Assessment of development methods for a heavy-oil sandstone reservoir

Abstract

The combination of growing energy demands, the declining performance of conventional oil fields and attractive oil prices have renewed interest in both Heavy Oil resources (HO) and the methods of exploiting them. The vast volume of these resources notwithstanding, their low reservoir-scale mobility precludes exploitation using traditional primary and secondary recovery techniques, making enhanced oil recovery (EOR) methods (both thermal and non-thermal) natural candidates. However, the influence of several factors, technical and non-technical, require that rigorous studies inform the choice of EOR method(s). HO is a thick, viscous, tar-like crude oil that does not pump easily or flow well. This presents huge challenges when estimating reserves and extracting them from the reservoir, as does pipeline transportation to refineries. Increasingly, focus is moving towards those technologies that can most efficiently recover and process HO. The challenge here is finding the best way to produce, transport and process the oil. In this study, the focus is on how to identify the best way to recover the HO medium from an unconsolidated sand stone reservoir; to achieve this aim the Lower Fars formation in Kuwait is used as an exemplary case to test our screening methodology and to discover the best strategies. At present, Kuwait is pursuing a national objective to produce 4 million barrels per day (b/d) of oil by the year 2020. However, this target can only be achieved sustainably with HO development. Although there is evidence in the Kuwait Oil Company’s (KOC) long-term plan that this is understood, there is not yet a clear-cut strategy for its realisation. Hence, the primary objective of this study is to establish possible development options for the medium heavy oil reservoirs. Other objectives include understanding the physics of selected thermal EOR processes in different medium heavy oil reservoirs and developing a robust screening tool for HO resources. Numerical modelling studies will be used to achieve these objectives. Given the huge number of EOR methods and their various combinations, it is not pragmatic to conduct detailed studies on each method for potential application to the reservoir. To accelerate decision-making, using experiences taken from field performances elsewhere, a relatively simple screening procedure has been developed and implemented. Using this tool, less favourable options have been eliminated, retaining only the ‘best’ options for further evaluation; these are unheated-water flooding, hot water flooding, Steam flooding (SF) and cyclic steam stimulation (CSS). For the preliminary numerical simulations, a homogenous, three-phase and multi-component numerical model was constructed using the known (average) geological, petrophysical and fluid properties of the Northern sector of the Ratqa field. Information from analogue fields and correlations was also used to complete the data. The reservoir was considered homogeneous in the first part of the study, allowing for the separation of process effects from reservoir geology. The second part of this study presents the results of the sensitivity study on a small scale model, extracted from a large field scale sector model of 0.9 Million cells. Several simulation runs were conducted to investigate the effects of petrophysical properties and operating variables on the performance of unheated-water flood, hot water flood, steam flood processes, and CSS. The simulation results show that any positive impacts from thermal injection on oil production are not instantaneous - they only become noticeable after an appreciable number of pore volumes have been injected. This finding is attributed to the time lag required to heat up the reservoir to a temperature that gives reasonable reduction of oil viscosity, creating a more favourable mobility ratio. In addition to giving a higher ultimate recovery rate, the preliminary results also indicate that high-temperature operation accelerates performance. From an economic viewpoint, production acceleration would improve overall project economics by mitigating the negative impact of discounting on the revenue stream. Another important finding from the simulation study is that while hot water flood is characterised by a stable displacement of oil by water, unstable fronts are evident in the cold-water process, resulting in a significant quantity of by-passed oil. When conducting the study it was also imperative to conduct a detailed economic analysis to assess the economic feasibility of each recovery process/case. To achieve this, a preliminary matrix of the main factors was integrated into the developed economic model. The input for project performance specified cumulative oil recovery (income) versus cumulative energy injected into the reservoir in terms of heated fluids (cost). Continuing the work to investigate the best development options for a major unconsolidated, shallow HO reservoir a comparative study and a sensitivity analysis of various operational conditions and reservoir parameters were conducted in order to: (1) find the best conditions to achieve a high RF, and (2) to understand the effect of reservoir heterogeneity on the reservoir’s performance. The operational parameters investigated are injected fluid type, injection swapping time and the perforation location. The reservoir parameters examined are oil viscosity, initial water saturation, porosity and permeability. In addition to studying these reservoir parameters, oil price sensitivity was investigated to evaluate the financial feasibility of the selected recovery methods within both the historical and forecasted oil price range.

The preliminary results show that the recovery factor (RF) is very sensitive to the oil viscosity value and the relationship between them is nonlinear. The simulation results also indicate that an increase in the porosity and permeability accelerates performance; however, the opposite is not true of the initial water saturation value. From an economic perspective, production acceleration would improve overall project economics by mitigating the negative impacts of discounting on the revenue stream due to the low oil price. Economically, successive (combination of injected fluids) cases support successful investment at the lowest (expected) oil price; in contrast, the continuous steam and hot water flooding development options show a higher economic risk after the second year.

This work contributes significantly towards our understanding of the performance of different development options in high permeability HO reservoirs. This is critical for the decision making process when determining the applicability of EOR recovery methods and their successful application in the field.