Vulnerability mapping of karst springs and its application for the delineation of protection zones (Mecsek Karst, Hungary)

Over the past decade or two, vulnerability mapping become a useful tool to determine the sensitivity of karst aquifers and allows the analysis of karstic aquifers affected by human activities. The Tettye Catchment, one of the eight catchments of the Mecsek Karst aquifer (SW Hungary), supplies drinking water for Pécs, the fifth most populous city in Hungary. However, due to its partly urbanized character and heterogeneous karstic features, this catchment is highly sensitive to anthropogenic impacts. In this study we aimed to generate resource vulnerability maps and risk maps to assess the role of physical and anthropogenic factors on groundwater vulnerability in the Mecsek Karst. Two formerly validated methods were used, the COP (Concentration, Overlaying layers and Precipitation) and SA (Slovene Approach) methods. The resource vulnerability maps, validated by former tracer tests, were combined with the hazard map obtained from the COST action 620 and EU Water Directive to generate risk maps. Tracer-based transit times were commonly less than 20 days in the majority of the areas of extreme vulnerability. During the current study, a new protocol has been elaborated for the delineation of the protection zones of karstic aquifers. Comparing the two methods, the SA performed better in terms of intrinsic vulnerability mapping, as it had a higher spatial resolution and was more detailed than the COP map and had a more sophisticated vulnerability indexing. In addition, high spatial correlation was revealed between the transit time maps and the SA map. Reassessed risk zonation, with appropriate legal consequences, likely minimizes undesired human activities within the zone of protection, hence maintaining water quality that complies with the protection acts

Thermal EOR Conformance – A New Frontier for Asset Optimization: Steam Shutoff Pilot in Oman

Over the last 50 years, thermal EOR has been an effective method for reducing the viscosity of and recovering heavy oil from deep reservoirs. In mature thermal EOR projects, conformance is one of the main challenges for maximizing reserves and meeting long-term production expectations. In this paper, Occidental presents a novel pilot to address thermal conformance in the Mukhaizna field in Oman. This is a thermal EOR operation in deep reservoirs (> 2,000 ft) with extremely high viscosity (>10,000 cp) in harsh desert conditions with temperatures exceeding 500°F. The pilot area is a mature thermal area with 15 years of continuous steamflood operations. The novel conformance technique, based on a combination of chemical and zonal mechanical isolation systems, was developed in-house in a low oil price environment. The pilot area consists of multiple reservoir zones that have undergone vertical steam injection since 2005. Thermal conformance has emerged as a challenge because more than 60% of the injected steam has been preferentially entering the high-permeability zones, with only 40% of the steam entering the other zones, which hold a larger amount the remaining oil. The subsurface and well engineering teams collaborated to design a rigless operation using dual coiled tubing units, one for cooling water and one pumping a chemical gelation recipe that gels at a certain trigger gelation temperature at the target zone. Zonal isolation of the reservoir is achieved using a novel inflatable packer triggered mechanically by ball gravitation through coiled tubing at 500°F and retrieved after the temporary zonal isolation. The well and reservoir surveillance included gathering data for injectivity assessment, vertical injection logging, temperature profiles, tracer tests in offset producers, and well testing for determining water cut. The pilot improved vertical conformance, as injection logging showed 40% steam reduction was achieved in the target zone, and more steam was re-allocated to the shallow zones. In addition, there was a water cut reduction of more than 20% in offset producers, and oil production tripled over a period of 3 months, which paid back the cost of the pilot and generated positive cash flow. To our knowledge, based on an SPE literature search, this is the first successful thermal conformance operation conducted with the following combination of technologies: 1) Placing a novel chemical recipe through temporary zonal isolation with an inflatable packer, and 2) Using rigless operation of coiled tubing units at harsh conditions of >500°F and high pressure >1000 psi. The outcomes open a new frontier for thermal EOR development in multi-stack reservoirs, offering better utilization of steam injection and improving mobility control over the field life cycle. The cost of the pilot project was paid off in the first 6 weeks, and all chemicals used were developed in an eco-friendly system.

Evaluating Efficiency of Surfactant-Polymer Flooding with Single Well Chemical Tracer Tests at Kholmogorskoye Field

EOR technologies in general and surfactant-polymer flooding (SP) in particular is considered as a tertiary method for redevelopment of mature oil fields in Western Siberia, with potential to increase oil recovery to 60-70% OOIP. The selection of effective surfactant blend and a polymer for SP flooding a complex and multi-stage process. The selected SP compositions were tested at Kholmogorskoye oilfield in September-December 2020. Two single well tests with partitioning chemical tracers (SWCTT) and the injectivity test were performed. The surfactant and the polymer for chemical EOR were selecting during laboratory studies. Thermal stability, phase behavior, interfacial tension and rheology of SP formulation were investigated, then a prospective chemical design was developed. Filtration experiments were carried out for optimization of slugs and concentrations. Then SWCTT was used to evaluated residual oil saturation after water flooding and after implementation of chemical EOR in the near wellbore areas. The difference between the obtained values is a measure of the efficiency of surfactant-polymer flooding. Pandemic restriction shifted SWCTT to the period when temperature dropped below zero and suitable for winter conditions equipment was required. Two SWCTT were conducted with same surfactant, but different design of slugs in order to prove technical and economic models of SP-flooding. Long-term polymer injectivity was accessed at the third well. Oil saturation of sandstone reservoir after the injection of a surfactant-polymer solution was reduced about 10% points which is around one third of the residual oil after water flooding. Results were compared with other available data such as well logging, lab core flooding experiments, and hydrodynamic simulation. Modeling of SWCTT is ongoing, current interpretation confirms the increase the oil recovery factor after SP-flooding up to 20-25%, which is a promising result. Temperature model of the bottom hole zone was created and verified. The model predicts that temperature of those zones essentially below that average in the reservoir, which is important for interpretation of tracer test and surfactant efficiency. The tested surfactant showed an acceptable efficiency at under-optimum conditions, which is favorable for application of the SP formulation for neighboring field and layers with different reservoir temperatures, but similar water composition. In general, the results of the conducted field tests correlate with the results of the core experiments for the selected surfactant

Estimation of the mass transport parameters of aquifers according to data from field tests with a pulse or a continuous source and an arbitrary location of the observation well

An identification method for determining the aquifer’s mass transport parameters is proposed, based on data from field tracer tests with a pulse or a continuous source and an arbitrary position of the observation well in respect to the tracer entry point. The method is also applicable in the presence of a representative set of data on changes in the concentration of pollutants at different points in the aquifer around a short-term (instantaneous) or a continuous surface or underground source. The identification procedure is based on the automated comparison of the observations data with a series of theoretical curves by varying the required parameters in order to achieve maximum compliance. The tracer transport is represented by analytical solutions of the partial differential equation for mass transfer in a homogeneous and isotropic two-dimensional porous media. The developed computer programs include numerical optimization using the Levenberg-Marquardt algorithm. Results from tests performed in order to assess reliability and errors of detection and identification are presented. Using the programs, the mass transport parameters: active porosity n0, effective (sorption) porosity nS, longitudinal dispersivity αL, transverse dispersivity αT and rate constant γ can be determined.

Delineation of discrete conduit networks in karst aquifers via combined analysis of tracer tests and geophysical data

Assessment of the karst network geometry based on field data is an important challenge in the accurate modeling of karst aquifers. In this study, we propose an integrated approach for the identification of effective three-dimensional (3D) discrete karst conduit networks conditioned on tracer tests and geophysical data. The procedure is threefold: i) tracer breakthrough curves (BTCs) are processed via a regularized inversion procedure to determine the minimum number of distinct tracer flow paths between injection and monitoring points, ii) available surface-based geophysical data and borehole-logging measurements are aggregated into a 3D proxy model of aquifer hydraulic properties, and iii) single or multiple tracer flow paths are identified through the application of an alternative shortest path (SP) algorithm to the 3D proxy model. The capability of the proposed approach to adequately capture the geometrical structure of actual karst conduit systems mainly depends on the sensitivity of geophysical signals to karst features, whereas the relative completeness of the identified conduit network depends on the number and spatial configuration of tracer tests. The applicability of the proposed approach is illustrated through a case study at the Hydrogeological Experimental Site (HES) in Poitiers, France.

The genesis and evolution of karstic conduit systems in the Chalk

The Upper Cretaceous Chalk Group is renowned as a major aquifer, but the development of secondary porosity due to karstic conduits is poorly understood. Hydrogeological data and evidence from boreholes, sections, and tracer tests indicate that dissolutional conduits occur throughout the Chalk aquifer. Here, we assess the evidence for Chalk karst, and combine it with theoretical models of dissolution and cave formation to produce a conceptual model for the development of karstic conduits. Dissolution due to the mixing of saturated waters of contrasting chemistry along key lithostratigraphical inception horizons form extensive but isolated conduit networks. These form a significant proportion of the secondary porosity and enhance permeability. They prime the aquifer for the development of more integrated conduit networks formed by focussed recharge of unsaturated surface derived water. However, the porous, well-fractured nature of the Chalk means that the time needed to form large integrated cave systems is often longer than timescales of landscape change. Continued landscape evolution and water table lowering halts conduit development before they can enlarge into cave systems except where geological and geomorphological settings are favourable. Groundwater models need to consider the formation of secondary karst permeability as this has a major influence on groundwater flow.

Tracer Dispersion through Karst Conduit: Assessment of Small-Scale Heterogeneity by Multi-Point Tracer Test and CFD Modeling

Tracer tests are widely used for characterizing hydrodynamics, from stream-scale to basin-wide scale. In karstic environments, the positioning of field fluorometers (or sampling) is mostly determined by the on-site configuration and setup difficulties. Most users are probably aware of the importance of this positioning for the relevance of data, and single-point tests are considered reliable. However, this importance is subjective to the user and the impact of positioning is not well quantified. This study aimed to quantify the spatial heterogeneity of tracer concentration through time in a karstic environment, and its impact on tracer test results and derived information on local hydrodynamics. Two approaches were considered: on-site tracing experiments in a karstic river, and Computational Fluid Dynamics (CFD) modeling of tracer dispersion through a discretized karst river channel. A comparison between on-site tracer breakthrough curves and CFD results was allowed by a thorough assessment of the river geometry. The results of on-site tracer tests showed significant heterogeneities of the breakthrough curve shape from fluorometers placed along a cross-section. CFD modeling of the tracer test through the associated discretized site geometry showed similar heterogeneity and was consistent with the positioning of on-site fluorometers, thus showing that geometry is a major contributor of the spatial heterogeneity of tracer concentration through time in karstic rivers.

Horizontal Versus Vertical Wells: Assessment of Sweep Efficiency in a Multi-Layered Reservoir Based on Consecutive Inter-Well Tracer Tests - A Comparison Between Water Injection and Polymer EOR

Enhanced Oil Recovery pilot testing aims at reducing uncertainty ranges for parameters and determining operating conditions which improve the economics of full-field deployment. In the 8.TH and 9.TH reservoirs of the Matzen field, different well configurations were tested, vertical versus horizontal injection and production wells. The use of vertical or horizontal wells depends on costs and reservoir performance which is challenging to assess. Water cut, polymer back-production and pressures are used to understand reservoir behaviour and incremental oil production, however, these data do not reveal insights about changes in reservoir connectivity owing to polymer injection. Here, we used consecutive tracer tests prior and during polymer injection as well as water composition to elucidate the impact of various well configurations on sweep efficiency improvements. The results show that vertical well configuration for polymer injection and production leads to substantial acceleration along flow paths but less swept volume. Polymer injection does not only change the flow paths as can be seen from the different allocation factors before and after polymer injection but also the connected flow paths as indicated by a change in the skewness of the breakthrough tracer curves. For horizontal wells, the data shows that in addition to acceleration, the connected pore volume after polymer injection is substantially increased. This indicates that the sweep efficiency is improved for horizontal well configurations after polymer injection. The methodology leads to a quantitative assessment of the reservoir effects using different well configurations. These effects depend on the reservoir architecture impacting the changes in sweep efficiency by polymer injection. Consecutive tracer tests are an important source of information to determine which well configuration to be used in full-field implementation of polymer Enhanced Oil Recovery.