of Saudi Arabia. The
well originally targeted a shallow formation but was drilled
deeper for appraisal of the deeper horizons. Six targets of interest were selected across a tight, heterogeneous sandstone
layer of the Q formation. These targets spanned a 552 ft vertical open hole section where previous experience had showed
large stress variations in the layers and natural fractures. The
large stress variations would require individual fracture treatments to ensure stimulation of each sand package. Not only
was this option costly, but the current completion pressure
limitations would not be adequate to perform a cased hole
fracture treatment.
A decision was made to move forward with an open hole
completion, based on work by Chang et al. (2014)1, who
demonstrated — through a series of open hole block tests —
that a fracture initiation position within an open hole can be
targeted using a weak point cut into a rock. It was further
demonstrated that two independent transverse fractures could
be initiated from two notches placed in a single open hole horizontal wellbore. Aidagulov et al. (2015)2 developed a model
that predicts the orientation, position and pressure at which a
fracture will initiate from the notched open hole, which built
the confidence needed to perform a hydraulic fracture treatment in a high stress area with pressure limitations due to the
completion.
The limitation of the work cited here is that it was developed for horizontal wells where the in situ stress contrast is
relatively constant throughout the lateral, making it simpler to
initiate and extend multiple fractures because the pressures are
relatively constant in a homogeneous wellbore. In a vertical
wellbore, one needs to consider that the stress increases as one
moves down the wellbore due to the changing overburden
pressure. Therefore, to compensate for the changing stress gradient, a diverter would be required to move the fluids from
zone to zone once the fracture is initiated. Adil et al. (2014)3
demonstrated in a 616 ft open hole — within a thick homogeneous rock layer — that diversion could be accomplished
through a series of diversion stages where pressure increases
were observed when the diverter entered the formation. This
work, however, did not show any post-diagnostics that demonstrated the effectiveness of the treatment coverage.
The diverter pill needs to be effective in diverting high-pressure fluids, needs to withstand bottom-hole temperatures
(BHTs) and needs to dissolve over time, leaving no residual behind. The selected sequence diverting fluid was a multimodal
size distribution of particulates and fibers. The material is effective up to 330 °F. The material dissolves within three hours,
leaving no residual materials behind.
Other challenges included testing the integrity of the 7”
shoe during fracturing operations, of the cement plug that isolated the non-reservoir rock below the zone of interest, and of
the formation during fracturing and cleanup of the well.
Fig. 1. Open hole log over the zone of interest.
RESERVOIR DESCRIPTION
The Q formation is a laminated quartz sandstone reservoir
with porosity up to 15% from the dissolution of calcite cement. The tighter intervals have a clay-bound matrix and are
quartz cemented fill. There appears to be moveable water in
the lower porosity intervals, and gas shows appear throughout
the reservoir. The Q formation is highly laminated and heterogeneous, showing a large stress contrast between layers — but
not exceeding 1,000 psi. Petrophysical interpretation suggested
six main target layers, which were designed to be stimulated
with three fracture stages. Figure 1 is the open hole log for the
zone of interest.
FRACTURE INITIATION FROM NOTCH
The fact that operators have limited or no control of the positions and orientations of initiated fractures represents one of
the major challenges encountered in hydraulic fracturing of
long open hole wellbore sections. Indeed, the hydraulic fracture initiates at location(s) along the wellbore subjected to the
lowest in situ stresses, surrounded by weaker rock and/or
crossed by a natural fracture — all factors that are out of the
operator’s control. One of the ways to “force” the hydraulic
fracture to initiate at the target depth is to mechanically
weaken the formation at that point. A circular notch — or
360° perforation — cut into the wellbore wall in a transverse
direction can play a role in creating such a weak point, Fig. 2.
The notch amplifies the particular tensile stress components in
the rock and so lowers the fracture initiation pressures within
the region of the wellbore near the notch. This circular notch
Fig. 2. Schematic of the open hole with a circular notch (360° perforation), along
with the hoop (σϴϴ) and axial (σZZ) stress components at the surface of the
wellbore and notch tip. The σϴϴ stress component opens a longitudinal fracture,
whereas the σZZ stress component opens a transverse fracture along the
corresponding dashed line.
can be made by a high-pressure liquid jet or mechanical cutter
placed on the rotating head of the downhole tool.
Chang et al. (2014)1 conducted a lab investigation of the
effect of circular and semicircular transverse notches on the
initiation of hydraulic fractures from an open hole drilled in the
direction of minimal far-field stress. This setup can be related
to the process of stimulating a horizontal wellbore drilled
along the minimal horizontal stress direction under the normal
stress regime. The experiments repeatedly demonstrated that
two transverse fractures initiated from two notches placed in a
single open hole interval — provided that the notches were cut
deep enough into the rock. For the experimental conditions
considered, it was found that notches had to be at least one
wellbore diameter deep to ensure transverse fracture initiation.
Otherwise, the fractures were initiated longitudinally and
required higher breakdown pressures.
Aidagulov et al. (2015)2 proposed the model that captures
the observed dependence of fracture orientation direction on
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3
notch depth, Dn. In that model, the notch has a round end (Ushape) and has a width, Wn, which is a certain portion of the
wellbore radius, Rw, Fig. 2. These assumptions about the
notch geometry match well with the actual shape of notches
observed in the lab tests. The model prediction is based on the
3D boundary element method (BEM) elastic analysis of
stresses near the wellbore and the notch that are caused by the
application of far-field stresses and wellbore pressure, Pw. Longitudinal and transverse fracture initiation is then governed by
the hoop, σθθ, and axial, σzz, tensile stress concentrations, respectively.
Whether or not a particular stress component causes the initiation of a fracture is decided based on the fracture criterion
for the rock. The experimental results were matched with the
model using the nonlocal fracture criterion based on the stress
averaging technique (SAMTS) and allowing for the microstructural scale of the rock, davg. It was demonstrated, starting from
the given notch depth, that the σzz stress concentration at the
notch tip met the fracture criterion earlier, i.e., at lower Pw,
than the hoop stress concentration at the wellbore wall, which
results in transverse fracture initiation. Next, we applied this
model to evaluate the effect of the notch on the fracturing
stimulation of the well under study.
The fracture initiation model proposed2 assumes nonporous
and impermeable rock, and it does not include formation pore
pressure, Pp. To apply this “dry rock model” to the real field
case, the Pp must be taken into account. The simplest way of
taking into account the effect of Pp on hydraulic fracture initiation is by assuming that over the course of pressure buildup,
fracturing fluid does not penetrate into the rock, which is valid
for low permeability rock and/or fast injection. As a result, the
Pp in the surrounding rock does not change and remains constant during pressurization4. In this case, all the formulas behind the stress analysis of the dry rock model are also valid for
effective stress::
. In contrast
to the total stress,
cont
, effective stress,
the load borne by the rock
ess, , represents
r
matrix and so is used in fracture criteria for porous saturated
rock. The poroelastic coefficient,, , is provided as a part of
the mechanical earth model, but is often set to 1 when used for
failure predictions. Therefore, under these assumptions, the
dry rock model can still be applied for this case of saturated
rock, but with the far-field stresses replaced by the effective
ones. As a result, the model will provide fracture initiation
pressure in terms of wellbore overbalanced pressure:
. In the absence of a notch, this approach is
equivalent to the classical and widely used Hubert-Willis estimate for breakdown pressure5.
Simulations were performed for the synthetic case representing the conditions for the well under study at roughly a true
vertical depth of 11,000 ft:
• Young’s modulus, E = 8.5E+6 psi.
• Poisson’s ratio,
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𝜈 = 0.22.
SAUDI ARAMCO JOURNAL OF TECHNOLOGY
• Tensile strength, T0 = 2,500 psi.
• Far-field stresses:
o Horizontal maximum, SHMax = 8,200 psi (SHMax_g =
0.75 psi/ft).
o Horizontal minimum, Shmin = 7,300 psi (Shmin_g =
0.68 psi/ft).
o Vertical, SV = 12,100 psi (SV_g = 1.1 psi/ft).
• Pp = 4,400 psi.
The following geometrical parameters for the notch and
wellbore were:
• Wellbore diameter, Dw = 57⁄8”.
• Notch:
o Wn = (3/16)*Dw ≈ 1.1”.
o Dn = Dw = 57⁄8”.
• SAMTS averaging length, davg = 1”.
According to the 3D model simulations for these synthetic
case parameters, a transverse notch does not promote initiation of a transverse fracture, Fig. 3. Only the initiation of longitudinal fractures is realistic under such high contrast between
vertical and horizontal effective stresses: 7,700 psi vs. 2,900
psi. It should be noted that as this well is directed along the
maximal (vertical) stress, longitudinal fracture orientation is
also preferred by the far-field stresses.
Fig. 3. The 3D model predicts initiation of longitudinal fracture(s) next to the
transverse notch. The red color (Sxx) is related to the concentration of the hoop
stress in the zone of fracture.
The transverse notch, when pressurized with the wellbore
pressure, produces a zone of elevated hoop stresses within the
part of the wellbore wall close to the notch. This is clearly
demonstrated in Fig. 4, where hoop stresses were alternatively
calculated in greater detail using the axisymmetric BEM formulation6 for the case of equal horizontal stresses: Shmin =
SHMax = 7,300 psi. Here, the cases of various notch depths are
shown: no notch (blue); 25% of wellbore diameter or ¼ Dw
(green); and 100% of wellbore diameter or 1 Dw (red). In all
cases, the wellbore pressure was taken to be equal to the Hubert-Willis breakdown pressure estimate: T0 - SHMax +3 ×
Shmin-α × Pp = 12,700 psi. In the absence of the notch (blue
curve), this results in the (effective) hoop stress value at the
wellbore wall being equal to the tensile strength of the rock.
One can see that for the same wellbore pressure, the
notched wellbore develops an effective hoop stress that is 8%
to 20% higher than the one for the wellbore without a notch.
For the notched wellbores, hoop stresses reach their maximum
within the region close to the notch, while decaying toward the
non-notch value away from the notch. Higher hoop stresses
thereby promote initiation of the longitudinal fracture first in
the zone of elevated stresses near the notch. The shallower
notch (25% of Dw) appears to induce even higher values of
hoop stresses. The extent of the area of elevated stress increases
consistently with the notch depth. This suggests there may
even be more chances for a longitudinal fracture to initiate, as
a larger number of defects fall into the region where the stress
exceeds the critical value. In this way, the region where elastic
hoop stress exceeds the non-notched value, i.e., tensile strength
for this case, by 3% extends for 12” when the notch is 25% of
Dw (green) and for 23” when the notch is 100% of Dw (red).
Fig. 4. Effective hoop stress profiles along the wellbore axis in the notch vicinity.
This result demonstrates a potential mechanism for controlling the position and initiation pressure for the longitudinal
fracture: placing the transverse notch in the target region of
the open hole wellbore. This does not exclude, however, the
need for excessive validation of the proposed mechanism, as
the presented argument relies on pure elastic static stress
analysis.
ROTATING JETTING YARD TEST
The ability of hydraulic jets to penetrate the rock — making
deep perforation tunnels7 and even breaking through several
casing layers8 — is well-known in the industry. Tools for such
high-pressure jetting applications can be found among the
standard coiled tubing (CT) services. The current project required the cutting of circular notches into the wellbore wall.
Conceptually, this can be achieved by having the high-pressure
jetting nozzle placed on the rotating head of a downhole CT
tool. Such a rotating head can be an intrinsic part of the tool,
or it can be made by assembling the tool with a stationary nozzle to work in combination with the downhole drilling motor
or turbine, which would additionally rotate the tool, and nozzle(s), around the tool axis. None of the existing tools or assemblies had ever been used to cut circular notches in open
hole wellbores, so a series of yard tests was performed with
different downhole tool configurations. The following highlights the resulting key observations, using examples of a couple of the tests performed with the high-pressure jetting CT
tool (Tests N-1-T and N-1-B).
Cement targets were manufactured for the yard test to simulate the open hole wellbore section. The block sample (cement target) was placed into a larger steel tank, referred to
here as a “sample container,” with the objective to keep the
sample and high-pressure jet contained in a safe area during
the jetting test, Fig. 5.
In Test N-1-T, the jetting pressure was ramped up in steps
from 1,000 psi to 5,000 psi over the 125 minutes of the test
total time, Fig. 6a. Although a shallow notch 0.5 cm deep was
already observed after jetting at pressures around 1,000 psi,
overall it took around 40 minutes to cut the notch to the depth
Fig. 5. Deployment of the yard test: The sample container general view (left);
cement block sample (target) placed inside the sample container (right). The
jetting tool is rigidly fixed with the centralizer arms to prevent its oscillation
around the borehole axis, which otherwise may gain significant amplitude during
high-pressure jetting.
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5
Fig. 6. The 125 pounds per cubic foot (PCF) cement target tests run with 0.156”
nozzles. For each test, the jetting pressure and notch depth are plotted against the
time (in the graphs, left). The reported notch depth corresponds to its “deepest”
part where the depth could be measured (given in cm values on the depth
diagrams, right). In sectors where the jet broke out of the cement target, the depth
of notches cannot be detected, which is indicated with “x” in the depth diagrams.
of 2 cm at pressures of approximately 2,000 psi, which appeared too slow. Nevertheless, the notch was nice and smooth
— free of cavities. A further increase of pressure to the range
from 3,600 psi to 3,700 psi and jetting for another 25 minutes
made the notch only 4 cm deep and from one side only — the
other side remained at 2 cm. Subsequent jetting for 20 minutes
at 4,000 psi deepened one side from 4 cm to 5 cm only. The
following increase of pressure to 5,000 psi did not run as
smoothly as required; the replacement of the pump was needed
after it was damaged by cavitation. After finally jetting at
5,000 psi for about 40 minutes, the jet broke through the
block, Fig. 7a. The final depth of the notch increased significantly during this last 40-minute jetting stage — up to 14 cm
at its deepest among the smooth regions of the notch. The
shallowest part of the notch — which was also the “slowest”
one to grow, keeping slightly above 2 cm deep over the previous jetting pressure levels — also jumped to 5 cm. On the
borehole side, Test N-1-T also looked smooth and did not reveal large breakouts, Fig. 7b; depth can be measured at all angles except the breakthrough side. The notch’s smooth depth
of 14 cm is just a little bit smaller than 17 cm, which is the targeted depth of “one wellbore diameter.”
Then the question arose: Will there be any drastic changes
in results — in notch depth and/or failure patterns — if the jetting was done at 5,000 psi pressure right from the start? That
was checked in Test N-1-B, Fig. 6b. The jet broke through the
block after 40 minutes of jetting, Fig. 7c, with a failure pattern
very similar to the N-1-T case. A final notch depth of 15 cm —
also very close to the N-1-T test result — was found, Fig. 7d.
Therefore, this was a well repeated result, which showed the
overall consistency of the results.
Based on the test results presented here, the following conclusions can be reached. A series of several jetting tests was
performed in cement targets made of a 125 PCF cement recipe
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SAUDI ARAMCO JOURNAL OF TECHNOLOGY
Fig. 7. Post-test image of the target #1 block representing 125 PCF cement recipe
used in the tests N-1-T and N-1-B (center). In both tests, the jet “broke out” of
the block via a single face where the resulting hole appeared localized as well,
leaving the remaining three faces intact (7a, 7c). Images of the borehole (7b, 7d)
also demonstrate the smooth openings of both notches — free of large breakouts
and longitudinal cracks.
using the actual CT tool, which comprised the rotating jetting
head equipped with 2 × jetting nozzle (0.156”). The test results
demonstrated mostly smooth failure patterns and consistent
results.
1. The ability to cut 10 cm to 15 cm deep circular notches
with the 27⁄8” jetting tool was demonstrated repeatedly in
the yard for the 17 cm diameter open hole in a cement tar
get. This assumed pure water jetting and required around
40 minutes of jetting time.
2. A minimal jetting pressure of 1,000 psi was required to initiate the erosion of notches. To cut the notch to the maximum depth observed required at least 4,500 psi jetting pressure. There is evidence as well that jetting at intermediate
pressures resulted in the notch depth’s being stabilized at
shallower depths. This is intuitively correct; as the standoff
distance increases, one expects jet dispersion and shear to
decrease the jetting efficiency.
3. The depth of the notches in all cases is highly nonuniform
— with respect to the angle — even in smooth regions, possibly as a result of the nonlinear nature of the erosive interaction with the fluid stream.
4. Jetting at constant pressure or ramping pressure up in steps
was inconclusive as the two approaches did not lead to notable differences in results — eventual notch depth — except
ramping required longer jetting times due to lower pressure
stages. Although some results indicate smoother and more
uniform notches as a result of ramping pumping schedules,
this is not considered operationally relevant at this time,
with the recommendation that pumping should take place
at the maximum pressure immediately.
Overall, we consider the performed tests as successful:
• The maximum observed notch depth was 150 mm,
which is 1 wellbore diameter for standard Saudi
Aramco open hole completions.
• We have strong evidence that this would increase
further with additional available pumping pressure.
There were limitations to the experimental arrangement.
First, the measured maximum penetration was a significant
fraction of the block size and associated with breakouts near
those regions. This means that to study reliably deeper jet
penetration, the sample would need to be larger to eliminate
boundary effects.
While the implementation of a similar test at high hydrostatic pressure and elevated pressures would represent an excessive engineering challenge, it is worth considering how these
tests might translate to a downhole environment and the resulting operational considerations. Taking into account high
velocities of water flow through the nozzle, there is an increased chance for the occurrence of cavitation in the jet — in
the areas of the flow with sudden pressure drop. It is known
that the appearance of gas bubbles in the fluid jet due to cavitation can increase the efficiency of the water jet cutting by additional mechanisms that damage and erode materials9, and
that cavitation will be modulated by the hydrostatic pressure
of the environment. This suggests that the efficiency of water
jetting drops with depth; it is believed that the most effective
way to de-risk this for field operations is to employ abrasives
to ensure consistent and controlled erosive action independently of entrained gas within the stream.
COMPLETION DESIGN
Completion of this well required the setting of two balanced
cement plugs in the open hole section. The lower plug was
required due to water-bearing porosity intervals below, while
the second plug was needed for support to land and cement
the 4½” liner. The liner was pressure tested to ensure there
would be no hydraulic leaks during the fracturing treatment
and then drilled out to expose the open hole section. After
that, the well was completed with 4½”, 13.5 lb/ft, C-95 tubing
and liner with VAM-TOP high compression connectors and a
4½” × 7”, VFLH 25 ft, polished bore receptacle and seal assembly. The completion was designed for a bottom-hole injection pressure as high as 14,500 psi, which would not be
sufficient for a cased hole fracture design for this particular
well. Figure 8 is a schematic of the open hole completion.
SEQUENCE DIVERTER
Fig. 8. Open hole completion schematic.
The diverter pill is an engineered slurry comprising a proprietary blend of degradable particles with multimodal size distribution and fibers. The diverter composite pill was specifically
designed to promote diversion in multistage fracture treatments for perforated cased hole wells where there is a limited
open area and so limited control of the placement of the pill.
The composite fluid overcomes the limitations of traditional
chemical diverters by coupling degradable particles of a wide
size distribution. Degradable fibers are added to improve dispersion of the particles in the tubulars, thereby keeping the
solid slug highly concentrated. The fibers modify the rheology
of the composite fluid by imposing a yield stress, which hinders dispersion in the tubulars. Fibers also help to level the
velocity profile toward the center of the conduit, which reduces
shearing forces on the slugs and mitigates dispersion as well10.
Large particles accumulate at the fracture entrance bridging
the fracture face, and then the smaller particles reduce permeability and deliver temporary isolation. The fibers enhance particle transport to ensure integrity of the blend from the surface
to the near wellbore area, helping to mitigate pill dispersion
and particle settling.
Particles and fibers completely degrade within three hours
triggered by the BHT; therefore no additional treatment is required to put the well back in production, ensuring that all intervals are available to contribute.
FRACTURE DESIGN
Three targets were identified in the well, Fig. 9 (left), covering
a total area of 250 ft out of the 550 ft of open hole. The three
target areas were selected based on porosity development and
a clean gamma response. Due to the formation’s heterogeneity,
permeability was a huge unknown, along with the uncertainty
as to the stress state and natural fractures that could be present
along the open hole section.
Six notch locations were selected with the intention to lower
the fracture initiation pressure and distribute the fracture
across the open hole interval. Cutting of the notches was performed with 35 bbl of 1 PPA sintered bauxite at 2 bpm. Each
stage was flushed with a gel fluid, and all six stages were performed consecutively. Tool integrity during the cutting stages
was determined by monitoring the CT injection pressure. Loss
of pressure would indicate the jets had deteriorated and were
not providing sufficient cutting power.
Due to the large surface area, the treatment was designed
for three stages with two pill stages, Table 1. The design was
to pump a total of 300,000 lb of nonradioactive tracer proppant, with the stage volumes increasing with each stage. The
larger volumes were placed toward the end, which was when
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Fig. 9. Post-diagnostic log indicating fracture diversion.
the proppant was placed into the tighter rock, providing maximum penetration and fracture conductivity.
To determine the effectiveness of the notches and to obtain
a better understanding of the breakdown pressures, a calibration injection treatment of 300 bbl of cross-linked fluid was
followed by a temperature log. Breakdown pressures were less
than originally calculated, allowing the fracture treatment to
move forward, and the temperature survey indicated good
fluid entry at the notches.
To avoid restimulating the same section, two diverter composite pills were deployed in two stages, with the goal to temporarily isolate each fracture. The volume of each pill, 900 lb,
was engineered to cover 60 ft to 70 ft of fracture height, which
was the expected fracture height growth based on fracture simulations and previous experience in the area. As a reference,
this volume is approximately eight to 10 times larger than the
typical pill volume used for cased holed perforated applications; the large volume was directly related to the larger surface contacting the wellbore in the open hole case.
The deployment of the composite pill can be performed in a
continuous action right after the last proppant stage — 4 PPA
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or 5 PPA — or as a separate stage after flushing. We opted for
the latter, which provides the flexibility to capture the postfracture initial shut-in pressure (ISIP) for evaluation purposes
and to have better control when the pill entered the formation;
this job was the first case worldwide to deploy such pill volumes.
FRACTURE RESULTS
The entire open hole interval was fracture stimulated with
three proppant ramps separated by two diversion pills as per
design — in the span of eight hours — improving operational
efficiency more than threefold. Diversion was confirmed by:
(1) Pressure increases of 380 psi and 500 psi, respectively,
when the pills landed on formation, Fig 10; and (2) Increasing
the trend of the ISIPs throughout the treatment, resulting in
1,270 psi of net pressure gain, Fig. 11. Comparison was made
of the post-diagnostic injection test temperature log data with
post-fracture neutron log data, showing where the nonradioactive traceable proppant was placed, previously seen in Fig. 9,
including into at least three notched pay intervals not broken
down during the injection test. Post-treatment production
Stage
Description
Fluid Type
Rate (bpm)
Stage Vol (bbl)
1
Pre-pad
45 PPTG
40
150
1
Pad
45 PPTG-XL
40
300
1
Slurry 0.5 to 4 PPA
45 PPTG-XL
40
463
1
Displacement
20 PPTG
40
171
Spacer
40 PPTG
7
10
Proppant Vol (lb)
40,000
Shutdown
Pill 1
Pill 1
Pill
Pill
7
20
Pill 1
Spacer
40 PPTG
7
10
Pill 1
Displacement
20 PPTG
10
131
Pill 1
Placement
20 PPTG
10
40
Pill 1
SDT
20 PPTG
45
100
2
Pre-pad
45 PPTG
45
150
2
Pad
45 PPTG-XL
45
350
2
Slurry 1 to 5 PPA
45 PPTG-XL
45
860
2
Displacement
20 PPTG
45
164
Spacer
40 PPTG
450
10
Shutdown
100,000
Shutdown
Pill 2
Pill 2
Pill
Pill
7
20
Pill 2
Spacer
40 PPTG
7
10
Pill 2
Displacement
20 PPTG
7
124
Pill 2
Placement
20 PPTG
10
40
Pill 2
SDT
20 PPTG
10
100
3
Pre-pad
45 PPTG
45
150
3
Pad
45 PPTG-XL
45
500
3
Slurry 1 to 6 PPA
45 PPTG-XL
45
1,313
3
Displacement
20 PPTG
45
163
Shutdown
Total Proppant
160,000
300,000
Table
T 1. Treatment design
Fig. 11. Increasing ISIP evolution indicating new rock breaking down.
Fig. 10. Pressure treatment plot indicating pressure effects from the pill stages.
expectations were obtained and confirmed with a long-term
well test.
CONCLUSIONS
Analysis of the results allows the following conclusions to be
drawn:
1. The rotating notching tool was successfully deployed down
SAUDI ARAMCO JOURNAL OF TECHNOLOGY
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9
hole via CT providing a 360° circular notch, supported by
the series of yard tests with cement targets, which tested the
actual field configuration of the tool.
2. Open hole notches reduce breakdown pressures by increasing
the tensile stress at the wellbore in the notch vicinity. This
promotes the initiation of longitudinal fractures in that zone.
3. Open hole notches can be used to provide for fracture initiation at multiple spots along the open hole section, as was
indicated by the nonradioactive traceable proppant placed
into at least three notched pay intervals not broken down
during the injection test.
4. A combination of degradable particulates and fibers will
divert fluids in an open hole, as was indicated by an
increasing ISIP between stages and the nonradioactive
tracer diagnostic log.
5. Pill volumes approximately eight to 10 times larger than
those of a cased hole application were employed to ensure
diversion in the open hole.
Overall, the feasibility of a new two-step sequenced fracturing technique was demonstrated for open hole wellbores. The
technique uses notching of the target pay zones to ensure the
selected areas are preferentially fractured with subsequent
pumping stages. Notching is followed by the injection phase,
without any mechanical isolation; the entire 552 ft length of
open hole was exposed to elevated pressures. Clearly, the
weakest point initiated the first fracture. Injection stages were
interchanged with diversion phases to temporarily impede
fluid flow into growing fractures and allow the pressure to rebuild to fracture the next weakest zone, effectively generating
multiple fractures at targeted zones without mechanical isolation. This makes the implemented two-step fracturing technique, i.e., notching plus diversion, a practical, efficient and
cost-effective preferred solution for completing and fracturing
similar zones that are traditionally bypassed, resulting in a
cost-effective means to increase production and reserves.
ACKNOWLEDGMENTS
The authors wish to thank the management of Saudi Aramco
and Schlumberger for their support and permission to publish
this article. The authors would also like to thank the Saudi
Aramco Unconventional Fracturing Team for supporting and
successfully executing the fracture treatment. The support of
Schlumberger’s Well Intervention, Well Services and Cementing
Teams in ‘Udhailiyah and al-Khobar is also very much
appreciated.
This article was presented at the SPE Hydraulic Fracturing
Technology Conference, The Woodlands, Texas, February 911, 2016.
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SAUDI ARAMCO JOURNAL OF TECHNOLOGY
REFERENCES
1. Chang, F.F., Bartko, K., Dyer, S., Aidagulov, G., SuarezRivera, R. and Lund, J.: “Multiple Fracture Initiation in
Open Hole without Mechanical Isolation: The First Step to
Fulfill an Ambition,” SPE paper 168638, presented at the
SPE Hydraulic Fracture Technology Conference, The
Woodlands, Texas, February 4-6, 2014.
2. Aidagulov, G., Alekseenko, O., Chang, F.F., Bartko, K.,
Cherny, S., Esipov, D., et al.: “Model of Hydraulic Fracture
Initiation Pressure from the Notched Open Hole,” SPE
paper 178027, presented at the SPE Saudi Arabia Section
Annual Technical Symposium and Exhibition, al-Khobar,
Saudi Arabia, April 21-23, 2015.
3. Adil, F., Pande, K. and Raina, B.: “First Open Hole
Hydraulic Fracturing Treatment Using Diverter Technology
in India,” SPE paper 167690, presented at the SPE/EAGE
European Unconventional Conference and Exhibition,
Vienna, Austria, February 25-27, 2014.
4. Jaeger, J.C., Cook, N.G.W. and Zimmerman, R.W.:
Fundamentals of Rock Mechanics, 4th edition, WileyBlackwell Publishing, Hoboken, New Jersey, 2007, 488 p.
5. Detournay, E. and Carbonell, R.: “Fracture Mechanics
Analysis of the Breakdown Process in Mini-fracture or
Leak Off Test,” SPE Production & Facilities, Vol. 12, No.
3, August 1997, pp. 195-199.
6. Becker, A.A.: The Boundary Element Method in
Engineering: A Complete Course, 1st edition, McGrawHill, New York, 1992, 350 p.
7. Pittman, F.C., Harriman, D.W. and St. John, J.C.:
“Investigation of Abrasive-Laden-Fluid Method for
Perforation and Fracture Initiation,” Journal of Petroleum
Technology, Vol. 13, No. 5, May 1961, pp. 489-495.
8. Zwanenburg, M., Schoenmakers, J. and Mulder, G.: “Well
Abandonment: Abrasive Jetting to Access a Poorly
Cemented Annulus and Placing a Sealant,” SPE paper
159216, presented at the SPE Annual Technical Conference
and Exhibition, San Antonio, Texas, October 8-10, 2012.
9. Momber, A.W.: “Wear of Rocks by Water Flow,”
International Journal of Rock Mechanics and Mining
Sciences, Vol. 41, No. 1, January 2004, pp. 51-68.
10. Kraemer, C., Lecerf, B., Torres, J., Gomez, H., Usoltsev,
D., Rutledge, J., et al.: “A Novel Completion Method for
Sequenced Fracturing in the Eagle Ford Shale,” SPE paper
169010, presented at the SPE Unconventional Resources
Conference, The Woodlands, Texas, April 1-3, 2014.
BIOGRAPHIES
Kirk M. Bartko is a Senior Petroleum
Engineering Consultant with Saudi
Aramco’s Unconventional Gas
Operations Department with the
Technical Support Unit focusing on
trial testing new technologies for
completions and stimulation. He
joined Saudi Aramco in 2000, where he works to support
hydraulic fracturing and completion technologies across all
Saudi Arabia operations. Kirk’s experience includes 19
years with ARCO with various global assignments in
locations, including Texas, Alaska, Algeria, and the
Research Technology Center supporting U.S. and
international operations.
He has authored and coauthored more than 40
technical papers on well stimulation and is a recipient of
four U.S. granted patents, and has been actively involved in
the Society of Petroleum Engineers (SPE) since 1977.
Kirk received his B.S. degree in Petroleum Engineering
from the University of Wyoming, Laramie, WY.
Roberto Tineo is currently a Senior
Production Stimulation Engineer for
Schlumberger working at the
Unconventional Resources Center in
Dhahran, Saudi Arabia. He has been
with Schlumberger for 15 years.
Roberto started his career as a
Stimulation Field Engineer in Eastern Venezuela, working
on design, execution and evaluation of fracturing, sand
control and matrix acidizing treatments. From Eastern
Venezuela he moved to the West as a Technical Sales
Engineer to support stimulation operations in Lake
Maracaibo. Roberto then worked for 4 years in California,
U.S., as a Design and Evaluation Services Client Engineer,
involved on horizontal fracture stimulation designs,
conventional formations and the Monterey shale. His
current assignment in Saudi Arabia is to advise, design and
evaluate fracture treatments for Saudi Aramco’s
unconventional shale gas resources.
Roberto received his B.S. degree in Electronic
Engineering from Simón Bolivar University, Caracas,
Venezuela.
Dr. Gallyam Aidagulov started his
Schlumberger career in 2004 when he
joined the company research center in
Moscow, Russia. Since that time,
Gallyam has focused on geomechanics
through his involvement in various
projects where he applied and further
developed his expertise in computational mechanics for
development of theoretical and numerical models of such
processes as proppant flow back, sanding, fault
reactivation and reservoir rock failure localization.
In March 2012, he moved to the Schlumberger
Carbonate Research Center in Dhahran, Saudi Arabia, to
work on numerical and laboratory studies of hydraulic
fracturing under a joint research project with Saudi
Aramco.
In 2000 and 2004, Gallyam received his M.S. and Ph.D.
degrees, respectively, in Computational Mathematics from
the Lomonosov Moscow State University, Moscow, Russia.
Ziad Al-Jalal is currently working as
the Stimulation Domain Manager for
Schlumberger, where he is involved in
fracturing projects in Saudi Arabia and
Bahrain. He has 15 years of experience
in fracturing treatments in both
conventional and unconventional
wells. Ziad joined Schlumberger in 2000 as a Fracturing
Field Engineer in Western Siberia, Russia, for four years,
then as a Technical Engineer in Saudi Arabia. From 2008
to 2012, he was a Team Leader in the Tight Gas Center of
Excellence based in Dhahran, Saudi Arabia. Ziad
previously worked as a Senior Production and Stimulation
Engineer in Oklahoma City, OK, from 2012 to 2014.
He received his B.S. degree in Mechanical Engineering
from King Fahd University of Petroleum and Minerals
(KFUPM), Dhahran, Saudi Arabia, in 1999.
Andrew Boucher has over 15 years of
well production and completion
engineering experience, with a focus
on fracturing and stimulation. He has
held various technical, sales and
operational positions with
Schlumberger, primarily in North and
South America. Most recently, Andrew held the position of
Technical Manager for Fracturing and Stimulation for the
Arabian GeoMarket.
In 1999, he received his B.S. degree in Chemical
Engineering from Queen’s University, Kingston, Ontario,
Canada.
SAUDI ARAMCO JOURNAL OF TECHNOLOGY
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Investigation of the Stability of Hollow
Glass Spheres in Fluids and Cement Slurries
for Potential Field Applications in Saudi
Arabia
Authors: Dr. Abdullah S. Al-Yami, Mohammed B. Al-Awami and Dr. Vikrant B. Wagle
ABSTRACT
Hollow glass spheres (HGSs) provide an attractive method to
reduce the densities of drilling fluids and cement slurries for
different objectives. There are several pressure ratings for
HGSs, and selecting and testing the right type for the suitable
application is important.
The objective of this article is to evaluate the performance
and stability of HGSs in three formulations: (a) HGS-based
fluids at different pH conditions, (b) low-density water-based
drilling fluids with HGSs as a density reducing additive, and
(c) low-density cement (LDC) with HGSs as a density reducing
additive.
The evaluation of the stability of low density inhibited water-based fluids formulated with HGSs in diverse pH environments was for their potential application in the Wasia
formations in Saudi Arabia. Intensive testing of the fluids included rheological properties, pH and density measurements
before hot rolling (BHR) and after hot rolling (AHR) in different pH environments at high-pressure/high temperature
(HPHT) for extended periods of time — up to four days.
The evaluation of the stability of LDC utilizing HGSs was
for their potential to cement shallow casings in gas wells and
oil wells in Saudi Arabia. In this study, we present the results
of extensive lab work that included rheology measurements,
thickening time tests, free water and sedimentation tests, a
fluid loss test and a compressive strength test.
Data generated supported the use of low-density fluids formulated with HGSs in the Wasia formation when applicable.
Also, this study supported the use of the examined cement for
casings under shallow conditions in gas wells and oil wells.
The shallow conditions simulated in the lab tests were at a
static temperature of 158 ºF and at 2,500 psi.
INTRODUCTION
Hollow glass spheres (HGSs) are lightweight solids composed
of soda-lime-borosilicate glass. They are incompressible microspheres with specific gravities (SGs) lower than that of water. The high strength and low density of HGSs make them an
attractive method to reduce the density of drilling fluids and
cement slurries. Furthermore, HGSs are chemically inert and
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SAUDI ARAMCO JOURNAL OF TECHNOLOGY
provide favorable flow properties. They are commercialized in
various ratings, based on the strength and density of the
spheres. The strengths of HGSs range from 2,000 psi to
18,000 psi, with true densities between 0.29 gm/cc and 0.63
gm/cc, and their particle sizes range between 1 µm and 100
µm. With the use of HGSs, the density of a water-based fluid
can be reduced to 41 pounds per cubic foot (PCF). Drilling fluids can be formulated with an upper limit of 40 vol% HGS
while maintaining suitable rheology and mud characteristics1.
The rheological properties of HGS-based fluids are similar to
those of conventional fluids and can be calculated through
Einstein’s viscosity model2.
Drilling fluids formulated with HGSs permit measurements
while drilling and have been found to be compatible with conventional surface equipment3. HGSs allow the employment of
near balanced and underbalanced drilling, which reduces the
differential pressure in the wellbore. Drilling in low differential
pressure conditions can result in numerous benefits, such as an
increase in the rate of penetration (ROP), reduction in formation damage, and elimination of loss of circulation and differential pipe sticking4. These improvements ultimately lead to
lower nonproductive time and greater efficiencies.
To reduce hydrostatic pressure on the formation, a low-density cement (LDC) needs to be applied, especially on a fractured weak formation. To reduce the density of cement, water
can be added in large volumes, but this will affect the mechanical properties of the cement, such as its compressive strength
and permeability. This type of cement is called water extender
cement. The lowest density that can be formulated using water
extender cements is 86 PCF5. Water extender cements also require multistage operations to avoid fracturing the formation
due to high hydrostatic pressure, and multistage cementing can
fail, which then requires remedial operations, such as perforation and squeeze jobs6-8.
Nitrogen can be used to make LDC, but attention is required to achieve the required density. Another way to make
LDC is to use materials with low SGs, such as hollow microspheres (ceramic or glass), mixed with the cement9-11. Gas contained in these hollow glass materials enable the reduction of
cement density down to approximately 60 PCF12. There are
several ways to make LDC other than just mixing hollow microspheres with cement; i.e., mixing coarse and fine cement
particles, fly ash, fumed silica, hollow microspheres and water13. Another way is to mix hollow microspheres with plasticizer, cement and aluminum metal powder and sodium
sulfate14. The first application of LDC utilizing hollow microspheres took place in 1980 at a density of approximately 69
PCF15.
The objectives of this article are:
• To formulate and evaluate HGSs for drilling fluids
applications.
• To formulate and evaluate HGSs for cementing
operations.
OVERVIEW OF SUCCESSFUL FIELD IMPLEMENTATIONS
OF HGS-BASED DRILLING FLUIDS
Drilling fluids formulated with HGSs have been tested in numerous field trials in the past decade, and many of these
drilling fluids have been proven successful. HGS-based fluid is
mostly deployed in areas with major problems, such as areas
with extremely slow ROP, frequent differential pipe sticking,
severe or total loss of circulation and high formation damage
in reservoir sections. HGS-based fluid successfully eliminated
differential sticking in the field deployment3 and was able to
reduce mud losses from 100+ bbl/hr to 6 bbl/hr in India16. In
areas of slow ROP, oil-based mud formulated with HGSs successfully reduced drilling operations by 11 days in Venezuela17.
A study conducted by Chen and Burnett (2003)18 determined
that HGSs do not create additional damage to the formation’s
permeability. The small particle size of HGSs, though, leads to
the formation of a tighter filter cake19. In these examples of
HGS field deployment, added benefits such as reduced torque
and enhanced productivity have also been observed.
OVERVIEW OF SUCCESSFUL FIELD IMPLEMENTATIONS
OF HGS-BASED LDCs
LDCs have been used throughout the industry for many years
as a specialty cement for application in areas of weak formations. Ripley et al. (1981)20 have described the use of small diameter, inorganic, high strength microspheres in LDC slurries
with improved compressive strength, enabling the slurry to
maintain its low density even at high pressures. Wu and Onan
(1986)21 have described the use of high strength microspheres
in LDC as resulting in improved primary casing and liner cementing in the Gulf of Bohai. Al-Yami et al. (2007, 2008)22, 23
have conducted a long-term evaluation of LDC stability where
LDC is used to achieve zonal isolation across weak sandstone
and carbonate formations in the fields of Saudi Arabia. Field
treatments were conducted without encountering any operational problems, and the cement maintained isolation for more
than three years, which confirmed the effectiveness of the LDC
system. Al-Yami et al. (2012)24 have also tested low-density
systems at 300 °F. After testing the durability of LDC at higher
temperatures and in different operational scenarios, they have
shown that the LDC is durable even in high-pressure/high temperature (HPHT) conditions. Carver et al. (2011)25 have used
hollow microsphere-based LDCs for increasing primary cementing success in steam injected, low fracture gradient areas.
Wang and Wang (2013)26 have used an ultra-LDC system with
HGSs as a weight reducing additive to control lost circulation
in coalbed methane wells.
METHODS AND MATERIALS
The performance and stability of HGSs were assessed in three
formulations: (a) HGS-based fluids in different pH conditions,
(b) low-density water-based drilling fluids with HGSs as a density reducing additive, and (c) LDC with HGSs as a density
reducing additive.
The experimental procedure to evaluate the stability and
performance of HGSs is given as follows.
Formulating HGS-based Fluids in Different pH Conditions
In this study, 57.5 PCF (7.69 lb/gal) water-based fluids were
designed having different pH values — acid condition pH < 4,
original pH = 9 and basic condition pH > 11 — to assess the
effect of pH on the stability of the HGSs. All fluids were designed utilizing HGS-8000 (SG = 0.42) to get a density of approximately 57.5 PCF, Table 1. The additives were mixed with
water using a standard multi-mixer. Mixing operations were
observed to ensure proper mixing of each component.
Concentration (ppb)
Original pH
(pH = 9)
Basic
Conditions
(pH > 11)
Acidic
Conditions
(pH < 4)
Water
306.8
306.3
302.9
HGS
18.01
18.06
18.40
0.5
0.5
0.5
NaOH
–
0.15
–
HCl Acid
–
–
3.54
Additives
XC-Polymer
Table
T 1. Formulation of the fluids at different pH conditions
Evaluation of Hollow Glass Microspheres in Low-Density
Drilling Fluids
In this study, 57.5 PCF water-based drilling fluids were designed with HGS-8000. The HGS-based drilling fluids were
formulated with a viscosifier, fluid loss additive, shale inhibitors, etc. The fluids were hot rolled at 160 °F/250 °F for
16 hours in HPHT aging cells.
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Evaluation of Hollow Glass Microspheres in LDC Slurry
A 75 PCF LDC slurry was formulated using HGS-4000 (SG =
0.38) hollow glass microspheres. This slurry was then evaluated for its performance after curing it at 158 °F and 2,500 psi
for four days.
Slurry Preparation Procedure. The LDC was formulated in the
lab using a standard American Petroleum Institute (API)
blender. The maximum speed during slurry preparation was
4,000 revolutions per minute (rpm) instead of the typical
12,000 rpm. To apply the same mixing energy, the duration of
mixing was changed to 330 seconds at 4,000 rpm, instead of
15 seconds at 4,000 rpm and 35 seconds at 12,000 rpm22. The
equation of mixing energy is27:
Fluid Loss Test. Dynamic fluid loss, i.e., loss of fluid from the
slurry while it is being placed, results in an increase in slurry
density, which may cause loss of circulation. Other properties,
such as rheology and thickening time, also may be adversely
affected. Static fluid loss, i.e., loss of fluid from the slurry after
placement, if not carefully controlled, will lead to a slurry volume reduction and pressure drop that can allow formation
fluids to enter the slurry28.
Curing at Downhole Conditions. A HPHT curing chamber
was used for curing the cement specimens at the required conditions. Cubical molds, 2” × 2” × 2”, and cylindrical cells,
1.4” diameter and 12” length, were lowered into the curing
chamber27. Pressures and temperatures were maintained until
shortly before the end of the curing, when they were reduced
to ambient conditions.
(1)
where:
E = mixing energy (kJ)
M = mass of slurry (kg)
k = 6.1 × 10-8 m5/s (constant found experimentally)
ȣ = rotational speed (radians/s)
t = mixing time(s)
V = slurry volume (m3)
After mixing and preparing the slurry, it was placed in a
consistometer, and a pressure of 2,500 psi was applied. The
objective of placing the cement under pressure is to simulate
field placement under a 2,500 psi hydrostatic column, based
on the usual placement of 75 PCF LDC. All tests were conducted after applying 2,500 psi (simulating hydrostatic pressure on the LDC) to find out if crushing the hollow microspheres
had an effect on the physical properties tested.
Slurry Rheology. The slurry was conditioned in the atmospheric consistometer before measuring rheological readings. A
standard rheometer was used to measure the slurry rheology27.
Thickening Time Test. A standard API HPHT consistometer
was used to evaluate the pumpability of the cement slurry.
Free Water and Slurry Sedimentation Tests. Water separation
in slurries is an indication of bad performance and a potential
zonal isolation problem. So, a free water test was conducted
using 250 ml in a graduated cylinder for two hours according
to API procedures. Settling is another indication of improper
performance and likely zonal isolation problems. This can be
tested for by measuring the densities of different sections of a
cured cement column27. A gas pycnometer was used to measure the density of these different sections at the specified conditions previously mentioned. Points 2” from the top, middle
and bottom sections of a 12” long and 1.4” diameter sample
of the cement were measured for densities.
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SAUDI ARAMCO JOURNAL OF TECHNOLOGY
Compressive Strength Test. The cubical molds, 2” × 2” × 2”,
were removed from the molds to be placed in a hydraulic press
where force was exerted on each cube until failure, which is in
compliance with API specifications for the oil well’s cement
testing27. The compressive strength was measured after curing
the samples for four days.
Density Measurements of HGSs. The density of the hollow
glass microspheres was determined using the following specified procedure:
1. Weigh the empty flask to the nearest 0.01 g.
2. Add approximately one-third of the volume of glass bubbles to the flask, and weigh the flask and the powder to the
nearest 0.01 g.
3. Add sufficient mineral oil to cover and wet the glass bubbles.
Stopper the flask and agitate it for several minutes, ensuring
that neither air pockets nor lumps of glass bubbles exist.
Wash the stopper and the walls of the flask with mineral oil
until they are free of glass bubbles and the flask is filled to
the 100 mL level.
4. Weigh the flask and the glass bubbles and mineral oil to the
nearest 0.01 g.
5. Empty the flask. Clean and dry the flask, add 100 mL of
mineral oil, and weigh the flask and the mineral oil to the
nearest 0.01 g.
6. Calculate the density of the mineral oil, Ps, using the formula
in Eqn. 2:
PS = 10(MFS – MF)
(2)
where:
PS = density of mineral oil (g/L)
MFS = mass of flask plus mineral oil (g)
MF = mass of flask (g)
7. Calculate the density of the glass bubbles using the formula
in Eqn. 3:
(3)
where:
PP = density of glass bubbles (g/L)
MFP = mass of flask plus glass bubbles (g)
MF = mass of flask (g)
MFPS = mass of flask plus glass bubbles and mineral oil (g)
PS = density of mineral oil (g/L)
Particle Size Distribution
The particle size distribution of the hollow glass microspheres
was determined using a Malvern Mastersizer 2000.
RESULTS AND DISCUSSION
Effect of pH on Hollow Glass Microspheres
The stability of the spheres in drilling fluids is critical to sustaining a practical and effective drilling fluid. Unplanned
breakage or dissolution of the spheres in the wellbore while
drilling could lead to numerous problems, such as increased
formation damage and loss of circulation due to the sudden
increase in the density of the drilling fluid. Alawami et al.
(2015)29 has studied the effect of various pH conditions on the
stability of HGSs. In that study, HGS-based fluids after hot
rolling (AHR) at a pressure of 500 psi and a temperature of
250 °F for intervals up to four days showed slight changes in
density. The results showed a slight density increase up to 0.5
PCF AHR in the fluids at 250 °F in alkaline conditions. This
could be attributed to a dissolution of the spheres driven by
the reaction of sodium hydroxide (NaOH) with the siliconoxygen bond in borosilicate HGS glass. The addition of
NaOH boosts the forward reaction of water with the siliconoxygen bond, Eqn. 4, which consequently encourages further
dissolution of the spheres, Eqn. 530.
Si-O-Si + H2O = SiOH HOSi
(4)
Si-O-Si + NaOH = SiOH Na+OSi
(5)
Hot Rolling
Duration
(Days)
Density Increase (lbm/ft3)
Original pH
(pH ~9)
High pH
(pH > 11)
Low pH
(pH < 4)
1 day
–
0.0
–
2 days
0.5
0.2
0.0
3 days
0.2
–
0.0
4 days
0.3
0.5
0.0
TableT2. Summary of the stability results of HGSs having different pH values28
agents, Tables 3 and 4. The two formulations targeted a density of a pH between 9 and 10.
The tests displayed excellent results with stable density and
pH before and after three days of hot rolling, Table 5. Formulation #1 was hot rolled at a temperature of 250 °F, while Formulation #2 was hot rolled at a temperature of 160 °F; these
simulated real wellbore conditions in the Wasia formation. The
density of the fluid remained within 0.1 PCF, and the pH values were sustained within the desired range of 9 to 10. The
plastic viscosity and gel strength values were kept low for both
formulations. The yield point of Formulation #2 recorded
higher values than that of Formulation #1; however, both values
are within the practical range.
Additives
Concentration (ppb)
Water
280.5
Bentonite
2
Soda Ash
0.3
Shale Inhibitor
10
XC-Polymer
0.5
Bio-polymer
2
Filtration Control
0.75
HT Filtration Control
4
HGSs
24.6
Table 3. Formulation #1 of a typical fluid, hot rolled at 250 °F
T
In acidic conditions, pH < 4, on the other hand, the spheres
revealed extremely high stability. The density of the fluid was
sustained without any changes at all hot rolling durations.
Table 2 is a summary of the stability results of the HGS in the
different pH conditions.
Additives
Water
Concentration (ppb)
296.3
Bentonite
3
XC-Polymer
0.5
Shale Inhibitor
Evaluation of Hollow Glass Microspheres in Low-Density
Drilling Fluids
Alawami et al. (2015)29 have assessed two 57.5 PCF formulations
of inhibited water-based muds using HGSs as density reducing
1
Bio-polymer
4
HGSs
20.3
NaOH
As needed
TableT4. Formulation #2 of a typical fluid, hot rolled at 160 °F
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Formulation
#1
Formulation
#2
BHR
AHR
BHR
AHR
Density (PCF)
57.5
57.4
57.5
57.4
pH
9.75
9
9.66
9.76
10 s Gel Strength
(lb/100 ft2)
13
2.7
–
5.3
10 m Gel Strength
(lb/100 ft2)
18.5
3.3
–
11.3
Plastic Viscosity (cP)
21.9
11.3
–
11.8
Yield Point (lb/100 ft2)
63.2
10.3
–
20.8
Measurement
TableT5. Performance of HGSs in drilling fluids before and after hot rolling at 160
°F (Formulation #1) and 250 °F (Formulation #2)28
Evaluation of Hollow Glass Microspheres in LDC Slurry
The density of hollow glass microspheres was measured using
the procedure previously described. The density of the HGSs
calculated from Eqn. 5 was 377 g/L (0.377 g/ml).
The particle size distribution of the HGS-4000 hollow glass
microspheres is given in Table 6. The HGSs show a particle
size distribution with a d(0.5) value of 41.385.
Cement crushing tests were done at a pressure of 2,500 psi
and 4,000 psi. These two pressures were selected to simulate
field conditions; they represent the hydrostatic pressure applied on the column of the cement slurry.
In the crushing test, the slurry density was measured before
and after exposing the cement slurry to 2,500 psi and 4,000
psi, using a mud balance. The density measurement was 76
PCF after exposure to 2,500 psi and 77 PCF after exposure to
4,000 psi.
Therefore, the following two conclusions can be drawn
from the crushing tests:
• The LDC slurry that is pressurized at a conditioning
pressure of 2,500 psi should result in approximately a
1 PCF to 2 PCF increase in density, compared to the
initial density.
• The LDC slurry that is pressurized at a conditioning
pressure of 4,000 psi should result in approximately a
2 PCF to 3 PCF increase in density, compared to the
initial density.
The pumping time was found to be 6 hr 49 min (409 min at
100 Bc) for shallow conditions, Fig. 1. The static fluid loss
value for the LDC slurry was 344.4 cc.
HGS-4000
d(0.1)
d(0.5)
d(0.9)
17.138
41.385
81.591
Table
T 6. Particle size distribution of HGS-4000 hollow glass microspheres
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SAUDI ARAMCO JOURNAL OF TECHNOLOGY
Fig. 1. Thickening time chart of the LDC at 158 °F and 2,500 psi.
Test data showing zero free water and no significant settling
or sedimentation are indications of good slurry stability and
good potential for zonal isolation27. The free water test in the
study showed no settling in the LDC slurry. The LDC cylinder
was cured at 2,500 psi and 158 °F for four days. Sections of
this cylinder then were cut and their density was measured.
Table 7 shows that the density of the six sections of the LDC
cylinder did not vary from one section to another. These results confirmed that there was no settling of the LDC over 24
hours.
Sections
Wt. in Water
Bottom
85.9 PCF
1
86.1 PCF
2
85.9 PCF
3
85.4 PCF
4
85.2 PCF
Top
85.6 PCF
Table
T 7. Density measurements of different sections in the LDC test cylinder
The growth of hydrated calcium silicate crystalline structures in cement leads to the development of greater compressive strength. More strength can grow due to structure growth
with each other31.
One study indicates that a 100 psi compressive strength is
enough for casing support32. A compressive strength of 500 psi
is needed for casing support, according to another study28. The
final compressive strength of the LDC in this study after curing
at 158 °F and 2,500 psi for four days was 2,487 psi, Fig. 2.
presented at the SPE Annual Technical Conference and
Exhibition, New Orleans, Louisiana, September 30October 2, 2013.
3. Arco, M.J., Blanco, J.G., Marquez, R.L., Garavito, S.M.,
Tovar, J.G., Farias, A.F., et al.: “Field Application of Glass
Bubbles as Density Reducing Agent,” SPE paper 62899,
presented at the SPE Annual Technical Conference and
Exhibition, Dallas, Texas, October 1-4, 2000.
4. Medley Jr., G.H., Maurer, W.C. and Garkasi, A.Y.: “Use of
Hollow Glass Spheres for Underbalanced Drilling Fluids,”
SPE paper 30500, presented at the SPE Annual Technical
Conference and Exhibition, Dallas, Texas, October 22-25,
1995.
Fig. 2. An example of the LDC API compressive strength load chart after curing
the LDC at 158 °F and 2,500 psi.
CONCLUSIONS
1. At pH = 9, the HGSs were found to be stable at high temperatures. The HGS-based fluids experienced a slight
increase in density, with a maximum change of 0.5 PCF.
2. At high temperatures and higher pH values (pH > 11), the
HGS-based fluids experienced a drop in pH values, accompanied by a slight increase in density.
3. The inhibited water-based drilling fluids formulated with
HGSs yielded favorable rheology and stable mud characteristics.
4. HGS-based LDC, after curing at 158 °F and 2,500 psi for
four days, gave a good compressive strength of 2,487 psi.
5. In the crushing test, exposure of the cement slurry to 2,500
psi and 4,000 psi resulted in a 76 PCF slurry after exposure
to 2,500 psi and a 77 PCF slurry after exposure to 4,000 psi.
ACKNOWLEDGMENTS
The authors would like to thank the management of Saudi
Aramco for their support and permission to publish this article.
This article was presented at the SPE Kuwait Oil & Gas
Show and Conference, Mishref, Kuwait, October 11-14, 2015.
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15. Smith, R.C., Powers, C.A. and Dobkins, T.A.: “A New
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SAUDI ARAMCO JOURNAL OF TECHNOLOGY
32. Mack, D.J. and Dillenbeck, R.L.: “Cement: How Tough
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BIOGRAPHIES
Dr. Abdullah S. Al-Yami is a
Petroleum Engineer with the Drilling
Technology Team of Saudi Aramco’s
Exploration and Petroleum
Engineering Center – Advanced
Research Center (EXPEC ARC).
In 2014, he received the Regional
Drilling Engineering Award from the Society of Petroleum
Engineers (SPE). Abdullah is a coauthor of the textbook
Underbalanced Drilling: Limits and Extremes. He has
four granted U.S. patents and more than 16 filed patents,
all in the area of drilling and completions. Abdullah has
more than 40 publications to his credit and is a technical
editor for the SPE Drilling and Completion journal.
He received his B.S. degree in Chemistry from the
Florida Institute of Technology, Melbourne, FL; his M.S.
degree in Petroleum Engineering from King Fahd University
of Petroleum and Minerals (KFUPM), Dhahran, Saudi
Arabia; and his Ph.D. degree in Petroleum Engineering
from Texas A&M University, College Station, TX.
Dr. Vikrant B. Wagle is a Petroleum
Scientist with the Drilling Technology
Team of Saudi Aramco’s Exploration
and Petroleum Engineering Center –
Advanced Research Center (EXPEC
ARC). His experience revolves around
the design of novel, environmentally
friendly drilling fluid additives and the development of
high-pressure/high temperature tolerant drilling fluid
systems.
Vikrant has 18 technical publications and four granted
U.S. patents, and he has filed 21 U.S. patent applications,
all in the area of drilling and completions.
He received his M.S. degree in Chemistry from the
University of Mumbai, Mumbai, India, and his Ph.D.
degree in Surfactant and Colloidal Science from the
Mumbai University Institute of Chemical Technology,
Mumbai, India.
Mohammed B. Al-Awami is a
Petroleum Engineer with the Drilling
Technology Division of Saudi
Aramco’s Exploration and Petroleum
Engineering Center – Advanced
Research Center (EXPEC ARC). He
joined Saudi Aramco in 2014 and has
published two Society of Petroleum Engineers (SPE)
technical papers alongside one patent application in the
first year of his professional career. Mohammed’s research
efforts have focused on drilling fluids, lost circulation
materials and cement slurries. He has also explored the
development potential of several local resources, such as
bentonite and volcanic ash in Saudi Arabia. Mohammed
has seen his interest grow in managed pressure drilling and
drilling automation while pursuing the latest innovations in
drilling engineering.
He is currently working with the Exploration and Oil
Drilling Engineering Department to gain a firsthand
understanding of the challenges and adversities faced there.
Mohammed is engaged in the design and planning of
production, evaluation and injection wells in major Saudi
Arabian oil fields, such as Abu Hadriya and Berri.
In 2014, he received his B.S. degree in Petroleum
Engineering from the University of Oklahoma, Norman, OK.
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Impact of Multistage Fracturing on Tight
Gas Recovery from High-Pressure/High
Temperature Carbonate Reservoirs
Authors: Dr. Zillur Rahim, Adnan A. Al-Kanaan, Dr. Hamoud A. Al-Anazi, Rifat Kayumov and Ziad Al-Jalal
ABSTRACT
INTRODUCTION
The multistage fracturing (MSF) technique has considerably
improved gas production from tight gas reservoirs all over the
world. Well production is one of the main determining factors
used to assess the success of a fracturing treatment. In this article, numerous vertical and horizontal wells drilled in highpressure/high temperature heterogeneous reservoirs have been
evaluated to confirm the effectiveness of stimulation treatments
and the benefits derived from the use of novel technologies.
Among many variables that were analyzed are drilling, completion and stimulation parameters, such as well azimuth,
completion types, fluid characteristics, acid strength, etc.
A database for stimulated wells was created, and various
parameters were grouped and assessed to provide a correlation
to, and understanding of, the effectiveness of fracture treatments,
and to optimize development plans. Correlations were drawn
by using the Pearson correlation coefficient (PCC) equation to
compute data trends and ensure good quality data. Numerous
very useful plots that show the different trends of the variables
evaluated and how they affect production rate have been constructed and are presented here.
Analyses results indicate that use of real-time geomechanics
is important to predict reservoir pressure and mud weight when
wells are laterally drilled in the preferred minimum in situ
stress (σmin) direction. This is because when wells are drilled
along the σmin direction, they tend to become more unstable
due to the higher stress acting on the wellbore. Accuracy in
predicting stresses and pressures is key to the drilling of such
wells. The completion assemblies were selected between the
open hole multistage approach and the plug and perforation
cased hole approach, based on reservoir properties and hole
conditions. The impact on production performance of using
non-damaging, low gel loading fracturing fluids, high strength
proppants, and optimal fluid and acid volumes is demonstrated using actual field examples. The application of channel
fracturing, a novel fracturing technique, for improved fracture
conductivity has proven successful for sustained gas production in tight gas reservoirs, thereby making low productivity
wells commercially viable.
A reservoir’s lateral and vertical heterogeneity and complexity
poses challenges in exploiting carbonate reservoirs1-3. Typical
carbonate formations can exhibit low reservoir quality, requiring long laterals and appropriate stimulation methods to make
them commercially viable4. The high temperature also requires
stable acid properties for deep penetration and optimal etching
of the formation3. Anhydrate streaks and high in situ stress
can restrict fracture growth. Moreover, condensate dropout
and banking can have severe consequences on gas production
and recovery.
Acid stimulation has become the preferred technology to
improve gas production and reservoir sustainability. To address
many varied challenges, different technologies have been applied
over the years, from simple acid washes to major acid fracturing
operations that use various fluids and acid systems, diverter
mechanisms, novel completions and improved chemicals3.
Numerous well, reservoir and operational data were analyzed to understand their impact on well production. The data
includes reservoir parameters, completion properties, operational data from a step-rate test and main stimulation treatments — including fluid types, volumes, rates and pressures —
fracture geometry details and monthly production data. Analyses of two areas are presented, Table 1. Area 1 represents a
moderate reservoir with comparably better porosity and permeability, while Area 2 consists of a tighter reservoir with a
Parameter
Area 1
Area 2
Reservoir Characteristics
Deep
Deep
Porosity (%)
10.5
8
Permeability (mD)
1.2
0.5
Reservoir Temperature (°F)
260
300
Young’s Modulus (Mpsi)
6.5
6.4
FG (psi/ft)
0.87
0.98
70
45
Condensate to Gas Ratio
(bbl/MMscf)
Table 1. Average reservoir properties for the selected areas
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higher fracture gradient (FG). Vertical and horizontal wells
were evaluated in Area 1, and deviated — more than 50° inclination — and horizontal wells were analyzed in Area 2.
Numerous parameters were evaluated to see their influence
on the gas rate (Qg) and productivity index (PI). The Qg and
PI were normalized on the reservoir net height (Hnet) and the
product of the Hnet and porosity (f ) for comparison. For horizontal wells, the Hnet was taken from the nearest vertical offset
well. Due to the fact that no vertical wells were available in
Area 2, the Hnet was taken from one of the deviated wells and
assumed to be equal for all analyzed wells. This assumption is
fair because all wells in Area 2 are located in close proximity
to each other. The main focus of the study is to evaluate completion, stimulation and reservoir parameters and their impacts
on well productivity. Many parameters were analyzed from
each category, Table 2, some showing a visible effect on the PI
and some not showing a clear trend.
The parameters have been analyzed using the Pearson correlation coefficient (PCC) calculated by the following equation:
(1)
where x and y are sets of independent parameters, –x and y– are
the average values. The PCC is a dimensionless index that
ranges from -1.0 to 1.0 inclusive and reflects the extent of a
linear relationship between two data sets. Figure 1 and Table 3
provide examples of different PCC values. For this particular
study, the PCC can be interpreted as described next.
Completion Parameters
Fig. 1. Examples of different PCC values.
PCC Values
Comments
+ 0 ç 0.19
Very weak
+ 0.2 ç 0.39
Weak
+ 0.4 ç 0.59
Moderate
+ 0.6 ç 0.79
Strong
+ 0.8 ç 1
Very Strong
Table 3. PCC values describing correlation strength
T
multistage fracturing (MSF). These were compared with offset
vertical wells stimulated with single-stage acid fracturing. The
normalized average PI for the horizontal wells was calculated
by PI/Hnet x f and clearly shows that the horizontal wells are
producing better compared to the offset vertical wells, Fig. 2
(top). On average, the horizontal wells show an 85% increase
in PI. In Area 2, results similar to those in Area 1 are observed,
and on average the horizontal wells perform 60% better compared to the vertical wells.
Well type: Vertical, horizontal, deviated
Contact length: Open hole (MSF), perforated (cement and
cased)
Well azimuth: Deviation from maximum in situ stress (σmax)
direction
OPEN HOLE LENGTH AND PERFORATED INTERVAL
Figure 2 (bottom) presents normalized PI values for vertical
and horizontal wells in Areas 1 and 2, respectively, showing a
Stimulation Parameters
Number of stages pumped without communication
Volume of acid per net pay
Pump rate
Pump time over overburden (OB) stress
Pump time above closure stress or FG but below OB
Treatment Evaluation Parameters
Etched fracture half-length
Average fracture width
Table 2. Evaluation parameters
T
TYPE OF WELL — VERTICAL VS. HORIZONTAL
A small reservoir section near the edge of the field was selected
for Area 1, having horizontal wells completed with three-stage
Fig. 2. PI for horizontal wells (top) and longer perforation/open hole intervals
(bottom).
SAUDI ARAMCO JOURNAL OF TECHNOLOGY
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good increasing trend in productivity. The gain in PI is due to
better communication when perforation lengths or open hole
sections are increased, allowing higher reservoir contact with
the wellbore. The open hole interval in a multistage completion can also contribute to production if vertical permeability
is favorable, although the major production comes through the
induced fractures.
ACID VOLUME
Fig. 4. PI as a function of acid pumped, Area 2.
Different types of acid can be pumped during an acid fracturing treatment, such as gelled hydrochloric (HCl) acid with
varying concentrations, emulsified acid, self-diverting acid, etc.
The type of acid is selected based on reservoir rock and fluid
properties. The volume of all pumped acid was recalculated to
an equivalent volume of 28% HCl acid for comparison purposes. An average acid volume per stage was used for the horizontal wells.
Figure 3 illustrates the normalized PI graph (top) and shows
somewhat nonlinear behavior in Area 1 for both vertical and
horizontal wells, suggesting that some optimum values of acid
volume exist and the optimum is not necessarily the maximum. The corresponding acid volumes are also provided in
Fig. 3 (bottom). Analyses suggest that 500 gal to 600 gal of
28% HCl acid equivalent per foot of net pay provides optimum well performance for vertical wells, and 300 gal/ft to 500
gal/ft provides optimum well performance for horizontal wells.
Larger acid volumes may not have a significant impact on fracture geometry and production as they may reduce the effectiveness of post-fracturing flow back due to the additional volume
of fluid introduced into the gas reservoir.
For Area 2, a good ascending trend of PI, further normalized
by the number of stages — productivity divided by the number
of stages — is observed, Fig. 4. For the tighter reservoirs of
Fig. 3. PI as a normalized function of acid pumped, Area 1 (top), and the
corresponding HCl acid volumes (bottom).
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Area 2, more acid per foot of net pay is required because the
increased reservoir contact area is the key contributor for productivity enhancement in tight formations.
PUMP RATE
In this section, the average pump rate used during the main
acid fracturing treatment is analyzed. The wellbore fluid displacement at the beginning of treatment and the closed fracture
acidizing stage at the end of the treatment are not considered,
as they do not contribute to the actual well stimulation.
Figure 5 shows the pump rates and normalized PI values in
Area 1 for vertical and horizontal wells. A somewhat good ascending trend is observed as a function of the pump rate for
the PIs in the vertical wells (bottom, blue bars). The sharp increase in PI observed in two wells, Well-2 and Well-8, is due to
other producing conditions, such as low drawdown pressure.
The maximum average pump rate for the vertical wells is 50
bbl/min, shown on the graph. The horizontal wells (red line
and bars) do not show a linear trend; well productivity increases with the pump rate at the beginning, but then it drops
after the rate reaches about 35 bpm.
Although the industry rule of thumb in acid fracturing treatment calls for pumping at the highest possible rate to transport
live acid deeper into the created hydraulic fracture, the gain in
length is sometimes offset by the decrease in width. The etched
fracture width is vital to keep the induced fractures open during production, and therefore, the reduced fracture width can
be a possible reason for the productivity drop for wells treated
Fig. 5. The separate PI values and average pump rates for horizontal and vertical
wells, Area 1.
with the high average pumping rate. Based on this analysis, it is
recommended to limit the fracturing pump rate to 50 bbl/min
in the study area.
Most of the wells in the tighter area, Area 2, were pumped
with a pump rate of 35 bbl/min to 38 bbl/min, Fig. 6. Higher
pump rates usually could not be achieved due to the higher in
situ stresses encountered in this area compared to those in
Area 1. A good ascending trend can be seen, with better productivity for wells pumped at a higher pumping rate.
Fig. 8. The PI values and pumping times with FG < BHP < OB for vertical and
horizontal wells, Area 2.
Fig. 6. The combined PI values and average pump rates for both horizontal wells,
Area 2.
PUMPING TIME AND BOTTOM-HOLE
PRESSURE (BHP)
The BHP impacts the created fracture dimensions. In general,
the higher the BHP, the larger the fracture size will be. If the
BHP drops below the FG, the fracture will close. The overburden (OB) stress was calculated by multiplying the formation’s
true vertical depth by an average OB stress gradient of 1.1 psi/ft.
Figures 7 and 8 show normalized PI values for vertical and
horizontal wells in Area 1 and Area 2, respectively. All wells
are placed in order of ascending value of pumping time, with
BHP > OB in Area 1 or OB > BHP > FG in Area 2. A very similar trend to that of the previously analyzed average BHP is
observed.
The PI decreases as BHP exceeds the OB stress, indicating
the possible creation of T-shaped fractures causing limited
fracture growth. On the other hand, when the BHP is main-
tained below the OB stress, the fracture grows optimally and
increased PI is observed.
ETCHED FRACTURE HALF-LENGTH AND
FRACTURE WIDTH
Normalized PI values were calculated for many horizontal and
vertical wells in moderate to tight reservoir conditions. A good
positive average productivity trend is observed in the tighter
area, Area 2, where horizontal wells are drilled, Fig. 9. There
Fig. 9. Normalized PI values as a function of fracture half-length.
is a nonlinear tread seen for vertical wells, where the productivity increases up to a certain value (~170 ft) and then starts
decreasing. It may be that with longer fracture half-lengths,
fracture widths are being compromised, thereby bringing
down the PI values. As for the width, Fig. 10, the vertical wells
Fig. 7. The PI values and pumping times with BHP > OB for vertical and
horizontal wells, Area 1.
Fig. 10. Normalized PI values as a function of fracture width.
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show a good increasing trend in PI values with wider fractures.
For the horizontal well examples, the maximum PI is reached
for a fracture width around 0.28”. A greater width attributes
to reduced fracture length, which is also a very important
parameter to achieve an improved production rate.
the number of stages is increased. For the Area 2 wells, the
number of stimulation stages varied between one and four,
whereas for Area 1, it varied between one and five. The improved PI numbers in both areas are noticeable.
SUMMARY
DRILLING AZIMUTH
Normalized PI values were calculated and plotted as a function
of well azimuth for horizontal, MSF wells. When wells deviate
from the maximum in situ stress (σmax) direction, the created
fractures no longer stay parallel to the wellbore; they become
oblique or transverse, thereby generating independent fractures. In the case of wells drilled toward the σmax direction, an
induced fracture is created along the wellbore. This restricts
the independent growth of subsequent fractures.
Independent fractures are needed to provide more reservoir
contact. The production rate is directly proportional to the
contact area, Fig. 11. Figure 12 presents the PI increase when
The PCC values were calculated for each set of variables to ensure that the correlations are acceptable and the trends are correct. The PCC numbers and correlation strength are provided
in Table 4. With actual field data, which usually have
inherent measurement errors, getting moderate to strong correlations is quite good and acceptable. This shows that the trends
reported in this article on the impact on PI and Qg, and determining some of the optimal parameters, are valid in general.
CONCLUSIONS
This article presents the impact of many critical reservoir, completion and stimulation parameters on well productivity. The
following conclusions are derived from the work presented in
this article. These conclusions are specifically for the reservoirs
studied and may not be applicable as a general guideline.
• Horizontal wells with MSF completion provide better PI.
• Drilling longer laterals in the σmin direction provides an
opportunity to design more stages for MSF completion,
resulting in improved production.
Fig. 11. Normalized PI values as a function of well azimuth.
• Preventing interstage communication is critical for
productivity optimization.
• For the vertical wells, longer perforated intervals
provide better productivity.
• For the moderate quality reservoir, 500 gal to 600 gal of
28% HCl acid equivalent per foot of net pay provides
the optimum well performance for vertical wells, and
300 gal/ft to 500 gal/ft provides the optimum well
performance for horizontal wells. For the tight reservoir,
more acid per foot of net pay is recommended.
Fig. 12. Normalized PI values as a function of the number of stimulation stages.
Variable
• A higher pumping rate positively affects production —
PCC
Correlation Strength
Type of Well
0.51
Moderate
Perforation Length
0.53
Moderate
Well Azimuth
0.93
Very strong
Number of Independent Stages
Acid Volume
Pump Rate
BHP > OB
Open Hole > BHP > FG
Table 4. The calculated PCC numbers and correlation strength
T
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0.7
Strong
0.58 (vertical) 0.38 (horizontal)
Moderate and weak
0.68 (vertical) -0.19
Strong and weak
-0.57 (vertical) -0.38 (horizontal)
Moderate and weak
0.38 (vertical) 0.23 (horizontal)
Weak
but only up to about 50 bbl/min.
• Maintaining the correct BHP during acid fracturing is
critical; BHP should be kept high enough to overcome
closure stress, but it must also be maintained below OB
stress. This can be done by changing the pumping rate,
changing the fluid viscosity, or in some instances,
adjusting the pumping schedule during the treatment.
• For the moderate quality reservoir, analysis shows that
well productivity increases with an increase in fracture
half-length up to about 170 ft. For the tight reservoir,
no constraint is observed for fracture length.
• An increase in the etched fracture width has positive
affects on production. At the same time, the fracture
half-length should not be compromised. The fracture
half-length should be long enough to increase reservoir
contact, but the fracture average width should be as
high as possible to ensure that the fracture will remain
open at production conditions.
ACKNOWLEDGMENTS
The authors would like to thank the management of Saudi
Aramco for their support and permission to publish this article.
This article was presented at the SPE Asia Pacific Unconventional Resources Conference and Exhibition, Brisbane, Australia, November 9-11, 2015.
REFERENCES
1. Al-Jallal, I.A.: “Diagenetic Effects on Reservoir Properties
of the Permian Khuff Formation in Eastern Saudi Arabia,”
SPE paper 15745, presented at the SPE Middle East Oil
Show, Manama, Bahrain, March 7-10, 1987.
2. Bukovac, T., Nihat, M.G., Leal Jauregui, J., Malik, A.R.,
Bolarinwa, S. and Al-Ghurairi, F.: “Stimulation Strategies
to Guard against Uncertainties of Carbonate Reservoirs,”
SPE paper 160887, presented at the SPE Saudi Arabia
Section Technical Symposium and Exhibition, al-Khobar,
Saudi Arabia, April 8-11, 2012.
3. Rahim, Z., Al-Anazi, H.A., Al-Kanaan, A.A., Makmum,
A., Fredd, C.N. and Gurmen, M.N.: “Evolving Khuff
Formation Gas Well Completions in Saudi Arabia:
Technology as a Function of Reservoir Characteristics
Improves Production,” SPE paper 163975, presented at the
SPE Unconventional Gas Conference and Exhibition,
Muscat, Oman, January 28-30, 2013.
4. Ahmed, M., Rahim, Z., Al-Anazi, H.A., Al-Kanaan, A.A.
and Mohiuddin, M.: “Development of Low Permeability
Reservoir Utilizing Multistage Fracture Completion in the
Minimum Stress Direction,” SPE paper 160848, presented
at the SPE Saudi Arabia Section Technical Symposium and
Exhibition, al-Khobar, Saudi Arabia, April 8-11, 2012.
BIOGRAPHIES
Dr. Zillur Rahim is a Senior Petroleum
Engineering Consultant with Saudi
Aramco’s Gas Reservoir Management
Department (GRMD). He heads the
team responsible for stimulation
design, application and assessment for
conventional and tight gas reservoirs.
Rahim’s expertise includes well stimulation, pressure
Rahim’
transient test analysis, gas field development, planning,
production enhancement and reservoir management. He
initiated and championed several new technologies in well
completions and hydraulic fracturing for Saudi Arabia’s
nonassociated gas reservoirs.
Prior to joining Saudi Aramco, Rahim worked as a
Senior Reservoir Engineer with Holditch & Associates,
Inc., and later with Schlumberger Reservoir Technologies in
College Station, TX, where he consulted on reservoir
engineering, well stimulation, reservoir simulation,
production forecasting, well testing and tight gas
qualification for national and international companies.
Rahim is an instructor who teaches petroleum engineering
industry courses, and he has trained engineers from the
U.S. and overseas. He developed analytical and numerical
models to history match and forecast production and
pressure behavior in gas reservoirs. Rahim also developed
3D hydraulic fracture propagation and proppant transport
simulators, and numerical models to compute acid
reaction, penetration, proppant transport and placement,
and fracture conductivity for matrix acid, acid fracturing
and proppant fracturing treatments. He has authored more
than 90 technical papers for local/international Society of
Petroleum Engineers (SPE) conferences and numerous inhouse technical documents. Rahim is a member of SPE and
a technical editor for SPE’s Journal of Petroleum Science
and Technology (JPSE) and Journal of Petroleum
Technology (JPT). He is a registered Professional Engineer
in the State of Texas, and a mentor for Saudi Aramco’s
Technologist Development Program (TDP). Rahim teaches
the “Advanced Reservoir Stimulation and Hydraulic
Fracturing” course offered by the Upstream Professional
Development Center (UPDC) of Saudi Aramco.
He is a member of GRMD’s technical committee
responsible for the assessment, approval and application of
new technologies, and he heads the in-house service
company engineering team on the application of best-inclass stimulation and completion practices for improved
gas recovery.
Rahim has received numerous in-house professional
awards. As an active member of the SPE, he has
participated as co-chair, session chair, technical committee
member, discussion leader and workshop coordinator in
various SPE international events.
Rahim received his B.S. degree from the Institut
Algérien du Pétrole, Boumerdes, Algeria, and his M.S. and
Ph.D. degrees from Texas A&M University, College
Station, TX, all in Petroleum Engineering.
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Adnan A. Al-Kanaan is the Manager
of the Gas Reservoir Management
Department (GRMD), where he
oversees three gas reservoir
management divisions. Reporting to
the Chief Petroleum Engineer, Adnan is
directly responsible for making
strategic decisions to enhance and sustain gas delivery to
the Kingdom to meet its ever increasing energy demand. He
oversees the operating and business plans of GRMD, new
technologies and initiatives, unconventional gas development
programs, and the overall work, planning and decisions
made by his more than 120 engineers and technologists.
Adnan has 20 years of diversified experience in oil and
gas reservoir management, full field development, reserves
assessment, production engineering, mentoring of young
professionals and effective management of large groups of
professionals. He is a key player in promoting and guiding
the Kingdom’s unconventional gas program. Adnan also
initiated and oversees the Tight Gas Technical Team to
assess and produce the Kingdom’s vast and challenging
tight gas reserves in the most economical way.
Prior to the inception of GRMD, he was the General
Supervisor for the Gas Reservoir Management Division under
the Southern Reservoir Management Department for 3 years,
heading one of the most challenging programs in optimizing
and managing nonassociated gas fields in Saudi Aramco.
Adnan started his career at the Saudi Shell Petrochemical
Company as a Senior Process Engineer. He then joined
Saudi Aramco in 1997 and was an integral part of the
technical team responsible for the on-time initiation of the
two major Hawiyah and Haradh gas plants that currently
process more than 6 billion standard cubic feet (bscf) of
gas per day. Adnan also directly managed Karan and Wasit
fields — two major offshore gas increment projects — with
an expected total production capacity of 5 bscf of gas per
day, in addition to the new Fadhili gas plant with 2.5 bscf
per day processing capacity.
He actively participates in the Society of Petroleum
Engineers (SPE) forums and conferences, and has been a
keynote speaker and panelist for many such programs.
Adnan’s areas of interest include reservoir engineering, well
test analysis, simulation modeling, reservoir characterization, hydraulic fracturing, reservoir development
planning and reservoir management.
In 2013, he chaired the International Petroleum
Technical Conference, Beijing, China, and in 2014, Adnan
was a keynote speaker and technical committee member at
the World Petroleum Congress, Moscow, Russia. In 2015,
he served as Technical Conference Chairman and Executive
Member at the Middle East Oil Show, Bahrain.
Adnan received the international 2014 Manager of the
Year award conferred by Oil and Gas Middle East magazine
and is the recipient of the 2015 SPE Regional Award.
He has published more than 40 technical papers on
reservoir engineering and hydraulic fracturing.
Adnan received his B.S. degree in Chemical Engineering
from King Fahd University of Petroleum and Minerals
(KFUPM), Dhahran, Saudi Arabia.
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Dr. Hamoud A. Al-Anazi is the
General Supervisor of the North
Ghawar Gas Reservoir Management
Division in the Gas Reservoir
Management Department (GRMD).
He oversees all work related to the
development and management of huge
Ain-Dar, Shedgum (SDGM) and ‘Uthmaniyah
gas fields like Ain-Dar
(UTMN). Hamoud also heads the technical committee that
is responsible for all new technology assessments and
approvals for GRMD. He joined Saudi Aramco in 1994 as
a Research Scientist in the Research & Development Center
and moved to the Exploration and Petroleum Engineering
Center – Advanced Research Center (EXPEC ARC) in
2006. After completing a one-year assignment with the
Southern Area Reservoir Management Department,
Hamoud joined the GRMD and was assigned to supervise
the SDGM/UTMN Unit and more recently the Hawiyah
(HWYH) Unit. With his team, he successfully implemented
the strategy of deepening key wells that resulted in the new
discovery of the Unayzah reservoir in UTMN field and the
addition of Jauf gas reserves in HWYH field. Hamoud was
awarded a patent application published by the U.S. Patent
and Trademark Office on September 26, 2013.
Hamoud’s areas of interest include studies of formation
damage, stimulation and fracturing, fluid flow in porous
media and gas condensate reservoirs. He has published
more than 60 technical papers at local/international
conferences and in refereed journals. Hamoud is an active
member of the Society of Petroleum Engineers (SPE), where
he serves on several committees for SPE technical
conferences. He is also teaching courses at King Fahd
University of Petroleum and Minerals (KFUPM), Dhahran,
Saudi Arabia, as part of the Part-time Teaching Program.
In 1994, Hamoud received his B.S. degree in Chemical
Engineering from KFUPM, and in 1999 and 2003, he
received his M.S. and Ph.D. degrees, respectively, in
Petroleum Engineering, both from the University of Texas
at Austin, Austin, TX.
Rifat Kayumov started his career
working in the Production
Enhancement Department for one of
the Russian service companies in
western Siberia. In August 2004, he
joined the Well Services Division in
Schlumberger. Rifat spent 3 years
working in western Siberia, then 6 years in the Volga-Urals
region of Russia in different technical positions. In June
2013, he was moved to Saudi Arabia as the Production
Stimulation Engineer in charge of stimulation activities for
Saudi Aramco. Rifat’s main focus as a Technical Engineer is
supporting hydraulic fracturing and matrix acidizing
operations.
He is the author of 10 technical papers published by the
Society of Petroleum Engineers (SPE) and the International
Petroleum Technology Conference (IPTC).
In 1999, Rifat received his B.S. degree in Mechanical
Engineering from the Russian State University of Oil and
Gas, Moscow, Russia.
Ziad Al-Jalal is currently working as
the Stimulation Domain Manager for
Schlumberger, where he is involved in
fracturing projects in Saudi Arabia and
Bahrain. He has 15 years of experience
in fracturing treatments in both
conventional and unconventional
wells. Ziad joined Schlumberger in 2000, working as a
Fracturing Field Engineer in western Siberia, Russia, for 4
years, then as a Technical Engineer in Saudi Arabia. From
2008 to 2012, he was a Team Leader in the Tight Gas
Center of Excellence based in Dhahran, Saudi Arabia. Ziad
previously worked as a Senior Production and Stimulation
Engineer in Oklahoma City, OK, from 2012 to 2014.
He received his B.S. degree in Mechanical Engineering
from King Fahd University of Petroleum and Minerals
(KFUPM), Dhahran, Saudi Arabia, in 1999.
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Development and Field Trial of the
Well Lateral Intervention Tool
Authors: Dr. Mohamed N. Noui-Mehidi, Abubaker S. Saeed, Haider Al-Khamees and Mohamed Farouk
ABSTRACT
Wells with extended reach, or multilateral wells, have improved reservoir contact and have opened the opportunity for
well placement and drilling optimization. Since the early
2000s, the number of maximum reservoir contact wells has
increased substantially, and the benefit of these wells is being
realized at the early implementation stage. To enhance the performance of these multilateral wells, intervention operations in
the laterals are required. Stimulation, data acquisition and
other operations help to optimize the production from the laterals; however, accessing the lateral of any wellbore for intervention in a reliable manner is still a challenge.
This article describes the development of an intelligent,
real-time controllable tool, the well lateral intervention tool
(WLIT), that can identify a lateral junction and steer an intervention/surveillance string into it. The WLIT is designed to be
deployed utilizing either coiled tubing (CT) or e-line (with the
help of Well Tractor® for extended reach horizontal deployments) for logging and/or stimulation purposes. This tool
provides the ability to increase the quantity and quality of information collected from the whole well — the motherbore
and each of the multiple laterals individually — to get the best
answers for intervention planning. The discussion here is dedicated to the development stages of the tool and the field trial
tests results.
The WLIT comes in two versions; the first version is
“wired,” which accommodates specific logging tools that are
compatible with the WLIT design, and the second version is
“wireless,” which allows the use of all types of logging toolstrings from any third party provider. The test results are from
trials using both versions of the tool. The WLIT sensory equipment as well as the control environment are described, and
results from the field trial tests are presented.
INTRODUCTION
The oil and gas industry is constantly advancing well technologies to increase recovery and reduce production costs, especially as more and more complex reservoirs are being targeted.
The idea of increasing reservoir contact with multilateral completions started in the 1990s, and since the first completions,
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multilateral horizontal well technologies have demonstrated
increased production rates. Several multilateral configurations
have been drilled, with four to seven legs, for both producer
and injector wells1. Well architecture and completion became
the focus of many innovative technologies that increased well
reservoir contact. Simultaneously, advanced completions were
sought to reduce field development costs by reducing the total
number of wells required to achieve production targets2, 3.
In the Kingdom of Saudi Arabia, multilaterals have been
drilled for decades. From this concept, Saudi Aramco moved
to successfully implement maximum reservoir contact wells to
further enhance hydrocarbon recovery4, 5. From there, Saudi
Aramco has been developing extreme reservoir contact wells
where control and monitoring measures are deployed in both
the motherbore and the laterals6. Lateral accessibility is an important aspect of these advanced completion concepts. Several
methods and tools have been developed to facilitate lateral accessibility, making changes to existing completion types and
tools7-11; however, active sensing and accurate mapping of the
lateral window required further improvement through new
intervention tools.
In this article, a new lateral accessibility tool, the well lateral
intervention tool (WLIT), is presented. This tool is a joint
development between Saudi Aramco and Welltec. Several field
trial tests have been successfully performed in Saudi Aramco
fields, which have proven the concept of smart lateral sensing
and access using several sets of advanced sensors and diagnostic
tools.
WLIT COMPONENTS AND SPECIFICATIONS
The first version of the WLIT introduced was “wired” due to
the fact that the third party tool has to be modified with a wire
feed to be able to communicate commands to the WLIT steering
joint — at the very bottom section of the string — and allow
steering of the toolstring in the desired direction for lateral accessing. This version proved the concept in the first two trials,
where a multiphase production logging tool was deployed and
successfully accessed the laterals. With the lessons learned from
the first two trials, stage 2 development commenced to introduce
the “wireless” WLIT. The wireless WLIT is basically equipped
with a wireless sub to allow the WLIT to send commands to
the steering joint without the need for modifying the third
party tool, given that some third party tools don’t have enough
space to accommodate the extra wiring required. The new solution was deployed in the rest of the trials.
The tool itself is an electromechanical platform comprising
several components: the sensor package with different types of
sensors; the electromechanical actuator system, which actuates
in the direction desired to allow steering of the tool toward the
lateral; and the wireless sub and control/monitoring interface.
Figure 1 provides a diagram of the WLIT, and Table 1 summarizes the main features.
In the following sections, the different parts of the WLIT
tool are described.
OD
2⅛”
Length (w/o third party tool or
well tractor)
32 ft
Length with Well Tractor
80 ft*
Weight in Air
220 lb
Maximum Pressure
Maximum Temperature
The well hardware scanner (WHS) is designed to detect the
magnetic characteristics of known reference points on the casing string; these points can be used to determine the position
of the entrance to a lateral window. The WHS consists of permanent magnets and magnetic sensors. The magnets and magnetic sensors are placed in a grid-like structure that ensures
well-defined magnetic flux lines. The sensors measure changes
to the magnetic field caused by changes in the metallic surrounding, i.e., indicating casing collars, perforation holes, sliding sleeves, etc. In this arrangement, the results are monitored
and the tool is controlled from the surface using the control
257 °F
Tensile Strength
36,000 lb
Compressive Strength
30,000 lb
Well Fluid
Oil/Water/Gas
Minimum Dev. at Junction
Maximum ID at Junction
Sensor 1: Well Hardware Scanner
20,000 psi
Third Party Tool Requirement
30°
8½” Cased Hole or
Open Hole
Mono Conductor
* Depending on desired
configuration; third party tool
will depend on logging tool
utilized.
Table 1. WLIT specifications
cockpit. The sensor measures the angle of a magnetic field relative to the sensitive axis — the direction crosswise to the sensor. Each of the sensors measures the anomaly of a magnetic
field relative to a given direction. When the tool is positioned
in the casing, the changes in geometry/metallic surrounding
will cause changes in the magnetic field. The sensors record the
same fluctuations in the signals when passing the same geometric/metallic structures in the well. As an illustration of the
concept, Fig. 2 shows a typical signal response received from
this sensor.
The WHS diagnostic tool provides the following:
• Depth measurement.
• Lateral entry confirmation.
• Lateral window identification.
• Inclination (in real time).
Fig. 1. A sketch of the WLIT tool assembly. This includes a well tractor to
illustrate the assembly when a well tractor is needed in the operation.
Fig. 2. Raw data from the WHS indicating the tool response to the changes in the
metallic surrounding environment (welds, holes, etc.), shown above the plot.
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• Tool speed/direction.
The WUS diagnostic tool provides the following:
• Open hole/cased hole distinction.
• Lateral window identification.
Sensor 2: Well Ultrasonic Scanner
The well ultrasonic scanner (WUS) is designed to be used in
single-phase flow regimes, mainly liquid. It is able to provide
fast, reliable and accurate range detection in that environment.
It consists of an array of ultrasonic transducers arranged circumferentially around the outer diameter (OD) of the tool,
facing outwards. The tool transmits individual signals in sequence while “listening” simultaneously on all transducers.
The echo return time and amplitude response provide information — a wellbore fingerprint — identifying the surrounding
environment.
In principle, it uses basic range finding principles of time of
flight measurements for ultrasonic signals, Fig. 3a. The measurements can be made using either one or two transducers. It
may be possible to acquire the speed of sound of the well fluid
in real time while operating in the well. To do so requires sampling the fluid once or repeatedly for calibration. Software at
the surface is designed to interpret/plot the transmitted/received signal and find the place of diverging radius, i.e.,
washouts and sidetracks. Basically, the WUS transducers,
placed around the circumference of the tool, are able to map
the inside OD of the opposite wall. Figure 3b illustrates how
the sensors show an opening space in the pipe on the righthand side where the reflected ultrasonic data is far off from the
data received directly from the pipe wall.
• Lateral entry confirmation.
• Tool orientation.
• Inclination (in real time).
• Open hole/cased hole and open hole/open hole
distinction.
The Wireless Sub
The wireless sub was designed to allow communication with
the steering joint without the need to modify the third party
tools. It is operated from the surface and uses batteries to provide the power required to activate and steer the steering joint.
The batteries are designed to work for 12 hours downhole for
the same run. The wireless kit has a data protocol converter to
connect to the wireless hub, Fig. 4.
The Electromechanical Actuator (Steering Joint)
Data from the sensor package, which is coupled with prior
well path information, is used to maneuver the electromechanical actuator section, Fig. 5, into the lateral in two steps. The
first step pivots the joint around its central axis in the direction
toward the center of an identified lateral. In the second step, a
hydraulic piston steers the joint in the desired direction; steering is done in increments of 15° to fine-tune access. The steer-
Fig. 3. (a) An ultrasonic scanner range measurement example in a slotted casing. (b) Recorded data showing an open space in the pipe (right-hand side) where the reflected
ultrasonic data is far off from the data received directly from the pipe wall.
Fig. 4. The wireless sub function.
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Fig. 5. The electromechanical actuator (steering joint).
able joint was developed to be controlled from the surface using the data from the sensor package. The control system is
used to engage and disengage the various tools in the toolstring.
Once an angle value has been set, the arm rotates to the desired direction, one that points toward the lateral entry. Steering then commences, and after the tool has been confirmed in
the lateral, the controller at the surface releases the arm to its
neutral point, which will deactivate it.
The toolstring, once in the lateral, progresses while the arm
is deactivated.
The Software and the Interface (Selective Access Interface)
The WLIT utilizes software that is run on an interface at the
surface, where it is operated by the field engineer. The software
controls and monitors the entire operation of all the tools, as
well as two sub modules specific for the intervention tool: (a)
Module 1 incorporates the data from the sensor package to
consistently display a proximity signal showing the casing/
pipe/tubing/liner in a 360° circumference, and (b) Module 2
controls the electromechanical actuator.
The signal response and the tool responses are monitored in
real time for accurate depth control and operational efficiency.
TRIAL TEST SUMMARY
The WLIT was designed to be compatible with deployment by
either an e-line or coiled tubing (CT) that uses an e-line to
lower power transmission to the sensors. Since the lateral window shape and integrity are unknown, it was decided to execute all trials utilizing CT for simplicity and to prove the
Well Number
concept of the WLIT. The tool was tested in seven wells in
Saudi Arabia; some had been completed with a cased hole
motherbore and open hole laterals and others had been completed with an open hole motherbore and open hole laterals.
The main objective of the trials was to prove the tool’s capability to map/scan the motherbore at lateral depths, using the sensor package to identify the depth and direction of the lateral
window, and then to guide the bottom-hole assembly to access
any desired lateral. Once a lateral window is scanned, the log
file can be used at any time later to access the lateral without
the need to re-scan the motherbore. Scanning and accessing
procedures were identical for all wells. One well example is
discussed next; all well trial configurations are summarized in
Table 2.
Trial Test of Well-1: Operational Details
Figure 6 shows the lateral intervention toolstrings deployed for
both jobs. The first test took place in Well-1, Fig. 7, where the
tool was deployed on a third party CT string. The primary objective was to map the motherbore, determine where the lateral windows were and then drive the toolstring from the
cased hole motherbore into the open hole laterals. The WLIT
was run in hole, and logging data of the sensors’ signals were
collected at the surface on the control computer. The toolstring
started logging 7,000 ft above the topmost lateral (L3) window. The WHS sensor clearly indicated the casing housing and
the different parts of the well completion as expected. At the
vicinity of L3, the sensors indicated a change in the signal amplitude that revealed the presence of the lateral window. Once
the toolstring passed the window, the sensor’s signal went back
to the previous signal range, indicating normal casing in the
motherbore. The motherbore mapping continued down toward the two other laterals, and at the vicinity of each lateral,
the same signal deviation was observed, indicating the presence of the lateral windows.
The toolstring was pushed further down into the motherbore to the open hole section where it was clearly seen that the
WLIT Version
Number of Laterals
Completion Type*
Well 1
Wired
MB – 3 × L
Cased Hole-Open Hole
Well 2
Wired
MB – 1 × L
Cased Hole-Open Hole
Well 3
Wireless
MB – 2 × L
Cased Hole-Open Hole and
Open Hole-Open Hole
Well 4
Wireless
MB – 1 × L
Open Hole-Open Hole
Well 5
Wireless
MB – 1 × L
Cased Hole-Open Hole
Well 6
Wireless
MB – 6 × L
Open Hole-Open Hole
Well 7
Wireless
MB – 1 × L
Open Hole-Open Hole
* CH-OH/OH-OH going from cased hole to open hole/Going from open hole to open hole
Table 2. The configurations for the WLIT test wells (MB: Motherbore; L: Lateral; Cased Hole-Open Hole: Going from cased hole to open hole; Open Hole-Open Hole:
Going from open hole to open hole).
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Fig. 6. The lateral intervention toolstrings used in the field trials.
Fig. 8. WHS sensor window signature during the motherbore logging.
Fig. 7. Schematic of Well-1 used for the first field trial.
signal was completely lost, again as anticipated, since this implied
the absence of any metallic surrounding, which is true for an
open hole section. The toolstring was then pulled back along
the motherbore, and the three lateral windows were mapped
again while moving the WLIT back toward the well heel.
Figure 8 shows a typical WHS signal response indicating a
lateral window signature; the large amplitude results from the
loss of signal that occurs with the interruption in the metallic
surrounding at the lateral junction. Before entering any of the
laterals, the toolstring was run at a slow speed several times
backwards and forwards in the vicinity of the window to allow the sensors to more clearly identify the entry point’s azimuth. The responses of multiple sensors from multiple passes
were then combined to better locate the window width and
window orientation, Fig. 9. The lateral window shown in Fig.
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9 corresponds to the window mapped in Well-1. The signal
clearly identifies the window extension from both sides, and
the window orientation can be seen on the vertical axis. Once
the lateral junction window was successfully mapped, the lateral entry preparation started by pulling the toolstring 30 ft
above the lateral window, powering up the electromechanical
actuator and changing its orientation to point toward the lateral window, i.e., 315° (45° from the left) for L2 in Well-1.
While powering the electromechanical actuator, the engineer
received a positive indication at the surface that the arm had
rotated to the desired set azimuth. The toolstring was then run
at the same slow speed while passing the window. Initially
while passing the window, the signal indicates a large amplitude
change in the magnetic flux. As the toolstring moves further
ahead into the lateral, the signal amplitude decreases until the
signal disappears completely, indicating it is in an open hole
environment, Fig. 10. During the field trial, the toolstring was
run several hundred feet further into the open hole lateral. As
anticipated, the signal never restarted. After progressing 200 ft
Fig. 9. Lateral window azimuthal indications after several passes across the
same window (the more passes taken the darker the area, i.e., a confirmed
window opening).
into the lateral, the toolstring was pulled back to the junction
to test the response. The signal returned at the same location
where it had been lost due to the presence once again of the
casing. The operation was repeated several times to assure repeatability of the signal. At each run and at each lateral, the
same results were obtained, indicating correct and positive lateral entrance and exit. The access was performed at different
speeds, between 5 ft/s to 15 ft/s.
During the mapping and lateral entry procedures, the engineer can analyze the response from the complementary combination of tool signals, as previously described. Therefore, to
make sure that the lateral was accessed before moving the
toolstring deeper in the lateral open hole, multiple signals were
compared while passing the window and while trying to access
the lateral, Figs. 11 and 12. In Fig. 11 it can be seen that two
independent passes for the same lateral window gave the same
signal responses, while in Fig. 12 the comparison of the signal
while passing the window and while entering the lateral are
completely different. The two signals in Fig. 12 deviated just at
the depth where the window started, indicating the high probability of a lateral intersection. The toolstring then progressed
further into the lateral open hole until the signal was completely lost at around 49 ft from the entry point — enough distance to lose the response from the casing — again indicating
that the sensors had moved deep into the open hole.
Fig. 11. The sensor response for two different passes across the same lateral
window. The two signals are clearly seen as being overlaid.
Fig. 12. The sensor response comparison for two different passes; one passing a
window and one accessing a lateral. It can be seen that the two signals are
different, indicating lateral entry.
Open Hole-Open Hole Laterals
In the open hole-open hole lateral completions — open hole
motherbore to open hole lateral — the WHS response will be
zero due to the absence of any metallic surrounding. Therefore, the WUS (Sensor 2) response is used alone to identify and
confirm lateral accessing. During the scanning passes, the WUS
gives a real-time measurement of the borehole inclination —
motherbore and lateral.
In Fig. 13, plots of the inclination data of the WUS in realtime measurement vs. data from a drilling survey are shown.
The overlay of the real-time measurement with the drilling
survey would confirm the location of the toolstring — whether
in the motherbore or in the lateral.
Fig. 10. WHS signal loss as the toolstring enters the open hole lateral.
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Controlled Hydraulic Interval Control Valves for the
Management of Water Production in the Saih Rawl Field,
Sultanate of Oman,” OTC paper 15134, presented at the
Offshore Technology Conference, Houston, Texas, May 58, 2003.
2. Ramakrishnan, T.S.: “On Reservoir Fluid Flow Control
with Smart Completions,” SPE Production & Operations,
Vol. 22, No. 1, February 2007, pp. 4-12.
3. Artus, V., Durlofsky, L.J., Onwunalu, J. and Aziz, K.:
“Optimization of Nonconventional Wells under
Uncertainty Using Statistical Proxies,” Computational
Geosciences, Vol. 10, No. 4, December 2006, pp. 389-404.
Fig. 13. Inclination plot (drilling survey vs. WUS measurement).
CONCLUSIONS
Lateral accessibility with the WLIT has been proven through
several well trials in both cased hole to open hole and open
hole to open hole well configurations. This tool is the first
electromechanical downhole tool in the industry for both lateral detection and repeatable access. The sensor package of the
tool can visualize the lateral window as well as direct the toolstring toward the lateral entry point. The sensors have shown
very good reliability in identifying the lateral junction window
shape and orientation, and they have been used several times
successfully to access laterals.
The WLIT is a tool designed to suit both e-line and CT with
an e-line deployment for logging; the potential exists to use the
tool for future acid stimulation purposes. The wireless communication provides the capability to deploy a wide range of surveillance tools with different service providers. This tool gives
operators the ability to locate and enter laterals, overcoming
previous limitations in the industry and allowing the operator
to fully understand and remediate lateral monitoring.
ACKNOWLEDGMENTS
The authors would like to thank the management of Saudi
Aramco and Welltec for their support and permission to publish this article, as well as thank the production engineering
and operations teams involved. In addition, the authors would
like to acknowledge the help of the following individuals and
their respective teams in the accomplishment of this work:
Mohannad Abdelaziz, Wessam Busfar, Talha Ahmed, Michael
Black, Brian Roth, Ahmed Zain and Marwan Zarea.
This article was previously published in SPE Production
and Operations, April 2015.
REFERENCES
1. Boyle, M., Earl, J. and Al-Khadori, S.: “The Use of Surface
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SAUDI ARAMCO JOURNAL OF TECHNOLOGY
4. Salamy, S.P., Al-Mubarak, H.K., Hembling, D.E. and AlGhamdi, M.S.: “Deployed Smart Technologies Enablers for
Improving Well Performance in Tight Reservoirs — Case:
Shaybah Field, Saudi Arabia,” SPE paper 99281, presented
at the Intelligent Energy Conference and Exhibition,
Amsterdam, The Netherlands, April 11-13, 2006.
5. Al-Arnaout, I.H., Al-Zahrani, R.M., Jacob, S. and Kumar,
S.: “Smart Wells Experiences and Best Practices at Haradh
Increment-III, Ghawar Field,” SPE paper 105618,
presented at the SPE Middle East Oil and Gas Show and
Conference, Manama, Bahrain, March 11-14, 2007.
6. Qahtani, A.M. and Dialdin, H.: “SS: Advanced
Completion Technologies Maximize Recovery,” OTC
paper 20136, presented at the Offshore Technology
Conference, Houston, Texas, May 4-7, 2009.
7. Hovda, S., Haugland, T., Waddell, K. and Leknes, R.:
“World’s First Application of a Multilateral System
Combining a Cased and Cemented Junction with Fullbore
Access to Both Laterals,” SPE paper 36488, presented at
the SPE Annual Technical Conference and Exhibition,
Denver, Colorado, October 6-9, 1996.
8. Antczak, E.J., Smith, D.G.L., Roberts, D.L., Lowson, B.
and Norris, R.: “Implementation of an Advanced
Multilateral System with Coiled Tubing Accessibility,” SPE
paper 27673, presented at the SPE/IADC Drilling
Conference, Amsterdam, The Netherlands, March 4-6,
1997.
9. Rivenbark, W.M., Al-Sowayigh, M.I. and Al-Furaidan,
Y.A.: “A New Selective Lateral Re-Entry System,” SPE
paper 59209, presented at the IADC/SPE Drilling
Conference, New Orleans, Louisiana, February 23-25,
2000.
10. Dahroug, A., Al-Marzooqi, A., Al-Ansara, F., Chareuf, A.
and Hassan, M.: “Selective Coiled Tubing Access into
Multilateral Wells in Upper Zakum Field: A Two-Well
Case Study from Abu Dhabi,” SPE paper 81716,
presented at the SPE/ICoTA Coiled Tubing Conference
and Exhibition, Houston, Texas, April 8-9, 2003.
11. Amorocho, J.R., Solares, J.R., Al-Mulhim, A., Al-Saihati,
A. and Kharrat, W.: “Horizontal Open Hole, DualLateral Stimulation, Using a Multilateral Entry with High
Jetting Tool,” SPE paper 126070, presented at the SPE
Saudi Arabia Section Technical Symposium and
Exhibition, al-Khobar, Saudi Arabia, May 9-11, 2009.
BIOGRAPHIES
Dr. Mohamed N. Noui-Mehidi is a
Petroleum Engineer Consultant at
Saudi Aramco’s Exploration and
Petroleum Engineering Center –
Advanced Research Center (EXPEC
ARC). He has been covering the
position of champion of multiphase
flow metering and well intervention for the Production
Technology Team. Mohamed joined Saudi Aramco in late
2008 and had previously been working for the Commonwealth Scientific and Industrial Research Organization,
Australia. He has more than 25 years of experience in the
area of multiphase flow dynamics, flow metering and flow
modeling.
Mohamed’s research activities are related to the
development of new technologies in well control and
monitoring for upstream oil and gas production. He has
published more than 90 journal articles and conference
papers on the different aspects of fundamental and applied
fluid dynamics as well as authored six company granted
patents and several patent applications.
Mohamed received his Ph.D. degree in Resource &
Energy Science from the University of Kobe, Kobe, Japan.
Abubaker S. Saeed joined Saudi
Aramco in 2011 as a Petroleum
Engineer, working in the sensing and
intervention focus area of the
Production Technology Team in the
Exploration and Petroleum
Engineering Center – Advanced
Research Center (EXPEC ARC). He has published eight
patents and several technical and journal papers, and led
the successful field deployment of several new intervention
technologies.
Abubaker has been a recipient of several international
awards, including the “2015 Best Young Oil and Gas
Professional of the Year” award as well as the prestigious
“2015 Young ADIPEC Engineer of the Year” award. His
project work in the area of downhole sensing and intervention was awarded the ICoTA Intervention Technology
Award of 2014, as well as being nominated as a finalist for
the World Oil Awards 2014 — Best Production
Technology.
Abubaker received his B.S. degree in Systems
Engineering from King Fahd University of Petroleum and
Minerals (KFUPM), Dhahran, Saudi Arabia. He received
his M.S. degree in Mechanical Engineering from King
Abdullah University of Sciences and Technology, Thuwal,
Saudi Arabia.
Haider Al-Khamees is currently the
Country Manager at Quinterra
Technologies. He previously worked at
Welltec, in the area of well intervention
and field services. Haider has 7 years of
experience in well intervention
technologies and logging operations.
His previous experience also included a short period
working at Schlumberger.
In 2003, he received his B.S. degree in Petroleum
Engineering from King Fahd University of Petroleum and
Minerals (KFUPM), Dhahran, Saudi Arabia.
Mohamed Farouk joined Schlumberger
in 1991 as a Field Engineer in Egypt. In
1995 he was the first DESC Engineer
placed by Schlumberger at Saudi
Aramco working in the ‘Uthmaniyah
Production Engineering Department. In
1996, Mohamed was transferred to
Center in the U.K. as the Well
Schlumberger’s Training
T
Intervention Technical Instructor where he worked with a
team of qualified instructors on writing online manuals for
both technical and operational training. Upon completion
of this project in 1999, Mohamed was transferred to Egypt
as the Well Intervention Area Manager for the East Africa
Market. He also acted as the technical focal point for the
coiled tubing services in the Middle East. In 2001,
Mohamed moved to Saudi Arabia as a Well Construction
Manager, working there for 3 years. He introduced the
lightweight cement systems to Saudi Aramco by working
closely with Saudi Aramco’s Fluids Division of the R&D
Center.
In 2005, Mohamed was assigned the role of Marketing
Manager for the Gulf Area for Well Intervention,
Cementing and Stimulation Business. During this
assignment, he worked closely with national oil companies
(NOCs) on value added projects and services by
introducing new technology solutions. Mohamed’s last
assignment with Schlumberger was as the Middle East
Region Well Intervention Manager in the company’s head
office in Dubai, UAE.
He joined Welltec in 2011 as the Middle East and
North Africa Vice President, staying in that position until
January 2015. While in this role, Mohamed managed to
introduce multiple “firsts” in the world of e-line
mechanical technologies to several NOCs, as well as
international oil companies (IOCs). These included: well
obstruction milling, a multilateral steering tool, open hole
tractoring solutions and coiled tubing tractoring in open
holes. He is currently the Middle East and Africa Region
Manager for Well Intervention, Cementing and Stimulation
Business with Weatherford.
In 1991, he received his B.S. degree in Civil Engineering
from Ain Shams University, Cairo, Egypt.
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Directional Casing while Drilling (DCwD)
Reestablished as Viable Technology in
Saudi Arabia
Authors: Germán A. Muñoz, Bader N. Al-Dhafeeri, Hatem M. Al-Saggaf, Hossam Shaaban, Delimar C. Herrera,
Ahmed Osman and Locus Otaremwa
ABSTRACT
To access the reservoir in a large Saudi Arabian development
field, the operator is required to drill an intermediate 5,000 ft
to 6,000 ft directional hole section with a dogleg severity varying from 2.5°/100 ft to 3°/100 ft. The 12¼” borehole typically
crosses several interbedded formations of limestone, shale and
sand. This is associated with a variety of hole problems, which
have occurred repeatedly in the offset wells. The main objective for the operator was to mitigate the problems by finding
alternative drilling technologies. Among those considered,
Saudi Aramco determined that the recent developments in directional casing while drilling (DCwD) technology may well
provide an effective method for diminishing the associated
nonproductive time (NPT).
The drilling engineering team conducted an extensive evaluation of the problems across this section, including issues with
wellbore stability, water flow and loss of circulation; tight
hole/stuck pipe incidents; and severe bit/stabilizer wear while
drilling abrasive sands. After a promising technical and engineering evaluation of DCwD, followed by a detailed risk assessment striving to determine the potential of the application,
a well was planned and executed using the DCwD service.
This article outlines the process carried out during all stages
from planning through the final deployment of the first 9⅝”
DCwD application in Saudi Arabia. It shows how the technology was successful in reducing the impact of some of the problems previously experienced while drilling the same section in
other wells in the field. The information provided will serve as
a starting point for the design and construction of subsequent
wells, leading to further improvement in drilling performance.
Best practices and lessons learned from this implementation
are expected to become a model, with the know-how transferred to other areas where comparable drilling problems occur.
As the technological benefits have been recognized by the
operator, this application has reestablished DCwD as a viable
technology to address a number of challenges common in
many of the Saudi Arabian oil and gas fields.
INTRODUCTION
Casing drilling replaces conventional drillpipe and other
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downhole tools by using the casing as the drillstring. Like
drillpipe, the casing string conveys torque, rotation and hydraulic energy to the bit. The directional casing while drilling
(DCwD) solution can be used with any conventional directional or logging bottom-hole assembly (BHA), while ensuring
that every foot drilled is cased off and secured1.
One of the benefits of the casing while drilling technology is
an augmented wellbore strengthening2. As a result, the wellbore retains a smoother, more uniform surface, thereby providing stability as well as minimizing the invasion of the drilling
fluid into the surrounding near wellbore area3. This aspect
alone can reduce the likelihood of differential sticking and improve cementing quality4.
Throughout the casing while drilling process, the operator
should expect to see an improvement in the ability to control
losses, as the casing always remains at the bottom of the wellbore5. This also allows every foot drilled to be cased off, bringing value through the elimination of nonproductive time
(NPT) that can occur with the extended reaming and back
reaming often needed in an open hole completion6.
DCwD technology was considered for drilling the directional hole section needed to access the reservoir in M field, a
large Saudi Arabian development field. The 12¼” hole required of the M field wells is a long directional section that extends an average of 5,000 ft with a dogleg severity ranging
from 2.5°/100 ft to 3.0°/100 ft. Moreover, this 12¼” interval
is drilled across a sort of problematic formation, including
fractured limestones, unstable shales and interbedded abrasive
sands and siltstones.
Some of the potential hole problems that are expected in a
well drilled in this field, based on information from offset
wells, are:
• Wellbore instability in shallower horizons as a
consequence of water flow, loss of circulation and/or
extended reaming and back reaming across such
formations.
• Severe or total losses.
• Severe drilling dynamic effects due to the harsh drilling
environment, such as “stick and slip” and high
abrasiveness.
• Possible tight hole, stuck pipe, shale sloughing and
invasive water flow.
• Early and deep bit and stabilizer wear while drilling
across the abrasive sands, along with a very low rate of
penetration (ROP).
Saudi Aramco set the objectives for the well in this study as:
• Reevaluate the viability of using DCwD with 9⅝”
casing in the M field.
• Drill the 12¼” section with casing and reach the
planned casing point with the minimum number of
BHA runs.
• Accomplish the directional plan for the section.
• Minimize the risks associated with typical hole issues
seen in offset wells (tight hole, stuck pipe and shale
sloughing).
PLANNING
Extensive pre-job planning was performed to determine the
feasibility of using DCwD in the section and whether the objectives were achievable or not. The main factors analyzed
were: torque and drag, casing connection selection, fatigue life
on the casing, bit and underreamer (UR) hydraulics, and shock
and vibration mitigation. The engineering modeling data and
their comparison with the actual results — including lessons
learned — are discussed in this article.
The results of the feasibility studies were analyzed by both
engineering and drilling operations teams, and additional efforts were made to optimize the initial proposed BHA following several risk assessment sessions. The participation of rig
crew and third parties in these technical meetings — including,
but not limited to, well supervisors, mud and cementing engineers, directional drillers, etc. — was crucial to review the design basis for the job.
The 2,000 horsepower (HP) drilling rig selected to run this
application did not require any modification. The DCwD supplier performed a rig survey before the job and provided a casing running tool, which was installed on the rig’s top drive, to
make up the casing connections and also transmit the required
axial and torsional loads while drilling.
A total of three downhole tool sets were made available for
this job. The directional BHA was planned to be retrieved and
run in hole again using drillpipe conveyed tools. Figure 1 illustrates the typical kit of downhole tools, running tools and consumables required for a DCwD application.
TORQUE AND FATIQUE ANALYSES WITH CASING
CONNECTION SELECTION
The torque and drag modeling analysis done during the planning
Fig. 1. Standard DCwD equipment and consumables package.
stage took into account the proposed directional trajectory,
typical friction factors (open hole and cased hole, as previously
calibrated from similar wells), bit torque and tortuosity. The
resulting estimate of the string torque required to drill to total
depth was close to 28,600 lbf-ft, Fig. 2a, which meant that the
casing connections had to be made up to 35,000 lbf-ft — 20%
above the calculated drilling torque — to meet the criteria to
safely drill with the casing string.
Therefore, it was realized that a buttress connection — using American Petroleum Institute (API) buttress thread casing
(BTC) — was best suited for the job. But the field standardized
thread is a long thread casing, needed if it becomes imperative
to cut and re-thread the pipe, which meant the connection
alone could not handle the calculated torque with the required
safety factor of 35,000 lbf-ft. Therefore, multi-lobe torque
(MLT) rings were recommended to increase the maximum
drilling torque capacity of the connections to 44,426 lbf-ft. The
MLT rings provide a positive makeup shoulder for the pin ends,
which increases the API BTC connection torque capacity, Fig. 2b.
In addition to torque capability, the fatigue life of the BTC
connections determines whether they can be safely used for a
given DCwD application. The fatigue life analysis for the BTC
casing string was done using conservative drilling parameters
— weight on bit (WOB), surface revolutions per minute (rpm)
and ROP.
A fatigue failure occurs when the casing string is exposed to
high alternating stress. The two common sources of alternating/cyclical tensile stress are the bending stresses resulting from
rotating the casing in a directional section and vibration.
The maximum allowable stress for a DCwD application depends on the number of alternating stress cycles. In this particular case, the maximum calculated stress level for 9⅝” casing
— based on the directional plan — was less than 8,000 psi.
That translates to a fatigue life for the casing of more than 10
million cycles, Figs. 3 and 4, which represents less than 1% of
the fatigue life of the string.
DIRECTIONAL BHA DESIGN
The BHA inside the 9⅝” casing was composed of 6¾” tools.
The BHA extruding below the casing shoe consisted of a
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Fig. 2. (a) Torque modeling for the “M” well; and (b) Torque capacity of MLT ring installed on a BTC connection.
Fig. 3. Plots showing accumulated fatigue life (left) and equivalent alternating stress (right).
directional drive system, a measurement while drilling (MWD)
tool and an underreamer. The drive system was a point-the-bit
rotary steerable system (RSS) along with an 8½” polycrystalline diamond compact (PDC) bit that was driven by a mud
motor placed and locked inside the casing. This drive system
was selected based on its proven performance in the field. The
MWD tool had the “pumps off” surveying feature that allowed
it to take surveys when pumps are stopped. Ensuring that the
tool is stationary when surveys are taken is a critical feature to
ensure good surveys in DCwD applications. This MWD tool
was also configured with a delayed surveying feature to minimize
the effect of lost surveys or signal noise when pumps are
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started, another feature that has shown to have great importance in such an application. Finally, the UR was dressed with
12¼” arms to allow enlarging the hole to 12¼” without jeopardizing the ability of the BHA to pass through the 9⅝” casing, Fig. 5.
SHOCKS AND VIBRATION MODELING
The dynamics of the proposed drilling system were modeled to
test the stability of the whole DCwD BHA and determine the
optimum parameters for drilling through the different formations.
The bit for a DCwD application is typically selected after
while drilling the more abrasive deep interval. The finite element analysis (FEA) software modeling also suggested, for optimum cutting structure performance, that the ratio of weight
on reamer to WOB must be maintained at 30%, Fig. 6.
Fig. 4. Typical SN curve used for fatigue life estimation.
Fig. 6. Weight on reamer to WOB ratio.
The FEA software is a time-based 4D modeling tool used to
accurately predict a drilling system’s behavior using laboratory-derived drilling mechanics data and physical input data
that characterizes the bit, BHA, wellbore, formations and operating parameters. FEA calculates solutions for a complex
system by breaking down each component into small elements,
establishing both stress equilibrium and strain compatibility at
each node of all the elements, and creating an assemblage of
the individual equations, which is used to derive global solutions for the entire drilling system.
Using FEA, the drilling performance of the DCwD equipment and BHA was simulated for all the expected formations
under different surface drilling parameter combinations —
WOB and rpm — to determine the optimum and most stable
parameter operating window. Figure 7 shows one example of
the parameter road maps produced by the analysis: The green
Fig. 5. Directional BHA configuration.
reviewing the best performing bits from offset wells, including
number of blades, PDC cutter size, etc. The candidate bits
went through an integrated drill bit design platform analysis to
check if they could drill the given formations and if they were
compatible with the UR cutting structure in the BHA. The
UR/bit cutting structures need to be compatible to enhance the
response of the directional BHA. The bit selection process led
to the suggestion to start with a five blade bit for the softer top
interval of the section and then to move to a six blade bit
Fig. 7. Example of drilling parameter sensitivity plot done with FEA software.
SAUDI ARAMCO JOURNAL OF TECHNOLOGY
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zone shows the combination of drilling parameters where the
BHA would be stable or without vibrations.
WELL CONTROL
Well integrity is one of the key aspects to be considered when
drilling sections, even for intervals where the associated risks
are low, e.g., where there are no bearing pay zone formations
or hydrocarbon production. The DCwD response is not significantly different from the regular approach when conventional
drilling is used7, but it does require additional equipment for
tripping out and in with a specific set of running tools, such as
to retrieve or set a new BHA. Under this circumstance — with
casing string on slips and with the drillpipe inside with running
tools — there are two different flow paths along which the
well can take an influx: (1) open hole casing annulus, and (2)
casing string drillpipe annulus.
The service provider offered the latest generation of a surface well control tool, the casing circulating tool (CCT), which
is designed to provide a reliable means of well control when
the drillpipe is being used to convey a retrievable DCwD BHA,
Fig. 8. It also allows pressure testing before and after installation, plus periodic circulation, reciprocation and rotation of
the casing string to mitigate the chance of the casings getting
Fig. 8. BHA being retrieved with drillpipe conveyed tools and a false rotary table (right). The yellow and red boxes show the CCT components (bottom).
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stuck as a result of sitting idle during the tripping process. This
can be done at any time and as frequently as required, depending on the magnitude of the risks associated with the operations. The tool has the following functionalities:
• Isolates the annulus inner string casing to contain
maximum anticipated surface pressure.
• Simultaneously suspends the casing string, the inner
string and the BHA.
and still have enough flow rate to clean the hole, while also
generating the required torsional loads from the mud motor
and keeping a good hydraulic energy for the bit — HP per
square inch ≥ 1.5 hydraulic HP.
Simulations showed that using an oil-based mud (OBM)
with a density of 72 pcf (9.6 ppg) at a flow rate of 500 gpm
will give annular velocities high enough — casing/open hole
annular velocity was 235 ft/min with 550 gpm, Table 1 — to
clean the hole, while maintaining an acceptable ECD below 79
pcf (10.6 ppg), Fig. 9.
• Allows measurement of the surface pressure in the inner
string casing annulus.
• Makes up to the inner string casing in an expeditious
manner.
• Has a secondary purpose once installed, enabling the
operator to reciprocate and circulate as needed to
ensure the casing string is free when differential sticking
has been identified as a potential risk, e.g., when drilling
through depleted and porous formations.
Bit and UR Hydraulics
Bit
Flow Rate
550 gpm
0.00 gpm
2
Flow Area
0.90 in
0.00 in2
Pressure Drop
271 psi
0 psi
195.65 ft/sec
0.00 ft/sec
1.5 HHP
0.0 HHP
533 lb
0 lb
Jet Velocity
Hydraulic Power
Impact Force
The CCT is mounted below the top drive, and once attached, it becomes part of the primary load path. All parts of
the CCT that are in the primary load path are designed for a
500 ton load, according to API 8C requirements.
The landing sub should be made up to the top of the casing
string and hung off in the split bushing on the rig floor. The
landing sub has a modified buttress box thread connection,
which allows the CCT, once it is made up to the drillpipe
string, to be stabbed into the landing sub. This reduces the
amount of time required to engage the CCT. As this thread
may be damaged during tripping, a thread protector is provided to protect the thread during tripping operations. A spider or drillpipe slip bowl is placed on top of the split flange to
support the drillpipe string when the pipe connections are being made or broken.
The CCT was developed to also provide well control when
the drillpipe is used for retrieving a BHA. The CCT includes a
chevron seal stack that provides a seal between the internal diameter of the casing and the drillpipe’s outer diameter once the
CCT is stabbed into the landing sub. When the seal is inside
the landing sub, the casing/drillpipe annulus will be closed and
circulated conventionally through the drillpipe and the top
drive. The CCT may include a diverter sub with metered ports
to allow circulation down the annulus between the casing and
drillpipe.
UR
Annular Hydraulics
Ft/min
Re
Flow Regime
BHA/Open Hole
125.05
638
Lam
Drill Casing 1/Open Hole
234.78
1,059
Lam
Drill Casing 1/Liner
219.24
989
Lam
Drill Casing 1/Casing
Drill Casing 2/Casing
Hydraulic Lift
45.44 ×
1,000 lb
Bottoms Up Time
45 min.
TTable 1. Hydraulics modeling results: bit and UR hydraulics (top) and annular
hydraulics (bottom)
HYDRAULICS
The hydraulic program was planned around maintaining an
equivalent circulating density (ECD) below the expected fracture
gradient while achieving adequate hole cleaning.
The hydraulic analysis was critical to balance the ECD created in the small annulus between the casing and the borehole
Fig. 9. ECD with and without cuttings.
PREPARATION AND LOGISTICS
A certain amount of equipment preparation was done in the
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provider’s warehouse prior to sending the tools out to the rig.
A special cut-to-length shoe joint was made to accommodate
the drill lock assembly (DLA), internal tandem stabilizers and
motor, which were to be installed before shipping. The DLA
was made up to the internal tandem stabilizers, which prevented excessive vibration at the DLA/casing profile nipple
(CPN) connection. The motor was made up to the stabilizers,
and the casing shoe joint was cut to such a length that the motor’s rotor sub was the only part that extended past the reamer
shoe. A sleeve stabilizer that matched the drift of the casing
was installed on the motor so that it would be located just inside the casing shoe. This location is critical in mitigating vibrations between the motor inside the casing and the UR just
below the casing shoe. This assembly was loaded into the casing shoe joint and locked in place to the CPN with the DLA. It
was then sent to the rig pre-assembled to save rig time. Figure
10 shows details of the DLA and CPN configuration.
procedures until the UR was below the 13⅜” casing shoe.
One of the major advantages of the DCwD system is the
ability to retrieve the BHA at any point without the need to
pull the casing out of the hole. This allows the BHA to be retrieved for any reason before reaching the end of the section,
after which a new BHA can then be run in hole.
The tool used to retrieve the BHA is run into the hole using
drillpipe. A false rotary table is required at the surface to run
the drillpipe through the casing. The retrieval tool is a grappletype tool, which locks into the DLA latch sub and when
picked up releases the locking mechanism and simultaneously
opens a bypass port through the seal cups in the DLA to prevent swabbing on retrieval.
To latch the new BHA to the casing, the DLA is set into the
CPN, using a hydraulic setting tool. After the hydraulic setting
tool sets the DLA, it is hydraulically released, and the conveyed drillpipe string with the hydraulic setting tool is then
tripped out of the hole and the DCwD operations are resumed.
The procedure of retrieving and latching the BHA was performed three times during the drilled interval with no problems.
The 12¼” interval was drilled in three runs as follows:
• Run 1: Drilled a total of 2,771 ft with an average ROP
of 49 ft/hr (5 to 10 Klb WOB, 40 surface rpm and 550
gpm flow rate).
Fig. 10. The BHA pre-assembled DLA and CPN section components.
DRILLING OPERATION
The 13⅜” casing shoe and an additional 151 ft of new formation were drilled out conventionally before DCwD operations
started to ensure that the UR would be positioned in the 12¼”
open hole when the pumps were brought on to commence
drilling.
The 9⅝” casing was inspected, measured and gauged to verify internal drift and joint length. A casing tally was prepared
referencing three key depths: (1) bit depth, which can change
with different BHAs; (2) total UR depth, which also changes
with the BHA; and (3) casing shoe depth, which is needed to
control the DCwD operations.
The lower components of the directional BHA were made up
conventionally and secured in the rotary table. These included
the 8½” PDC bit, RSS, MWD tool, roller reamer and 12¼”
UR. The casing running tool was then rigged up to the top
drive, and the pre-assembled section was picked up. The motor
was made up to the directional assembly using the rig tongs
and the casing joint, with the BHA hung off beneath it in the
slips. The casing was then run using conventional casing running
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SAUDI ARAMCO JOURNAL OF TECHNOLOGY
The BHA was pulled out of the hole due to a motor failure.
After changing the motor and while trying to run the new
BHA, the operator observed an obstruction inside the casing.
Because the BHA was unable to pass it, a decision was made
to pull the BHA back and then pull the casing out to the depth
of the obstruction. Once it was on the surface, a failed MLT
ring was found, Fig. 11. All the rings and casing connections
were checked prior to running the casing back in the hole. The
root cause of the torque ring failure was related to overtorque,
thread height and/or thread forms issues or to wrong ring
color selection. The bit dull grade was 1-1-WT-A-X-I-ERDMF.
• Run 2: The mud motor and bit were replaced, and
drilling was continued to a total of 1,762 ft with an
Fig. 11. Failed MLT ring (left) found while running in the hole to retrieve BHA
#1, with the new ring (right).
average ROP of 26.5 ft/hr (6 to 10 Klb WOB, 40
surface rpm and 550 gpm). The BHA was tripped out
due to slow ROP. The UR arms were found to be
severely worn out, Fig. 12. The bit dull grade was 1-1WT-A-X-I-NO/RR-BHA.
The UR was changed, and BHA #3 was run back and set
into the CPN with no problem.
• Run 3: Drilled only 214 ft in abrasive siltstone, then the
BHA was tripped out due to a drop in ROP (from 25 to
0 ft/hr). The bit and UR arms were checked on the
surface. The bit was still in good condition (1-1-WT-AX-I-NO/RR-TD), but the UR arms were found to be
severely worn out after only drilling 214 ft.
The cause of the UR’s wearing out in the two runs was associated with the use of medium speed mud motors in an abrasive formation, which caused the UR to rotate at speeds close
to its design limit — 220 rpm for soft and nonabrasive formations. The motors used were 0.3 rev/gal, which means that
with a 550 gpm flow rate and 40 surface rpm, the UR was
rotating at 205 rpm.
Another factor that may have caused the UR to quickly
wear out in the third run was the need to ream down a significantly undergauged hole along an abrasive formation, thereby
accelerating the wearing process. At that point, the hole was
being reamed faster than drilled to minimize the chances of an
unplanned sidetrack.
Table 2 shows the bit run summary.
Torque and Drag
The friction factors used throughout pre-planning to predict
the torque and drag were conservative: 0.20 cased hole and
0.25 open hole. Those conservative values resulted in a high
predicted torque and therefore a high connection torque.
The maximum surface torque that was recorded in the first
two runs was 22,000 lb-ft. It was decided after Run #2 to revisit the pre-job model and reduce the friction factors to get a
more representative value. The new friction factors used were
0.15 cased hole and 0.20 open hole. These values proved to be
more realistic, Fig. 13; therefore, the connection makeup
torque was reduced from 38,000 lb-ft to 32,000 lb-ft.
CEMENTING OPERATION
To achieve cementing success, a full understanding of the
changes in the cementing operation for a DCwD application in
comparison to conventional drilling cementing operations was
necessary, in addition to adhering to the general best practices
for cementing.
At the time of this implementation, there was no available
Fig. 12. UR arms in closed position from Run #2 (left) and Run #3 (center). The
picture on the right shows the arms in the open (activated) position.
Run #
1
2
3
Mud
Motor
Inside
CSG
(Yes/
No)
Yes
Yes
Yes
RSS
(Yes/
No)
RSS Specs
WOB
Mud Motor
(Klb)
Specs
Yes
Point the
Bit RSS 7/8
Lobes, 5
stages, 300
to 600 gpm
Yes
Point the
Bit RSS
7/8 Lobes,
6.8 stages,
300 to 600
gpm
Yes
Point the
Bit RSS
7/8 Lobes,
6.8 stages,
300 to 600
gpm
5-20
6-20
9-23
Torque
(ft-lb)
× 103
7-15
17-21
22-25
Flow
Surface
Rate
RPM
(gpm)
550
580
550
30
32
25
Start
Depth
Inc.
Azi.
Final
Depth
Inc.
Azi.
PDM
(rev/
gal)
Total
RPM
0.3
195
4,965 ft 7,736 ft
37.36* 61.33*
28.02* 28.23*
200
7,736 ft 9,498 ft
61.33* 68.86*
28.23* 30.01*
185
9,498 ft 9,712 ft
68.86* 69.28*
30.01* 30.15*
0.29
0.29
Bit
Bit Dull
Grade
1
1-1-WTA-X-IER-DMF
2
1-1-WTA-X-INO/RRBHA
2R
1-1-WTA-XI-NO/
RR-TD
TTable 2. Run summary for the DCwD drilled interval
SAUDI ARAMCO JOURNAL OF TECHNOLOGY
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43
issues; the well was shut-in because of the lack of float equipment to prevent cement flow back into the casing after its
placement in the annulus. Contaminated cement slurry reached
the surface; however, no pure cement was seen. The level in the
annulus was seen to drop while waiting on the cement by an
estimated volume of 45 bbl.
When operations resumed, the cement was tagged inside the
casing as expected and the casing was pressure tested to 1,100
psi. Hard cement was drilled out of the casing and down to 33
ft below the casing shoe.
The operator’s main objectives of obtaining cement back to
the surface and achieving competent cement around the shoe
were successfully obtained. Figure 14 shows the actual pressure and the simulated pump pressure.
Fig. 13. Torque and drag comparison (actual vs. modeling).
field-tested solution for a two-stage cementing tool to be used
along with DCwD — which is the traditional method in Saudi
Arabia for cementing across known weak and fractured formations with the potential of a loss of circulation. The operator
took this into consideration, analyzed the potential risks and
mitigation plan, and relied on the fact that even in highly sensitive formations, the ability to smear drilled cuttings into the
pores of the formation could result in a stronger wellbore that
might make multistage cementing systems unnecessary.
The need for full bore casing access to run and pull out of
the hole the BHAs implied that the conventional floating
equipment — float collars with displacement plugs — could
not be used. The plug landing nipple (PLN) was not available
at the time of the implementation, which meant that the pump
down displacement plug (PDDP), designed to be used along
with the DCwD BHA retrievable system, also could not be used.
The standoff obtained from the number of centralizers that
were crimped on the casing was a challenge insofar as achieving complete mud displacement during cementing since the
section was deviated. Also, a long rat hole existed because of a
long stick out of the BHA, leading to slumping of the cement
slurry during placement and after displacement that could lead
to a wet shoe.
Given the limitations of the formation fracture gradient,
lead and tail slurries were designed at 101 pcf and 118 pcf,
respectively. Fluid loss and the rheological properties of the
slurries were optimized to ensure no annulus bridging and
minimize frictional pressures.
A sufficient amount of spacer was determined to take into
account the in-pipe contamination because of the lack of mechanical separation, e.g., bottom plugs, at the fluid interfaces
— the properties optimized for efficient mud removal purposes.
The well was circulated for several hours before the start of
the single-stage cement job. The cement job was executed as
planned, leaving 300 ft of cement slurry inside the casing, and
the well was shut-in — via the closed master valve at the surface — throughout the wait on the cement with no operational
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SAUDI ARAMCO JOURNAL OF TECHNOLOGY
Fig. 14. Actual vs. simulated pump pressure.
LESSONS LEARNED
1. Conservative friction factors were used during the planning
phase, e.g., 0.20 for cased hole and 0.25 for open hole,
which resulted in a recommended makeup torque of 38,000
ft-lb — maximum predicted drilling torque + 20%. The
friction factors observed were closer to 0.15 in the cased
hole and 0.20 in the open hole, which resulted in a revised
recommended makeup torque of 32,000 ft-lb. This will further reduce the connection torque requirements for future
jobs in this area.
2. The designed BHA with a RSS performed as expected, providing a smooth well profile with minimal well tortuosity
that could affect casing fatigue life, which should lower
torque requirements for the surface equipment and casing
connections.
3. To be able to drill the interval in a single run, the UR arms
design needs to be improved, e.g., by using premium PDC
cutters and/or by modifying the gauge protection and
exposed cutting area. The DCwD supplier is currently
developing a new generation of high ratio URs with the
field proven concept of cutter blocks, which is expected
to replace the existing design for hard rock or abrasive
applications.
4. Proper planning and logistics are crucial to a successful
DCwD operation. The following, in particular, need to be
considered for DCwD applications:
• The PLN was not available, which meant that the
PDDP could not be used. This affected the planned
rotation and reciprocation of the casing before and
during the entire cementing job, which is one of the key
advantages of DCwD. In future applications, this would
help break up the gelled stationary pockets of drilling
fluid and loosen cuttings trapped in the gelled drilling
fluid.
• Lost circulation pills could also be pumped ahead of the
slurry to minimize losses.
• Foam cement is an option that could be considered to
further lighten the cement column and reduce the risk of
losses.
• Using a low speed/high torque motor, e.g., 7:8 lobes, 3.3
stages, is recommended to prevent premature wear of
the UR caused by the high speed rotation.
• The casing running tool was provided with a 4½”
internal flush (NC50) top connection, which prevented
the top drive from being used to make up the casing.
This required the use of undersized power tongs at the
start of the operations and resulted in 4 hours of NPT.
This could be eliminated by having a 6⅝” regular top
connection, which will improve operational efficiency
and reduce safety risks.
• Usage of an integral blade for the motors, instead of
thread lock, is a must for future jobs. This minimizes
the risks of losing the blade when there is vibration
while drilling.
5. The service provider needs to launch an investigation to
determine the root cause of the MLT ring failure and avoid
a further occurrence. If the failure is related to the wrong
MLT ring selection, the installation process will need to
incorporate a revision before running the casing joints in
the well. Operators will also need to verify that the base of
the triangle is reached while making up the connections.
CONCLUSIONS
Fig. 15. The planned trajectory (red) vs. the actual directional trajectory plot (blue).
operation. The benefits from the smearing effect, typically
seen when using DCwD, were not observed 100% as
expected. It is possible that this is linked to the surface rotation restriction (40 rpm) imposed by the high speed on the
motor.
4. This project has reestablished DCwD as a viable technology
to address a multitude of drilling challenges common in
Saudi Arabia.
ACKNOWLEDGMENTS
The authors would like to thank the management of Saudi
Aramco and Schlumberger for their support and permission to
publish this article. The authors also would like to thank the
crew members of the rig, the rig foremen and the Schlumberger
team for their support in the achievement of the project goals.
This article was presented at the SPE/IADC Middle East
Drilling Technology Conference and Exhibition, Abu Dhabi,
UAE, January 26-28, 2016.
REFERENCES
1. Graves, K.S. and Herrera, D.C.: “Casing during Drilling
with Rotary Steerable Technology in the Stag Field —
Offshore Australia,” SPE Drilling & Completion, Vol. 28,
No. 4, December 2013, pp. 370-390.
1. The DCwD system was able to achieve the planned trajectory while minimizing the potential risks associated with
wellbore instability observed in offset wells, Fig. 15.
2. Warren, T., Houtchens, B. and Madell, G.: “Directional
Drilling with Casing,” SPE paper 79914, prepared for
presentation at the SPE/IADC Drilling Conference,
Amsterdam, The Netherlands, February 19-21, 2003.
2. The CCT proved to be very effective in allowing the casing
to be circulated while the drilling assembly was being
tripped in and out of the hole.
3. Karimi, M., Petrie, S.W., Moellendick, E. and Holt, C.: “A
Review of Casing Drilling Advantages to Reduce Lost
Circulation, Augment Wellbore Strengthening, Improve
Wellbore Stability, and Mitigate Drilling-Induced
Formation Damage,” SPE paper 148564, presented at the
3. Approximately 1,785 barrels of OBM were lost during the
SAUDI ARAMCO JOURNAL OF TECHNOLOGY
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45
SPE/IADC Middle East Drilling Technology Conference
and Exhibition, Muscat, Oman, October 24-26, 2011.
4. Moellendick, E. and Karimi, M.: “How Casing Drilling
Improves Wellbore Stability,” AADE paper 11-NTCE-64,
prepared for presentation at the American Association of
Drilling Engineers National Technical Conference and
Exhibition, Houston, Texas, April 12-14, 2011.
5. Chima, J., Zhou, S., Al-Hajji, A., Okot, M., Sharif, Q.J.,
Clark, D., et al.: “Casing Drilling Technology Application:
Case Histories from Saudi Arabia,” SPE paper 160857,
presented at the SPE Saudi Arabia Section Technical
Symposium and Exhibition, al-Khobar, Saudi Arabia, April
8-11, 2012.
6. Sanchez, F.J., Turki, M., Houqani, S., Al-Nabhani, Y.N.,
Al-Hinai, D.M., Maimani, S., et al.: “Casing While Drilling
(CwD): A New Approach Drilling Fiqa Shale in Oman. A
Success Story,” SPE paper 136107, presented at the Abu
Dhabi International Petroleum Exhibition and Conference,
Abu Dhabi, UAE, November 1-4, 2010.
7. Beaumont, E., De Crevoisier, L., Baquero, F., Sanguino, J.,
Herrera, D.C. and Cordero, E.: “First Retrievable
Directional Casing-While-Drilling (DCWD) Application in
Peruvian Fields Generates Time Reduction and Improves
Drilling Performance Preventing Potential Nonplanned
Downtime,” SPE paper 139339, presented at the SPE Latin
American and Caribbean Petroleum Engineering
Conference, Lima, Peru, December 1-3, 2010.
BIOGRAPHIES
Germán A. Muñoz is a Senior Drilling
Engineer in Saudi Aramco’s
Exploration & Oil Drilling
Engineering Department. He is an
experienced engineer with more than
18 years in the oil industry, mainly
focused in drilling optimization and
the deployment of drilling technology. Germán developed
his drilling career holding field and office positions in
Colombia, Venezuela, Ecuador, Mexico and the U.S.,
working for different oil companies before joining Saudi
Aramco in 2008.
His exposure to numerous drilling environments and his
knowledge in areas such as extreme extended reach
drilling, managed pressure drilling and directional casing
while drilling, among others, enabled Germán to
accomplish the planning, execution and delivery of the
longest well in Saudi Arabia (37,042 ft MD) as well as
achieve three other world records. He has also succeeded in
the reestablishment of 95⁄8” directional casing while drilling
in the Kingdom.
He has authored and coauthored various technical
papers for the Society of Petroleum Engineers (SPE). He
has also been recognized by the company several times
through the Drilling & Workover Recognition Program for
his significant contributions.
In 1996, Germán received his B.S. degree in Petroleum
Engineering from Universidad de América, Bogotá,
Colombia.
Bader N. Al-Dhafeeri joined Saudi
Aramco in 2005. His experience
includes work on several field
development projects, such as South
Ghawar, Manifa and AFK. Bader is
now a Drilling Engineering Supervisor.
He received his B.S. degree in
Petroleum Engineering from the University of Tulsa, Tulsa,
OK, and his M.S. degree in Petroleum Engineering from
Heriot-Watt University, Edinburgh, U.K.
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SAUDI ARAMCO JOURNAL OF TECHNOLOGY
Hatem M. Al-Saggaf joined Saudi
Aramco’s Drilling Department in
2002. He is now a Drilling
Engineering General Supervisor for the
Manifa increment. Hatem’s experience
includes work on several drilling
projects, such as the Qatif field
development and Khurais increment, and he was a team
leader for the Nuiyyem field development.
He received his B.S. degree in Applied Mechanical
Engineering from King Fahd University of Petroleum and
Minerals (KFUPM), Dhahran, Saudi Arabia.
Hossam Shaaban is currently working
as the Schlumberger Drilling Tools
Geo-Market Operations Manager for
Kuwait. He was previously assigned to
Saudi Arabia from May 2010 to April
2015, where he held multiple
positions, including as the Project
Manager for the Drilling & Measurements activities in
Manifa. During his 15-year career with Schlumberger,
Hossam has also worked as a Sales and Marketing
Manager for Drilling Tools, where he was responsible for
the implementation of the Level 3 casing drilling at the
Manifa field.
Hossam received his B.S. degree in Engineering from
Benha University, Cairo, Egypt, in 1994.
Delimar C. Herrera is a Senior Drilling
Engineer for Schlumberger in Saudi
Arabia. He has 14 years of experience
in drilling and completions. Starting
his career as a Field Engineer for
drilling contractor Independence
Drilling Ltd. in Colombia, Delimar
then moved to the drilling department in Ecopetrol where
he held various positions, including Well Site Supervisor
and Drilling Engineer. From 2007 to 2012, Delimar
worked for Tesco Corporation, and then went to work
with Schlumberger Oilfield Services in various drilling
engineering and operations roles, specifically on the
technical development of casing while drilling and liner
drilling technologies in Latin America, Southeast Asia,
Australia and the Middle East.
He received his B.S. degree in Petroleum Engineering
from Universidad Industrial de Santander, Santander,
Colombia.
Ahmed Osman is currently the Drilling
Engineering Lead for Schlumberger
Drilling & Measurements in Saudi
Arabia, where he has been for 13
years. He started his career working as
a MWD/LWD Engineer in Venezuela,
Egypt, Algeria and Jordan. Ahmed
then became a Directional Drilling Engineer in Egypt and
Sudan, using different drilling systems in various drilling
applications. He then went on to work and manage several
different drilling engineering projects in Egypt, Sudan,
Vietnam, Thailand and Myanmar for different big
operators, such as BP, Shell, Eni and Petronas.
Ahmed has participated in a number of Society of
Petroleum Engineers (SPE) conferences, technology
seminars and drilling training courses during the course of
his career.
He received his B.S. degree in Mechanical Engineering
from the American University in Cairo, Cairo, Egypt.
Ahmed has received several internal awards and also
has several published papers on advanced drilling systems
in different applications.
Locus Otaremwa is a Cementing
Engineer with Schlumberger. His six
years of experience with Schlumberger
has been characterized by providing
solutions to clients for challenges in
both primary and remedial cementing
of oil and gas wells. Locus is currently
the focal point for cementing in the casing while drilling
applications in the Saudi Arabia.
He received his B.S. degree in Civil Engineering from
the University of Dar Es Salaam, Dar Es Salaam, Tanzania.
SAUDI ARAMCO JOURNAL OF TECHNOLOGY
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Preliminary Test Results of an Eco-Friendly
Fluid Loss Additive Based on an Indigenous
Raw Material
Authors: Dr. Md Amanullah, Dr. Jothibasu Ramasamy and Mohammed K. Al-Arfaj
ABSTRACT
The Kingdom of Saudi Arabia spends a significant amount of
money per year on importing various fluid additives from
overseas countries to meet the demand of the oil and gas sector. An analysis of the drilling fluid additive import cost of
2012 indicates that a substantial amount of money was spent
on importing fluid loss control additives only. This very common mud additive is frequently needed for both water- and oilbased mud formulations to fulfill certain functional tasks while
drilling or while making a connection or a trip. Therefore, its
total or partial replacement will save a considerable amount
per year. If we only replaced 10% of the imported fluid loss
additive, we would see a significant savings per year. This justifies the development of in-Kingdom fluid loss additives using
locally available natural, industrial and/or agricultural raw
materials.
Localization of the product development would be highly
beneficial to the Kingdom in terms of industrial growth, technology ownership and creation of new job opportunities for
the local public. It would also make a major contribution to
the national economy by bringing about a major reduction in
the mud additives’ import budget.
This article describes the preliminary results of testing a locally developed fluid loss additive made using an agricultural
waste product. Experimental results indicate that the fluid loss
additive is equally applicable for clay-free freshwater-based
and for saltwater-based drilling muds. Therefore, they demonstrate the additive’s suitability for current and future exploration and exploitation of oil and gas resources.
INTRODUCTION
Drilling fluid plays a vital role during the course of drilling a
well. The mud, either water- or oil-based, is circulated from
the surface to the bottom of the hole and then brought back to
the surface. The primary objectives for circulating the drilling
mud are hole cleaning while drilling, cuttings suspension during the non-circulation period, maintaining of borehole stability while drilling or making a trip, etc.
A drilling mud serves a variety of other functions, such as
bit cooling, energy supply to the mud motor, shale stabilization,
48
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SAUDI ARAMCO JOURNAL OF TECHNOLOGY
etc. Once the excessive solids from the mud are screened out in
the shale shaker, the cleaned mud can then be recirculated to
fulfill a suite of functional tasks. While drilling through porous
and permeable zones, however, there is a high possibility of
losing a huge volume of the fluid phase of the mud while
drilling or making a trip.
To avoid fluid loss while drilling a borehole, loss control
additives are incorporated in the drilling mud for sealing and
blocking the borehole pores by creating a low permeable mud
cake on the borehole wall. It is necessary to prevent excessive
loss of the mud fluids into the porous formation since that
may lead to a dramatic change in mud properties, which then
leads to different mud-related drilling problems, including increased mud cost, deposition of excessively thick filter cakes
on the borehole wall, a significant increase in torque and drag
problems, a dramatic rise of equivalent circulation density,
surge and swabbing pressures, an increase in casing running
load, problems in primary cementing and differential sticking
problems in the presence of high permeable formations1. This
explains the importance of having a fluid loss additive as a
part of the formulation of drilling and completion fluids.
A typical fluid loss additive should be able to control the
loss of drilling and completion fluids into the surrounding formations within an acceptable range: less than 15 cc/30 minutes
in standard American Petroleum Institute (API) fluid loss test
conditions, i.e., at room temperature under 100 psi pressure.
The formulation of the drilling mud is engineered to keep fluid
loss close to zero or as far as possible below the API recommended value to: (1) maintain the drilling fluid consistency, (2)
ensure near wellbore formation stability, and (3) prevent damage to the pay zone, etc. Different types of chemicals and polymers are used by the petroleum industry to design drilling
muds, with mud rheology, density, fluid loss control property,
etc., appropriate to a given well2.
Another important consideration in fluid design is the minimization or elimination of any detrimental effect caused to the
surrounding environment, ecosystems, habitats, etc., by drilling
fluids. Due to strict environmental regulations around the
globe, the oil and gas industries are reluctant to use chemicals
and polymers that can cause a short- and/or long-term environmental impact.
Nearly three-fourths of the earth is covered in water, and
those areas offer significant prospects for hydrocarbon resources, in addition to other valuable marine resources3. Subsequently, there has been a progressive move of drilling
activities from onshore to highly sensitive offshore and deepwater environments. To preserve the marine life, research has
focused on the development of a new generation of “green”
chemicals and mud additives that are eco-friendly, nontoxic
and readily biodegradable, thereby avoiding short- and longterm environmental impact in highly sensitive offshore and
deep-water environments. This is reflected in the increase in
research activities by the industry centered on finding or developing virtually nontoxic, readily biodegradable and environmentally benign green chemicals and polymers for use in
designing high performance drilling and completion fluids4.
Drilling fluids are alkaline and usually have a pH above 9,
ideally ranging from 9 to 10.5. Excessive loss of alkaline mud
filtrate to the near wellbore formation can cause swelling and
dispersion of clays in the formations, leading to borehole instability problems. Excessive fluid loss can also cause severe formation damage while drilling the pay zone5 due to the fluid’s
alteration of the poro-perm characteristics, fluid saturation
limits, relative permeability profiles, etc., of the near wellbore
reservoir formation. Therefore, effective control of fluid loss
while drilling a borehole is very important, for both the
drilling and the production phases of oil and gas exploration
and exploitation.
Fluid loss additives minimize loss by creating mud cake with
favorable mechanical characteristics. The thickness of the mud
cake plays an important role in mitigating a suite of drilling
and reservoir engineering problems. Muds producing soft,
thick mud cakes increase the potential of differential sticking
when drilling a high permeable zone, and therefore, are not desirable for geological formations with high poro-perm characteristics and differential sticking potential. Deposition of a
thick mud cake will reduce the ease of recovery of stuck pipe if
the mud cake creates strong sticking bonds at the drillpipe and
mud cake interface.
This type of mud cake will also create high torque and lead
to drag problems while drilling deviated, horizontal or extended reach wells, and therefore, are not desirable for drilling
such wells. The formation of soft, thick mud cake in a horizontal well may also create an embedded cuttings bed at the low
side of the borehole, leading to poor hole cleaning and tight
hole problems. The formation of an embedded cuttings bed in
the presence of a soft, sticky mud cake may further lead to mechanical pipe sticking problems. Subsequently, development of
superior fluid loss additives with excellent physical and chemical properties compared to conventional mud additives will
significantly mitigate these problems.
This article describes the application of an eco-friendly fluid
loss additive derived from an indigenous raw material. The
additive is applicable for both clay-free freshwater- and saltwater-based drilling muds and is able to control the loss of the
fluid while drilling a borehole without any detrimental impact
to the surrounding environment, ecosystem, habitats, etc. The
newly derived fluid loss additive has a particle size of less than
150 microns and is easily dispersible in an aqueous medium at
a low to moderate shear rate. The processing steps of producing the additive include removal of the external skin of the raw
material, washing of the material to remove any dirt and leftover skin, and thermal treatment to improve the material’s
processability and ease the manufacturing of a fine powder
with particle sizes of less than 150 microns.
The suitability of the locally derived agri-based additive was
evaluated by formulating clay-free freshwater-based and saltwater-based drilling muds with the additive and then conducting: (1) API tests at room temperature and 100 psi overbalance
pressure, and (2) high-pressure/high temperature (HPHT) fluid
loss tests at 212 °F and 500 psi overbalance pressure. Preliminary test results indicate that the locally produced fluid loss
additive labeled “DSP” can significantly mitigate the fluid loss
behavior of clay-free systems. Initial results also demonstrate
the suitability of the indigenous raw material for localization
of product development in the Kingdom within the oil and gas
industry.
INDIGENOUS RAW MATERIALS
Several agricultural waste materials available from various local sources were evaluated to select a suitable raw material for
this feasibility study. A cursory study of the performance of the
locally available product selected demonstrated its suitability
as a fluid loss control additive for freshwater- and saltwaterbased drilling muds. Preliminary evaluation of the volume of
the source material readily on hand then indicated the availability of hundreds of thousands of tons of this material per
year. Due to the renewable nature of this source material, its
availability can be increased significantly to meet the changing
demand of the oil and gas industry. Subsequently, the selected
raw material was determined to be a viable local source of
supply of the material needed to create the additive, leading to
localization of product development for oil and gas field applications. The advantages of localization of product development to replace the imported fluid additives, whether in whole
or in part, are: (1) reduction of the import cost, (2) increase in
the growth of the local industry, (3) creation of new job opportunities for the public, and (4) contribution to the local and
national economy.
MATERIALS AND METHODS
Preparation of DSP
Figure 1 shows the process flow for the fluid loss additive
preparation. Initial treatment is to clean all the external dirt
and skin from the raw material to isolate the base material,
and then to wash that material with freshwater to remove any
sticky material from the seed. The seed is then treated thermally
SAUDI ARAMCO JOURNAL OF TECHNOLOGY
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slowly to the fluid phase to provide adequate time for proper
mixing and homogenization of the system. The pH of the mud
was adjusted to 10 by adding an appropriate amount of
sodium hydroxide (NaOH) solution. In the case of excessive
foaming, 2 to 3 drops of defoamer were added to remove any
air bubbles. To keep the DSP suspended homogeneously in the
fluid system, 1 g Xanthan gum (XC) polymer or 2 g PHP was
added to the mud as a viscosifier to raise the viscous properties
of the fluid before adding the DSP.
Table 2 shows the formulation of freshwater- and saltwaterbased muds used in tests to evaluate the fluid loss behavior of
the mud at API and HPHT conditions. A test temperature of
212 °F and an overbalance pressure of 500 psi were used to
evaluate the HPHT fluid loss behavior of the muds.
Fig. 1. Diagram showing the process flow for the fluid loss additive preparation.
to remove excessive moisture and make the seed more brittle
for easier grinding. Next, the seeds are cooled to room temperature. After cooling, the seeds are ground by placing them in
the sample placement chamber of a programmable grinding
machine. Finally, the ground powder is sieved to isolate particles less than 150 microns, which are stored.
RESULTS AND DISCUSSION
Formulations to Evaluate DSP Performance
API Fluid Loss Behavior
Table 1 shows several clay-free water-based mud (WBM) systems that were used in tests to evaluate the API fluid loss
behavior of the DSP-based fluid loss additive and then to compare that behavior with the API fluid loss behavior of several
conventional fluid loss additives, such as modified starch (MS)
and psyllium husk powder (PHP). The components shown in
the formulation were mixed adequately by using a high speed
mixer to prepare the mud systems. The ingredients were added
Mud Components
Figure 2 shows the API spurt loss behavior of several clay-free
water-based systems. Comparison of the spurt loss behavior of
the clay-free system with XC polymer alone (Test-1) and with
DSP added (Test-2) indicates 90 cc API spurt loss for the XC
polymer containing system but only 9 cc API spurt loss after
adding DSP to the clay-free system. This is about a 90% drop
of API spurt loss due to the presence of DSP. This undoubtedly
Test-1
Test-2
Test-3
Test-4
Test-5
Test-6
350
350
350
350
350
350
PHP (g)
0
0
0
0
2
2
XC (g)
1
1
0
1
0
0
MS (g)
0
0
6
0
0
0
DSP (g)
0
6
0
6
0
6
to raise
pH to 10
to raise
pH to 10
to raise
pH to 10
to raise
pH to 10
to raise
pH to 10
to raise
pH to 10
as required
as required
as required
as required
as required
as required
Water (ml)
NaOH (ml)
Defoamer (cc)
Table
T 1. Clay-free freshwater-based mud formulations used in tests of the DSP additive
Mud Components
Test-5
Test-6
Test-7
Test-8
350
350
–
–
Red Sea Seawater (ml)
–
–
350
350
PHP (g)
2
2
2
2
DSP (g)
0
6
0
6
to raise
pH to 10
to raise
pH to 10
to raise
pH to 10
to raise
pH to 10
as required
as required
as required
as required
Freshwater (ml)
NaOH (ml)
Defoamer (cc)
Table
T 2. Clay-free freshwater- and seawater-based mud formulations used in HPHT tests of the DSP additive
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proves the application and suitability of DSP as a fluid loss additive or additive supplement for clay-free water-based drilling
fluid systems.
Comparison of the spurt loss behavior of the same DSP containing clay-free system (Test-4) with a clay-free mud system
containing only MS (Test-3), which is a conventional fluid loss
additive, indicates much better performance for both, with
about 40% reduction in spurt loss for the fluid containing the
newly developed DSP-based fluid loss additive. It again supports the application of the DSP as a fluid loss additive to control the fluid loss behavior of WBMs.
Comparison of another clay-free system with PHP (Test-5)
and with both PHP and DSP (Test-6) indicates 2 cc spurt loss
for the clay-free system in the absence of DSP and only 1 cc
spurt loss, i.e., about 50% lower spurt loss, in the presence of
DSP. This again proves the suitability of DSP as a fluid loss
additive for WBM systems.
Figure 3 shows the API fluid loss behavior of several clayfree water-based systems. Comparison of the API fluid loss
behavior of the clay-free systems used in Test-1 and Test-2 indicates 175 cc API fluid loss for the XC polymer containing
system but only 31 cc API fluid loss after adding DSP. This is
about an 82% drop of fluid loss due to the presence of DSP.
This undoubtedly proves the application and suitability of DSP
as a fluid loss additive or additive supplement for water-based
drilling fluid systems.
Comparison of the fluid loss behavior of clay-free mud containing only MS (Test-3), which is a conventional fluid loss additive, with the earlier DSP containing clay-free system (Test-4)
indicates better performance for the newly developed DSPbased fluid loss additive. It again supports the application of
the DSP as a fluid loss additive to control the fluid loss behavior of clay-free WBMs.
Comparison of a clay-free system with PHP with and without the presence of DSP (Test-6 and Test-5, respectively) indicates a much higher fluid loss in the absence of DSP. It is about
50% higher than the clay-free system containing the DSP as a
fluid loss additive supplement. This again proves the suitability
of DSP as a fluid loss additive for WBM systems. The red line
shown in Fig. 3 indicates the API recommended maximum
fluid loss value — which is less than 15 cc/30 minutes filtration time — for water-based drilling fluid systems. The presence of the DSP in the clay-free system in Test 6 reduced the
filtration behavior of the system to 25% below the API recommended value. The results again demonstrate the suitability of
the DSP as a fluid loss additive or additive supplement for
clay-free water-based drilling fluid systems.
Figure 4 shows the API mud cake quality and thickness of
several clay-free water-based systems. Comparison of the mud
cake thickness of the clay-free systems used in Test-1 and Test2 indicates the formation of very thin but poor quality mud
cake for the XC polymer containing system and a thin, good
quality mud cake after adding DSP. The improved quality of the
DSP containing mud cake is reflected in the significant drop in
the API spurt and fluid loss behavior of the DSP containing
clay-free systems previously discussed. The deposition of thin,
good quality mud cakes will play a positive role in reducing
the scope of differential sticking in a borehole environment
prone to that problem. It will also play a positive role in reducing other mud cake related drilling problems. In conclusion, it
Fig. 3. Evaluation of the API fluid loss behavior of tested clay-free drilling fluids.
Fig. 4. Evaluation of the API mud cake thickness behavior of tested clay-free
drilling fluids.
Fig. 2. Evaluation of the API spurt loss behavior of tested clay-free drilling fluids.
SAUDI ARAMCO JOURNAL OF TECHNOLOGY
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can be said that the agri-waste-based product DSP has a high
potential for use as a locally available raw material for development of additives/products for oil and gas field applications.
HPHT Fluid Loss Behavior
Figure 5 shows the HPHT spurt loss behavior of several clayfree freshwater- and saltwater-based systems at 212 °F and 500
psi overbalance pressure. Comparison of the spurt loss behavior of the clay-free freshwater-based muds used in Test-5 and
Test-6 indicates 8.4 cc HPHT spurt loss in the absence of DSP
but only 4 cc HPHT spurt loss in the presence of DSP. This is a
drop of more than 50% of HPHT spurt loss due to the presence of DSP. In the case of the clay-free saltwater-based muds
used in Test-7 and Test-8, the results again show a reduction in
spurt loss in the presence of DSP. All comparisons support the
application of DSP as a fluid loss additive or additive supplement for both clay-free freshwater- and saltwater-based
drilling mud systems.
Figure 6 shows the HPHT fluid loss behavior of several
clay-free freshwater- and saltwater-based systems at 212 °F
and 500 psi overbalance pressure. Comparison of the HPHT
fluid loss behavior of the clay-free freshwater-based muds used
in Test-5 and Test-6 indicates 76.4 cc HPHT fluid loss in the
Fig. 5. Evaluation of the HPHT spurt loss of tested clay-free freshwater- and
saltwater-based muds.
absence of DSP, but only a 30 cc HPHT fluid loss in the presence of DSP. This is more than a 60% drop of HPHT fluid loss
of the freshwater-based mud due to the presence of DSP. In the
case of the saltwater-based clay-free systems used in Test-7 and
Test-8, the results again show a reduction in fluid loss in the
presence of DSP. This supports the application of DSP as a
fluid loss additive or additive supplement.
Figure 7 shows the HPHT mud cake thickness of clay-free
freshwater- and saltwater-based systems at 212 °F and 500 psi
overbalance pressure. Comparison of the mud cake thickness
of these mud systems indicates the formation of very thin mud
cakes in both the absence and the presence of the DSP. This indicates that the DSP has no unusual effects on the physical behavior, i.e., thickness of the mud cakes; however, in subsequent
tests, the muds containing no DSP produced poor quality mud
cakes due to the lack of formation of a dispersed well and
tough mud cake as revealed while conducting the filtration test.
The superior quality of DSP containing mud cake was reflected
in the dispersed well formation and the homogeneous nature of
the mud cakes. The deposition of thin, good quality mud cakes
can play a positive role in reducing the scope of differential
sticking in borehole environments prone to that problem.
The API and HPHT fluid loss test results previously described support the application of DSP as a locally derived
fluid loss additive/product for oil and gas field applications.
Fig. 7. Evaluation of the HPHT mud cake thickness of tested clay-free freshwaterand saltwater-based muds.
CONCLUSIONS
Fig. 6. Evaluation of the HPHT fluid loss of tested clay-free freshwater- and
saltwater-based muds.
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In conclusion, the preliminary experiments have demonstrated
that locally available agri-waste DSP used as a fluid loss additive
is applicable for clay-free freshwater and saltwater systems in
oil and gas field applications. Furthermore, due to the organic
nature of the raw material and the use of an environmentally
friendly, thermo-physical preparation method, the incorporation
of the additive in fluid will have no detrimental impact on the
surrounding environment, ecosystems, habitats, etc.
This result will open up the potential of finding applications
for various natural, agricultural and other industrial products,
byproducts and waste products in oil and gas field fluid design.
ACKNOWLEDGMENTS
The authors wish to thank the management of Saudi Aramco
for their support and permission to publish this article. The
authors cordially acknowledge the financial support of EXPEC
ARC management for this pioneering research. Our special
thanks to our chief technologist Nasser Khanferi for his encouragement and support for this innovative research, and to
Omar Fuwaires and Turkie Alsubaie for testing and evaluation
of the product. We also would like to thank Al-Hasa Research
Center for supplying the date seed samples for this research.
This article was presented at the SPE Oil and Gas India
Conference and Exhibition, Mumbai, India, November 24-26,
2015.
REFERENCES
1. Alford, P., Anderson, D., Bishop, M., Goldwood, D.,
Stouffer, C., Watson, E., et al.: “Novel Oil-based Mud
Additive Decreases HPHT Fluid Loss and Enhances
Stability,” paper AADE-14-FTCE-18, presented at the
AADE Fluids Technical Conference and Exhibition,
Houston, Texas, April 15-16, 2014.
2. Amanullah, M., Marsden, J.R. and Shaw, H.F.: “An
Experimental Study of the Swelling Behavior of Mudrocks
in the Presence of Drilling Mud Systems,” Canadian
Journal of Petroleum Technology, Vol. 36, No. 3, March
1997, pp. 45-50.
3. Amanullah, M. and Yu, L.: “Environment Friendly Fluid
Loss Additives to Protect the Marine Environment from the
Detrimental Effect of Mud Additives,” Journal of
Petroleum Science and Engineering, Vol. 48, Nos. 3-4,
September 2005, pp. 199-208.
4. Amanullah, M., Al-Arfaj, M.K. and Al-Abdullatif, Z.A.:
“Preliminary Test Results of Nano-based Drilling Fluids for
Oil and Gas Field Application,” SPE paper 139534,
presented at the SPE/IADC Drilling Conference and
Exhibition, Amsterdam, The Netherlands, March 1-3,
2011.
5. Amanullah, M.: “A Novel Method of Assessment of Spurt
and Filtrate Related Formation Damage Potential of
Drilling and Drill-in Fluids,” SPE paper 80484, presented
at the SPE Asia Pacific Oil and Gas Conference and
Exhibition, Jakarta, Indonesia, April 15-17, 2003.
BIOGRAPHIES
Dr. Md. Amanullah is a Petroleum
Engineering Consultant working at
Saudi Aramco’s Exploration and
Petroleum Engineering Center –
Advanced Research Center (EXPEC
ARC). Prior to joining Saudi Aramco,
he worked as a Principal Research
Scientist at CSIRO in Australia.
Aman is the lead inventor of a vegetable oil-based
dielectric fluid (patented) that led to the formation of a
spinoff company in Australia for commercialization of the
product.
He has published more than 70 technical papers and
filed 25 patents, with nine already granted. Two of Aman’s
patents were highlighted in two scholarly editions of two
books published in the U.S. He is one of the recipients of
the 2005 Green Chemistry Challenge Award from the
Royal Australian Chemical Institute. Aman also received
the CSIRO Performance Cash Reward in 2006, the Saudi
Aramco Mentorship Award in 2008 and the World Oil
Certificate Award for nano-based drilling fluid
development in 2009. He is a member of the Society of
Petroleum Engineers (SPE). Aman received the 2014 SPE
Regional Service Award for his contribution to the
industry.
He received his M.S. degree (First Class) in Mechanical
Engineering from the Moscow Oil and Gas Institute,
Moscow, Russia, and his Ph.D. degree in Petroleum
Engineering from Imperial College, London, U.K.
Dr. Jothibasu Ramasamy is a
Petroleum Scientist working with the
Drilling Technology Team of Saudi
Aramco’s Exploration and Petroleum
Engineering Center – Advanced
Research Center (EXPEC ARC). He
joined Saudi Aramco in July 2013.
Prior to this, he worked as a Research Fellow with the
Department of Chemistry at the National University of
Singapore and as a Postdoctoral Fellow with the Catalysis
Center at the King Abdullah University of Science and
Technology (KAUST), Saudi Arabia.
Jothibasu received his B.S. degree in Chemistry from
Bharathidasan University, Tiruchirappalli, India, and his
M.S. degree, also in Chemistry, from Anna University,
Chennai, India. In 2010, he received his Ph.D. degree in
Chemistry from the National University of Singapore,
Singapore.
Jothibasu has published 15 techincal papers and filed
three patents.
SAUDI ARAMCO JOURNAL OF TECHNOLOGY
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Mohammed K. Al-Arfaj joined Saudi
Aramco in 2006 as a Petroleum
Engineer, working with the Drilling
Technology Team in the Exploration
and Petroleum Engineering Center –
Advanced Research Center (EXPEC
ARC). He works in the area of drilling
and
nd completion, and has conducted several projects in the
areas of shale inhibition, drilling nano-fluids, loss
circulation materials, spotting fluids, swellable packers,
completion fluids and oil well cementing.
Mohammed received his B.S. degree in Chemical
Engineering from King Fahd University of Petroleum and
Minerals (KFUPM), Dhahran, Saudi Arabia, in 2006. In
2009, he received his M.S. degree in Petroleum Engineering
from Heriot-Watt University, Edinburgh, Scotland.
Mohammed is currently pursuing a Ph.D. degree in
Petroleum Engineering from KFUPM.
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Pioneering Utilization of Fluid Cryogenics
in Mimicking Shutoff Barrier Characteristics
Authors: Nawaf D. Al-Otaibi, Nelson O. Pinero, Ibrahim A. Al-Obaidi and Carlo Mazzella
ABSTRACT
The objective of this article is to discuss the successful application of a cryogenic freeze plug to fulfill the requirements of
having dual shutoffs available prior to removing the production tree. This operation is presented as a substitute to use
when conventional means are not feasible.
The Saudi Aramco policy regarding the decompletion of
wells with downhole packers requires having two independent
shutoff barriers in place — for the tubing and tubing casing
annulus — prior to the removal of the production tree. These
shutoffs must be independent and able to be simultaneously
operated. Moreover, each shutoff must be pressure tested separately. A dual shutoff is easily achievable with conventional
means, e.g., tubing plugs and tubing hanger back pressure
valves, or with a combination of the two.
This pioneering operation was proposed when, prior to
removing the production tree from an oil producing well, the
production tubing was found to have collapsed and parted.
Given these conditions, the only annular barrier was the kill
fluid column. The well also had leaking tubing hanger seals
that were not holding pressure. As a result, introducing an
additional shutoff barrier would be challenging.
This need for a second shutoff application led to the proposal
to utilize the method for creating a cryogenic freeze plug as a solution. When the kill fluid column, filling the tubing and tubing
casing annulus, was frozen using the cryogenic freeze plug method, it allowed the fluid to mimic the form of a second barrier.
This temporary secondary barrier would withstand the required pressure test if there were a full column of kill fluid in
the tubing and tubing casing annulus.
This article reviews the methodology, purpose, technique,
and qualification of using cryogenic freezing to create a second
barrier. It also supports the positive trend in technical reviews
toward new methods or alternative techniques for nonconventional isolation barriers or shutoffs.
INTRODUCTION
The removal of a production tree for the decompletion of an
oil producing well with a downhole packer can be anything
but routine, particularly when the production tubing has
collapsed and parted, and when the well contains leaking tubing hanger seals that are not holding pressure. Because of these
conditions, meeting the requirement by some companies to
have dual-independent shutoff barriers for the tubing and tubing casing annulus is unlikely using conventional methods.
With a kill fluid column pumped into the annulus, however,
there is a tested, proven alternative method for a successful
solution: a cryogenic freeze plug.
STATEMENT OF THEORY AND DEFINITIONS
Pipe freezing is a method of isolating the inside diameter of a
pipe or pipes for maintenance or repair. To accomplish this, a
metal container, designed to contain liquid nitrogen and to fit
around the pipe to be frozen, is installed around the pipe. The
container is then precooled with nitrogen gas and then filled
with liquid nitrogen to freeze the water-based fluid inside the
pipe. The frozen ice becomes a pressure barrier. In cases of
cement filled outer annuli, the outer barrier is already in place,
yet the cold transfers through the cement and into the fluid of
the inner strings of casing and tubing, causing the fluid to form
the freeze plug. Further cooling lengthens the ice mass, which
becomes very stable and controllable. Temperature monitoring
sensors allow consistent verification of both the temperatures
applied to the surface of the pipe as well as the temperatures of
the nitrogen source. A gradual decrease in temperature is facilitated to a range of 0 °F to -80 °F to ensure adequate cooling has
been applied, enough to provide a pressure resistant ice plug.
This pipe freezing technique has been safely and successfully
used over many years for many types of repairs. Wellhead and
tree replacements, casing valve replacements, and other drilling
and production problems that require total well isolation have
been performed using ice plugs as a primary or secondary barrier. The freezing of multiple strings of pipe is not outside the
normal operations, but instead is a preferred method of isolation because the freeze plugs can be pressure tested to verify
integrity and can be maintained indefinitely until all repairs or
replacements have been made. Single string freezes, by allowing a break in the connection above the freeze, provide the
opportunity to add a valve or other component without performing a costly fluid kill operation. Negative and/or positive
pressure testing of the freeze plug’s integrity can confirm isolation.
SAUDI ARAMCO JOURNAL OF TECHNOLOGY
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DESCRIPTION AND APPLICATION OF EQUIPMENT
AND PROCESSES
To assure that this service is safe and reliable, independent
tests and research have been conducted to determine the effects
of subjecting API grades of tubing and casing to liquid nitrogen temperatures.
A testing laboratory was retained to perform mechanical
testing of several grades of API tubing and casing and to undertake a metallurgical examination to determine if they are
affected by cryogenic temperatures.
This involved tensile tests and tests of the Charpy impact on
prepared samples from each of the four provided grades of API
pipe. One tensile sample from each was tested at ambient conditions to establish a base line of property values; another
sample from the same pipe was then tested at temperatures
ranging from -30 °F to -100 °F through the course of the test;
and yet another tensile sample was tested at a constant temperature near -230 °F. Next, a Charpy set from each pipe was
tested at the impact test temperature prescribed in the API
5CT and 5D specifications, with another set tested at an impact temperature of -60 °F. All test temperatures were monitored, with thermocouples attached directly to the samples
during the tensile tests performed at temperatures other than
ambient. The Charpy tests were monitored with a thermocouple placed directly in the test bath.
In addition, two sections of the tested N80 pipe were submitted to another test laboratory for metallurgical assessment
of retained austenite. One sample was taken directly from the
area that received the cryogenic application during testing. The
second was taken from a section of pipe located well away
from the cryogenic exposure area. This examination using Xray diffraction would show any effects the frequent cryogenic
exposure may have had on the microstructure of the material.
• The tubing casing annulus and tubing must be filled
with a water-based fluid.
As a part of the ongoing operation, the work scope conditions were met with 0 psi pressure readings on the tubing and
tubing casing annulus.
The standard setup for a multi-string freeze is as follows:
• Excavate to a predetermined depth, exposing 8 ft to 10
ft of surface casing, Fig. 1.
• Inspect the pipe to ensure there are no visible defects in
the pipe or welds.
• Bolt the vendor’s freeze jacket onto the casing, leaving
at least 2 ft of room from the casing head weld.
• Connect the thermocouples, nitrogen supply hoses and
vent pipes, Fig. 2.
The excavation is then closed to all personnel until after the
freeze is complete and a gas test has been performed to verify
that no nitrogen gas is present.
With setup complete, nitrogen is flowed through the jacket
until a trained service provider has confirmed that a pressure
resistant ice plug is in place, Fig. 3. Pressure testing should
then take place until it is confirmed that all annuli are plugged.
Then the safe removal of the tree can be facilitated and the
blowout preventers installed. A pressure test should be performed again to ensure that all bolted connections are tested.
Planning should consider the time needed to perform the freeze
and so ensure an adequate nitrogen supply for lengthy repair
or replacement periods, including delays. A continuous supply
of nitrogen should be planned for as a contingency plan, given
that pipe freezes have been held for as long as 10 days.
Operational Procedures
Safety was the key criterion that drove the design execution of
this job. Many factors were considered during job planning,
which included:
• A detailed job safety plan covering each technical step
in the workover.
• Contingency planning in case of a well control event.
• Issues involving the release of hydrogen sulfide.
• Avoidance of leaks at the surface that would jeopardize
the integrity of the ice plug being formed.
As a part of the work scope, it was determined that several
conditions must be met to perform the freeze plug successfully:
• The casing-casing annulus must be cemented or full of a
water-based fluid.
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Fig. 1. Excavation to a predetermined depth exposing 8 ft to 10 ft of the
surface casing.
Fig. 2. Connection of the thermocouples, nitrogen supply hoses and vent pipes.
The freeze plug does not affect the exposed area of casings
or wellhead equipment integrity. As seen in Table 1, the overall
results of the testing for the API 5CT N80 pipe showed that
the tensile strength values of the subzero samples were slightly
higher than the ambient samples’ tensile strength values. The
elongation values varied when comparing the subzero samples
to the ambient samples, but remained within a 5% difference.
Table 2 shows that the Charpy impact values were lower for
the subzero impacts of the API 5CT N80 pipe in comparison
to ambient and +32 °F impacts, as is expected of any material.
All tensile, yield and elongation values showed that the cryogenic exposures were not causing a deleterious effect on any of
the materials tested.
Blind samples were provided to the testing facility to determine if a section of the N80 pipe that had been exposed to a
pipe freeze more than 100 times could be differentiated from a
sample that had not been exposed to the freezing process. No
difference could be noted. The tensile test values from the area of
the N80 pipe that had been subjected to numerous and frequent
testing only showed a slightly higher tensile strength. Additional samples of API 5CT P110, API 5D S135 and API 5CT
L80 pipe were provided to facilitate additional tests, Tables 3
through 8. Pull testing at ambient and cryogenic temperatures
shows an increase in tensile strength in all but the N80 samples.
Additional tests of carbon steel samples exposed to different
cryogenic temperatures were performed at the Texas A&M
University Microscopy and Imaging Center using a scanning
electron microscope (SEM). Images produced by the SEM of
the surfaces of these samples at fracture initiation zones
showed similar morphological characteristics. During the observations of these samples by the SEM, an energy dispersive
spectrometry detector produced similar plots of elements present in each sample1.
CONCLUSIONS
Fig. 3. Formation of the ice plug as nitrogen is flowed through the jacket.
PRESENTATION OF DATA AND RESULTS
In this case, a freeze plug was placed through the tubing casing
annulus and the tubing, covering a total height of approximately 4 ft. To assist with heat withdrawal and ice formation,
the hoses were prepared as previously shown in Fig. 2. The
lower hose served to withdraw heat from below and prevent
an ice plug from forming underneath, while the top hose
served as the main ice forming hose.
Once all strings on the well had been frozen, the tubing
casing annulus was successfully pressure tested to 1,000 psi
against the freeze plug, which allowed operators to nipple
down the tree and nipple up the blowout preventer safely.
Pipe freezing is most frequently used when a previous operation — wireline, coiled tubing, snubbing, cementing or fracking — has left a situation where isolation from the wellbore
cannot be completed because of a valve failure or restriction.
Wellhead and casing valves become inoperable for a variety of
reasons and frequently need to be replaced. Performing a fluid
kill operation is sometimes not feasible because of either logistics or cost. When tool damage, inoperable valves or some type
of obstruction in the master valves leads to valve failure, a
freezing operation below the wellhead to isolate all the valves
above the casing head is proposed.
In circumstances where operation companies’ policies require two barriers, a combination of kill weight fluids, downhole plugs and pipe freezes can be implemented. On gas wells
where no fluid is present for the freeze operation, millable or
retrievable plugs can be set with a water-based fluid above to
provide an adequate freeze medium in the pipe. Pressure testing to ensure plug integrity can be easily facilitated, and after
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Specimen
Identification
Reduced Area
Dimensions (in.)
Area
(sq. in.)
Yield
Strength
0.2% (psi)
Yield Strength
0.5% EUL (psi)
Total
Load (lb)
Tensile
Strength (psi)
Elongation
(%)
Ambient
0.755 x 0.235
0.177
94,940
95,185
19,360
109,115
25
Cryogenic
0.504 x 0.208
0.105
90,945
90,590
11,150
106,360
20
T 1. Tensile test results for the API 5CT N80 pipe
Table
Impact Value (ft-lbf)
Specimen
Temperature
Cryo. Area
1, 2, 3
+32 °F
66
70
74
70
61
76
77
100
100
100
1, 2, 3
+32 °F
74
68
67
70
77
74
75
100
100
100
1, 2, 3
−60 °F
58
61
58
59
59
62
78
100
100
100
Individual
Lateral Expansion (Mils.)
Avg.
% Shear Fracture
Table
T 2. Charpy test results for the API 5CT N80 pipe
Specimen
Identification
Reduced Area
Dimensions (in.)
Area
(sq. in.)
Yield
Strength
0.2% (psi)
Yield Strength
0.6% EUL (psi)
Total
Load (lb)
Tensile
Strength (psi)
Elongation
(%)
Ambient
0.505 x 0.333
0.168
123,815
124,045
22,850
135,880
20.8
Cryogenic
0.502 x 0.331
0.166
137,350
142,805
24,840
149,490
20.8
T 3. Tensile test results for the API 5CT P110 pipe
Table
Impact Value (ft-lbf)
Specimen
Temperature
Cryo. Area
1, 2, 3
+32 °F
79
76
78
78
67
61
60
100
100
100
1, 2, 3
−60 °F
47
73
73
64
32
52
54
100
100
100
Individual
Lateral Expansion (Mils.)
Avg.
% Shear Fracture
T 4. Charpy impact test results for the API 5CT P110 pipe
Table
Specimen
Identification
Reduced Area
Dimensions (in.)
Area
(sq. in.)
Yield
Strength
0.2% (psi)
Yield Strength
0.7% EUL (psi)
Total
Load (lb)
Tensile
Strength (psi)
Elongation
(%)
Ambient
0.503 x 0.418
0.210
154,040
157,685
36,710
174,600
13.9
Cryogenic
0.509 x 0.393
0.200
166,755
119,657
37,520
187,565
15.5
Table 5. Tensile test results for the API 5D S135 pipe
T
Impact Value (ft-lbf)
Specimen
Temperature
Cryo. Area
1, 2, 3
Ambient
17
15
15
16
6
5
7
45
45
45
1, 2, 3
−60 °F
10
10
8
9
2
2
2
5
5
5
Individual
Avg.
Table 6. Charpy impact test results for the API 5D S135 pipe
T
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SAUDI ARAMCO JOURNAL OF TECHNOLOGY
Lateral Expansion (Mils.)
% Shear Fracture
Specimen
Identification
Reduced Area
Dimensions (in.)
Area
(sq. in.)
Yield
Strength
0.2% (psi)
Yield Strength
0.5% EUL (psi)
Total
Load (lb)
Tensile
Strength (psi)
Elongation
(%)
Ambient
0.755 x 0.211
0.159
91,920
92,185
16,640
104,455
24.0
Cryogenic
0.503 x 0.192
0.097
106,365
106,315
11,990
124,150
17.2
Table
T 7. Tensile test results for API 5CT L80 pipe
Impact Value (ft-lbf)
Specimen
Temperature
Cryo. Area
1, 2, 3
+32 °F
62
62
65
63
72
71
75
100
100
100
1, 2, 3
−60 °F
57
57
58
57
61
57
60
100
100
100
Individual
Avg.
Lateral Expansion (Mils.)
% Shear Fracture
Table 8. Charpy impact test results for the API 5CT L80 pipe
T
the repair or replacement, a post-repair or makeup pressure
test can also be performed to ensure that the new components
are tested before drilling or production is resumed.
ACKNOWLEDGMENTS
The authors would like to thank the management of Saudi
Aramco for their support and permission to publish this article.
This article was presented at the SPE/IADC Middle East
Drilling Technology Conference and Exhibition, Abu Dhabi,
UAE, January 26-28, 2016.
REFERENCE
1. Pendleton, M.W. and Mazzella, C.: “Scanning Electron
Microscopy Characterization of Carbon Steel Fractured by
Pressure while Exposed to Cryogenic Temperatures,”
Microscopy and Microanalysis, Vol. 16, No. S2, July 2010,
pp. 1260-1261.
SAUDI ARAMCO JOURNAL OF TECHNOLOGY
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59
BIOGRAPHIES
Nawaf D. Al-Otaibi joined Saudi
Aramco’s Drilling and Workover
Department as a Drilling Engineer. He
worked in the operations side of the
department from 2010 to 2013.
Afterwards, Nawaf joined the
Workover Engineering Department as
Engineer, where he worked on multiple critical
a Workover
W
Engineer
projects.
He received his B.S. degree from King Fahd University
of Petroleum and Minerals (KFUPM), Dhahran, Saudi
Arabia, in 2010.
Nelson O. Pinero began his career in
1996 when he went to work for
Lagoven, a Venezuelan oil company,
as a Foreman. In 1997, he began
specializing as a Drilling Engineer and
then began working as a Drilling &
Workover Engineer. In 2003, Nelson
started working as a Workover Foreman in Servicios Ojeda
in the western part of Venezuela. Two years later, he went
to work for BP Venezuela as a Workover Foreman. The
following year, BP relocated him to Bogota, Colombia, to
work as a Workover Engineer. Nelson joined Saudi
Aramco’s Workover Department as a Workover Engineer in
2007.
In 1995, he received his B.S. degree Mechanical
Engineering from National Experimental Polytechnic
University, Barquisimeto, Venezuela.
Ibrahim A. Al-Obaidi is a Division
Head at Saudi Aramco’s Workover
Engineering Department. During his
career, he has gained experience in
drilling and workover engineering,
drilling and workover operation and
production engineering. Ibrahim has
been heavily involved in several upstream projects, also he
has been a member of numerous teams during his career.
He is a member of the Society of Petroleum Engineering
(SPE).
In 1995, Ibrahim received his B.S. degree in Petroleum
Engineering from King Saud University, Riyadh, Saudi
Arabia.
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SAUDI ARAMCO JOURNAL OF TECHNOLOGY
Carlo Mazzella is the Wild Well
Global General Manager of Special
Services. He has 32 years of experience
in the energy industry, with 29 years of
specialization in hot tapping, cryogenic
pipe freezing, and gate valve drilling.
In addition to publishing numerous
cutting-edge industry papers, Carlo has coauthored
pioneering research in cryogenics hosted by the worldrenowned Texas A&M University, College Station, TX. He
is a patent holder and master of freezing techniques who
continues to expand industry knowledge, increasing the
effectiveness of intervention operations around the world.
Advancements in Well Conformance
Technologies Used in a Major Field in Saudi
Arabia: Case Histories
Authors: Ahmed K. Al-Zain, Mohammed A. Al-Atwi, Ahmed A. Al-Jandal, Rami A. Al-Abdulmohsen and Hashem A. Al-Ghafli
ABSTRACT
Water management practices are an integral part of effective
well and reservoir management to avoid various water production problems, which present major challenges in the oil and
gas industry. Many strategies have been used in the industry to
control water production, both in producer wells and in injector wells. There are many water control methods available in
the industry, including mechanical and chemical methods;
sometimes a combination of both methods is used.
With the advent of horizontal drilling technology, unique
opportunities have been seized to enable efficient and effective
water management via horizontal wells. More complex wells
of various types and shapes have been drilled and completed.
The benefits of drilling these wells not only include a reduction
in development and operating costs because of the lower number of wells, but also improvement in the reservoir performance and in the management of fluid movements. These
complex wells are drilled with various objectives, which may
include, but are not limited to, increased production, enhanced
reservoir characterization, improved sweep, maximized recovery and efficient reservoir management.
Water management practices implemented for effective water control and to sustain oil production in two different areas
of a major field are presented in this article. One exemplifies
water management practices in a conventionally developed
field, and the second describes drilling conformance technology utilizing smart maximum reservoir contact (MRC) wells.
INTRODUCTION
The subject field consists of three main segments: area-I, areaII and area-III. Initial production from area-I started in 1996,
followed by area-II in 2003, and finally area-III began production in 2006. These areas were developed over a span of about
two decades, which offers a unique opportunity for gauging
the impact of various technologies. A separate gas-oil separation plant (GOSP) serves each production area. All GOSPs are
equipped with wet crude handling facilities to desalt the crude
oil and separate the produced water. The produced processed
water is then injected back into the flank of the same reservoir,
usually below the original oil-water contact1.
The reservoir is under secondary recovery using waterflooding, mainly seawater. The seawater is injected at the periphery
of the field for reservoir pressure maintenance.
GEOLOGICAL SETTING
The oil from this major field is produced from a carbonate
reservoir that is a composite anticline. The anticline is relatively asymmetric. Generally, the reservoir is characterized by
heterogeneity in reservoir rock properties, salinity and fluid
movement. Major and minor faults identified from 3D seismic
data and associated fracture swarms have been observed to
various degrees throughout the reservoir. The fluid mechanism
in this specific area is highly influenced by the presence of fracture corridors and strata from super permeability1-3.
EFFECTS OF EXCESSIVE WATER PRODUCTION
As previously mentioned, seawater is injected at the periphery
of the field. The primary objective is to maintain a healthy
reservoir pressure to keep oil wells flowing and ensure good oil
sweep. Injection water could break through to oil producers
and consequently be produced in association with the oil. Water
production mechanisms vary due to many factors related to
geological complexities, rock and fluid properties, and the
proximity of oil producers to water injectors. Excessive water
production has to be controlled to minimize its negative impact
on oil production. Effects of increased water production include:
• Reduced oil production rate.
• Reduced efficiency of oil recovery.
• Increased hydrostatic pressure in the well.
• Relative permeability effects in the formation.
• Downhole scale in the formation and tubulars.
• Surface water handling bottlenecks.
• Corrosion failures (subsurface and surface).
• Additional treatment costs.
• Reduced profits from increased operating and capital
costs.
SAUDI ARAMCO JOURNAL OF TECHNOLOGY
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• Earlier well abandonment.
% Complying
Wells
% Wells Over
Target
% Wells Under
Target
I
97
2
1
II
100
0
0
III
100
0
0
Total
99
1
0
Area
KEY ASPECTS OF WELL CONFORMANCE
The key to successful well conformance is the production strategy, from project planning to production, with a focus on developing an oil field to ensure sustainable oil production and
maximize oil recovery. Once the field is on production, the focus is shifted to excellently managing the reservoir by acquiring well and reservoir data. The data collection requirements
are part of the field’s surveillance master plan. Well surveillance and data acquisition are vital processes to effectively and
continuously communicate with the reservoir to fully understand the response of fluid movements and to make the necessary adjustments to production and injection plans on a
well-by-well or region-by-region basis in the face of any undesirable anomalies.
The production and injection plans that are in agreement
with reservoir responses are then deployed for field implementation. Collaboration among stakeholders is very important to
ensure compliance with well production and injection rates.
One of the useful checks and balance tools is to employ the
concept of well target rates for oil producers and water injectors. The target rate compliance is then cross-checked frequently and reported monthly to management. Next is a brief
discussion of this exercise.
COMPLIANCE WITH WELL TARGET RATES
Oil Production Side
Every oil producer serving a GOSP area is assigned a target
rate and a production priority. The wells are listed with the
higher producing wells at the top, giving them higher priority.
This list, called production priorities, reflects the reservoir and
production management strategy. The wells with top production priorities are the first to be flowed to meet the oil target
rate of the GOSP area while limiting produced water. Wells at
the bottom of the list, and so beyond the GOSP target rate, are
to be shut-in as standby wells or as alternatives to replace a
shut-in high priority oil producer — one that, for instance, is
closed for well service jobs.
Wells are rate tested frequently, or continuously in the case of
the intelligent field, to ensure compliance with assigned target
rates. The wells may be choked or relaxed, via a surface choke
valve installed on the well flow line, to meet the assigned target
rates. The objective of well restriction is to balance oil production with water injection, optimizing drawdown on each well
to sustain oil production and slow water encroachment. Table
1 shows a typical monthly report for oil rate compliance in the
subject field.
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SAUDI ARAMCO JOURNAL OF TECHNOLOGY
Table
T 1. Oil rate compliance for a typical month
Water Injection Side
Likewise, a water injection target rate is assigned to every injector. Injection well rates are measured continuously via online meters. Every well is equipped with a surface choke valve
to allow adjusting water flow to the assigned target rate. The
injection target for every well is set such that a predetermined
inflow performance rate is achieved for that well and area of
the field. The objective is to balance the water injection with
oil withdrawal while maintaining a healthy reservoir pressure
and ensuring good oil sweep. Table 2 shows a typical monthly
report for water rate compliance.
% Complying
Wells
% Wells Over
Target
% Wells Under
Target
I
83
0
17
II
100
0
0
III
93
0
7
Total
91
0
9
Area
Table
T 2. Water rate compliance for a typical month
WATER MANAGEMENT PRACTICES
Excessive unwanted water production is one of the undesirable
responses of fluid movement in the reservoir and a major concern since it may lead to negative consequences, including reserve and ultimate recovery loss. Therefore, every opportunity
has to be taken to enhance stringent water management strategies to maximize oil production, conserve reservoir energy,
reduce operation costs and protect the environment. Water
management is an integrated process that involves both subsurface and surface facilities, including separator retrofits, system debottlenecking, pump upgrading, piping enlargement and
disposal well additions4, 5.
Water management practices implemented for effective water control while at the same time sustaining oil production in
two different field areas are presented next. One exemplifies
water management practices in a conventionally developed
field, and the second describes drilling conformance technology utilizing smart maximum reservoir contact (MRC) wells.
WELL CONFORMANCE IN A CONVENTIONAL FIELD:
AREA-I
Initially, area-I was developed using mainly vertical wells.
Most wells are generally completed open hole. The last casing
or liner is set at the top of the reservoir, which is then drilled,
penetrating all zones to some point below the base of the reservoir. With the advent of horizontal drilling and for various
strategic reasons, infill wells have been completed as horizontal producers throughout the field during the last two decades.
As water encroaches into the wellbore, the water is monitored
and evaluated using different diagnostic tools. These tools include rate tests, surface fluid samples, production logs, saturation logs, etc. The purpose of this diagnostic work is to
identify the type of water and its point of entry. If the water is
identified as unwanted water, a remedial action to shut off the
water is considered using different approaches, based on the
severity of water encroachment.
Rigless Water Shut-offs
One option is to use rigless methods, such as wireline, to run
bridge plugs or coiled tubing (CT) for cement squeezing, which
involves plugging back perforations with cement or calcium
carbonate chips capped with cement. The wireline option is
very cheap. Through tubing bridge plugs deployed on an electric wireline have proven to be very effective on vertical wells
and are used routinely to shut off unwanted produced water
throughout the field. Depending on various factors related to
geological complexity, rock properties and the shortness of the
remaining oil columns, the treated well can last from a few
months to 18 months on production before it ceases to flow6, 7.
In the case of horizontal wells, more sophisticated methods
using CT are used to shut off water production. The CT is
used to deploy mechanical tools and chemical treatment fluids.
These chemical and mechanical treatments on horizontal wells
have been used with limited success8, 9.
For example, Well-A is completed as a cased hole horizontal
producer at the top of the reservoir in a mature area. The well
began to exhibit high water cut and ceased to flow with a water cut above 60%. A water shut-off job, using a through-tubing inflatable plug, was performed to shut off the watered out
perforations. The inflatable plug was deployed and set across
the 4½” liner using a CT. Figure 1 shows the water cut performance before and after the water shut-off. Afterward, the
well achieved its target oil rate of 1.5 thousand barrels per day
(MBD) with a water cut of less than 20%. This performance
has been sustained for about 12 months.
Fig. 1. Water cut performance for Well-A.
existing vertical and horizontal wells. This technique has been
successful in recovering the remaining unswept oil in areas
with a thin remaining oil column while preserving the water
underneath. Short radius horizontal recompletions like this are
preferred to conventional water shut-off jobs because short radius horizontal wells produce at a lower drawdown pressure.
A lower drawdown pressure minimizes water breakthrough
and sustains oil production for a longer time compared to rigless water shut-offs. In addition, short radius horizontals cost
66% less than drilling new horizontal wells. In high risk areas,
the well is usually completed with inflow control devices
(ICDs) to evenly distribute production contributions along the
pay zone, which improves the oil sweep and defers any premature water enchroachment7, 10.
For instance, Well-B was drilled and completed as a horizontal open hole producer at the top of the reservoir in a mature location. The well showed a rapid water cut increase and
ceased to flow at a water cut above 70%. Accordingly, the
well was sidetracked in a different direction in the top 10 ft of
the pay zone. Because operators encountered complete loss
circulation while drilling the horizontal section, the wall was
equipped with an ICD completion. Figure 2 shows the water
Horizontal Recompletions
The second option is to sidetrack a watered out well and drill
horizontally in the top 10 ft of the pay zone to maintain maximum distance from the water zone. This option is viable for
Fig. 2. Water cut performance for Well-B.
SAUDI ARAMCO JOURNAL OF TECHNOLOGY
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63
cut performance before and after the sidetrack for Well-B. After the sidetrack, the well produced 3 MBD of oil at less than
20% water cut. The well has a sustained flow at its target rate
with a water cut of less than 20% for more than two years.
Figure 3 compares the number of historical rigless water
shut-offs with that of horizontal sidetracks for area-I. During
the seven-year review period, the engineering tendency was to
select the sidetrack option more frequently than the rigless
shut-offs; there were 68 horizontal sidetracks drilled as compared to 18 rigless water shut-offs for the period. The preference for horizontal sidetracks is to a large extent related to the
area’s geological complexity, rock properties and a thin remaining oil column. The horizontal recompletions have been
found to considerably prolong well oil production with limited
water production. The performance of water cuts for Well-A
and Well-B demonstrates this fact.
Fig. 4. Water cut trend showing the positive impact of well conformance practices
in area-1.
for this type of field development has been intensively investigated in other literature. The bottom-line objective is to sustain oil production on a long-term basis while avoiding
premature water breakthrough1-3.
Description of Smart MRC Well Completion
Fig. 3. Historical rigless water shut-offs and horizontal sidetracks in area-I.
Area-I Field Performance
Figure 4 shows the positive impact of stringent compliance
with well target rates and of implementation of water management practices in area-I. The oil production rate was maintained at the desired target while keeping the water cut below
20% for the seven years of review.
A typical MRC well is a trilateral or quadrilateral well. Figure
5 shows a schematic of a typical smart trilateral well. The well
is drilled as an 8½” mainbore and cased with a 7” liner, set
horizontally into the top of the producing interval. A 6⅛” horizontal open hole is then drilled as a mainbore extension — the
motherbore, L0. Then two 6⅛” open hole horizontal sidetracks, L1 and L2, are drilled by opening windows in the 7”
liner across the motherbore. After drilling, a smart completion
is installed with smart completion assemblies, including a
zonal isolation packer and flow control valve across each lateral.
Control lines are extended from each assembly to a surface
control panel to operate the flow control valve. Each valve has
11 choke positions, ranging from fully closed to the equivalent
of the tubing flow area. The lateral flow can be restricted to
different degrees using the remaining choke positions; the goal
WELL CONFORMANCE IN A SMART MRC FIELD:
AREA-III
Area-III posed a variety of challenges that ruled out a conventional field development. Geological complexity, characterized
by reservoir heterogeneity in rock properties and the presence
of fault and fracture systems, governs the fluid mechanism in
this part of the field. The degraded reservoir quality of area-III
limits the productivity of wells. Therefore, the area was developed mainly with MRC wells and equipped with smart completions having intelligent field capabilities. The driving force
64
SPRING 2016
SAUDI ARAMCO JOURNAL OF TECHNOLOGY
Fig. 5. Schematic of a typical MRC smart trilateral well.
is to produce the lateral at an optimum oil production rate and
limit water production. Generally, laterals are produced all together, honoring the commingled production target specified
for that well.
Utilization of Smart Completion in Water Management
The production performance for a smart MRC well is monitored very closely. Once premature water production is observed, comprehensive rate tests are performed while
manipulating the downhole choke valve for each lateral to determine the source of the unwanted water that risks oil production. In addition, rate tests of production from all laterals
commingled are carried out to decide on the final choke setting
for each lateral’s valve.
For example, Well-C was observed cutting water, and the
water cut increased gradually to 51% while L0, L1 and L2
produced at downhole choke positions of 5, 6 and 7, respectively.
Accordingly, intensive rate tests were carried out for every lateral
by manipulating each one’s downhole flow control valve. Figure 6 shows the inflow control valve (ICV) choke performance
and rate results for the mainbore. It is clear that the mainbore
is cutting water at the low choke position of 3; the water cuts
increase from 6.8% at the first choke position to 38.6% at the
third choke position. L1 showed a similar performance to that of
L0. Unlike the other laterals, the ICV choke performance of L2
was very promising, Fig. 7; the water cut trend remains almost
flat below 19%, indicating no sensitivity to the choke position.
In addition to the individual testing of each lateral to determine its rate performance, tests were performed on the production of all laterals commingled together to assess the well
performance. Rate tests are performed for three or more choke
position scenarios. Table 3 shows the results of the commingling rate tests for a typical smart MRC well, Well-C. The first
scenario, showing the optimum oil production of about 10
MBD with the least water cut of 3.4%, was subsequently
selected as the production rate target for that well.
Fig. 6. ICV choke performance for the Well-C mainbore.
Fig. 7. ICV choke performance for L2 in Well-C.
Downhole Choke
Position
Scenarios
1st
Production Data
L-0
L-1
L-2
Oil Rate
(MBD)
Water
Cut (%)
1
1
10
10.7
3.4
nd
2
3
1
10
10.2
11.3
3rd
3
3
10
9.2
18.9
Table
T 3. Rate results of tests run for three choke position scenarios with all
laterals commingled in Well-C, a typical smart MRC well
Area-III Field Performance
Area-III was the first Saudi Aramco development project to be
developed exclusively using MRC wells with ICVs for flow
control. The value gained from using smart MRC wells is depicted in Fig. 8. The required oil production rate was sustained
while keeping the water cut below 10% for the first seven
Fig. 8. Water cut trend in area-III showing the value of smart MRC wells.
SAUDI ARAMCO JOURNAL OF TECHNOLOGY
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65
years of production. The smart completion, employed while
drilling conformance technology, proved to be necessary to ensure production sustainability in the face of premature water
encroachment despite the geological complexity of the field.
CONCLUSIONS
Crude oil production sustainability, as demonstrated by this article, is a direct result of strategies that ensure adherence to
pragmatic practices to facilitate conformance in response to
various factors related to fluid movements in structurally complex reservoirs. The success of well conformance is attributed
to the selection of techniques that fit in the right circumstances. This selection accuracy would not materialize without
well surveillance and data acquisition programs to sustain the
flow of data to practicing engineers — the decision makers
who, through continuous observation and learning, respond
agilely to changes to comply with strategic objectives. Below
are the main lessons learned:
• The key to successful well conformance is the field
development strategy, extending from the initial stage to
the final stages of the project. A long-term perspective
offers opportunity for technology exploitation.
• The advent of horizontal drilling technology and
geosteering capability in near real time has shifted the
reliance on conventional water shut-offs to horizontal
recompletions.
• Following the evolution of smart technologies, MRC
smart completions became necessary to ensure
production sustainability in the face of premature water
encroachment in highly complex geological regions of
faults and fracture systems.
• Whether it is a conventional or smart field, collaboration among stakeholders is vital to manifest such
successful accomplishments.
ACKNOWLEDGMENTS
The authors would like to thank the management of Saudi
Aramco for their support and permission to publish this article. The authors further acknowledge Saudi Aramco’s Southern
Area Production Engineering management and personnel for
their support during the issuance of this article.
This article was presented at the SPE/IADC Middle East
Drilling Technology Conference and Exhibition, Abu Dhabi,
UAE, January 26-28, 2016.
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3. Al-Afaleg, N.J., Pham, T.R., Al-Otaibi, U.F., Amos, S.W.
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Development of a Carbonate Reservoir,” SPE paper 93138,
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4. Hintemair, R.W.: “Production Water Management,” SPE
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6. Mohammed, M.A., Al-Mubarak, M.A., Al-Mulhim, A.K.,
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in Open Hole Well Completions in Saudi Arabia,” SPE
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7. Al-Jandal, A.A. and Farooqui, M.A.: “Use of Short Radius
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8. Al-Zain, A., Duarte, J., Haldar, S., Al-Driweesh, S.M., AlJandal, A., Shammeri, F., et al.: “Successful Utilization of
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9. Sharma, H.K., Duarte, J., Eid, M., Turki, S. and Vielma,
J.R.: “Lessons Learned from Water Shut-off of Horizontal
Wells Using Inflatable Packers and Water Shut-off
Chemicals in the Ghawar Field of Saudi Arabia,” IPTC
paper 16637, presented at the International Petroleum
Technology Conference, Beijing, China, March 26-28,
2013.
10. Al-Mulhem, N.I., Sharma, H.K., Al-Zain, A.K., AlSuwailem, S.S. and Al-Driweesh, S.M.: “A Smart
Approach in Acid Stimulation Resulted in Successful
Reviving of Horizontal Producers Equipped with ICD
Completions, Saudi Arabia: Case History,” SPE paper
127318, presented at the SPE International Symposium
and Exhibition on Formation Damage Control, Lafayette,
Louisiana, February 10-12, 2010.
BIOGRAPHIES
Ahmed K. Al-Zain currently works as
a Production Engineering Consultant
in Saudi Aramco’s Southern Area
Production Engineering Department
(SAPED). Having joined Saudi Aramco
in 1983, he now has over 30 years of
experience, mainly in production
engineering as well as in reservoir and drilling engineering.
Also during this time, Ahmed has made many substantial
contributions in relation to the upstream sector.
He has published several technical papers on various
petroleum engineering topics, such as acid stimulation,
scale inhibition, water compatibility, transient well testing,
advanced coiled tubing applications, automated well data
acquisitions and new technology applications.
Ahmed has participated in many technical Society of
Petroleum Engineers (SPE) conferences, workshops and
teams, noticeably leading the production engineering
efforts in the Saudi Aramco carbon dioxide enhanced oil
recovery demonstration project from the initial design
phase to commissioning.
His interests covers a wide spectrum of petroleum
engineering aspects, such as well treatments, stimulations,
well conformance, well integrity, well/reservoir data
acquisition, produced water management, unconventional
completions, smart completions, intelligent fields,
deployment of new technologies and coaching
subordinates.
In 1989, Ahmed received his B.S. degree in Petroleum
Engineering from Tulsa University, Tulsa, OK.
Mohammed A. Al-Atwi is a General
Supervisor in the Southern Area
Production Engineering Department
(SAPED), where he is involved in gas
production engineering, well
completion, and fracturing and
stimulation activities.
Mohammed joined Saudi Aramco in June 2003 as a Gas
Production Engineer. He has been involved in several
assignments and projects since then. Mohammed’s previous
experience includes working as a Gas Drilling Engineer and
a Well Completion Foreman. He also has working
experience in the oil production and reservoir management.
Mohammed has published several technical reports,
studies and Society of Petroleum Engineer (SPE) papers.
He received his B.S. degree in Petroleum Engineering
from the University of Tulsa, Tulsa, OK, and an M.S.
degree in Business Administration from University of
Strathclyde, Glasgow, U.K.
Ahmed A. Al-Jandal joined Saudi
Aramco in 1986 as a Petroleum
Engineer for the Southern Area Oil
Operations Department, managing oil,
gas and water operations. He joined
the in-house Production Engineering
Specialist program in 2001 and
graduated in 2005 as a Production Optimization Specialist.
During this period of time, Ahmed also taught as an
instructor for the in-house Production Engineering School,
covering well integrity, well rate testing and well
monitoring subjects. Since 2007, he has been the
Supervisor for one of the specialized units under the
Southern Area Production Engineering Department,
covering the areas of acid stimulation and water injection
for Ghawar field. In 2013, Ahmed was promoted to a
Petroleum Engineering Consultant for his department.
He has authored/coauthored numerous Society of
Petroleum Engineer (SPE) papers and participated in
several national and international conferences around the
world.
In 1986, Ahmed received his B.S. degree in Petroleum
Engineering from King Fahd University of Petroleum and
Minerals (KFUPM), Dhahran, Saudi Arabia.
Rami A. Al-Abdulmohsen joined Saudi
Aramco in 2001. Currently, he is
working as a Production Engineer
handling oil production in the
Southern Area of Ghawar reservoir.
Rami received his B.S. degree in
Computer Engineering and his M.S.
degree in Petroleum Engineering, both from King Fahd
University of Petroleum and Minerals (KFUPM), Dhahran,
Saudi Arabia.
Hashem A. Al-Ghafli is a Production
Engineer with more than 6 years of
experience in the oil and gas industry.
As a Production Engineer (having
worked in both oil production and
water injection), he has working
experience in well surveillance, well
integrity, well stimulation, well completion and
integrity
commissioning, and surface facilities. Currently, Hashem is
working as an ‘Uthmaniyah area Production Engineer in
Saudi Aramco’s Southern Area Production Engineering
Department.
In 2009, he received his B.S. degree in Petroleum
Engineering from King Fahd University of Petroleum and
Minerals (KFUPM), Dhahran, Saudi Arabia.
SAUDI ARAMCO JOURNAL OF TECHNOLOGY
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possibilities
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