Summary This paper examines the oil composition distribution of a large deep-water field which the temperature variation, because of the water depth (800 to 2000 m), is in the opposite direction of the Earth's thermal gradient. The main practical objective is to investigate if the oil distribution would suggest fluid connectivity along this 40 km long and 15 km wide oil field. This could significantly impact the appraisal and development phases of the field. The methodology adopted here includes reservoir geochemistry, fitting of a single equation of state, compositional simulation, and thermodynamic equilibrium. The results from reservoir geochemistry indicate a common oil source, different migration pulses, a lateral migration path and some hydrocarbon mixing after filling process. A single equation of state is set to represent the oil behavior for the whole field. The successful matching is achieved by means of splitting the heaviest component and so reducing the molar concentration of the pseudocomponent on a single regression procedure. Compositional simulation runs, representing the secondary migration, suggest spots of gas caused by phase changes. During the filling process, the results show heavier oil in front of the upward flow. During the mixing process, the gravitational segregation seeks to reverse this trend. A new thermodynamic equilibrium model that accounts for the effect of temperature shows an increase of oil segregation with a temperature gradient opposite to the thermal's gradient. The results suggest thermodynamic equilibrium of oils in an area of the reservoir. This may suggest reservoir connectivity. In the area the oils are in thermodynamic equilibrium, fluid composition and properties are extrapolated to different depths while function of their respective temperatures. Introduction Many reservoirs around the world1–4 experience fluid composition variations. They may have a significant impact on fluid properties that lead to different exploration and development strategies. In light oils (API gravity greater than 35) an adequate knowledge of the oil composition distribution is particularly important to understand the oil formation volume factor variation and the development of miscibility. The former is critical in the calculation of the hydrocarbon volume in place. The latter is vital when considering gas injection. In heavy oils (API gravity smaller than 20), the compositional changes are important to estimate the viscosity variation that affects the waterflooding strategy (highly viscous oil near the oil water contact can be a serious handicap for down dip water injection). Many factors can cause the spatial distribution of the original reservoir fluid.5 These can be related in a simplified manner to the generation, migration, and alteration of hydrocarbon. The generation of hydrocarbon requires organic matter quality, quantity, preservation, and evolution. Organic matter quality relates to its source and original environment. They can be classified as (i) algae and bacteria in a marine environment leading to a light oil generation; (ii) bacteria and leaves in a mixed marine/continental environment leading to a black oil generation; and (iii) leaves and wood in a continental environment leading to a gas generation. Organic matter quantity relates to the rate of sediments deposited in the original basin. The accumulation is usually greater in the equatorial zones than that in the temperate and polar zones. Organic matter preservation depends on oxygen conditions of sedimentary layers. Aerobic bacterias in permeable layers cause a premature degradation of the organic matter. This alteration leads to the generation of biogenetic gas. Low permeable layers with anaerobic conditions (such as clays) tend to preserve organic matter. The evolution of the preserved organic matter comes with the burial of the sedimentary layers. The increase of pressure and temperature with time leads to chemical reactions that initially turn the preserved organic matter into a substance called kerogen. At temperatures ranging from 100 to 150°C kerogen generates oil, some gas, and an inert component, in a chemical process called metagenese. Further on, at temperatures ranging from 150 to 190°C gas is also generated in a chemical process called catagenese. At the final stage, the rock, which hosted the generation process, is then called source rock. In general, 1-10% of total organic carbon in the source rock is sufficient to generate a commercial hydrocarbon accumulation. The hydrocarbon migration can be divided in two parts: primary and secondary migration. The former applies to the hydrocarbon flow in the source rock. The latter refers to the hydrocarbon flow towards and within the reservoir. Internal pressures drive primary migration. They may appear because of the load of sediments, thermal expansion of water, and generation of light hydrocarbon. The achievement of a critical saturation (5 to 10%) allows the connection of previously separated hydrocarbon bubbles and causes the flow of a continuous phase in the source rock. The hydrocarbon can then flow through different pathways in the source rock such as oil-wet network, laminations of kerogen, and microfractures. The flow of hydrocarbon in separate phase from water is believed to be the major mechanism in primary migration. Other mechanisms such as diffusion and oil solubility would either affect only light hydrocarbons or require a great volume of water and gas (insufficient oil solubility). Polar compounds of hydrocarbon constituents can be adsorbed along the primary migration by rock mineral surfaces and organic matters. The trend of chemical changes is however discontinuous and nonsmooth. Most retained constituents are asphaltenes-resins, aromatics, and long chain hydrocarbon components. Most retainer rock minerals are sequentially carbonates, quartz, and clays.

A new computational model for the non-isothermal gravitational compositional equilibrium is developed and presented. The mathematical formulation is based on the works of Bedrikovetsky (gravityand temperature using irreversible thermodynamics) and Whitson (algorithm). The computational model is validated on published data and previous simplified models. An application case is presented for a reservoir in a large deep water fieldin Brazil. The magnitude of the calculated oil composition variations issufficient to explain most observed data. The results suggest that the reservoir is partially connected and that the temperature effect can be asimportant as the gravity effect on the oil composition variation. The changes are significant and the methodology applied is an example of the application of thermodynamic data to the evaluation of reservoir connectivity and fluid properties distribution under the conditions approaching those encountered in natural reservoirs. Introduction Compositional variations along the hydrocarbon column are observed in many reservoirs around the world. They may affect reservoir/fluid characteristics considerably, such asviscosity, total hydrocarbon volume in place and the development of miscibility, leading to different field development strategies. These variations are caused by many factors, such as gravity, temperaturegradient, rock heterogeneity, and hydrocarbon genesis and accumulation processes. In the cases where thermodynamic associated factors are dominant, the existent gravitational compositional equilibrium (GCE) models, which do not properly account for the temperature gradient effect, allow the explanation of most observed variations. However, it is noted that in some cases, the thermaleffect could have the same order of magnitude as the gravity effect. In this paper, a non-isothermal compositional gravitational model is developed and presented. The model is validated and applied to some fields inBrazil, among them a large deep water field. Statement of the Theory and Definitions The formulation for calculating compositional variation under the force ofgravity for an isothermal system is first given by Gibbs. (1) (2) (3) Where: P = pressure Z = fluid composition = chemical potential ref = reference i = component indices n = number of moles ln = natural logarithm g = gravitational acceleration T = temperature, M = mass h = depth EOS = equation of state R = real gases constant f = fugacity X = component concentration Muskat, in 1930, provides an exact solution to equation (1), assuming asimplified equation of state and ideal mixing. Because of the oversimplifiedassumptions, the results suggest that gravity has a negligible effect oncompositional variation in reservoir systems. In 1938, a more realistic EOS (3) is used by Sage & Lacey in order toevaluate equation (2). At this time, the results show significant composition variations with depth and greater ones for systems close to criticalconditions. Schulte, in 1980, solves equation (1) using a cubic equation of state (3).The results show significant compositional variation.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper reviews the twenty years of steam injection in heavy oil fields of Alto do Rodrigues area. The review includes the beginning, consolidation and expansion of this enhanced recovery method. Main topics involve project management of cycled injection and steam drive along with steady improvements on the quality control of the whole steam generation process. At the end, this work shows the positive impacts on the recovery factor and environmental issues.

Significant fluid compositional variations at discovery conditions areobserved and discussed for some hydrocarbon reservoirs around the world. These variations may considerably affect the reservoir fluid properties and lead to different exploration and development strategies. Mostly, they are associated with the thermodynamics (gravity, temperature), accumulation processes (genesis, migration) and reservoir characteristics(permeability, porosity, capillarity, geological structure). In this work, a synergetic approach is used to examine the effects of the above factors on the oil composition distribution of a large deep water field which the temperature variation, because of the water depth (800 to 2000m), is in the opposite direction of the Earth's thermal gradient. The methodology includes the use of EOS fitting, thermodynamics, reservoir geochemistry and compositional simulation. A single equation of state model, capable of accurately reproducing the wide range of experimental data, is adjusted to the PVT analyses. The successful matching is achieved by means of splitting the heaviest component and so reducing the molar concentration of the pseudo-component on the single regression procedure. A new compositional equilibrium model which accounts for the effect of gravity and temperature gradient is developed, presented and applied to evaluate the steady state thermodynamic equilibrium. The overall results suggest the partial reservoir connection and the increase of oil segregation with temperature decrease toward deeper waters. Fluid composition and properties are extrapolated to different depths as function of their respective temperatures. Reservoir geochemistry testing, such as computerized gas chromatography-mass spectrometry GC - MS, and analyses, such as the ratio of biological markers, are used for understanding the genesis and migration processes. The overall results indicate the same source rock (genesis), biodegradation, different migration pulses and a lateral migration path. Field scale compositional simulations examine the dynamic effects of the accumulation process (secondary migration, entrapment) on the oil composition changes. The results suggest that geological structures, permeability, porosity and capillarity can also play an important role on the oil compositional distribution and leave spots of undrained water in the reservoir. Introduction Original fluid composition variations along the hydrocarbon column have been observed in many reservoirs around the world. They may have a significant impact on the reservoir fluid properties, leading to different exploration and development planning. In light oils (API gravity >35), an adequate knowledge of the compositional variation is particularly important to understand the oil formation volume factor variation and the development of miscibility. The former is meaningful in the calculation of the hydrocarbon volume in place. The later is vital when considering gas injection. In heavier oils (API gravity < 35),), the compositional changes are important to estimate the viscosity variation which affects the waterflooding strategy to be applied (highly viscous oil near the oil/water contact can be a serious handicap for down dip water injection). The spatial distribution of the original reservoir fluid are believed to be caused by many factors, These can be categorized in an approximate manner as factors associated with the thermodynamics, reservoir characteristics, genesis and accumulation processes. The thermodynamic associated factors are those related to the local temperature, pressure, composition, elevation of the fluid system(gravitational force), interfacial curvatures of the surrounding porous medium(capillary force), geothermal, geological temperature gradients (causing thermally driven convection and steady state thermal diffusion) and molecular diffusion. P. 125^