Optimization of WAG Process for Coupled CO2 EOR-Storage in Tight Oil Formations: An Experimental Design Approach
- Seyyed Mohammad Ghaderi (University of Calgary) | Christopher R. Clarkson (University of Calgary) | Yan Chen (Penn West Petroleum Ltd)
- Document ID
- Society of Petroleum Engineers
- SPE Canadian Unconventional Resources Conference, 30 October-1 November, Calgary, Alberta, Canada
- Publication Date
- Document Type
- Conference Paper
- 2012. Society of Petroleum Engineers
- 5.3.2 Multiphase Flow, 5.5 Reservoir Simulation, 5.10.1 CO2 Capture and Sequestration, 5.8.3 Coal Seam Gas, 5.4.2 Gas Injection Methods, 2 Well Completion, 5.4 Enhanced Recovery, 1.14 Casing and Cementing, 5.1.1 Exploration, Development, Structural Geology, 2.4.3 Sand/Solids Control, 5.4.9 Miscible Methods, 4.3.4 Scale, 5.4.1 Waterflooding, 5.1 Reservoir Characterisation, 7.1.9 Project Economic Analysis, 6.5.2 Water use, produced water discharge and disposal, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 5.2 Reservoir Fluid Dynamics, 5.7.2 Recovery Factors, 1.2.3 Rock properties, 5.2.1 Phase Behavior and PVT Measurements, 2.5.1 Fracture design and containment, 4.1.5 Processing Equipment, 5.2.2 Fluid Modeling, Equations of State, 7.1.10 Field Economic Analysis
- 5 in the last 30 days
- 1,156 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||USD 8.50|
|SPE Non-Member Price:||USD 25.00|
Restricted flow capacity of low permeability oil formations imposes unique challenges to the implementation of CO2-WAG processes in such reservoirs. Application of multi-stage fractured horizontal wells can substantially improve the injection and
production rates. However, there are various design parameters and operating conditions which can affect the performance of a WAG flood. The parameters considered in this study are those related to development pattern (well spacing and well
completion strategy), hydraulic fracture geometry (half-length and spacing), WAG parameters (WAG ratio and CO2 slug size) and the timing of the switch from primary or water-flood to WAG scheme. In this study, CO2 EOR performance is assessed
based on the oil recovery factor and also the amount of stored CO2; in other words, the objective is to achieve both the goals of enhanced oil recovery and sequestration of CO2 in the tight oil formation. However, to reflect the effect of time, the net present
value (NPV) of the projects was also considered. All three of these parameters were therefore included in objective functions to be optimized.
The effect of all aforementioned parameters on objective functions was investigated using a compositional simulator. Design of experiment (DOE) was then utilized to perform a comprehensive statistical analysis to recognize the most prominent
factors in fulfillment of each objective function in a tight reservoir with properties similar to Pembina Cardium field. Response surfaces were generated to quantify the effect of the factors on the objective functions. Optimization was carried out to find
those sets of factors which provided the highest recovery, storage, and NPV. Searching for optimal values can be extended to any combination of objective functions which are obtained by applying weighting multipliers to each individual objective function.
Appropriate implementation of CO2-EOR in depleted or partially depleted oil reservoirs can provide two simultaneous benefits: (1) environmental benefit by permanent storage and retention of part of the injected CO2 volume; (2) economic
benefit by noticeable improvement in oil production rates and hence incremental oil recovery.
In CO2-EOR, a portion of the injected CO2 dissolves into the oil and water that remains in the reservoir. Therefore, not all the injected gas can be recycled back to the surface. The capillary process will trap an additional fraction of CO2 underground,
a process known as non-wetting phase capillary trapping (Lake, 1989). Although very dependent on the reservoir properties and injection/production strategy, typical estimates for CO2 storage of EOR schemes are between 30% to 50% of the injected
quantity (Smyth, 2008; Han et al., 2010; Hovorka, 2010). The ability of CO2 to dissolve in reservoir oil (causing swelling of the oil), and reduce oil viscosity are the mechanisms for increased oil production rates using CO2-EOR (Jarrel et al., 2002). In
many floods, water is introduced episodically to augment a CO2 flood as a chase fluid, a process known as water alternating gas or WAG process. WAG is used to reduce the amount of required expensive CO2, as well as increasing the amount of
contacted oil (Lake, 1989; Green and Whillhite, 1998).
To date, the majority of the CO2-EOR projects are designed to minimize the amount of gas injected per barrel of oil
produced, hence, minimizing the CO2 purchase and making the most profit possible. However, when the goal is aimed toward
sequestration of injected carbon dioxide, the design challenges and considerations change significantly (Kovscek, 2002;
Kovscek and Cakici 2005). The design and implementation of the process in tight formations become even more complicated
because obtaining commercial production/injection rates is a serious concern in such reservoirs.
|File Size||2 MB||Number of Pages||17|