High Permeability Zones Research Articles

The Role of Silica Nanofluid as a Plugging Agent for Enhanced Oil Recovery – Experimental Approach

Many enhanced oil recovery techniques have been adopted in oil production to recover as much oil as possible. However, enhanced oil recovery techniques are complex and costly. Therefore, nanofluids have been modified in the laboratory to be consistent with reservoir fluids and rocks while also being environmentally benign. This study aims to investigate the role of silica nanofluid in plugging the high permeable zones after oil is recovered from the reservoir to divert pressure to the low permeable zone for enhanced oil production from the low permeable zones. A digital gas permeameter (DGP-300-B) was used to determine the permeability of the core by injecting nitrogen gas. In addition, a DHP-100-M Digital Helium Porosimeter was used to determine bulk volume, grain volume, and grain density porosity. The experiment was conducted with different percentages of silicon dioxide nanoparticles to observe the effect of plugging in each stage. Results show that a 52% reduction in core permeability was observed when using 0.5wt.% of silica nanoparticles, a 72% reduction in core permeability when using 1wt.% of silica nanoparticles and a 94% reduction in core permeability when using 2wt.% of silica nanoparticles.

Field-scale numerical investigation of a hybrid gas production method from the oceanic hydrate accumulation at site NGHP-02-09 in the Krishna-Godavari Basin, and the associated geomechanical responses

The objectives of this study are to investigate (a) the technical feasibility of gas production from a gas hydrate accumulation at Site NGHP-02-09 in the Krishna-Godavari Basin, India Ocean using a hybrid production method involving a combination of depressurization and thermal stimulation, as well as (b) the associated geomechanical system response when considering both a simplified and a full geomechanical model. This is an extension of the earlier numerical study of Moridis et al. (2019a) of the site using cylindrical (single-well) 2D systems, which indicated (a) the main source of the produced gas to be CH4 dissolved in the water rather than CH4 from hydrate dissociation because of the presence of a high-permeability water-bearing zone that short-circuits the depressurization process and (b) the possibility of adverse geomechanical issues caused by significant displacements that could not be adequately investigated and resolved by the one-way coupling scheme invoked in that study. The proposed hybrid production plan involves two vertical wells in a 3D Cartesian domain: an injection well of warm ocean (saline) water and a production well at an appropriate distance, with the expectation that the hydrate dissociation caused by the depressurization at the production well can be augmented by the thermal effect of the injected warm water (as well as by its salinity), thus mitigating the effects of the high-permeability water zone. The results of this study that uses high-resolution 3D grids indicate that (a) the hybrid production scheme does not appear to offer any advantage over the simple single-well depressurization method of the earlier study, (b) the majority of the produced gas originates from CH4 exsolution from the water rather from hydrate dissociation, and (c) consideration of full geomechanics leads to generally slightly higher dissociation and fluid production because of the evolution of lower porosities and permeabilities, but also to the disappearance of the gas phase after 62 days of production, after which time CH4 from hydrate dissociation is fully dissolved in the water before production. Thus, the hybrid scheme investigated here appears ineffectual in enhancing hydrate dissociation and gas production, and the hydrate deposits at the Site NGHP-02-09 do not appear to be a promising production target under the conditions in this study, in agreement with the earlier conclusion of Moridis et al. (2019a).

A sustainable chitin nanocrystal-stabilised emulsions to enhance the conformance control in porous media

The presence of high permeability zones causes the injected fluid/gas to bypass the low permeability pores, initiating an early breakthrough. One of the most influential and promising methods to control fluid bypass is fluid diversion using an emulsion/chemical agent placed at the highly permeable zone, which eventually diverts the injected fluids to a less permeable region. Chitin Nanocrystal (ChiNCs), a naturally abundant nanomaterial with high oil-water interfacial adsorption, has attracted significant interest as an emulsion stabiliser in various applications. Unlike traditional surfactants, ChiNCs offer a sustainable alternative by stabilising the emulsion, providing long-term stability and enhanced viscoelasticity. This study presents a novel, eco-friendly solution by exploring ChiNCs as pickering emulsions stabilisers for conformance control in porous media. The ChiNCs were prepared through acid hydrolysis of chitin powder derived from crab shells. ChiNCs and their emulsions were analysed using Transmission Electron Microscopy (TEM), Dynamic Light Scattering (DLS), Zeta (ζ)-Potential, Cross-Polarised Microscopy (CPM), and rheometer. The presence of ChiNCs in the emulsion resulted in shear-thinning behaviour, making it suitable for conformance control. Core-flood experiment results confirmed the effectiveness of ChiNCs-stabilised emulsions for permeability reduction. Pressure drops and permeability reductions increased with larger emulsion slug sizes, indicating successful pore plugging and improved fluid diversion. The highest-permeability reduction with 85.6% were obtained with 0.7 pore volume (PV) of emulsion injection for a short time. In contrast, injecting 0.5 PV of the emulsion led to a significant and sustained permeability reduction of 80.8%. To the best of the authors' knowledge, this is the first application of chitin nanocrystals in fluid diversion and conformance control. The ζ-potential over +20 mV within the pH range 3–6 was sufficient to achieve the highest colloidal stability via electrostatic effect and good ChiNCs suspension transparency. The microstructure observed under the CPM correlates with the rheological behaviour, showing that the ChiNCs provide a significant steric barrier to coalescence, thus enhancing the emulsion's resistance to flow and deformation.

Investigation of the permeability build-up method in the bottom-hole zone of the pay zone

In oil wells, the bottomhole formation zone is subjected to various influences during drilling, development and operation. The porous medium of the bottomhole zone is clogged by heavy components of the produced products and rock particles, reducing permeability and production. Various technologies are used to restore bottomhole permeability. A new method has been developed, including injection of a composition containing aqueous sodium bicarbonate solution with the addition of a chemical reagent, light oil and an acid solution into the formation. The essence of the acid treatment new method of heterogeneous terrigenous formations is that high permeable zones are blocked by a foam system, and injection of acid solution activates low-permeable zones. The new method developed in laboratory conditions was tested in field conditions. The test results showed that the set objectives were achieved.

Development of a drought-resilient water supply from dolomitized limestones of the Irish Midlands

A hydrogeological investigation is presented that focused on the development of a drought-resilient groundwater supply for a town (Carlow) in the Irish Midlands. The combination of thick overlying glacial deposits and Carboniferous limestones of low primary permeability posed a challenge to identifying a groundwater source. The source exploration strategy comprised surface geophysics and follow-on pilot well drilling to identify zones of high (secondary) permeability in bedrock. The study identified a previously unrecorded large ( c . 3.5 km long) and deep infilled karst feature that possibly extends 2 km further to a nearby area of known Neogene-aged karst infill. Separately, the investigation revealed new areas of dolomitized limestone, suitable for water supply development, where two production wells were constructed. A programme of pumping tests showed that dolomitized limestone areas exhibited low-nitrate groundwater quality, relatively high transmissivity and sustained recharge boundaries (leakage from a nearby riverbed). Analysis of data from the operational stage provided further insights into recharge behaviour, and showed that groundwater levels are resilient during droughts at current abstraction rates. The analysis concluded that the wellfield could sustain higher abstraction volumes, even through extended periods of low effective rainfall. Thematic collection: This article is part of the Climate change and resilience in Engineering Geology and Hydrogeology collection available at: https://www.lyellcollection.org/topic/collections/climate-change-and-resilience-in-engineering-geology-and-hydrogeology

Control mechanism of trichloroethylene back diffusion by microstructure in a low permeability zone

The trailing effect caused by the back diffusion (BD) of contaminants in low-permeability zones (LPZs), which prolongs remediation time and increases remediation costs, has caused widespread concern. In this study, the BD of trichloroethylene (TCE) from the LPZ to the high-permeability zone (HPZ) was determined using flow cell experiments. The anomalous variance in the BD flux of the TCE—spanning 2–4 times the deviation under identical experimental conditions, attracted our attention. To determine the cause of this aberrant behavior, a micro computed tomography (micro-CT) characterization of the flow cell was conducted, which revealed significant microstructural disparities in the LPZ. The study found that the pore connectivity of LPZs determines the efficiency of BD and that LPZs with different porosities have different sensitivities to connectivity. The pore shape complexity indicates the possibility of BD retardation, and remediation is more difficult for these types of LPZs. Changing the structure of LPZs to improve their remediation efficiency may be a new research topic. Notably, correcting the model parameters through microstructural characterization significantly refined the prediction accuracy.

Assessment of engineering geology and grouting applications in Yalnızardıç Dam Site (Antalya, Türkiye)

The Yalnızardıç roller compacted concrete (RCC) dam, constructed in 2015, is located in the Mediterranean region of Turkey, intended for electric power production. It is approximately 303 m long and 92 m in height. In this paper, it is aimed to determine the performance of the grouting method, conducted to control the water seepage and improve the foundation of the Yalnızardıç dam. The engineering properties of the site were introduced by geological mapping, drilling, and laboratory tests. The seepage of the foundation was determined by the in-situ Lugeon test method, also referred to as a water pressure test, which is estimate the mean hydraulic conductivity of rock mass. As a result of the tests, high-permeable and permeable zones were determined in the dam axis area. To make a barrier layer for these permeable zones, grout curtains were built in the left abutment, thalweg and right abutment with two lines of grouting holes which is proposed according to the Lugeon test and rock quality designation (RQD) results. Consolidation grouts were built to increase the density of the soil which makes the strength of the dam's foundation. After the groutings, check boreholes were drilled and water pressure tests were performed to control the seepage along the foundation and dam site. The results indicated that average Lugeon (LU) values reduced, and the values were within the recommended limit. The process shows considerable accuracy in evaluating grouting efficiency.

Identification of high-permeability and water-rich zones in a fractured karst water source area based on the hydraulic tomography method

Determining the spatial hydraulic parameters of aquifers is of paramount importance for the development and utilization of groundwater in water source areas. However, most methods are unable to accurately characterize the heterogeneity of aquifers because of the influences of complex geology, hydrogeology, structure and insufficient information. Hydraulic tomography (HT) is an effective and robust method for hydraulic parameter inversion to characterize heterogeneity. In this study, a two-dimensional HT model was established to simulate hydraulic parameter fields for a fractured karst aquifer in the Zhangji water source area (Xuzhou city, China). Steady-state hydraulic tomography (SSHT) and transient hydraulic tomography (THT) with different prior information conditions were applied to determine the high-permeability area and water-rich zones, and to infer possible locations of karst conduits and strong runoff paths in the water source area. The results indicate that: (1) THT can better reveal larger-scale heterogeneous characteristics of hydraulic properties compared to SSHT. The hydraulic conductivity distribution estimated by THT correlates well with the geological conditions of the area, especially in identifying water-rich zones formed by faults and other formations. (2) When combined with geological conditions, HT possesses the ability to identify strong runoff paths in fractured karst aquifers. (3) Accurate prior information, which is more relevant to the head response information, is conducive to obtaining more acceptable HT results. (4) THT can simultaneously identify high-permeability and high-storage zones, and the analysis of the overlap of these two regions has the potential to predict underground water reservoirs, which is of the utmost importance for the development and utilization of groundwater resources in water source areas.

A History Matching Study for the FluidFlower Benchmark Project

In this study, we conduct a comprehensive history matching study for the FluidFlower benchmark model. This benchmark was prepared and organized by the University of Bergen, the University of Stuttgart, and Massachusetts Institute of Technology, for promoting understanding of the complex physics of geological carbon storage (GCS) through in-house experiments and numerical simulations. This paper synthesizes the experiences of history matching the benchmark data encountered by the Delft-DARTS and CSIRO participants. History matching is first performed based on a low-dimensional-zonated structured model using a simple Poisson-like solver. The permeability of six facies and two faults is inferred in this stage to match the digitized concentration data. The history matching is then further enhanced to richer spatial and physical models to capture the spatial variation of permeability and buoyancy effects, using an unstructured grid. Efficient adjoint methods are used to evaluate the gradient used in the optimization of data misfits or equivalent Bayesian log-likelihoods. With efficient optimization methods available for both maximum a posteriori model inference and Randomized Maximum Likelihood methods for model uncertainty, we perform history matching using both binary and continuous concentration observations. The results show that the tracer plumes in the enriched model match the experimental plumes more accurately compared with the results from the parsimonious-zonated model. The history matching results based on the concentration observations provide more similar plume shapes compared with the case based on the binary observations. The permeability difference between the model before and after history matching reveals that the tracer plume zone and the high permeable zone are the regions of high sensitivity in terms of data misfit between the model response and observations. Surprisingly, CO2\\documentclass[12pt]{minimal} \\usepackage{amsmath} \\usepackage{wasysym} \\usepackage{amsfonts} \\usepackage{amssymb} \\usepackage{amsbsy} \\usepackage{mathrsfs} \\usepackage{upgreek} \\setlength{\\oddsidemargin}{-69pt} \\begin{document}$$_2$$\\end{document} concentration plume forecasts based on these history-matched models were not especially sensitive to the improvements observed in the enhanced model.

Facilitated transport of toluene and naphthalene with humic acid in high- and low-permeability systems: Role of ionic strength and cationic type

The occurrence of colloids on pollutants transport in groundwater has attracted more attention. However, the research on the regulation mechanism of colloids on combined pollutants transport in heterogeneous aquifers is limited. In this study, a series of tank experiments were conducted to systematically investigate the effects of ionic strength, and cation type on humic acid (HA) facilitated transport of toluene (TOL), and naphthalene (NAP) in high- and low-permeability systems. The results showed that HA facilitated pollutants transport in low Na+ solution. In Ca2+ solution, the presence of HA hindered pollutants transport, and the inhibition increased with the increase of ionic strength. Both in Na+ solution and low Ca2+ solution, the influence of heterogeneous structure on pollutant transport played a dominant role, and TOL and NAP had a greater transport potential in the high permeability zone (HPZ) due to the preferential flow. Whereas, deposition of HA aggregates, and electrostatic attractive interaction had negative effects on transport than groundwater flow in high Ca2+ solution. Pollutants were prone to accumulate at the bottom of the HPZ, and the top of the low permeability zone (LPZ). These new findings provide insights into the mechanism of colloids influence on the pollutants transport in heterogenous aquifer.

Experimental simulation study on influencing factors of liquid production capacity in heterogeneous water drive reservoirs

Oilfield development involves a complex, dynamic flow process of oil and water, with reservoir characteristics and environmental conditions continually evolving as the field evolves. Particularly when a waterflooding reservoir reaches a stage of ultra-high water cut, prolonged waterflooding intensifies challenges in reservoir development: the exacerbation of reservoir heterogeneity and development behaviors disrupts the initial understanding of the reservoir's liquid production capacity from current development conditions. Thus, it becomes imperative to adjust the productivity prediction methods for oil wells in heterogeneous waterflooding reservoirs. Leveraging the flow simulation of reservoir micro channel networks, and integrating features such as the geometric characteristics of the reservoir percolation field, micro channel characteristics, interlayer differences of mixed layers, degree of plane heterogeneity, production pressure differentials, and fluid properties, a visual sand filling experimental model is established that adheres to specific similarity criteria. Using this sand filling experimental model, we simulate the percolation characteristics of oil–water two-phase flow during the waterflooding process, and uncover the diverse influencing factors and their varying degrees of impact on the oil-phase flow during this waterflooding phase. Qualitative and semi-quantitative percolation simulation experiments are employed to intuitively demonstrate the interlayer interference, degree of plane heterogeneity, and oil–water distribution in heterogeneous reservoirs, which influence the change in oil well productivity during waterflooding. This lays bare the microscopic percolation mechanisms behind the productivity changes in heterogeneous waterflooding reservoirs. The simulation experiment results show that the higher the permeability, the stronger the micro-heterogeneity, and the smaller the overall mobility increase after flooding, the smaller the JLDmax obtained by testing or calculation. At the same permeability, the greater the driving pressure difference, the greater the microscopic sweep coefficient within the pore network, and the greater the mobility increase after flooding, the greater the JLDmax. There is interlayer interference in commingled mining, and the higher the permeability of the high-permeability layer (the greater the interlayer difference), the higher the initial productivity of the commingled well. However, due to the high permeability layer being prone to flooding, resulting in ineffective water circulation, the low-permeability tube is difficult to completely flood, resulting in a small increase in overall mobility, and therefore, JLDmax is small. Water drive preferentially breaks through the high permeability zone on the plane, and the shape of the water drive sweep zone is controlled by the planar permeability gradient, the width of the high permeability zone, and the displacement pressure difference.

Flow and plugging behavior of foams in fractures of fractured reservoirs

The development of fractured reservoirs can benefit from the use of foams, as they can enter fractures to increase the flow resistance of high-permeability zones, thereby redirecting fluid flow toward low-permeability zones. This can reduce the leak-off of working fluids during flow and improve the reservoir stimulation efficiency. The fracture visualization models applicable to micro-scale foam flow are developed to fully reveal the flow and plugging behavior of foams in micro-fractures. The models are accompanied by the implementation of the micro-fracture foam flow experiments. The experiment results show that with the increasing flow rate and foaming agent concentration, foams become smaller, more homogeneous, stable, and capable of plugging micro-fractures. However, both significantly large and small gas-liquid ratios degrade these properties of foams. For optimal results, a gas/liquid flow rate of 100–150 μL/min, a gas-liquid ratio of 2–4, and a foaming agent concentration of higher than 0.75 wt% are recommended. During foam flow, foams preferably enter wider fractures, where they accumulate and become trapped, plugging the flow channels. This results in a diversion of the subsequent foams towards narrower fractures, leading to more effective plugging of the fractures.

Geological conditions and controls on accumulation of tight sandstone gas, deep part of the Shengbei sub-sag, Turpan-Hami basin, NW China

With the further exploration of the Jurassic strata in the Turpan-Hami Basin, the targets for hydrocarbon exploration have been gradually shifted from the tectonic belts around sags to the proximal lithological zones of deep sags. Based on the systematic coring of the first exploration well (well Qintan-1) in the center Shengbei sub-sag, this study conducted experiments of organic carbon, pyrolysis, gas chromatography (GC), nuclear magnetic resonance (NMR), and low-temperature nitrogen adsorption. Then, this study systematically analyzed the geological conditions and major controlling factors for the accumulation of tight sandstone gas in the deep part of the Shengbei sub-sag. The results show that: (1) Multiple sets of coal-measure source rocks have developed in the Jurassic strata in the center Shengbei sub-sag, providing plenty of gas sources for multilayered hydrocarbon accumulation; (2) Tight sandstones have poor physical properties and complex pore structures. However, high-permeability zones and anomalous zones of nano-scale pores have developed in the deep part, providing favorable spaces for the accumulation and preservation of tight oil and gas in the deep part; (3) Compaction and late carbonate cementation are key factors in reservoir densification. The microscopic storage space and connectivity of the tight sandstone reservoirs in the Shengbei sub-sag were improved due to the dissolution of fluids in coal measure strata. The occurrence of high-quality reservoirs in the Shengbei sub-sag is significantly controlled by source rocks, and both the former and the latter are characterized by adjacent sources and reservoirs and short-distance migration and accumulation. Furthermore, the special geological phenomena of chert cementation, abnormally high homogenization temperatures of fluid inclusions, and abnormal pyrolysis parameters confirm the presence of low-temperature hydrothermal activity in the deep part of the target strata. Therefore, the center Shengbei sub-sag has geological conditions for the large-scale accumulation of primary gas and, thus, is a key area for future hydrocarbon exploration.

Detailed numerical evaluation of diffusion convection equation in layered reservoirs during tracer injection

Characterization of heterogeneous reservoirs such as multilayered or fractured systems is an important issue in different disciplines such as hydrology, petroleum and geothermal systems. One of the popular methods that can be used for this purpose is tracer tests. Better understanding of the mechanisms of mass transfer (convection–diffusion process) is essential for having a proper test interpretation. In this study, the solutions of different scenarios of tracer flow in a pair of high and low-permeable layered reservoirs including convection and diffusion mechanisms are discussed. Although analytical solutions generally provided exact solutions, they involve several assumptions and might be hard to use for complex problems. As a result, numerical methods are selected for the investigation of different scenarios and addressing cases that are beyond access of analytical methods. In this study, several scenarios of considering diffusion and convection in low and high permeable zones and effective parameters on tracer concentration are investigated. According to the results of this study, the higher the porosity ratio of low to high permeable layer, the more time is needed to get the final concentration value. Also, by increasing the value of the dispersivity coefficient, the time needed to increase the concentration decreases. In other words, the sharp increase in concentration for lower times is seen in higher dispersivity values. The concentration profile variation is affected by Peclet number. The difference among concentration profiles in different cases is considerable, especially in low Peclet numbers where the diffusion mechanism is dominant. This behavior is more common in low permeable mediums such as multilayered tight or shale reservoirs.

The Using of Unconventional Method depending on Well Power in the Mishrif Formation to Release Differential Stuck Pipe, Nahr Umr Oil Field, Southern Iraq

One of the main drilling problems is differential stuck pipe that lead to excessive non-productive time. The drill string usually stuck in the filter cake in permeable formations because it becomes immobile as a result of the drill string movement to connect a new pipe, make a trip, handle a drilling issue, etc. because there is a high permeability zone and a pressure difference between formation and filtering. So, without first releasing it by mechanical or chemical processes, the driller is unable to reciprocate or rotate it. Nahr Umr oil field was selected to study the problem of differential stuck pipe occurred while tripping out in the Hartha Formation and procedure steps to formulate the appropriate method to release the stuck string. Used unconventional method to free stuck pipe depend on well power in the Mishrif Formation after the conventional method failed to treat the problem. Then, the results were discussed with estimating stuck pipe depth and the force needed to release the string and comparison between the methods relative to the time and cost. Also, the result can be concluded that the appropriate mud weight is 1.27gm/cc. On the other hand, it was concluded that the unconventional method cheaper than the conventional method but it can be used if the formations contain oil or salt water only.

Characterization of silicification and dissolution zones by integrating borehole image logs and core samples: a case study of a well from the Brazilian pre-salt

Precise knowledge of the spatial distribution patterns of non-matrix porosity zones and the establishment of the geological factors controlling their evolution are crucial for building more accurate carbonate reservoir models and improving hydrocarbon production. The occurrence of intervals affected by significant carbonate dissolution may result in drilling fluid loss and time-consuming drawbacks during well construction. Vug or cave-rich reservoirs may exhibit excess permeability and extremely high initial flow rates. Similar situations have been reported in exploration activities in the Brazilian pre-salt plays, where evidence of dissolution and other burial diagenetic processes, such as severe silicification and dolomitization, are common. In this study, we investigate evidence of major post-depositional changes in the lacustrine carbonate reservoirs of the Barra Velha Formation, which comprises the most prolific hydrocarbon play in Brazil. Using a comprehensive database consisting of both core samples and well-log data from a vertical well in the Santos Basin, we have characterized, at multiple scales, reservoir zones affected by silicification and carbonate dissolution. In addition, we have performed a petrophysical evaluation of the reservoir to understand the impact of such processes on porosity and permeability development. The results suggested an intimate relationship between silicification and dissolution processes, which can be associated with late fluid percolation under a deep burial flow regime. The occurrence of silicified and vuggy beds, associated with specific zones and lithofacies, indicates an important degree of stratigraphic control on fluid percolation and lateral migration. Furthermore, the presence of fractures at discrete stratigraphic levels has preferentially influenced the development of high-permeability zones, including metric-scale fracture-related conduits. This study contributes to the general knowledge of carbonate reservoirs affected by silicification and dissolution while providing support for the recognition of such processes in partially- or non-cored wells.

Fluid seepage mechanism and permeability prediction model of multi-seam interbed coal measures

The successful development of coal measure gas (CMG) in the Surat Basin in Australia shows that the geological conditions of thin-interbed CMG development may be more favorable, but the above understanding is still in the geological law summary level. This study combines numerical simulation and physical simulation experiments to study the core geological problems of CMG in the geological control of the permeability of a multi-thin coal seam composite reservoir (MTCCR). The results show that in the initial stage of stress loading, the permeability advantage of the coal-mudstone/sandstone composite reservoir is reflected in the bedding permeability. Based on this phenomenon, the concept of “cross-layer seepage effect of fluid in MTCCR” is proposed for the first time, which is analyzed as the result of the permeation effect of adjacent rock fluids in the composite reservoir under the action of pressure difference. The numerical simulation shows that the permeability increase of the MTCCR depends on the increase in the fracture, and the coupling effect of the fracture and pore changes the fluid pressure field and seepage mode around the fracture. From the experimental perspective, the above understanding confirms the results of previous conclusions on the geological law of high permeability of MTCCR, and explains the geological phenomenon of high permeability of MTCCR from the seepage mechanism. Based on numerical and physical simulation experiment, a sedimentation-tectonics controlled permeability prediction model was constructed. The seepage mechanism and the permeability prediction model established of MTCCR in this study can provide theoretical support and quantitative basis for the selection of high permeability zones and evaluation of high permeability sections in the exploration and development process of thin interbed CMG.

On the dissolution paths and formation mechanisms of paleokarst reservoirs: Constraints from reactive transport modeling

Paleokarst is widespread in ancient carbonate rocks and is often related to hydrocarbon reservoirs, but the physico-chemical mechanism of forming such paleokarst reservoir remains poorly understood due to the complexity of meteoric water–rock interactions and a lack of geological research methods other than petrological analysis. Here, we implement the reactive transport modeling approach and reconstruct the dynamic evolution of the fluid–mineral–porosity system during paleokarst processes. In an eogenetic karst system, the early dissolution path is dominated by relatively uniform and diffuse dissolution in intergranular pores. The dissolution path then gradually transitions to preferential dissolution in local high-permeability zones, resulting in spongy dissolution. This is interpreted as the result of a combination of a heterogeneous initial pore distribution and the positive feedback between increasing flow and increasing dissolution. A higher degree of porosity heterogeneity and the presence of penecontemporaneous microfractures could facilitate the formation of preferential flow and spongy karst systems. Comparative simulations of eogenetic and telogenetic karst systems show different dissolution paths, formation mechanisms and distributions of hydrocarbon reservoirs, i.e., intergranular pore-dominated eogenetic karst with high mobility and high reactivity characteristics versus tectonic fault/fracture-dominated telogenetic karst with high mobility and low reactivity characteristics. The results provide a better general understanding of the water–rock interactions in meteoric diagenetic environments, and they indicate that hydrocarbon exploration should concentrate on carbonate shoals/mounds in the structural slope break zones associated with syngenetic faults, paleo-uplifts/highlands, and platform margins to identify high-quality eogenetic karst reservoirs and on tectonic fault/fracture systems and the lower parts of the high-permeability layers connected by these faults/fractures to identify high-quality telogenetic karst reservoirs.

Investigation of Geological Structure Using Magnetotelluric and Gravity Data Optimization on Non Volcanic Geothermal, Bora, Centre of Sulawesi

The existence of geological structures is one of the important parameters in determining the permeability zone in a geothermal system. This research was conducted in a non-volcanic geothermal field, Bora, located in the province of Central Sulawesi, aiming to identify the subsurface features, especially geological structures related to permeability zones by optimizing geophysical data. Magnetotelluric (MT) 3D inversion modelling is some of the latest methods to identify geological structural patterns in geothermal systems. The results of the MT model and analysis its parameters can find variations in the distribution of subsurface resistivity, orientation of the direction of the prospect area, and indications of geological structure zones. The type and geometry of the geological structure associated with the high permeability zone can be complemented by determining the contrast of gravity values ​​and analysis of the maximum First Horizontal Derivative (FHD) and zero of the Second Vertical Derivative (SVD). Based on the analysis of geophysical data, it is possible to identify the permeability zone associated with the main structure, namely the Palu-Koro fault, delineate the geothermal reservoir at a depth of 1500-2000 meters and determine the location of well drilling. To visualize the geothermal system comprehensively, a conceptual model is developed by integrating the geophysical model with geological and geochemical data that are correlated with each other, therefore it can assist in determining the location of production well development.

An amphiphilic nano calcium carbonate: Preparation, emulsification, interface properties, and displacement mechanism in low permeability reservoir

More extensive attention has been directed toward amphiphilic nanomaterials in the field of chemical enhanced oil recovery owing to they have the same excellent properties as surfactants. In this work, an amphiphilic nano calcium carbonate(ANCC) was prepared by chemical one-pot synthesis of NCC and alkyl acid. ANCC had a lipophilic property, which can make the oil and water were completely emulsified at the concentration of 500 ppm to form W/O emulsion with a particle size of 0.2–2.6 µm. ANCC had best dispersion effect at the solution of 0.1% Tween80. In the oil-water phase, ANCC can be adsorbed on the oil-water interface to reduce interface tension, and increase interface strength, and improve emulsion stability. The lipophilic slide can be changed from lipophilic to hydrophilic when immersed in the nanofluid. Using TW-ANCC (0.1% of Tween80 +500 ppm of ANCC) as the oil displacement fluid, which improved oil recovery by 23.3% in the single core displacement experiment and by 36.9% in the flat panel visualization experiment with comparing primary water flooding. The oil displacement mechanism of TW-ANCC was obtained by the etched glass micromodel experiment and the nuclear magnetic resonance experiment, the result shown that TW-ANCC can enhance oil recovery by reducing interface tension, changing rock wettability, reducing flow in high permeability zone, and expanding sweep volume in low permeability zones.