EAGE Workshop on Petroleum Geochemistry in Operations and Production

Abu Dhabi Company for Onshore Petroleum Operations Ltd. embarked on a massive campaign, about three years ago, to evaluate Middle Cretaceous aged (Cenomanian) intra-shelf deposited Shilaif source rock widely and variably developed in its concession area. During this campaign, ADCO has acquired over 3000 feet of core and 150 SWC samples through the Formation. Thorough studies comprising Geochemistry, Petrophysics, Sedimentology and Geomechanics on these Core & SWC samples have been performed. The results revealed that the formation has significant hydrocarbon potential which is spatially and stratigraphically variably developed in the source rock and cleaner section facies of the formation. In addition, the geo mechanical properties also vary both spatially and stratigraphically. These variations in properties demands that the formation need to be tested at multiple locations to fully escalate its flow behavior. It is believed that testing at multiple locations would provide a confidence, full cycle play evaluation which would help in designing economically favorable development program, that the formation is proven interesting. This formation has better TOC contents and thickness than the USA tight formations under production.

Fundamentals of geochemical fingerprinting in the oil industry have been described by several authors and while detailed workflows vary between users the overall approach of combining gas chromatography with software supported interpretation remains common. The primary applications of geochemical fingerprinting include production back-allocation, support of wider reservoir continuity studies or time-lapse geochemistry. Our methodology is based on analysis of whole oil (black oil, gas condensate, heavy oil) or organic extracts from rock/sediment for the determination of ratios of heights of neighbouring chromatographic peaks.

This novel approach using geochemical fingerprinting in combination with a new data processing technology is presented through a selection of diverse case studies and demonstrates that it can be applied with confidence to even the most challenging production back-allocation and reservoir continuity cases. Numerous tests and calibrations with various oil companies have been carried out to improve the methodology and increase the overall accuracy, robustness and global applicability.

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This work was motivated for establishing a robust asphaltene flow assurance engineering in unique carbonate oil field where encountered a contradictory asphaltene precipitating risk distribution in which asphaltene onset pressure (AOP) could be detected from some locations but not from others. At first, a quick analysis was performed to solve this contradiction by applying a general engineering rule-of thumbs (based on compositional gradients and sampling horizons dependency); however, the effort could not succeed to provide appropriate understanding into the probable reasons of the AOP result variations. Then, more wide views were applied to our assessment through a multidisciplinary discussion taking participation from engineers to geoscientists. This made an effective synergy between them to seek a missing link to the contradictory AOP results. The engineer’s perspective focusing on the current fluid equilibrium was tied in the geoscientist’s perspective covering the geologic time of hydrocarbon migration. Consequently, the re-assessment succeeded in explaining of relationship in heterogeneous distributions of asphaltene precipitating risks and solid bitumen occurrence as two sides of the same coin. Because solid bitumen deposits were results of de-asphalting, consequently, higher asphaltene precipitating risks in liquid was considered identical to less solid bitumen deposition during hydrocarbon migration history.

Advanced wellsite analytical technologies for measuring inorganic elemental and mineral analysis of rock, hydrocarbon components, hydrocarbon isotopic components, and hydrocarbon pyrolysis are proving to be very useful when drilling and completing different type of wells. Experience in different wells have shown that these techniques can be used to assist in predicting rock properties, fluid type, delineating potential pay zones and compartmentalization for reservoir evaluation and further production stages based on rock and chemical properties.

A combination of technologies involves instruments for real-time fluid composition analysis using a high resolution hydrocarbon analysis (C1–C8) dissolved in the drilling fluid along with a high resolution Cavity Ring-Down Spectroscopy (CRDS) laser spectroscope for carbon isotopic analysis. Drill cuttings and core chips are also collected and evaluated on well site using X-ray fluorescence (XRF) for the elemental breakdown of the composition of the rock and X-ray diffraction (XRD), which provides the mineralogical composition of the rock. Pyrolysis analysis performed to evaluate residual oil content in source rock (S1), remaining hydrocarbon generation potential (S2) and thermal maturity (Tmax). Furthermore the Thermal Extraction gas chromatography (C9–C25) was performed at well site to evaluate hydrocarbon quality and elaborate fluid quality profile.

The Hith and Gotnia Formations comprising of alternating halite and anhydrite plus limestone intervals traditionally considered as regional seals for lower Jurassic hydrocarbon bearing reservoirs. Sharp contrast in lithology of halite-anhydrite and high pressure in interbedded limestone layers make this formation extremely challenging to drill and evaluate. Casing is set immediately after drilling, limiting open hole data acquisition. Due to complex lithology and low porosity, a comprehensive acquisition and interpretation methodology was required to further characterize and assess the potential of this formation. A single mass spectrometer combined with a dynamic oil base mud discriminator was used during drilling. The OBM isolates and quantifies formation fluids from drilling fluid and aids in better characterization of fluid in reservoir matrix.

Comparison of oil signatures in the three zones reveals a decrease in fluid density from top to bottom. The difference in fluid density for zones and sealing efficiency of the interbedded halite suggests that there is no direct fluid communication between the individual halite beds. The last anhydrite has signatures similar to the lower reservoirs.

Calibrating these findings with other wells and finally the entire region, will give a better understanding on the overpressure within the carbonates and its distribution.

Production decline prediction is important to understand the performance and life span of oil and gas wells. The most common prediction method is decline curve fitting based on available production rate data. However, the parameters are often poorly constrained, especially when the production rate data is limited. In this study, we establish a novel gas isotope interpretation tool to better predict the resource quantity and life span of producing gas wells. This tool is based on the evolution of methane (CH4) carbon isotope ratios due to different gas releasing processes during the production. We successfully applied the tool to a producing shale gas well in the Barnett Shale. We obtained real-time methane carbon isotope data for about a year using our proprietary, field-deployable natural gas isotope analyzer (NGIA). Our prediction in this well shows that the total reserve would reach 7.34–7.75 bcf. The production rate may decline to 200–225 Mcf/day by 30 yr, whereas the empirical Arps’ equation would predict a significantly high production rate for a longer period of time. The novel production decline prediction method thus provides the important constraint on the future well production and expected ultimate recoverable reserves (EUR).

In this presentation we will discuss the currently known studies in which both chlorine and bromine stable isotopes are analysed in formation waters from sedimentary basins. Although these two elements are chemically similar their isotopes show clearly different characteristics. We will discuss how the observed differences might be explained in these sedimentary basins and we will show how the use of Br isotopes in used in determining the origin of saline water in an Iranian gasfield. Further we will discuss how we will extend the research in further understanding of the processes that fractionate bromine isotopes in general and in sedimentary basins in particular.

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Concerning injection of CO2 into saline aquifers, it may induce formation of dry-out and precipitation of salt near the injection well, which may reduce formation porosity, permeability, and injectivity.

Here, we investigate experimentally the possibility that chlorine isotopes could be used as a geochemical tool to constrain the interplay of solute transport processes occuring during CO2 injection. δ37Cl is already used as a tracer of solute transport (especially diffusion) and salt precipitation so that it is likely to be useful to characterise their complex dynamics in porous media during evaporation.

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