Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Bedrikovetsky, Pavel
Development of Predictive Models in Support of Micro-Particle Injection in Naturally Fractured Reservoirs
You, Zhenjiang (School of Chemical Engineering, The University of Queensland) | Wang, Duo (School of Mechanical and Mining Engineering, The University of Queensland) | Di Vaira, Nathan (School of Mechanical and Mining Engineering, The University of Queensland) | Johnson, Raymond (School of Chemical Engineering, The University of Queensland The University of Queensland Centre for Natural Gas) | Bedrikovetsky, Pavel (Australian School of Petroleum, The University of Adelaide) | Leonardi, Christopher (School of Mechanical and Mining Engineering, The University of Queensland The University of Queensland Centre for Natural Gas)
Abstract New models for particle embedment during micro-particle injection into naturally fractured reservoirs are developed. The proposed models aim to predict production benefit from the application of micro-particle injection during coal seam gas (CSG) stimulation with broader applications to other naturally fractured reservoirs. The elastoplastic finite element modelling is applied to coal sample from Surat basin (Australia), to predict micro-particle embedment and fracture deformation under various packing densities and closure stresses. The coupled lattice Boltzmann-discrete element model (LBM-DEM) is then used for permeability prediction. These results are combined in a radial Darcy flow analytical solution to predict the productivity index of CSG wells. Modelling results indicate that considering elastoplastic fracture surface deformation leads to smaller permeability increase and less production enhancement, if compared with the linear elastic deformation of fracture implemented in traditional models. Although focused on Australian coals, the developed workflow is more broadly applicable in other unconventional resources. Modelling of particle transport and leak-off in coal fracture intersected with a cleat using LBM-DEM approach demonstrates the effects of particle and cleat sizes, particle concentration and sedimentation on the leak-off process. The leak-off is significantly affected if the particle-cleat size ratio is higher than 0.5. Particle sedimentation increases leak-off into vertical cleat substantially, but has no effect on horizontal cleat. Suspensions of higher concentration result in higher leak-off for cleats with different apertures.
- Geology > Geological Subdiscipline > Geomechanics (0.93)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (0.68)
- Oceania > Australia > Queensland > Surat Basin (0.99)
- Oceania > Australia > New South Wales > Surat Basin (0.99)
- Information Technology > Modeling & Simulation (0.83)
- Information Technology > Data Science > Data Mining (0.40)
Kaolinite Mobilisation in Unconsolidated Porous Media: Effect of Brine Salinity and Salt Type Na- and Ca Salts
Russell, Thomas (University of Adelaide) | Pham, Duy (University of Adelaide) | Petho, Genna (University of Adelaide) | Neishaboor, Mahdi Tavvakoli (University of Adelaide) | Badalyan, Alexander (University of Adelaide) | Behr, Aron (Wintershall Holding GmbH) | Genolet, Luis (Wintershall Holding GmbH) | Kowollik, Patrick (Wintershall Holding GmbH) | Zeinijahromi, Abbas (University of Adelaide) | Bedrikovetsky, Pavel (University of Adelaide)
Abstract Existence of clay particles in reservoir rock plays a major role in both oil recovery and formation damage. Clay mobilisation and consecutive formation damage have been observed during injection of low-salinity water in oil fields and laboratory coreflood experiments. Hence, this research aimed at understanding and quantifying the effect of clay type, clay content and composition of injected brine on clay mobilisation. In order to study the effect of clay content, several unconsolidated cores using kaolinite and sand are prepared. The clay content of each sample is controlled by mixing an accurately measured mass of kaolinite with sand. A new procedure is developed to assure: a uniform distribution of kaolinite along the core length, reproducible preparation of sand-clay mixture, identical compaction of the mixture in all experiments using axial and overburden stresses, and reproducible permeability data. Each core is initially saturated with high salinity brine (equivalent to sea water salinity) by creating a constant flow rate of 0.6 M solution through the core. The experiments continue with stepwise reduction of salinity of the injected solution (6 steps down to DI water). Around 150 PV of solutions is injected at each step until permeability stabilization. This indicates that no more kaolinite particles are mobilised. Differential pressure across the core is measured continuously and particle concentration and the conductivity of the effluent samples are also measured The kaolinite concentration, solution salinity and valency of ionic species (salt type) are found to be the controlling factors for clay mobilisation. The following correlations are established: relationships between initial kaolinite concentration and initial core permeability, initial kaolinite concentration and degree of permeability damage, and salt type and permeability damage due to salinity reduction. Experimental data show that a core with lower kaolinite content has higher undamaged/initial permeability. It is also observed that the lower is kaolinite content the higher is permeability damage during injection of low salinity water. Significant permeability decline during low-salinity corefloods is due to mobilization of the kaolinite particles and their capture in pore throats. The results also show that injection of solution containing divalent ions (Ca) stabilises the kaolinite particles and prevents their migration during low salinity brine injection.This study is novel in several aspects including: developing a new methodology for unconsolidated core preparation with desired clay content, studying the effect of clay content on initial permeability and severity of formation damage and studying the effect of divalent ions on clay behaviour during low salinity brine injection. The results of this study could be used to engineer the composition of injected water to minimise formation damage based on rock clay content.
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (2 more...)
Fines Migration as an EOR Method During Low Salinity Waterflooding
Al-Sarihi, Abdullah (ASP, University of Adelaide) | Zeinijahromi, Abbas (ASP, University of Adelaide) | Genolet, Luis (Wintershall Holding GmbH) | Behr, Aron (Wintershall Holding GmbH) | Kowollik, Patrick (Wintershall Holding GmbH) | Bedrikovetsky, Pavel (ASP, University of Adelaide)
Abstract This study presents a novel mechanism of enhancing oil recovery by fines migration during low salinity waterflooding. Formation damage is isolated from other low salinity mechanisms in the experimental tests performed in this work. Therefore, the reduction in residual oil saturation is attributed to fines migration mechanism only that is caused by improved microscale sweep efficiency via water flux diversion due to fine particles straining. Corefloods were performed on Berea cores with high clay content, Bentheimer cores with low clay content, and artificial clean sand cores with no clay to investigate the effect of clay presence on residual oil saturation. HSW and LSW took place after drainage displacements that resulted in the same initial conditions of connate water saturation and oil relative permeability. Non-polar oil is used to ensure water-wetness in the cores and to avoid possible wettability alteration by low salinity waterflooding. Single phase corefloods were also performed to study the effect of piecewise decreasing salinity on permeability. The results show a permeability decline with low salinity water injection in the single phase tests of clay-rich cores accompanied by fine particles production and pH increase. The same effect is observed in the two phase tests. In addition, incremental oil production is observed along with the permeability decrease and fines production. This is due to detachment of clay particles by weakened attraction as a result of LSW, which leads to fines migration and straining in water filled pores. Therefore, water flux diversion into trapped oil pores takes place, which displaces the residual oil in these pores. A relationship between formation damage, ฮฒฮฯ, and residual oil saturation has been introduced and it can be applied in reservoir simulation for LSW.
- Research Report > New Finding (0.49)
- Research Report > Experimental Study (0.34)
Fines-Migration-Assisted Waterflooding to Improve Sweep Efficiency Analytical Model
Borazjani, Sara (The University of Adelaide) | Behr, Aron (Wintershall Holding GmbH) | Genolet, Luis Carlos (Wintershall Holding GmbH) | Kowollik, Patrick (Wintershall Holding GmbH) | Zeinijahromi, Abbas (The University of Adelaide) | Bedrikovetsky, Pavel (The University of Adelaide)
Abstract We derive a general system of equations accounting for two-phase fines migration with fines mobilization by injected water with different salinity, rock plugging by the migrating fines and consequent permeability damage in the swept reservoir zones. The analytical model derived contains explicit formulae for water-saturation and ion-concentration fronts along with pressure drop and water-cut in production wells. The model developed is applied to the cases of heavy oils, in low consolidated rocks with different clay composition and different injected and formation water compositions. We show that non-equilibrium effects of the delayed fines release highly affect incremental oil during injection of different-salinity water. The oil-recovery is maximum for fast fines release. For slow fines release, the recovery tends to that of "normal" waterflooding. The fines-migration-assisted smart waterflood is successful in reservoirs with a high content of fines-generating clays in the rocks (kaolinite, illite, and chlorite). A novel analytical model presented in the paper allows predicting reservoir behavior and incremental oil for different compositions of injected water and clay contents in the rock. It permits recommending ionic-composition for the injected water.
Abstract Compressibility needs to be accounted for when estimating productivity decline in closed gas and oil reservoirs, and in closed aquifers. Previous works derived an analytical model and well index for inflow performance accompanied by fines migration and consequent permeability damage for incompressible flow towards well. In the present work, we account for fluid and rock compressibility. The problem with given and constant well production rate is investigated. Mathematical model is developed, which provides well productivity index decline with time. Under this model, the solution of damage-free compressible flow in a closed reservoir is matched with the impedance growth formulae for incompressible flow in the well vicinity. The well production data have been successfully matched by the model; the tuning parameters have the common values. It allows indicating the fines mobilization, migration and straining as possible well impairment mechanism in wells under investigation.
- North America > United States (0.68)
- Africa (0.46)
Abstract Injectivity decline by fines migration with two-phase flow is important in low-salinity and smart waterflooding in oilfields. The complexity of detachment of the natural reservoir fines, their mobilization, migration and straining in two-phase environment preclude simple formulae for injectivity decline prediction. The objective of the present study is to derive of the semi-analytical model for two-phase axi-symmetric flow with variation of injected salinity, fines migration, and consequent permeability damage. A simple and robust model allows investigating the effects of injection rate, injected salinity, oil viscosity, relative permeability, and kaolinite content in the rock on skin-factor growth.
Systematic Laboratory and Modelling Study of Kaolinite in Rocks on Formation-Damage-Fines-Migration Non-Equilibrium Effects, Analytical Model
Russell, Thomas (The University of Adelaide) | Chequer, Larissa (The University of Adelaide) | Badalyan, Alexander (The University of Adelaide) | Behr, Aron (Wintershall Holding GmbH) | Genolet, Luis (Wintershall Holding GmbH) | Kowollik, Patrick (Wintershall Holding GmbH) | Zeinijahromi, Abbas (The University of Adelaide) | Bedrikovetsky, Pavel (The University of Adelaide)
Abstract The main objective of this work is to characterize the formation damage induced by fines migration in reservoir rocks with different kaolinite contents. The problem is particularly important for water production during oil and gas well operations, and for injectivity and sweep during low-salinity waterflooding. We perform laboratory corefloods using aqueous solutions with different salinities in engineered rocks with different kaolinite content, yielding fines migration and permeability alteration. A novel methodology of preparing artificial sand-packs with a given kaolinite fraction has been established. Sequential injections of aqueous solutions in order of decreasing salinity were performed in five sand-packs with different kaolinite fractions varying from 1 to 10 weight percentage. Severe permeability decline was observed when deionized water was injected into the cores. A new analytical model that captures the effects of fines release with delay and their re-entrapment by the rock has been developed. The new model allows for explicit expressions for the attached, suspended, and strained particle concentrations, as well as the pressure drop across the core. The analytical model shows good agreement with the laboratory-observed phenomena across a wide range of kaolinite concentrations. The model constants are presented for each of the five cores and lie within typically reported values. The laboratory protocol and mathematical model allows for reliable prediction of fines-migration related formation-damage during waterflood, EOR, and commingled production of low-salinity water with oil or gas.
- North America > United States (0.46)
- Europe (0.28)
Improving the Conductivity of Natural Fracture Systems in Conjunction with Hydraulic Fracturing in Stress Sensitive Reservoirs
Keshavarz, Alireza (Australian School of Petroleum, The University of Adelaide) | Johnson, Ray (Australian School of Petroleum, The University of Adelaide) | Carageorgos, Themis (Australian School of Petroleum, The University of Adelaide) | Bedrikovetsky, Pavel (Australian School of Petroleum, The University of Adelaide) | Badalyan, Alexander (Australian School of Petroleum, The University of Adelaide)
Abstract The technology of injecting micro-sized proppant particles along with fracturing fluid is proposed to improve the conductivity of naturally fracture systems (e.g., cleats, natural fractures) in stress sensitive reservoirs, by placing graded particles in a larger, preserved stimulated reservoir volume around the induced hydraulical fracture. One of the main parameters determining the efficiency of the proposed technology is the concentration of placed proppant particles in the fracture systems. A laboratory study has been conducted to evaluate the effect of placed proppant concentration on coal permeability enhancement using a one-dimensional linear injection of micro-sized proppant into coal core and varying effective stress. Permeability values are measured for different concentrations of placed particles as a function of effective stress. The results show that there is an optimum concentration of placed particles for which the cleat system permeability reaches a maximum and permeability enhancement is more sensitive to concentration of placed proppant at higher than lower effective stress. The experimental results show maximum permeability enhancement of about 20% for an optimum concentration of placed particles at 490 psi effective stress. Permeability enhancement by 3.2 folds is observed at elevated effective stress of 950 psi. Finally, the paper proposes a field application strategy to apply graded particle injection in field case study.
- Europe (1.00)
- North America > United States (0.46)
- Oceania > Australia > Queensland (0.28)
- Research Report > New Finding (0.69)
- Research Report > Experimental Study (0.55)
- Geology > Geological Subdiscipline > Geomechanics (0.97)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (0.30)
Abstract A common problem in water flooding projects in heterogeneous reservoirs is early water production through high permeable zones. Polymer gel treatment has been used widely for water shut-off and well water-oil ration WOR reduction. However, a large injection volume is required for gel treatments that imposes high operational, material and environmental costs. This study introduces an alternative technique for water shut-off using Low-Salinity water injection. Injection of a small slug of Low-Salinity water induces permeability damage that blocks the water influx from high permeable water producing layers. The simulation study shows that the water shut-off treatment using Low-Salinity water, results in a significant reduction of produced WOR and may improve the final recovery. Injection of 10% PV of Low-Salinity water into the production well, resulted in ~20% reduction in produced WOR and ~6% incremental recovery.
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.65)
Prevention of Water-Blocking Formation Damage in Gas Reservoirs Wettability Alteration, Analytical Modelling
Naik, Saurabh (Australian School of Petroleum, The University of Adelaide) | You, Zhenjiang (Australian School of Petroleum, The University of Adelaide) | Bedrikovetsky, Pavel (Australian School of Petroleum, The University of Adelaide)
Abstract Water blocking is a widespread formation damage mechanism in oil and gas reservoirs. The end effect on the well sand-face or fracture results in the creation of a water film which significantly reduces gas permeability. The removal of the water film by changing wettability near to the wellbore or hydraulic fracture is the traditional method of well stimulation. We describe inflow performance by two-phase steady-state flow towards well. The wettability affects the relative permeability and the capillary pressure. Treatment of the well neighbourhood by nanoparticles or surfactants results in a reservoir with non-uniform wettability. We present a steady-state solution for inflow performance and show how the alteration of the contact angle and the treatment depth affects the well productivity index. The model is verified by comparison with coreflood data. The developed analytical model can be used for the prediction of gas well productivity, and for the planning and design of wettability-alteration well-stimulation. The main result of the paper is the existence of the optimal contact angle.