The Buah formation has gained increasing interest in the search for new exploration plays in the Sultanate of Oman. Significant hydrocarbon accumulation has been discovered in the Buah recently. The Buah formation is complex in terms of lithology, pore structure, and the coexistence of oils with different gravities, including bitumen. The existence of bitumen makes it difficult to determine permeable and recoverable hydrocarbon intervals. The rock characteristics of Buah formation impose significant challenges to traditional formation evaluation methods. Because of the low porosity, error tolerance for estimation is low. Saturation determination using resistivity logs is uncertain because of low porosity and inexact Archie parameters. These include the cementation factor (m) that accounts for water phase connectivity, and the saturation exponent parameter (n), which is sensitive to rock wettability. The wettability status is unknown. However, the existence of bitumen could greatly influence the wettability and thus the saturation exponent. A formation evaluation workflow has been developed to provide accurate petrophysical parameters necessary to estimate stock-tank oil initially in place (STOIIP) and conduct static and dynamic modeling. The triple combo and elemental capture spectroscopy logs are first combined for the best total porosity estimate and lithology determination. Nuclear magnetic resonance provides a lithology-independent pore space hydrogen index, which improves the accuracy of the porosity estimate and also quantifies the bitumen-filled pore volume. Dielectric dispersion analysis provides water-filled porosity together with the water tortuosity exponent (mn) that is strongly related to the cementation factor that can be incorporated in resistivity analysis to obtain a better estimate of water saturation in uninvaded zone. Thus, the integration between nuclear logs and dielectric measurements enables the direct estimate of producible hydrocarbon. Conventional core analysis was used to categorize different rock types in this reservoir by using the reservoir quality index (RQI) approach. The results of our analyses have improved the static model, and examination against production logging and the dynamic model has revealed the best contributing rock types, the importance of fractures, and the impact of bitumen in hindering production.

Over the last 50 years, Acid Stimulation has been growing as an effective method for enhancing Permeability, improving inflow, and reducing wellbore skin. In mature EOR projects, maintaining high inflow to offtake producers are of the main challenges to safeguard reserves and meeting long-term production expectations. In this paper, a novel workflow is presented to discuss best practices into acid stimulation campaign during 2020-2022, resulting incremental oil gain which quick payback period during cyclic oil price environment. This is a thermal EOR operation in deep reservoirs (> 2,000 ft) with extremely high viscosity (>10,000 cp) with temperatures exceeding 500°F. The area is a mature thermal area with 15 years of continuous steam flood operations resulting in different type of scale deposit including Carbonate, Sulfate and Sulfide scales that impact the well deliverability over the last 15 years. The novel workflow, based on a combination of chemical analysis, root cause analysis for Artificial lift failures, zonal treatment systems, was developed in-house and deployed in > 50 wells with a great success rate. The pilot area consists of multiple reservoir zones that have undergone vertical steam injection since 2005 and horizontal producing at dedicated reservoir zone. The skin is induced either by Rock/fluid interaction causing scale drop out and resulting in Artificial lift failures, which holds a larger amount of the remaining oil. The Subsurface and Well Engineering teams collaborated to design a novel well deployment methods treating up to 3000 ft horizontal lateral and operation using coiled tubing units with high rate techniques. The well and reservoir surveillance included gathering data for injectivity/productivity assessment, vertical injection logging, temperature profiles, production in offset producers, and well testing for determining water cut. The low inflow wells manage to increase their pump fillage to highest level in the last 5 years, post flow back shows a short spike of hardness as a result of successful stimulation. In addition, wells with high H2S remain a challenge for stimulation as a result for iron sulfide scale limited dissolving with available chemical in the industry. The final oil production tripled over a period of 3 months, which paid back the cost of the pilot. To our knowledge, based on an SPE literature search, this is the first comprehensive Sandstone Acid Stimulation in thermal EOR operation conducted with the following combination of technologies: 1) skin characterization techniques either wellbore or deep reservoir, and 2) Using downhole sensors with rigless operation of coiled tubing units at harsh conditions. The outcomes open a new frontier for well enhancement in matured thermal EOR development in multi-stack reservoirs, offering better offtake management, safeguard reserve over the field life cycle. The cost of the stimulation per well project was paid off in the first 4 weeks, and chemicals used were developed in an eco-friendly system with much less CO2 emission compared to commodity chemical which allow better management for CO2 emission.

Over the last 50 years, thermal EOR has been an effective method for reducing the viscosity of and recovering heavy oil from deep reservoirs. In mature thermal EOR projects, conformance is one of the main challenges for maximizing reserves and meeting long-term production expectations. In this paper, Occidental presents a novel pilot to address thermal conformance in the Mukhaizna field in Oman. This is a thermal EOR operation in deep reservoirs (> 2,000 ft) with extremely high viscosity (>10,000 cp) in harsh desert conditions with temperatures exceeding 500°F. The pilot area is a mature thermal area with 15 years of continuous steamflood operations. The novel conformance technique, based on a combination of chemical and zonal mechanical isolation systems, was developed in-house in a low oil price environment. The pilot area consists of multiple reservoir zones that have undergone vertical steam injection since 2005. Thermal conformance has emerged as a challenge because more than 60% of the injected steam has been preferentially entering the high-permeability zones, with only 40% of the steam entering the other zones, which hold a larger amount the remaining oil. The subsurface and well engineering teams collaborated to design a rigless operation using dual coiled tubing units, one for cooling water and one pumping a chemical gelation recipe that gels at a certain trigger gelation temperature at the target zone. Zonal isolation of the reservoir is achieved using a novel inflatable packer triggered mechanically by ball gravitation through coiled tubing at 500°F and retrieved after the temporary zonal isolation. The well and reservoir surveillance included gathering data for injectivity assessment, vertical injection logging, temperature profiles, tracer tests in offset producers, and well testing for determining water cut. The pilot improved vertical conformance, as injection logging showed 40% steam reduction was achieved in the target zone, and more steam was re-allocated to the shallow zones. In addition, there was a water cut reduction of more than 20% in offset producers, and oil production tripled over a period of 3 months, which paid back the cost of the pilot and generated positive cash flow. To our knowledge, based on an SPE literature search, this is the first successful thermal conformance operation conducted with the following combination of technologies: 1) Placing a novel chemical recipe through temporary zonal isolation with an inflatable packer, and 2) Using rigless operation of coiled tubing units at harsh conditions of >500°F and high pressure >1000 psi. The outcomes open a new frontier for thermal EOR development in multi-stack reservoirs, offering better utilization of steam injection and improving mobility control over the field life cycle. The cost of the pilot project was paid off in the first 6 weeks, and all chemicals used were developed in an eco-friendly system.