Summary In-Situ Combustion. In-situ combustion (ISC) is an enhanced oil-recovery method. Enhanced oil recovery is broadly described as a group of techniques used to extract crude oil from the subsurface by the injection of substances not originally present in the reservoir with or without the introduction of extraneous energy (Lake 1996). During ISC, a combustion front is propagated through the reservoir by injected air. The heat generated results in higher temperatures leading to a reduction in oil viscosity and an increase of oil mobility. There are two types of ISC processes, dry and wet combustion. In the dry-combustion process, a large part of the heat generated is left unused downstream of the combustion front in the burned-out region. During the wet-injection process, water is co-injected with the air to recover some of the heat remaining behind the combustion zone. ISC is a very complex process. From a physical point of view, it is a problem coupling transport in porous media, chemistry, and thermodynamics. It has been studied for several decades, and the technique has been applied in the field since the 1950s. The complexity was not well understood earlier by ISC operators. This resulted in a high rate of project failures in the 1960s, and contributed to the misconception that ISC is a problem-prone process with low probability of success. However, ISC is an attractive oil-recovery process and capable of recovering a high percentage of oil-in-place, if the process is designed correctly and implemented in the right type of reservoir (Sarathi 1999). This paper investigates the effect of water on the reaction kinetics of a heavy oil by way of ramped temperature oxidation under various conditions. Reactions. Earlier studies about reaction kinetic were conducted by Bousaid and Ramey (1968), Weijdema (1968), Dabbous and Fulton (1974), and Thomas et al. (1979). In these experiments, temperature of a sample of crude oil and solid matrix was increased over time or kept constant. The produced gas was analyzed to determine the concentrations of outlet gases, such as carbon dioxide, carbon monoxide, and oxygen. This kind of studies shows two types of oxidation reactions, the Low-Temperature Oxidation (LTO) and the High-Temperature Oxidation (HTO) (Burger and Sahuquet 1973; Fassihi et al. 1984a; Mamora et al. 1993). In 1984, Fassihi et al. (1984b) presented an analytical method to obtain kinetics parameters. His method requires several assumptions.

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In order to enhance extra heavy oils and tar sands recovery, steam injection has become popular as it decreases bitumen viscosity via increase of formation temperature. However, such process comes with some drawbacks such as the necessity to dispose of substantial nearby quantity of water, the impossibility to 100% recycle this water, and the co-generation of a significant quantity of acid gases. Moreover the resulting hydrocarbons are still extra heavy oil/bitumen with all the constraints it implies in terms of pipe transport and refining. For these reasons, the development of the process of In-Situ Upgrading (IUP) by Subsurface Pyrolysis is debated. The idea would be to sufficiently heat the formation in order to pre-upgrade the oil in-situ; instead of just temporarily decreasing its viscosity. The process can be highly energy consuming but would offer multiple potential advantages such as production of a higher quality product with already a high commercial value, reduction of required infrastructure and expenses on production site for dilution or pre-upgrading before pipe transport, and no use of water, etc. This study presents the feasibility of such IUP process by performing a core experiment under reservoir conditions. First, a compositional kinetic model is developed in order to correctly predict the products composition during pyrolysis; which is then validated using laboratory data. This is a key element in an IUP process as the results of kinetic model gives an idea of better designing the core experiment, who can properly mimic reservoir behavior. The experimental results are promising in terms of upgraded oil production i.e. light cuts, acid gases, pyrobitumen with proper thermal front propagation. It showed that with time and temperature there will be production of large quantity of light components, light cuts, and while generated pyrobitumen will remain be in the core. This means that at constant temperature, sufficiently higher for pyrolysis; longer the duration of the experiment more will be the production of light cuts due to cracking of heavy components. These results provide key elements to extend the approach to a larger scale for field test application.

Summary The main technical contribution of the study presented in this paper was, by an integrated assessment of uncertainties in geophysics, geology and reservoir engineering, to provide a rational basis with risk analysis for the management of uncertainties in the development of the field and therefore better decision making. The objective of the study was to integrate the uncertainties identified on the Lambda Lower & Upper reservoirs and to quantify their impact on Gross Rock Volume (GRV), Oil Originally in Place (OOIP), recoverable reserves and produc-tion profiles. The work was carried out in five main steps:Determination of the distribution of the GRV.Building of a representative cloud of geological full field models (1000 equiprobable models) integrating geophysical, sedimentary and petrophysical uncer-tainties. Determination of the distribution of OOIP.Sorting and selection of a representative subset of reservoir models to quantify dynamic uncertainties.Modelisation by means of experimental design of the impact of dynamic uncertainties on the representative subset of geological models.Integration of static and dynamic uncertainties to assess statistical distributions of recoverable reserves, production profiles and plateau duration using experimental design technique coupled with multi-variable regression and Monte-Carlo simulations. The following results were obtained:probability distributions of GRVprobability distributions of OOIP for each reservoir (Lower & Upper) and for each zone of the Upper reservoirprobability distributions of recoverable reserves and production profilesprobability distribution of production plateau durationprobability estimation of different models, associated with quantiles 10, 50 and 90 of the OOIP and Np distributionsmeasure of the weight of the main uncertainties on the OOIP and reserves. Introduction Throughout the life of a hydrocarbon reservoir, from discovery to abandonment, a great number of decisions (which development with which recovery mechanism? the sizing for surface installations? …) depend on incomplete and uncertain information. Indeed, the only certain information comes from the cuttings and cores extracted from wells. This information represents only a tiny percentage of the rock volume involved and may itself be compromised by the way samples have been extracted. Any other knowledge of the reservoir comes from indirect measurements, either seismic surveys, logs or dynamic information gathered from well tests or production histories. Thus, because it comes from an interpretation process, any parameter that characterises the reservoir is uncertain. Finally, these uncertainties are case dependent (the reservoir and its heterogeneities, the production mechanism involved or even the type of surface installation…) and, for a given field, they depend on its stage of development (initial appraisal, initial development, complementary development). Therefore major uncertainties affect the decisions. Uncertainties in reservoir characterization The process that leads from the definition of structural maps to the estimation of reserves and production profiles for a given recovery mechanism and a given development scheme can be summed up in a few main stages:Definition of the reservoir envelope: maps and faults.Definition of contacts and nature of fluids.

In a previous paper [1], a geological/geostatistical methodology has been presented to model heterogeneity in a complex turbiditic formation. The methodology is based on geostatistical conditional simulation techniques that allow building 3D models of geological heterogeneity. The next step consists in translating such stochastic models of heterogeneity into models of flow properties for reservoir simulations. The present paper describes the approach that has been followed to achieve that goal. It includes two steps: a first one, to translate the fine grid geological models of heterogeneity generated in [1] into fine grid petrophysical models,a second one, to upscale the fine grid petrophysical models into coarser grids of effective flow parameters for full-field simulations. The procedure requires precise methods for averaging absolute and relative permeabilities. A new technique for averaging relative permeabilities and capillary pressures is presented. The procedure is validated by the available dynamical data (well tests and a 25 years production history). The integrated geological-geostatistical-upscaling strategy described in [1] and in the present paper is shown to be particularly useful to reservoir history matching and monitoring, as well as to evaluate uncertainties on reservoir performances in undrilled areas of the field.