Shiraz 2009 - 1st EAGE International Petroleum Conference and Exhibition

Gravity-Assisted Inert Gas Injection performance was investigated in heterogeneous packed model through a number of experiments for recovering waterflood residual oil. These heterogeneous media consisted of isolated regions of large pore-sizes, at the macroscopic scale, randomly distributed in small-size continuum. In such heterogeneous media the waterflood residual oil saturation is proportional to the volume fraction of heterogeneity. Experimental results of tertiary gravity drainage experiments have shown that the presence of large pore-size regions leads to the gas invading through such regions and thus improve the recovery of the large amount of residual oil.

Oil recovery from naturally fractured reservoirs is difficult. Especially in the Middle East where carbonate rocks are oil or mixed-wet. In these reservoirs typical production mechanisms like viscous displacement and counter current imbibition will not work. Gas–oil gravity drainage (GOGD) is then the production mechanism of choice. However, gravity drainage with immiscible (equilibrium) gas could result in low oil rates and/or low ultimate recovery due to capillary hold-up. Miscible gas injection could have significant advantages in a GOGD situation. Miscibility might be achieved with for instance CO2, which has typically a low minimum miscibility pressure. When the injected gas is (first contact) miscible with the oil, density and viscosity will be reduced. Miscibility adds the advantages of single-phase flow and interfacial tension reduction, which further improves GOGD rates and ultimate recovery. This paper evaluates the impact of first contact miscible gravity drainage on oil recovery and discusses the main modelling aspects. The key parameters were identified to be matrix block width over height ratio and vertical heterogeneity. First contact miscible gas injection benefits mainly from IFT reduction and has its application in heterogeneous reservoirs with large capillary hold up and re-imbibition effects.

Typically, conventional reservoir simulators underestimate the recovery factor of heavy oil reservoirs under solution gas drive. We hypothesize that natural surfactants in oil (e.g. asphaltenes) cause this phenomenon in two ways: 1) by hindering the mass transfer rate of gas molecules through the gas-oil interface and 2) by enhancing the solubility of gas in the heavy oil. We investigate effect of surfactants on mass transfer rate of gas through gas-water interface and on the solubility of gas in oil. In bulk experiments, we observe that the addition of sodium dodecyl sulfate (SDS) does not influence the gas transfer rate while in the presence of a porous medium the growth of gas bubbles becomes increasingly difficult with increasing SDS concentration, which indicates that the interaction of the grain with fluids is an essential element in bubble growth in porous media. The effect a non-ionic surfactant on the solubility of methane in n-dodecane is also examined. The bubble point pressures of the gas+oil+surfactant system are determined experimentally.It is found that the bubble point pressures of the system decrease with increasing surfactant concentration, i.e., the surfactant enhances the solubility of methane in the oil.

Abstract A comprehensive geochemical study and research on crude oil samples from different producing oil field in the Persian Gulf resulted in preparation of the first phase of Atlas of Iranian oils which is unique in its own kind. Detailed measurements on oil physical properties included determining of API gravity, viscosity, pour point, sulfur content, Ni/V and stable carbon isotope 13C. Complementary geochemical analyses such as SARA tests, Gas Chromatography and Gas Chromatography and Mass Spectrometry were carried out for the purpose of oil to oil correlation and in order to identify characteristic biomarkers of organic origin, depositional environment, thermal maturity and geologic age. Based on physical and chemical properties and characteristic geochemical fossils, three major petroleum systems with respective oil families were recognized in the Iranian offshore of the Persian Gulf. Most oils produced from Aboozar, Dorood, Foroozan (1 and 3) and Reshadat fields were sourced from Paleozoic petroleum system. Oils encountered in Nowrooz, Hendijan 3, Bahregansar 1and 2, Salman 2and 3 and Reshadat 2 fields are assigned to Jurassic petroleum system. Oils produced from fields including Hendijan 1and 2, Foroozan 2, Salman1, SirriA and C are sourced from Cretaceous petroleum system. Keywords: Petroleum system, Persian Gulf, Atlas of Iranian Oils

The southeastern Zagros is situated at the eastern tip of the Zagros system, close to the Makran accretionary prism and Oman Mountains. This orogenic system results from the ongoing collision between the Arabian and Central-Iran plates. In this context, the main features of the studied area are; (i) the existence of numerous emerged or buried salt diapirs, made up of Late Precambrian Hormuz salt moving since the early Paleozoic, and (ii) the irregular along-strike shape of the collision-related detachment folds, with frequent apparent bending, change in width and structural association with salt diapirs which express the control of deformation by the pre-existing salt structures.

Three magnetostratigraphic sections across the Pusht-e Kuh Arc in NW Zagros and Izeh Zone constrain the ages of syntectonic foreland deposits as well as the timing of folding. These sections are located in the front of the Pusht-e Kuh Arc in the Changuleh growth syncline, in the centre of the arc in the Afrineh growth syncline and in the hinterland along the footwall of the High Zagros Fault. The ages for folding onset are well constrained in Changuleh at 7.65 Ma and in Afrineh at 11.8 Ma. In Chaman Goli growth syncline the age of initial folding could be as old as 13.5 Ma that fits with even older ages (early Miocene) along the footwall of the Main Zagros Thrust. Folding propagated towards the foreland during at least 20 My, which implies an older age and a longer duration than previously assumed.

It is crucial for exploration in fold-and-thrust belts to get robust understanding of foreland basin evolution and deformation, in order to constrain the timing of hydrocarbon generation, migration and trap formation. Although it is widely accepted that the main phase of deformation in the Zagros belt occurred in the Miocene and Pliocene, recent field studies have demonstrated that folding started in the NW Zagros (Lurestan Province) as early as the Late Cretaceous and Paleocene. The objective of this work is to constrain the timing of the development and folding of the NW Zagros foreland basin, on the base of accurate dating of the Amiran, Taleh Zang and Kashkan syntectonic foreland formations at different places through Lurestan Province. A multidisciplinary approach has been used, combining benthic foraminifera biostratigraphy, calcareous nannoplankton biostratigraphy, palynostratigraphy and strontium isotope stratigraphy. Dating results show that the Amiran-Kashkan clastic wedge prograded south-eastward in the NW Zagros foreland basin between the late Cretaceous and the early Eocene. The dating of associated syn-depositional folding structures permits to establish that an early folding of the NW Zagros foreland basin progressed south-westward during the same period.

The description of folded/fractured reservoirs requires the understanding of mechanical behaviour of rocks during deformation. In folds, at the decametric scale, deformation is accommodated by flexural slip, faulting and formation of macroscopic fracture sets. The role of LPS has been recognized for years using magnetic fabric analysis which shows that in siliciclastic deposits the deformation is mainly accommodated by pretilting strain. This paper thus combines analyses of calcite twins, Anisotropy of Magnetic Susceptibility and Anisotropy of P-wave Velocity, together with petrological study to investigate the relationship between fold development and stress/strain. The results are compared to already available and newly collected mesoscale fracture and fault slip data. The Sheep Mountain anticline was chosen as a natural laboratory.Our results show a good agreement between calcite twinning and anisotropy of rocks properties, and with macroscopic fracturing on the other hand. Our study points toward a better description of deformation mechanisms of folded strata. A major result is the consistency of the record of deformation at microscopic and macroscopic scales, emphasizing that core scale data can be relevant to fold-scale structuring. This study yields important constraints for forthcoming modeling of stress distribution during fold development.

Folding in the south-eastern Lurestan Province was analysed by measuring anticline’s wavelength and axial-length and by comparing the fold distribution with the available paleofacies maps. It was found that the large variability of the measured parameters occurs in relation with facies changes within the Cretaceous Bangestan Group, which acts as the competent carbonate unit that governs buckling in this region. The Oligocene-Miocene Shahbazan-Asmari unit folds harmonically with the Bangestan Group, except in the areas where the Paleogene deposits interposed between the two units exceed 1300m of thickness. In these areas the Shahbazan-Asmari carbonate displays short wavelength folds that indicate a complete decoupling from the underlying folds of the Bangestan Group. It is suggested that this decoupling occurs because the summed thickness of the incompetent units separating the Shahbazan-Asmari from the Bangestan Group exceeds the extension of the effective zone of contact strain of the Bangestan Group folds.