Production 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 region.
The 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.
When 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.
To 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.
HISTORICAL PERSPECTIVE
Different 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.
The 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 stimulation slurry.
NEW DIVERSION METHOD
In 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.
Fig. 1. Divergent acid.
Fig. 2. Viscosity vs pH @ 28oC of acid diverting system with 5% HCl.
The 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.
Viscosity 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.
CASE HISTORY
The 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.
Fig. 3. Well profile.
The 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.
Fig. 4. Porosity v/s depth of the open-hole section.
Fig. 5. Permeability v/s depth of the open-hole section.
Optimization strategy. The work showcases the comparison between a non-optimized (i.e., without diversion) and an optimized approach using three stages of diversion.
Stimulation 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.
Fig. 6. Injection profile (without diversion).
Fig. 7. Wormhole and skin prediction (without diversion).
The 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.
Figure 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.
Fig. 8. Stimulation fluids injected into reservoir per unit length of the well at a given time (without diversion).
Fig. 9. Wellbore invasion profile (without diversion).
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.
Fig. 10. Injection profile (with diversion).
The 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.
Fig. 11. Wormhole and skin prediction (with diversion).
Fig. 12. Stimulation fluids injected into reservoir per unit length of the well at a given time (with diversion).
Figure 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.
Fig. 13. Wellbore invasion profile (with diversion).
Production 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.
VALUE ADDED
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 diversion treatment.
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.
ACKNOWLEDGMENT
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 Symposium, Buenos Aires, Argentina, March 27-29, 2023.
REFERENCES
- Abdelfatah, E., S. Bang, M. Pournik, J. Shiau, J. Harwell, M. Haroun and M. Rahman, “Acid diversion in carbonates with nanoparticles-based in situ gelled acid, SPE paper 188188-MS, presented at the Abu Dhabi International Petroleum Exhibition & Conference, Abu Dhabi, UAE, November 2017. https://doi.org/10.2118/188188-MS
- Sarmah, A., A. Ibrahim, H. Nasr-El-Din, J. Jackson, “A new cationic polymer system that improves acid diversion in heterogeneous carbonate reservoirs, SPE Journal 25: pp. 2281–2295, 2020. https://doi.org/10.2118/194647-PA
About the Authors
Mohammed Omer
Weatherford
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
Weatherford
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 of Mexico.
Carmen Ramirez
Weatherford
Carmen 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.
Dr. Francisco Fragachan
Weatherford
Dr. Francisco 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.
