Summary The Mukhaizna heavy-oil field in the Sultanate of Oman desert has three distinct zones that require steam injection to enhance oil recovery. A new, geocellular-based reservoir description was prepared to evaluate the steamflood performance of these three zones using different horizontal- and vertical-well configurations. On the basis of the results of thermal simulations, the final design called for vertical wells injecting steam into all three zones, with three stacked horizontal production (HP) wells, one for each zone. One advantage of this design is the ability to control the steam flux from each vertical injector (VI) into each zone to mitigate early steam breakthrough and optimize recovery. After 2 years of steam injection, oil production is tracking the thermal model nicely.
The Mukhaizna heavy oil field in the Sultanate of Oman has three distinct zones that need steam injection to enhance oil recovery. A new geocellular based reservoir description was prepared as the starting point to evaluate the performance of these three zones; UG2A, UG2B, and MG to different injector and producer configurations. The major challenge was to ensure good production rates without compromising recovery efficiency. The three zones are separated from each other except in a few places where the two zones UG2A and 2B communicate.During the flood design, producers with horizontal laterals were considered for each of the three zones. However, determining a method for steam injection that delivered recoveries similar to steam assisted gravity drainage (SAGD) was a challenge. A thermal reservoir simulation model was used to evaluate various configurations including horizontal and vertical injectors.The final design called for commingled vertical injectors positioned between offset horizontal producers with three laterals stacked vertically. This design created a new modified SAGD recovery process for the reservoir. A steam chamber is created above each horizontal lateral, but the steam arrives from the side. One advantage of this design is the ability to control steam in each vertical injector. With advanced surveillance techniques to determine locations of early steam breakthrough, vertical injectors can be controlled to optimize recovery. This paper will show the design options considered and their estimated recovery. Then the modified SAGD design, implemented at Mukhaizna, will be compared to current production performance in a selected area of the field which has been under injection for around 2 years. Field performance, which will be presented as rate versus time, and, also using dimensionless plots is tracking the thermal model based design quite nicely. The use of surveillance methods to control injection is also discussed.
The Late Cretaceous Mishrif limestone is known locally in Bahrain as the "Rubble" due to extensive tectonic fracturing and karst brecciation which may have tens to hundreds of times the permeability of the tight matrix where most oil resides. If these secondary features are not properly managed, steam utilization during thermal heavy oil recovery is compromised, so heat transfer to viscous crude in the matrix is less effective. To address this challenge, field pilots are conducted across Awali field to apply customized thermal processes to varying geology. Designing the thermal pilots uses 3D static and dynamic models representing the heterogenous reservoir to test various thermal processes (cyclic steam stimulation, forced imbibition, and steamflood). Initial geocellular models are multi-well secular models utilizing simplified erosional surface truncations and fault-fracture networks to optimize run times for multi-component thermal simulation. Reservoir properties are guided by well log data and geostatistics, whereas an effective permeability hierarchy accounts for historic well performance and observations. Additional inputs for simulation include thermal properties for rock and fluids, temperature-dependent relative permeability curves, temperature-viscosity relationships and vapor-liquid equilibrium ratios for each crude component, and injected steam quality. Piloting in a sparsely fractured portion of Awali field gave unexpected results that required revisiting conceptual geologic models and testing new ideas with dynamic simulation. This effort was accelerated by multiple scenario playing with "pseudo-fractures" strategically relocated to honor dynamic data while remaining consistent with the known fault, fracture and karst trends. This paper describes the results of this particular pilot and the versatile modeling approach taken to understand the outcomes. It recommends early quick multiple scenario playing to help guide subsequent time-intensive detailed fault-fracture-karst modeling.
The Mukhaizna heavy oil field in the Sultanate of Oman has three distinct zones that need steam injection to enhance oil recovery. A new geocellular based reservoir description was prepared as the starting point to evaluate the performance of these three zones; UG2A, UG2B, and MG to different injector and producer configurations. The major challenge was to ensure good production rates without compromising recovery efficiency. The three zones are separated from each other except in a few places where the two zones UG2A and 2B communicate.During the flood design, producers with horizontal laterals were considered for each of the three zones. However, determining a method for steam injection that delivered recoveries similar to steam assisted gravity drainage (SAGD) was a challenge. A thermal reservoir simulation model was used to evaluate various configurations including horizontal and vertical injectors.The final design called for commingled vertical injectors positioned between offset horizontal producers with three laterals stacked vertically. This design created a new modified SAGD recovery process for the reservoir. A steam chamber is created above each horizontal lateral, but the steam arrives from the side. One advantage of this design is the ability to control steam in each vertical injector. With advanced surveillance techniques to determine locations of early steam breakthrough, vertical injectors can be controlled to optimize recovery. This paper will show the design options considered and their estimated recovery. Then the modified SAGD design, implemented at Mukhaizna, will be compared to current production performance in a selected area of the field which has been under injection for around 2 years. Field performance, which will be presented as rate versus time, and, also using dimensionless plots is tracking the thermal model based design quite nicely. The use of surveillance methods to control injection is also discussed.
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