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.
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)
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.
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)
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.
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.
Russell, Thomas (Australian School of Petroleum, The University of Adelaide) | Pham, Duy (Australian School of Petroleum, The University of Adelaide) | Petho, Genna (Australian School of Petroleum, The University of Adelaide) | Neishaboor, Mahdi Tavakkoli (Australian School of Petroleum, The University of Adelaide) | Badalyan, Alexander (Australian School of Petroleum, The University of Adelaide) | Behr, Aron (Wintershall holding GmbH) | Genolet, Luis (Wintershall holding GmbH) | Kowollik, Patrick (Wintershall holding GmbH) | Zeinijahromi, Abbas (Australian School of Petroleum, The University of Adelaide) | Bedrikovetsky, Pavel (Australian School of Petroleum, The University of Adelaide)
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.
Pronk, Robin (Australian School of Petroleum, The University of Adelaide) | Russell, Thomas (Australian School of Petroleum, The University of Adelaide) | Pham, Duy (Australian School of Petroleum, The University of Adelaide) | Tangparitkul, Suparit (Australian School of Petroleum, The University of Adelaide and Chiang Mai University) | Badalyan, Alexander (Australian School of Petroleum, The University of Adelaide) | Behr, Aron (Wintershall holding GmbH) | Genolet, Luis (Wintershall holding GmbH) | Kowollik, Patrick (Wintershall holding GmbH) | Zeinijahromi, Abbas (Australian School of Petroleum, The University of Adelaide) | Bedrikovetsky, Pavel (Australian School of Petroleum, The University of Adelaide)
Fines migration and consequent permeability damage is one of the major mechanisms for formation damage. Natural reservoir fines can be mobilised at high injection/production rates or in the presence of low-salinity water. The mobilised fines can block thin pores resulting in a drastic permeability impairment. Several factors affect mobilisation of in-situ clay particles and the degree of damage it causes, including rock clay content and type. This study aims to understand effect of rock's clay content on the permeability response due to clay mobilisation.
Several experiments are performed using artificially prepared unconsolidated cores with known clay content. Sand grains are mixed with a desired amount of kaolinite. The samples are compactedin a specifically designed core-holder and put under overburden and axial pressure to create a sufficient compaction. A laboratory procedure is developed to assure that all cores are prepared at the same condition and kaolinite clay particles are uniformly distributed along the core samples. Each sample is then subjected to a constant flow of high salinity brine (0.6M NaCl, equivalent to sea water salinity) to measure the initial permeability. The injected salinity is reduced in 6 steps down to deionizedwater. Each solution is injected until permeability stabilisation is achieved. The produced fluid is sampled continuously to measure salinity and particle concentration. Sixunconsolidated cores with different kaolinite content (0to 10 weight %) are studied.
It was observed that the initial permeability of cores decreases with increasing kaolinite content. Reduction of injected water salinity resulted in permeability decline in all samples; however, the observed permeability damage is surprisingly non-monotonic. In all tests, permeability increased slightly when salinity reduced to 0.3 M solution; and then decreased when solution salinity was reduced to 0.1M and continued to decrease monotonically for all injection steps. Itwasdiscoveredthatonly0.2-1.6%oftheinitialkaoliniteis recoveredat the end of each test (after injection of DI water) implying that pore plugging is the cause of severe permeability damage (9.5-54times). Moreover, the permeability variation behaviour of the samples with low kaolinite content is different from that for samples with high kaolinite content. In addition, it is observed that the damaged permeability can berecoveredby300-700%byreversing the flow direction in the cores.
The laboratory methodology for core preparation and focusing on effect of clay content is novel. The non-monotonic behaviour of permeability variation is significant in water injection projects when injected water is slightly less saline than formation water. The proposed methodology can be applied for prediction of permeability decline in low-consolidated rocks with high and low kaolinite content during water injection in oil reservoirs and also in designing the composition of the injection water.
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)
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.
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)
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.
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.
Lotfollahi, Mohammad (University of Texas at Austin) | Farajzadeh, Rouhi (Shell Global Solutions International) | Delshad, Mojdeh (Delft University of Technology) | Al-Abri, Al-Khalil (University of Texas at Austin) | Wassing, Bart M. (Petroleum Development Oman) | Al-Mjeni, Rifaat (Petroleum Development Oman) | Awan, Kamran (Petroleum Development Oman) | Bedrikovetsky, Pavel (Petroleum Development Oman)
Polymer flooding is one of the most widely used chemical enhanced-oil-recovery (EOR) methods because of its simplicity and low cost. To achieve high oil recoveries, large quantities of polymer solution are often injected through a small wellbore. Sometimes, the economic success of the project is only feasible when injection rate is high for high-viscosity solution. However, injection of viscous polymer solutions has been a concern for the field application of polymer flooding.
The pressure increase in polymer injectors can be attributed to (1) formation of an oil bank, (2) polymer rheology (shear-thickening behavior near wellbore), and (3) plugging of the reservoir pores by insoluble polymer molecules or suspended particles in the water.
In this paper, a new model to history match field injection-rate/pressure data is proposed. The pertinent equations for deep-bed filtration and external-cake buildup in radial coordinates were coupled to the viscoelastic polymer rheology to capture important mechanisms. Radial coordinates were selected to minimize the velocity/shear-rate errors caused by gridblock size in the Cartesian coordinates.
The filtration theory was used and the field data history matched successfully. Systematic simulations were performed, and the impact of adsorption (retention), shear thickening, deep-bed filtration, and external-cake formation was investigated to explain the well-injectivity behavior of polymer. The simulation results indicate that the gradual increase in bottomhole pressure (BHP) during early times is attributed to the shear-thickening rheology at high velocities experienced by viscoelastic hydrolyzed polyacrylamide (HPAM) polymers around the wellbore and the permeability reduction caused by polymer adsorption and internal filtration of undissolved polymer. However, the linear impedance during external-cake growth is responsible for the sharper increase in injection pressure at the later times.
One can use the proposed model to calculate the injectivity of the polymer-injection wells, understand the contribution of different phenomena to the pressure rise in the wells, locate the plugging or damage that may be caused by polymer, and accordingly design the chemical stimulation if necessary.