Multistage Fracturing Completion in Vertical Wells - Is it Applicable? Yes
Abstract: In low-permeability formations such as tight gas reservoirs, a well would be economic only if an effective hydraulic fracturing technique is selected. In central part of Sultanate of Oman a deep tight gas field is developed with hydraulic fracture stimulation. Normally, between 7 and 13 frac stages are done per well. Majority of wells are vertical with pay zones separated with shale layers that prevent fracture growth. Plug & perf is a common technique used in this field, therefore there are multiple well … Show more
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Petro-Phyiscal Evaluation Methods of Complex Clastic Deep Tight Gas Reservoirs to Improve Hydraulic Stimulation Efficiency
In most cases calstic deep tight gas reservoirs contain considerable hydrocarbon reserves but the ultra-low permeability and the poor inter-connection between the pores may dramatically reduce the recovery for economical gas production. In such cases, hydraulic stimulation techniques can be beneficial to improve the connectivity between the pore spaces and provide a larger conductive channel to allow communication between the reservoir and the well bore. Prior to the fracturing design it is imperative to understand the borehole and the reservoir environment. Hence, the application of petro-physical evaluation. The main objectives of this paper is to discuss the petro-physical evaluation; conventional and advanced methods to understand fracture initiation and propagation behaviors that are essential to plan, design and execute an effective hydraulic fracture treatment program. A large range of wireline logging tools are available today, and several provide sophisticated interpretations of the formation; including details of formation lithology, fluid type, porosity, fluid content and stress regime, etc. In this paper, integrated interpretation has been conducted from both open and cased hole wireline logging. With the aim of assessing the rock mechanics, formation pressures, cement bond, well bore integrity and other reservoir properties to establish a prominent fracturing zone in Barik and Miqrat tight gas reservoirs. Post fracture analysis such as radioactive tracers has been demonstrated, production logging and noise log are studied and linked with the amount of proppant placed in the selected fracturing intervals to assess the stimulation efficiency. Cement bond log evaluations showed good zonal isolation across the 4.5" tubing in the studied wells, notably in Barik and Miqrat reservoirs. However, poor to intermediate cement was observed across the overlap section between 9 5/8" and 4.5". In which was not a stimulation obstacle. Saturation and electrical parameters were derived from Archie's equation and Special Core Analysis (SCAL), respectively. The interpretation revealed that Barik and Middle Miqrat formations are relatively conclusive in some fields and not in others. Mainly due to the high saturation of the trapped gas due to the tightness of the reservoir. Moreover, based on the saturation log analysis, porosity controlled hydrocarbon saturation profile and created a challenge in determining the top of water bearing interval. Non-resistivity based saturation estimates, such as pulsed neutron and dielectric logs did not offer benefit in fluid typing. Well test showed different results as compared with the anticipated water and gas rates. Gas inflow was observed in all tested wells. In addition, some wells not-necessarily located in the extreme flanks of the field, showed high water influx. Irreducible water saturation derived from NMR and/or capillary pressure data helped to identify moveable water in Barik but not in Lower Miqrat formation due to presences of bitumen and vugs. Selective completion strategy for hydraulic stimulation proved to be successful by screening the reservoir intervals thru the use of a combination of petrophysical and cased hole production analysis. Allowing hydraulic fracturing execution to achieve up 90% of the desired proppant placement. Knowledge of in-situ stresses (magnitudes & directions) is critical to understand hydraulic fracture initiation & propagation behaviors. The initiation and propagation behaviors are essential to plan, design and execute an effective hydraulic fracture treatment program. Open hole and cased hole logging are key practices for evaluating fracture behavior. It provides the grounds to optimize for future wells for stimulation.
Petro-Phyiscal Evaluation Methods of Complex Clastic Deep Tight Gas Reservoirs to Improve Hydraulic Stimulation Efficiency
In most cases calstic deep tight gas reservoirs contain considerable hydrocarbon reserves but the ultra-low permeability and the poor inter-connection between the pores may dramatically reduce the recovery for economical gas production. In such cases, hydraulic stimulation techniques can be beneficial to improve the connectivity between the pore spaces and provide a larger conductive channel to allow communication between the reservoir and the well bore. Prior to the fracturing design it is imperative to understand the borehole and the reservoir environment. Hence, the application of petro-physical evaluation. The main objectives of this paper is to discuss the petro-physical evaluation; conventional and advanced methods to understand fracture initiation and propagation behaviors that are essential to plan, design and execute an effective hydraulic fracture treatment program. A large range of wireline logging tools are available today, and several provide sophisticated interpretations of the formation; including details of formation lithology, fluid type, porosity, fluid content and stress regime, etc. In this paper, integrated interpretation has been conducted from both open and cased hole wireline logging. With the aim of assessing the rock mechanics, formation pressures, cement bond, well bore integrity and other reservoir properties to establish a prominent fracturing zone in Barik and Miqrat tight gas reservoirs. Post fracture analysis such as radioactive tracers has been demonstrated, production logging and noise log are studied and linked with the amount of proppant placed in the selected fracturing intervals to assess the stimulation efficiency. Cement bond log evaluations showed good zonal isolation across the 4.5" tubing in the studied wells, notably in Barik and Miqrat reservoirs. However, poor to intermediate cement was observed across the overlap section between 9 5/8" and 4.5". In which was not a stimulation obstacle. Saturation and electrical parameters were derived from Archie's equation and Special Core Analysis (SCAL), respectively. The interpretation revealed that Barik and Middle Miqrat formations are relatively conclusive in some fields and not in others. Mainly due to the high saturation of the trapped gas due to the tightness of the reservoir. Moreover, based on the saturation log analysis, porosity controlled hydrocarbon saturation profile and created a challenge in determining the top of water bearing interval. Non-resistivity based saturation estimates, such as pulsed neutron and dielectric logs did not offer benefit in fluid typing. Well test showed different results as compared with the anticipated water and gas rates. Gas inflow was observed in all tested wells. In addition, some wells not-necessarily located in the extreme flanks of the field, showed high water influx. Irreducible water saturation derived from NMR and/or capillary pressure data helped to identify moveable water in Barik but not in Lower Miqrat formation due to presences of bitumen and vugs. Selective completion strategy for hydraulic stimulation proved to be successful by screening the reservoir intervals thru the use of a combination of petrophysical and cased hole production analysis. Allowing hydraulic fracturing execution to achieve up 90% of the desired proppant placement. Knowledge of in-situ stresses (magnitudes & directions) is critical to understand hydraulic fracture initiation & propagation behaviors. The initiation and propagation behaviors are essential to plan, design and execute an effective hydraulic fracture treatment program. Open hole and cased hole logging are key practices for evaluating fracture behavior. It provides the grounds to optimize for future wells for stimulation.
In the past two decades, the advent of the Shale Gas Revolution (SGR) was made possible by the visionary idea that hydrocarbons contained in ultra-low permeability source rocks could be extracted using available technology. Usually, these hydrocarbons take geological time to migrate to higher permeability reservoir rocks until the right structural conditions evolve to extract as recoverable resources. However, paradigm shifts in drilling and completion engineering have enabled unlocking resources from these ultra-tight formations. The innovative idea at the base of this industrial revolution was the combination of horizontal well drilling and hydraulic fracturing, which allowed increasing the surface area available for hydrocarbon flow and overcame the slow and shallow hydrocarbon release from the source rock. This approach can be considered as a bridge between petroleum engineering based on radial diffusivity equation and mining engineering based on physically accessing and extracting the resource. To achieve the high number of hydraulic fractures needed for economical production, different execution techniques evolved and developed in what is known as horizontal multistage fracturing (HMSF) completions. Although HMSF is indescribably linked to SGR, it was surprisingly applied in tight gas formation and offshore sand control applications more than 30 or 40 years ago. SGR contributed to the fast development of new innovative systems engineered and deployed at scale all over North America land operations and was subsequently exported internationally in conventional, unconventional, land, and offshore applications. This paper will cover the most common HMSF completion systems types with a primary focus on unconventionals. It will encompass the evolution of these systems over the past several decades. It will also explore the opportunity case for conventional, and high permeability plays through a series of theoretical and real examples.
Hydraulic Fracture Design Evaluation Through a Robust Geo-Mechanical Model, Tested in a Tight Gas Reservoir, North of Oman
Natural gas plays an essential role in providing the world with a cleaner energy for possibly the next 50 years. Conventional gas resources are quickly declining and many countries (e.g. Oman) are investing in tight gas extraction. Such natural gases are usually accumulated in tight sand or shale formations, which have extremely low permeability. Thus, they don't flow at a commercial rate without implementing a hydraulic fracturing, which is an expensive and complicated technique. Therefore, proper fracturing design is a must to enhance well productivity and connectivity. In this study, the petrol physical logs and real field test data were used to construct an intensive rock mechanical model (RMM) for a specific tight gas field to be used in an economical simulator, to optimize the hydraulic fracturing design and strategy for the field. In this study, a rock mechanical model (RMM) was constructed to calculate the rock mechanical properties of the Formations, such as Poisson ratio, Young's modulus, uniaxial compressive strength (UCS), pore pressure and situ stresses. This was achieved by using the drilling data, wireline logs and core data of two wells from the field. The calculated properties from RMM were calibrated by inputting them in a specific constructed geo mechanical equation at which its trend was matched with the field caliber log trend. Some revision and modification were applied using an economical simulator to optimize the hydraulic fracture treatment. The simulation was run twice. In the first run, the simulator calculated the mechanical properties of the formation automatically by the built-in correlations of the simulator. In the second run, the outcome of constructed RMM were input in the simulator. The results from simulator were compared with the real fracture height from the radioactive tracer measured from the field test. The simulator's result shows the error percentage in the first run, which was done without the RMM, was 112%. While in the second run, where rock mechanical properties were entered in the software, it was 11%. As expected theoretically, building a fracturing model with calibrated data from RMM provides accurate and precise results that are close to the real measurements. However, the minor difference between the second run and the actual measurements can be because of uncertainties in the rock formation, and unavailability of some test data. In addition, the accuracy of the radioactive tracer to measure the real fracturing treatment should be considered. The outcome of this project would help to enhance and optimize the fracturing design and ultimately enhance the productivity of the newly fractured wells. Further, this study is considered an excellent guideline for current and new hydraulics fracture design to reduce the OPEX of the well and optimize production.
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