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Collaborating Authors
Results
A Physics-Based Method for Production Data Analysis of Tight and Shale Petroleum Reservoirs Using Succession of Pseudo-Steady States
Shahamat, M. S. (University of Calgary) | Mattar, L.. (IHS) | Aguilera, R.. (University of Calgary)
Abstract Analysis of production data from tight and shale reservoirs requires the use of complex models for which the inputs are rarely known. The same objectives can also be achieved by knowing only the overall (bulk) characteristics of the reservoir, with no need for all the detailed rarely known inputs. In this work, we introduce the concept of continuous succession of pseudo-steady states (SPSS) as a method to perform the analysis of production data. It requires very little input data yet is based on rigorous engineering concepts which works during the transient as well as the boundary dominated flow periods. This method consists of a combination of three simple and well-known equations: material balance, distance of investigation and boundary dominated flow. It is a form of a capacitance-resistance methodology (CRM) in which the material balance equation over the investigated region represents the capacitance, and the boundary dominated flow equation represents the resistance. The flow regime in the region of investigation (whose areal extent varies with time during transient flow) is assumed to be pseudo-steady state. This region is depleted at a rate controlled by the material balance equation. The initial flow rate and flowing pressure are used to define the resistance, and the distance of investigation defines the capacitance. The capacitance and resistance are then used in a stepwise procedure to calculate the depletion and the new rates or flowing pressures. The method was tested, for linear flow geometry, against analytical solutions for liquids and numerical simulations for gas reservoirs, exhibiting both transient and boundary dominated flow. Excellent agreement was obtained, thus corroborating the validity of the method developed in this paper. The proposed method is easy to implement in a spreadsheet application. It indicates that complex systems with complicated mathematical (e.g. Laplace space) solutions can be represented adequately using simple concepts. The approach offers a new insight into production analysis of tight and shale reservoirs, using familiar and easy-to-understand reservoir engineering principles.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.81)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.64)
New Models for Reserve Estimation and Non-Darcy Gas Flow in Shale Gas Reservoirs
Haghshenas, B.. (University of Calgary) | Clarkson, C. R. (University of Calgary) | Chen, S.. (University of Calgary)
Abstract Organic-rich shale gas reservoirs have various complexities related to the physics of gas storage and transport. Traditionally, the OGIP in shales has been calculated as the sum of the adsorbed gas and the free gas, using CBM reservoirs as an analog. However, as recently noted in the literature, the free gas volume must be corrected for presence of adsorbed gas, assuming all gas storage occurs in kerogen. Even with these corrections in place, shales are still complex reservoirs in terms of flow characteristics. The contribution of viscous, diffusive, and slip forces in nano-scale conduits cause the permeability calculated from Darcy's Law to be higher than the value for liquids. A new model is developed to address the effect of the adsorbed gas volume on the nanopore storage capacity. The relative fraction of adsorbed gas volume is treated as a sorbed-phase saturation. The initial free gas volume is then calculated by subtracting any non-free gas saturation from the effective void volume. We have extended this concept to a gas material balance equation through which the free gas volume is dynamically adjusted during depletion. The Simplified Local Density (SLD) adsorption model is used to evaluate sorbed-phase density and volume. To address the complexity in gas flow, permeability of the reservoir model is assumed to be a function of pressure in order to determine the impact of advection, slippage and diffusion mechanisms. The permeability is calculated via a multi-mechanism flow model. Finally, we utilized the dynamically-corrected permeability in parallel with dynamically-corrected porosity to simulate the primary recovery of a shale gas reservoir. The new models successfully describe the unique characteristics of shale reservoirs and correct the conventional methods for overestimation of reserves and underestimation of permeability. The format of the final material balance equation and flow model used here preserves the conventional reservoir engineering framework, but with some important modifications.
- North America > Canada (0.68)
- North America > United States > Texas (0.46)
- North America > United States > Alabama (0.28)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Michigan > Michigan Basin > Antrim Shale Formation (0.93)
Abstract Tight oil production is emerging as an important new source of energy supply and has reversed a decline in U.S. crude oil production and Western Canadian light oil production. At present, combination of the multistage hydraulic fracturing and horizontal wells has become a widely used technology in stimulating tight oil reservoirs. However, the ideal planar fractures used in the reservoir simulation are excessively simplified. Effects of some key fracture properties, such as facture geometry distributions and permeability change, are usually not taken into consideration during the simulation. Over simplified fractures in the reservoir model may fail to represent the complex fractures in reality, leading to significant errors in forecasting the reservoir performance. In this paper, we examined the different fracture geometry distributions and further discussed the effects of geometry distribution on well productions. All fracture geometry scenarios are confined by the microseismic mapping data. To make the result more reliable and relevant, a geo-model was first constructed for a tight oil block in Willesden Green oil field, AB, Canada. The simulation model was then generated based on the geo-model and history-matched. A horizontal well was drilled in the simulation model and different fracture geometry scenarios were analyzed. Results indicate that the simulation results of simple planar fractures overestimate the oil rate and lead to relatively higher oil recoveries. In addition, the effect of hydraulic fracture geometries under the higher fracture conductivity is more significant compared to those under lower fracture conductivity.
- North America > Canada > Alberta > Wetaskiwin County No. 10 (0.49)
- North America > Canada > Alberta > Ponoka County (0.49)
- North America > Canada > Alberta > Clearwater County (0.49)
- North America > Canada > Alberta > Lacombe County (0.35)
Production Data Analysis of Multi-Fractured Horizontal Wells Producing from Tight Oil Reservoirs โ Bounded Stimulated Reservoir Volume
Qanbari, F.. (University of Calgary) | Clarkson, C. R. (University of Calgary)
Abstract Multi-fractured horizontal wells (MFHWs) are the most widely used technology for producing tight oil and gas reservoirs. Production data from a MFHW may exhibit multiple linear flow periods including linear flow within the fracture, linear flow in the stimulated reservoir volume (SRV), and linear flow in the unstimulated region of the reservoir. This study focuses on an SRV containing infinite-conductivity hydraulic fractures and no fluid flow contribution from the unstimulated region. The existing analytical models for these flow periods have been developed based on the linearized form of the flow equation. However, these models introduce considerable errors in permeability estimation and production forecasts for tight oil reservoirs if they do not account for stress-sensitivity. In previous work by the authors, the stress-sensitivity of permeability was incorporated into rate transient analysis (RTA) of tight oil reservoirs during transient flow period for wells containing a single hydraulic fracture. In this paper, the effects of stress-dependent formation permeability on the production data of MFHWs are studied. A new model is used to correct the conventional RTA techniques for these effects to improve permeability estimation and oil production forecasting. This study shows that the conventional methods that do not account for stress sensitivity give less accurate results for MFHWs producing under a high pressure drawdown. The results show that the new method reduces the error of the conventional techniques significantly and provides a reliable strategy for RTA of MFHWs. This study fulfills two important requirements of the tools for RTA of MFHWs; simplicity and accuracy. The strategy is to keep the conventional analysis routine unchanged, with a correction factor applied to account for the effects of the stress-sensitivity of permeability. The value of the correction factor is that it shows how far the conventional analytical methods are from the exact solutions. Further, the correction factor is used to remove the considerable error in conventional analyses.
- North America > United States (1.00)
- North America > Canada > Alberta (0.47)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Production forecasting (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Evaluation of Recovery Performance of Miscible Displacement and WAG Process in Tight Oil Formations
Ghaderi, S. M. (University of Calgary) | Clarkson, C. R. (University of Calgary) | Chen, S.. (PennWest Exploration) | Kaviani, D.. (University of Calgary)
Abstract Recent advances in well design and production techniques have brought considerable attention to exploitation of tight (low permeability, absolute permeability <1 mD) oil resources. Drilling of long horizontal wells and deployment of hydraulic fractures along these wells (multi-fractured horizontal wells) can substantially improve the primary production rates from such reservoirs. Nevertheless, the low effective permeability of these reservoirs to oil hinders the sustainability of favorable oil rates and at some point applying some EOR technique becomes inevitable. In the current study, CO2 miscible flooding and WAG process in a tight oil reservoir are investigated. Although several studies have investigated different aspects of the process in conventional oil plays, the design of an effective scheme in tight oil formations is more complex. These complexities are related to the proper design of the fractures (half-length, conductivity, orientation (transverse vs. longitudinal), etc.) and their relative placement along producers and injectors and the operational constraints on each well or segment of the well. In this work, we utilize an EOR scheme design where multi-fractured horizontal wells are used for both injection and production, and the hydraulic fracturing stages are staggered to delay breakthrough and improve sweep efficiency. For a set of defined parameters, compositional simulations are conducted to investigate the effect of the CO2 slug size, WAG ratio and cycle length on the recovery efficiency of the model. The recovery from the aforementioned EOR process is then compared with its corresponding base case in which the reservoir has gone through periods of primary and water-flooding stages. The results of this study show that the incremental oil recovery from WAG process in tight formation can reach as high as 20%.
- North America > United States (0.94)
- North America > Canada > Alberta (0.30)
- Europe > Norway > Norwegian Sea (0.24)
Assessment of SAGD Well Configuration Optimization in Lloydminster Heavy Oil Reserve
Tavallali, M.. (University of Calgary) | Maini, B.. (University of Calgary) | Harding, T.. (University of Calgary) | Busahmin, B.. (Sait Polytechnic)
Abstract Large quantity of heavy oil resources are present in variety of complex thin reservoirs in Lloydminster area which are situated in east-central Alberta and west-central Saskatchewan. Primary depletion and waterflooding are the principal recovery techniques. Although these techniques work, the recovery factors remain low and large volumes of oil are left unrecovered when these methods have been exhausted. Because of the large quantities of sand production, many of these reservoirs end up with a network of wormholes that makes most of the displacement type enhanced oil recovery techniques inapplicable. Because of these high conductivity channels, only gravity drainage based techniques have a good chance of success. Among the applicable methods in Lloydminster area, SAGD has not received adequate attention, mostly due to the notion that heat loss in thin reservoirs would make the process uneconomical. While this may be true, the limiting reservoir thickness for SAGD under varying conditions has not been established. These reservoirs contain light oil with sufficient mobility. Therefore the communication between the SAGD well pairs is no longer a hurdle. This opens up the possibility of increasing the distance between the two wells and introducing elements of steamflooding into the process in order to compensate for the small thickness of the reservoir. The main objective of this study was to evaluate the effect of well configuration on SAGD performance and develop a methodology for enhancement of the SAGD performance through optimizing the well configurations for Lloydminster type of reservoir. A new well configuration was able to significantly improve the application of SAGD in thin reservoirs of Lloydminster. It provided high RF at reasonable cSOR. The effects of some common Lloydminster reservoir characteristics, which are problematic for the SAGD process (such as initial gas saturation, bottom water, and gas-cap) were investigated for the most promising well configuration.
- North America > Canada > Alberta (0.50)
- North America > Canada > Saskatchewan (0.35)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.47)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin > Pikes Peak Field > Waseca Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Provost Field (0.99)
- North America > United States > Montana > Western Canada Sedimentary Basin > Alberta Basin (0.91)
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