A method has been developed for improving both steam injection and production conformance in a thermal EOR project by utilizing intelligent well technology incorporating interval control valves (ICV), well segmentation and associated downhole instrumentation. This provides the ability to selectively open and close segmented sections of the well bore and monitor the key parameters of temperature and pressure from surface. The initial field trial is ongoing in the injector of an Orion field SAGD well pair. Development of the completion system suitable for thermal conditions, initial field trial results and plans for further development are described. Modelling shows that, depending on the level of heterogeneity present in the reservoir, an improvement of 20 to 40% in the steam oil ratio and 5 to10 % in recovery can be achieved in a SAGD process when both improved injection conformance and producer differential steam trap control can be applied in a segmented horizontal well pair. A cost effective solution to achieve this segmentation and control has the potential to add substantial value to field developments through improved steam conformance resulting in increased energy efficiency and oil recovery. The method being developed is applicable to a wide range of EOR processes such as CSS, steam drive and variations. The initial field deployment in the injector well was primarily to prove operability of the system in high temperature thermal applications, to demonstrate the feasibility of modifying steam distribution and to learn for future optimization and deployment of the system. A successful installation and commissioning has substantially validated the completion technology. Early injection test results and data provide a significant improvement in the understanding of the injection and production behavior in the well pair. A test program to optimize the distribution of steam injection in the well is underway and the preliminary results are discussed. Lessons learned from the trial are highlighted. The intelligent completion technology under trial, and proposed further developments, should enable more extensive use of downhole measurement and control in thermal EOR projects to improve performance.

The problem of multiphase flows in chokes presents an interesting problem for steam injection and hydrocarbon production. In both cases it is important to evaluate the maximum possible mass fluxes through a perforation. Several models are used in the oil industry for this purpose, e.g., Ashford (1974) [1], Sachdeva et al. (1984) [2], and Perkins (1993) [3]. This paper explains physical principles behind these theories, and outlines their range of applicability. The task of the study is to choose a model that would provide the most general and accurate description of a multiphase flow that can be used for implementation in a reservoir simulator. It is concluded, that existing models are very restricted. They are applicable to particular cases, where the phase transition between the liquid and gas phases is absent. A rigorous description of a multiphase flow with a phase transition does not seem feasible. The possibility of a phase transition introduces a large uncertainty in the flow parameters. This uncertainty essentially exceeds differences between predictions of existing approaches. For this reason, it is sufficiently to analyze flows within the framework of the simplest theory. Such a theory is presented in this report. We derive simple relations to estimate critical flow parameters and transported fluxes. These relations provide a relatively simple evaluation of steam injection and hydrocarbon production without significant loss of accuracy. Preliminary simulation results to illustrate the flow of a wet steam (i.e., two-phase fluid) through the choke are also discussed. Introduction In most heavy oil recovery scheme's, steam is injected into the reservoir to lower the viscosity of the oil, thereby increasing its productivity. Key is the distribution of steam in the reservoir and its optimal use to mobilize as much oil as possible (high Oil-Steam ratios). Efficient steam distribution control in standard completions passing through the multi-sand (i.e., high permeability contrast) reservoir is extremely difficult. Higher-permeability sands usually act as a thief zones with respect to the tighter sands open in the same wellbore. This results in poor injection profile due to the appearance of preferential steam paths. Consequently, many sands cannot be effectively steamed and produced. In order to provide and to control the uniform steam flow distribution from the wellbore to the reservoir, the steam flow rate should depend not on the downstream (reservoir) but on upstream pressure alone. This condition is satisfied if the flow rate through a perforation reaches its maximum value (i.e., steam velocity equals the sonic velocity), which is the critical flow condition. This means that, providing the flow is critical, as long as the pressure in the wellbore is uniform and diameters of the perforations along the well are constant, the steam flow from the wellbore to the reservoir is uniform. Thus, no portion of the reservoir can behave as a thief zone. Limited entry perforations (LEPs) are a completion technology that is used to improve steam injection uniformity along the length of the well [4]. This technique originates from the "pin-point" method, which was commonly utilized in the late 60's as the well completion technique used for hydraulic fracturing [5, 6]. The marked improvement in steam profile control led to the extensive application of LEP technique as injection completion scheme in HVO recovery process. Therefore, description of sub-critical and critical flows, and calculation of maximal allowed flow rates present essential interest for oil industry. Knowledge of these flows is necessary for a proper planning of oil production as well as of (wet) steam and water injection. This paper presents an assessment of the existing multiphase flow theories and derives simple relationships to estimate critical flow parameters and transported fluxes without significant loss of accuracy. It also presents preliminary simulation results of the flow of a wet steam through the LEP perforation.

This paper presents an assessment of the performance of a horizontal well, completed by limited-entry perforation (LEP) technique, based on reservoir and well simulation of a typical HVO reservoir, e.g., Peace River field and theoretical calculations. The issues that are primarily covered in the LEP simulation work address the comparison of horizontal LEP injector with conventionally perforated liner for a generic reservoir; the role of the sand-screen in LEP design during HVO production and the analysis of the pressure drops through the LEP hardware. Modelling of the injection scenario with LEP's has shown that in high permeability contrast reservoirs at critical flow conditions, perforations located in zones with permeability variation between 10,000 and 1,000 mD, have the same maximum injection rate. If the wells from Peace River perform similar to the Imperial D-36 HWCSS LEP wells from Cold Lake, then the expected gross production performance that these wells will have under LEP conditions will be around 16 m3/day per perforation. These results are in line with the production performance observed in pad D-36 and also in line with our simulations. The calculations performed here do not take into account any skin damage effects that potentially could occur when LEP's are applied in the field. Calculated total pressure drops across the LEP hardware have shown that the liquid flow is limited by the ability of the reservoir to deliver the necessary amount of fluid to the LEP. The simulation results show that for a steam injection flow rate of 42 m3/day per perforation the expected net oil production rate of the LEP with a sand-screen in Peace River reservoir is around 4.8 m3/day/perf. Overall it can be concluded that injection through LEP's is feasible and production through LEP's in their current configuration is possible if the formation properties are similar to Cold Lake. Potential adverse impact of skin damage under Peace River conditions could invalidate our conclusions; this should be confirmed by the testing of LEPs in the field. Introduction Studies show that heavy oil constitutes a strategic option for the industry to increase reserves by tapping into at least 12 trillion barrels of in-place heavy hydrocarbons worldwide. We target the present work to increase reserves and production from a typical heavy oil reservoir, e.g., Shell Canada's Peace River asset. Quantitatively it means the development and utilization of technology that can increase the recovery by relatively uniform deposition of large amounts of heat in a reservoir. One of such technologies is the limited-entry perforation (LEP) technique originated from the "pin-point" method, which was commonly utilized in the late 60's as a well completion technique used for hydraulic fracturing [1], [2], [3]. At that time "limited-entry" was a term for the practice of limiting the number of perforations in a completion interval to promote the simultaneous entry of hydraulic fracturing fluid into multiple reservoir zones with varying in-situ stresses. Few years later the LEP completion technique was introduced in steam-injection wells by Mobil Oil Corp. in 1975 [4]. Mobil Oil Corp. tested this technique in the Tulare formation D and E zone sands as a part of continuous-steam injection with vertical wells in the South Belridge field, Kern County, California. Shell introduced LEP completion design in a portion of the South Belridge field in September 1982 [5]. By Dec. 1984, the LEP technique was used in approximately 400 vertical steam-injection wells. Injection data from LEP wells was in close agreement with the theoretical design maximum rate per 0.25inch. (6.4 mm)-diameter hole of 63 b/d (10.0 m3/d) of steam. A standard completion design does not guarantee steam profile control when a wellbore passes through thick, higher permeability sands, layered with thin, lower-permeability sand shales, in between (i.e., so-called high permeability contrast reservoir). Efficient steam distribution control with such multi-sand completion wells is extremely difficult. Usually, higher-permeability sands will act as thief zones with respect to the thinner, tighter sands open in the same wellbore, thus, establishing preferential steam paths and resulting in poor injection profile. Consequently, many sands cannot be effectively steamed and produced.

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