An analytical model, based on CFD
and discrete element modeling, simulates treatment placement efficiency and
diversion effectiveness in HPHT fractured carbonate reservoirs. Application of
the innovative technique increased expected production 20% in a North American
OMER, DIANA VELAZQUEZ, CARMEN RAMIREZ, and DR. FRANCISCO
enhancement from permeability-challenged formations depends on the
effectiveness of the hydraulic fracturing design. During a stimulation
operation, a fracturing fluid is injected into the formation, above the
formation pressure, to create fractures from the wellbore wall in different
orientations, due to the stress concentration and variation in the near-wellbore
industry practices in North America prove that hydraulic fracturing is an
essential tool for enhancing production from low-permeability reservoirs. Some
of the common shale plays around the world, including the Barnett, Vaca Muerta
and others, experienced an initial high production rate after stimulation but
had a steep decline within the first few months after reaching peak rate,
resulting in low recovery efficiency.
stimulation fluids are injected into the formation, they take the path that
offers the least resistance i.e., they penetrate areas with open flow paths,
like perforations, fractures, natural fissures, wormholes, or vuggy zones. The
reservoir and rock mechanical properties of the formation, like Young’s
modulus, UCS, porosity, and permeability, dictate the competition between
simultaneously and propagating flow paths and hence affect the stimulation
slurry distribution. When mechanical interactions happen between fractures that
are in close proximity to each other, this could further create challenges in
the distribution of the stimulation fluid.
maximize the zonal coverage of the stimulation fluids, existing fluid paths
and/or higher permeability areas or natural fractures must be temporarily
sealed, enabling the treatment fluid to uniformly penetrate across the zone. The
controlling parameters for enhancing the production efficiency are the fracture
network, distribution of stimulation fluids i.e., zonal coverage enhancement,
high displacement efficiency, and uniform and effective diversion. This is to
obtain high production efficiency, optimum production rates and reduction in
completion costs. The authors will focus on effective diversion design, using an
engineered workflow to achieve the goal.
types of diversion mechanisms have been utilized for enhancing the zonal
isolation and preventing the stimulation slurry from taking the path of least
resistance. Abdelfatah introduced a model to design and optimize in-situ acid
diversion systems using nanoparticles.1 Sarmah explored the
effectiveness of a cationic‐polymer acid system with a self‐breaking ability
for acid diversion for carbonate formation.2 Also, engineered bio-degradable
bi-particulate diverters can effectively seal the openings or high-permeability
areas to divert the stimulation fluid into under-stimulated regions for enhancing
the zonal coverage, thereby increasing the production efficiency.
success of fluid diversion treatments is governed by the reservoir and rock mechanical
properties of the formation, and which influence the pumping strategy design of
the diversion system. This study focuses on the underlying mechanisms of fluid
movement. The workflow utilized combines both analytical and numerical
techniques to optimize the design of stimulation slurry and its deployment in
the field to ensure effective zonal coverage. One field data set from North
America was used to demonstrate the applications of the proposed workflow in
different fluid simulations. Our analysis shows that we can optimize the
configuration, using the workflow to enhance the zonal coverage of the
this study, we utilized a divergent acid system, Fig. 1. It contains a
cationic polyacrylate copolymer of moderately high molecular weight pH buffer,
along with a crosslinking agent. The acid diversion system is designed with 5% active
HCl. Activation occurs when the systems reach a pH between 2.5 and 3 and breaks
when the pH gets to 5 or higher. This is stable for temperatures up to 350°F or
177°C. Viscosity is generated in situ, as the acid spends, reducing friction
pressure, which, in turn, reduces the horsepower (HP) required to pump the acid
treatment. Figure 2 represents the viscosity versus (v/s) pH behavior of
this acid diverting system at 28°C.
crosslinked fluid will divert the live acid to another part of the formation,
to minimize the development of a dominant wormhole and reduce fluid loss. As
the acid continues to spend, and the pH increases to between 4.0 and 5.0, the
system will return to the original viscosity. This is used in acid fracturing applications
and self-diverting acid systems for carbonate gas and oil reservoirs.
development allows the flow of acid to be diverted within the reservoir, as the
acid begins to spend and then allows efficient flowback of spent acid, once the
pH reaches above 5.0. This helps in a deeper penetration than a conventional
HCl system without gel, and due to the self-diverting feature of these systems,
more complex wormhole patterns can be expected.
data utilized in this work is from a highly fractured carbonate formation in
North America with a bottomhole temperature of around 355°F. The
well is an “S” type directional profile with a total depth of 24,947 ft, Fig.
3. It consists of 4½-in. tubing at 13,983 ft and a packer at 13,146 ft. The
7-in. liner runs through 22,913 ft.
open-hole section starts from 22,913 ft and runs to 24,948 ft, which is an approximately
2,000-ft-long interval with the presence of natural fractures. The average
water saturation (Sw) of the well was 10%, with a reservoir pressure
of 11,500 psi. The average porosity of the open-hole section is approximately 4%,
Fig. 4. The permeability varies between 0.05 mD and 3 mD at certain
depths, like 22,000 ft, 23,881 ft and 24,400 ft. Figure 5 shows higher
permeability, indicating a high likelihood of natural fractures. The average
skin estimated prior to the stimulation was 70.
strategy. The work showcases the comparison between a non-optimized (i.e., without
diversion) and an optimized approach using three stages of diversion.
modeling without diversion. Figure 6 represents
the wellbore profile of injection fluids without diversion. The packer was
installed at a depth of 13,142 ft. The hydrocarbon fluids were present in the wellbore
as static fluid. In the scenario, we simulated the case by pumping the
stimulation treatment without diversion across the 1,775-ft open-hole section. The
model predicted that stimulation fluids were distributed non-uniformly, and
most of the fluid seems to have gone into higher permeability zones or zones
with the presence of natural fractures; hence, the open-hole section between
23,500 ft and beyond was not stimulated effectively, Fig. 7. Note that
there is no improvement in the skin from 23,500 ft to 24,688 ft.
injection into the reservoir per unit length of the well is an indicator of the
zonal coverage. In Fig. 8, each
colored line represents injection into the reservoir at each specific depth. We
can see that injection of stimulation fluids into the formation is very low in the
first 100 minutes (mins.) of injection. At around 115-118 mins., we see a sharp
increase in the injection into the reservoir. This is probably due to the fluid
following the path of least resistance, i.e., stimulation fluids entering higher-permeability zones or natural
fractures. This is not desirable, as it reduces the treatment efficiency, due
to the non-uniform distribution of the stimulation fluids.
9 shows the invasion profile along the well. It shows that most of the
stimulation fluid invades into the highest-permeability interval and openings
(fractures), whereas the bottom interval of the open-hole section does not take
(or takes very little) acid. We can also see regions of under-stimulation.
modeling with diversion. The first step in this
physics-based approach is to calculate the optimum injection rate and total
acid volume, prior to considering the diversion system. The design is
continuously improved by considering multiple scenarios of diversion system
injection until the highest zonal coverage and stimulation efficiency are
achieved. The next step is to optimize the stimulation treatment. This scenario
was designed by using three stages of an acid diversion system in-between the
main acid stages, Fig. 10. The first batch of the diversion stage is
usually designed to provide temporary flow resistance in the highest-permeability
zone, and the second and third batches are expected to further homogenize the flowrate
along the wellbore.
associated wormhole penetration and final skin reduction along the wellbore
length are demonstrated in Fig. 11. It can be seen from the figures that
the zonal coverage has been enhanced, as compared to the previous case (no
diversion). The skin reduction is obtained in the lower section of the open hole.
This is a considerable achievement to uniform the stimulation along the
completed length of the wellbore. Figure 12 shows the injection profile
along the wellbore after design improvement with diversion slurry. The
diversion system in three stages has caused a more homogenized fluid invasion
along the wellbore and better skin reduction of the well.
13 captures the invasion of stimulation fluids after the improvement
of the design. A comparison between Fig. 13 and Fig. 8 clearly
demonstrates more homogenous distribution of fluid along the entire length of the
open-hole section. This was made possible by optimizing the design of the
diversion stages using our novel workflow. By using the fit-for purpose stimulation/diversion
design, we were able to force the stimulation fluid flow into zones of low
permeability to homogeneously stimulate the formation to enhance production
efficiency. The presented workflow and analyses can quantify the impact of the
key parameters on the resulting fluid diversion and, hence, the stimulation
efficiency to maximize recovery.
enhancement. The expected production from this well was around 9,320 bcpd and
33.9 MMcfgd. But after the successful engineering design and optimized
stimulation, the operator increased production, compared to expected production
prediction. The well started producing 11,180 bcpd and 35 MMcfgd.
Due to the heterogeneity of the reservoir,
it is important to implement a fluid diversion tactic in stimulation
application. The case study outlines how to use an engineered solution to
design the diversion properly, to distribute the stimulation fluid uniformly
into the open-hole section between 22,913 ft and 24,948 ft. The client expected
approximately 9,320 bcpd, but after the stimulation job, the well produced 11,180
bcpd. A proper design, based on physics, was critical to the success of
The integrated engineering design
workflow can guide the fluid design and application in fracturing, matrix acidizing
and refracturing operations. We can conclude from the comparison between
diversion and non-diversion stimulation treatment designs, that the optimized
design can be engineered to enable successful diversion of fracturing fluids
into the target zones to create additional fractures.
The presented design workflow and
analysis will better enable operators to design and customize solid particles
for efficient fluid diversion. Further, the applications of the presented
engineered design workflow can also be prospectively extended for re-fracturing,
as well as an acid fluid diversion for matrix acidizing. In this case study, we
were able to enhance the distribution of the stimulation fluid across the open-hole
interval by optimizing the diversion stages. Uniform fluid distribution, with
enhanced zonal coverage, was achieved. This helped the operator to achieve
incremental production gains, compared to expectations. WO
This article contains excerpts from SPE paper
212424-MS, “Enhancing stimulation efficiency in a fractured open-hole carbonate
reservoir by diversion design using advanced modelling techniques,” presented
at the SPE Argentina Exploration and Production of Unconventional Resources
Aires, Argentina, March 27-29, 2023.
MOHAMMED OMER is project engineer for Weatherford’s global R&D team, based
in Abu Dhabi. He has over 10 years of experience in the oil and gas industry
specializing in drilling/digitalization, wellbore stability modeling, geomechanics
studies and development of new stimulation chemicals in addition to water
conformance strategy. He has published 25 international publications and has served
as a technical committee member for various SPE conferences. He is also an SPE
certified technical trainer for Energy4me. Mr. Omer holds a master’s degree in
petroleum engineering and a bachelor’s degree in mechanical engineering.
DIANA VELAZQUEZ has more
than 10 years of experience in the oil and gas industry. She specializes in
developing solutions focused on production improvement and has led and/or
contributed to several stimulations, fracturing and water conformance projects
in sandstone and carbonates formations in unconventional and HPHT reservoirs.
She is also proficient in developing EOR treatments through microorganism’s
injection. Ms. Velazquez is based in Mexico and holds a degree in mechanical engineering
and a master’s degree in thermofluids from the National Autonomous University
RAMIREZ is manager of the PPS Weatherford laboratories based in Mexico.
She is responsible for developing technologies/materials and executing acid
and/or propped fracturing in HTHP/LTLP wells. During her 20 years in the
industry, Ms. Ramirez has specialized in formulating a new generation of gelled,
divergent and chelating acid systems specifically for HTHP applications. Also, the
evaluation of different fracture fluids for low and high temperatures. She graduated
from the Central University of Venezuela with a master's degree in engineering from
the Universidad De Carabobo, Venezuela.
FRAGACHAN is global engineering director for pressure pumping and drilling
fluids for Weatherford based in Houston. He has over 40 years of experience in
the industry, including 10 years with Weatherford. His expertise encompasses well-log
analysis, rock physics, well fracture stimulation and formation damage. He has
published more than 100 articles and authored 15 patents relating to these
issues. Dr. Fragachan holds a master’s degree and a PhD in rock physics from
Purdue University, Indiana and a master's degree in petroleum engineering from the
University of Tulsa in Oklahoma.