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.

Since the discovery of the Khuff and Kahmah reservoirs at Mukhaizna field in 2010, Oxy Oman has faced a number of challenges in producing heavy oil (8000-20,000 cP) from these carbonate reservoirs. These large, low-productivity reservoirs have few analogues in the world, so Oxy has had to find our own way, pioneering new approaches to bring these reserves to market. In addition to the complicated geology of these naturally fractured, vuggy, and dolomitized carbonate reservoirs, identifying the right steam injection method and selecting the best artificial lift system were critical to the success of the project. This paper covers the staged field development methodology, which we found to be beneficial for reducing both geological and reservoir engineering uncertainties. We will share our analysis and evaluation of various development concepts, including steamflooding, sequential steam injection, and scheduling cyclic steam stimulation across the field to optimize overall field production rates. Our focus on data gathering and analysis has enabled us to optimize both our completion design and artificial lift selection, which has reduced downtime and lowered operating costs by nearly 50%. Persistent efforts by our engineers during the past two years have resulted in peak oil production this year – without any significant drilling activity.

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 Panna field is a heterogeneous limestone reservoir consisting of a thin oil column overlain by a gas cap and underlain by a water column. The reservoir is coning dominated and the wells show a marked increase in Gas Oil Ratio (GOR) and water cut very early in the production history. Horizontal wells were drilled to minimize drawdown, and hence coning, and maximize recovery. The initial horizontals had openhole completions and displayed a peculiar inflow performance curve that was concave upwards and almost flat at the higher rates. This was thought to be caused by the formation of water sumps at low rates, due to the undulating profile of the drainhole & the low fluid velocities, which resulted in a non-uniform flow contribution along the horizontal. Subsequent wells were completed with a centralized, selectively perforated tubing (tailpipe) installed in the drainhole and it was thought that this would result in a uniform flow contribution along the entire horizontal section and correct the inflow performance curve shape. Analysis of pressure data from the tailpipe wells showed that the tailpipe caused progressively higher drawdown at high rates. However, the flow distribution along the drainhole could not be determined from pressure data alone. A production logging campaign utilizing tractor as the conveyance system had to be aborted due to a) limited coverage of the horizontal section by the tractor and b) operational problems resulting in fishing of the tractor in one of the wells. This campaign was expected to provide an insight into the flow process in the two completions and determine the most optimum one. This case study presents the performance of the various horizontal completions in existence in the field and integrates production and bottom-hole pressure data to explain them. Introduction Panna field is located in the Bombay Basin in Western offshore India 50 km east of the giant Bombay High Field and 95 km Northwest of the city of Mumbai (Bombay). It has initial oil in place of over 1 billion barrels. The field presently has 63 wells of which 19 are vertical wells and 44 horizontal. The horizontal wells have been completed in three different ways: openhole, stinger completions and perforated tailpipe completions. A brief description of the different completion schemes and efforts made to evaluate them are presented in the paper. Modeling studies indicate preference towards tail-pipe completions, but measured production and pressure data indicates that the barefoot completions are advantageous when producing at high liquid rates. Reservoir Geology The principal hydrocarbon bearing formations in Panna Field are the Middle Eocene Bassein B Upper and the Early Eocene Bassein A limestones. An unconformity representing approximately 4 million years of Upper Eocene time separates the Bassein A and B zones. These are ramp setting, tropical limestone deposited in marginal marine to inner nerritic depths in a low to moderate energy environment. A structural cross-section of the Panna field is shown in Figure 1.