Third EAGE Geochemistry Workshop

Wells generally face barium, strontium and calcium sulphates (BaSO4/SrSO4/CaSO4) scaling due to incompatibility of formation water and seawater injected in the reservoir. Barium sulphate deposit was expected in this field due to the high level of barium in the formation water. Scale mitigation is achieved using conventional treatments such as continuous scale inhibitor injection or batch scale inhibitor squeeze treatment; another non-chemical and environmental preventive mitigation is the injection of low sulphate seawater (LWSW). This study showed that the increasing level of heterogeneity (layering permeability contrast), size of aquifer and high initial barium concentration in the formation water, delay the optimal relaxation timing from desulphated seawater to full seawater injection. Sulphate level in the desulphated seawater, the existing of horizontal flow barriers and slow barium sulphate reaction rate, have marginal impact on the optimal relaxation timing from desulphated seawater to full seawater injection. Gradual build-up in the sulphate concentration allows earlier relaxation behavior, with lower degree of risks compared to the direct switch to full seawater injection.

Carbon capture and storage (CCS) is a viable approach to mitigate atmospheric CO2 emissions in relation to fossil fuel combustion. Mineralization of carbon dioxide in basaltic rock offers a permanent and stable entrapment of CO2, which has potential applications in various places worldwide. Reactive transport modeling is an essential tool for improving our understanding of basalt-water-CO2 interaction, plan and optimize existing and new storage sites. One of the main challenges in modeling reactive transport of CO2 in basalt is the large number of primary and secondary reactions and in the uncertainties associated with the input parameters. In this study, we introduce an uncertainty quantification approach that integrates a flow simulator, PHREEQC, with genetic optimization tools and Morris method for sensitivity analysis. Experimental data from the literature for basalt-water-CO2 interaction in a high-pressure column flow reactor is used to demonstrate the proposed approach.

Production Allocation by geochemical fingerprinting is widely used to quantify relative proportions of liquid hydrocarbons produced from distinct reservoir layers, wells or fields. In some Middle East gas/condensate fields liquid phases are often characterised by only limited compositional differences, and hence, endmember identification can be challenging. This study proposes the use of Multivariate Curve Resolution Alternating Least Square (MCR-ALS) to identify unknown endmembers and to allocate the relative endmembers proportions in commingled fluids. A benchmarking of five distinct analytical techniques (NIR, SimDist, GC2D-MS, GC-FID, LC-UV) interpreted by MCR was performed to assess the MCR accuracy on condensate mixtures artificially prepared. The results show that GC2D-MS and GC-FID coupled with MCR were able to correctly identify unknown endmembers within the tested condensate samples. The quantification of the endmember proportions in artificial mixtures (commingled liquid phase) by MCR without prior endmember selection showed an accuracy of ±3%.

In this presentation we will review a workflow for the evaluation of high-quality fluid samples, incorporating geochemistry measurements and integration with other fluids data for a comprehensive fluid characterization. Case studies will be discussed to illustrate the utility of geochemical data acquisition during reservoir appraisal and development to support Field Development Planning.

The aim of this study was to investigate usefulness and applicability of sapropel- and clay-containing soil conditioners for bioremediation of polluted soils with the further target to develop new sustainable soil improving products.

A giant offshore oil field in Middle East is characterized by significant vertical and lateral heterogeneity in hydrocarbon compositions (API gravities ranging from 16 to 38 °API). To better understand the fluid properties distribution in the field, we have developed a fluid mapping approach based on reservoir cutting extract analyses. We have used liquid-chromatography analyses (GPC-UV: Gel Permeation Chromatography – UV detector) to characterise the reservoir fluids extracted from cuttings and we have established a relationship between the GPC-UV signals and some produced oil properties such as the API gravity. This new approach can be used for a continuous logging of dead oil properties along the several kilometres long horizontal well transects. Using our reservoir fluid mapping approach, we aim to better understand the processes responsible for these compositional variations in the field.