This paper was prepared for presentation at the 1999 SPE Mid-Continent Operations Symposium held in Oklahoma City, Oklahoma, 28-31 March 1999.
Most of the oil characterization approaches for thermal recovery are designed for heavy oils at moderate temperatures where oil can be represented in very simplistic ways (i.e., 'gas' and 'oil'). However, when oil is exposed to very high steam temperatures (i.e. 550 • F ), and/or the oil is lighter than the classical range defined for heavy oils and is exposed to wide spectrum of thermal effects such as distillation of the lighter ends, the conventional methods representing the interaction of steam and the in-situ fluids is not accurate. In many cases, we have to first evaluate the quality of the data, and then represent the average behavior with a single most likely fluid model per reservoir segment (plus other scenarios, as needed) to simulate the production performance. There is a need to develop a streamlined approach to bring such data into industrial simulators in a practical way.In this study, we have developed a fit-for-purpose approach to generate a consistent PVT model over the whole reservoir, reflecting both pressure and temperature changes through the entire oil accumulation. The model represents the oil viscosity for wide spectrum of temperatures, from reservoir temperature to steam temperature (thermal process range). A systematic lumping scheme enables conversion of the characterized PVT model for numerical simulators with the minimal number of pseudo-components while still capturing the essence of thermal physics. To our knowledge, there has been no systematic study of this nature in the literature available yet.We have tested the above approach in the Belridge Diatomite steam drive project. The study confirmed that steam flood incremental oil production in light oil reservoir is sensitive to the component lumping scheme because of distillation of the lighter ends. We also found that a five component PVT model, representing the physics in 'fit-forpurpose' dynamic simulation, best compromises between minimal number of components and physical description of the light oil behavior.
Most of the oil-characterization approaches for thermal recovery are designed for heavy oils at moderate temperatures, in which oil can be represented in very simplistic ways (such as "gas" and "oil"). However, when oil is exposed to very high steam temperatures (i.e., 550 F), and/or the oil is lighter than the classical range defined for heavy oils and is exposed to a wide spectrum of thermal effects, such as distillation of the lighter ends, the conventional methods of representing the interaction of steam and the in-situ fluids are not accurate. In many cases, we have to first evaluate the quality of the data, and then represent the average behavior with a single most likely fluid model per reservoir segment (plus other scenarios, as needed) to simulate the production performance. There is a need to develop a streamlined approach to bring such data into industrial simulators in a practical way.In this study, we have developed a fit-for-purpose approach to generate a consistent pressure/volume/temperature (PVT) model over the whole reservoir, reflecting both pressure and temperature changes through the entire oil accumulation. The model represents the oil viscosity for a wide spectrum of temperatures, from reservoir temperature to steam temperature (thermal-process range). A systematic lumping scheme enables conversion of the characterized PVT model for numerical simulators with the minimal number of pseudocomponents while still capturing the essence of thermal physics. To our knowledge, there is no systematic study of this nature available in the literature.We have tested this approach in the Belridge diatomite steamdrive project. The study confirmed that steamflood incremental oil production in a light-oil reservoir is sensitive to the componentlumping scheme because of distillation of the lighter ends. We also found that a five-component PVT model, representing the physics in "fit-for-purpose" dynamic simulation, best compromises between minimal number of components and physical description of the light-oil behavior.
This paper describes the first known offshore application of distributed horizontal pulse testing. This technique appraises the deliverability of naturally fractured resource, using only a single penetration and Drill Stem Test (DST) string run. Central to the design is the ability to collect near real-time interference data at a known minimum length from a drawdown interval. The pulse test is distributed in that the signal and observation zones can be swapped on demand from surface, acoustically via sleeve. BP successfully applied this technique to two appraisal wells in their 2014 offshore drilling operations.The dual zone DST pulse testing method is a new approach to the appraisal of naturally fractured reservoirs. It was developed to create a real-time interference dataset outwith the active production interval, i.e. within a passive zone. The formation is produced (and rate data are measured) in two spatial locations and across two known length-scales (by swapping the active and passive zones prior to commingling). Pressure diffusivity can thus be calibrated to data measured in two spatial locations of the same reservoir, and not just one, as per a conventional test design, i.e. enabling a history match of the pressure response of two lateral zones from a pulse signal in one. The horizontal aspect is achieved via high-angle well, drilled sub-parallel to unit bedding (Figure 1).With the double staging approach (upper and lower zones), which has been developed for fractured reservoir appraisal studies, three tests were successfully performed in each appraisal well: two partial penetration tests on discrete short intervals (DST#1a, DST#1b), and one final test on a longer interval that included both of the short intervals (DST#1c). Results of this application have demonstrated that pressure diffusivity can be derived from pressure data that are measured simultaneously in two spatial locations, within and outwith an active production interval. This has proved particularly useful for reducing the degrees of freedom in reservoir model identification. The paper concludes that appraisal of naturally fractured reservoir might be sub-optimal in a DST design where drawdown and observation data are limited to a singular inflow zone only. This is the first known application in the industry where one DST run has successfully yielded six unique appraisal data types, gathered simultaneously at both intra/inter zone and commingled lengthscales. These data are conventionally not gathered in a single zone design, i.e. without the ability to selectively inflow and monitor pressure in each discrete lateral zone. Consequently this technique has significantly improved the description of both static and dynamic reservoir properties and reduced development uncertainty, all at a relatively low incremental cost.
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