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.

Tatweer Petroleum completed the first successful Bahrain Field Forced Imbibition Gas Injection Pilot in 2014. This pilot was completed in the Ahmadi formation and demonstrates classical and economic performance. The paper also describes the systematic effective and efficient Tatweer pilot management approach which allowed an impressive results in a time frame less than one year. The Ahmadi formation consists of three, carbonate, highly fractured reservoirs designated as Aa, Ab1, and Ab3. The Ahmadi reservoirs have the greatest areal extent of any of the oil-bearing reservoirs in the Bahrain field. The Aa and Ab productive zones cover over 41,500 acres, and are separated by 40-45 feet thick, shale members. The gas injection (GI) pilot development in the Ahmadi reservoir, along with the waterflood pilot, is considered a secondary recovery process. The objectives of this pilot is to test the concept of forced imbibition (FIMB) in Ahmadi reservoir after it was successfully tested in Rubble reservoir with steam injection. The FIMB GI process is performed by injecting gas within the pattern area for certain period while offset oil producers are kept shut-in. The offset oil producers are opened once the GI cycle is achieved and accordingly the gas injector kept shut-in. This process will enhance the stripping of the oil from the matrix to the fracture system, which are connected to the offset oil producers. The selection criteria to select the optimum FIMB pilot pattern was developed based on an intensive matrix selection criteria. The selected pilot consists of three horizontal wells; one injector and two producers. The wells were completed as open-hole with ~1000m lateral in the Ab3 unit, and the space between the producers and injector is ~180m. The selected pilot was initially a water injection pilot. However, the production after the introduction of this pilot was not promising, and water break-through resulted in a reduction of the base production. Consequently, the pilot injector was suspended. The suspended water flood pilot area was selected since it is located in highly fractured and confined area. A simulation dynamic model was constructed covering a sector area within the vicinity of the pilot. The model was used to run different scenarios for the number of GI cycles at different GI rates, and assess the required soaking time post GI Cycles. So far, 3 GI cycles have been completed with around 60 MMscf being cumulatively injected. The initial results were very encouraging during the FIMB GI execution. The dynamic scenario output predication was calibrated with actual production data from the executed FIMB GI pilot, and the results were in line with the model's predictions. Thus, the FIMB GI seems to be effective and promising enhanced recovery in a highly fractured carbonate reservoirs. The results of the pilot provided confidence on proposing crest GI pilots to enhance the secondary recovery process in the Ahmadi reservoir.