Evaluation Of EOR Techniques For Medium-Heavy Oil Reservoirs With a Strong Bottom Aquifer In The South Of Oman.
- David Brooks (Shell Intl. E&P Co.) | Albert Hendrik De Zwart (Shell Intl. E&P Co.) | Andrey Bychkov (Shell) | Nasser Azri (Shell International EP) | Carolinne Hern (Shell) | Widad Al Ajmi (Petroleum Development Oman) | Mukmin Mukmin (Petroleum Development Oman)
- Document ID
- Society of Petroleum Engineers
- SPE EOR Conference at Oil & Gas West Asia, 11-13 April, Muscat, Oman
- Publication Date
- Document Type
- Conference Paper
- 2010. Society of Petroleum Engineers
- 3.1.2 Electric Submersible Pumps, 2.4.3 Sand/Solids Control, 5.3.2 Multiphase Flow, 5.7.2 Recovery Factors, 3.1 Artificial Lift Systems, 4.1.2 Separation and Treating, 5.1.5 Geologic Modeling, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 4.3.4 Scale, 4.1.5 Processing Equipment, 3.2.6 Produced Water Management, 5.3.9 Steam Assisted Gravity Drainage, 5.4.6 Thermal Methods, 5.4.2 Gas Injection Methods, 4.1.4 Gas Processing, 5.2.1 Phase Behavior and PVT Measurements, 3.1.1 Beam and related pumping techniques, 5.2 Reservoir Fluid Dynamics, 5.4 Enhanced Recovery, 5.6.9 Production Forecasting, 6.5.2 Water use, produced water discharge and disposal, 1.6 Drilling Operations
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This paper describes the search for viable EOR techniques for a medium-heavy oil reservoir with high permeability and a strong bottom aquifer in south Oman. Horizontal production wells drilled at the top of the oil column yield high (commercial) initial oil rates however, they suffer fast water breakthrough and subsequent oil production is at high water cut. Given the poor primary oil recovery, these reservoirs are candidates for EOR as a means by which to improve the ultimate recovery. However, determination of the most appropriate process is non-trivial as field characteristics pose a significant challenge to most EOR schemes. These challenging characteristics include an oil column of around 40m, a large and strong bottom aquifer, sustained high reservoir pressure (100bar) and medium-high oil viscosity (250 to 500cP).
Three EOR techniques were identified as potentially feasible, both in terms of increasing ultimate recovery and their practical implementation; in-situ combustion (ISC), high-pressure steam injection (HPSI) and polymer flooding. None of the three processes are conventionally prescribed for reservoirs such as these and modifications to the basic processes were imperative. ISC is generally applied to thin, confined and dipping sands in the absence of bottom water. Steam injection is normally applied at low reservoir pressure and polymer is normally applied to oils with viscosity less than 150cP.
The paper describes a fully integrated evaluation of these EOR processes. Comparison is made in terms of simulated incremental recovery, economics, energy requirements and CO2 footprint, target volume and the practicality of implementation in a brown field. Against these metrics, polymer flooding is shown to be the best option.
The field under examination consists of several separate, topographically flat, oil bearing accumulations (so-called "reservoir highs??). The highs at a depth of ~900m below ground level are normally pressured having an initial pressure of approximately 100 bar. The reservoir fluid is a highly undersaturated 20oAPI medium heavy oil with a low gas-oil-ratio (0.5 v/v) and viscosities in the range 250-500cP at a reservoir temperature of 50oC.
The main productive unit is the Amin Formation of the Haima Supergroup that comprises aeolian sands deposited in an arid continental setting. The Amin is a massive sandstone unit, with no further stratigraphic subdivisions because of its relative homogeneity. The sands are friable and poorly consolidated in places. Net average porosity is 27%; average horizontal permeability is ~ 5 Darcies and vertical permeability is estimated to be 0.3 - 0.7 times horizontal permeability.
Early production began with a limited number of vertical wells. Later, horizontal wells were drilled at a spacing of 172m before well spacing was reduced to an average of 86m. Figure 1 shows the steep increase in liquid production as a function of an increase in drilling rate after 10-12 years of production. Watercut rose rapidly and remained high, between 80-95%, due to the combined effects of a very unfavourable oil-water mobility ratio, a short standoff from the OWC of only 35 m and a high permeability, regionally extensive, basal aquifer. Support from the aquifer is such that during the life of the field a pressure depletion of only 10 bar has been observed.
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