A new method to characterize scaling damage from pressure measurements

Sulphate scaling with consequent deposit formation and wellbore damage is a well-known phenomenon that occurs during waterflooding, when mixing of incompatible injection and formation waters may result in sulphate salt precipitation and flow restriction. The reliable productivity decline prediction is based on mathematical modelling with well-known model coefficients. The sulphate scaling system contains two governing parameters: the kinetics coefficient characterising the velocity of chemical reaction and the formation damage coefficient showing how the permeability decreases due to salt precipitation. Previous works have derived analytical-model-based method for determination of both coefficients from breakthrough concentration and pressure drop during laboratory coreflood on quasi steady state commingled flow of injected and formation waters, and also from just pressure drop measurements during two corefloods with two different ratios “formation water : seawater”. This paper extends the previous works, by sequence of two commingled injections of incompatible waters into the same core with two different ratios “formation water : seawater”. Two different slopes of skin factor increase during two injections allow calculating the kinetics and formation damage coefficients in order to predict scaled-up well behaviour.T. Carageorgos, M. Marotti, and P. Bredrikovetsk

A new laboratory method for evaluation of sulfate scaling parameters from pressure measurements

Summary Sulfate scaling in offshore waterflood projects, in which sulfate from the injected seawater (SW) reacts with metals from the formation water (FW), forming salt deposit that reduces permeability and well productivity, is a well known phenomenon. Its reliable prediction is based on mathematical models with well-known parameters. Previous research presents methods for laboratory determination of model coefficients using breakthrough concentration during coreflooding. The concentration measurements are complex and cumbersome, while the pressure measurements are simple and require standard laboratory equipment. In the present work, a new laboratory method is developed for determination of the model coefficients from pressure measurements. Several laboratory corefloods have been performed. The tests show that the proposed method is more precise for artificial cores than for the natural reservoir cores. Further development of the method is required to determine parameters of formation damage caused by sulfate scaling for reservoir core samples.Themis Carageorgos, Marcelle Marotti, Pavel Bedrikovetsk

Characterization of Sulfate-Scaling Formation Damage From Pressure Measurements

Document ID: 107884-MS Abstract Mixing of sea- and production waters during waterflooding of offshore oil reservoirs results in reaction of barium and sulphate ions causing precipitation of barium sulphate with consequent rock permeability decrease and well productivity decline. The reliable productivity decline prediction is based on mathematical modelling with well-known model coefficients. The sulphate scaling system contains two governing parameters: the kinetics coefficient characterising the velocity of chemical reaction and the formation damage coefficient showing how the permeability decreases due to salt precipitation. Previous works have derived analytical-model-based method for determination of both coefficients from breakthrough concentration and pressure drop during laboratory coreflood on quasi steady state commingled flow of injected and formation waters. The current study extends the method and derives formulae for calculation of two scale damage coefficients from just pressure drop measurements during two corefloods with two different ratios "formation water : seawater". Data from series of three corefloods on commingled injection with three different "formation water : seawater" ratios, were treated. Equality of scaling damage parameters as obtained from three different floods in similar artificial cores validates the method proposed. Introduction In deepwater offshore operations where seawater injection is a common development practice, barium, calcium, and strontium sulphate scale deposition is a serious concern. Barium sulphate and related scale occurrence is considered a serious potential problem that causes formation damage near the production-well zone 1–5. The major cause of sulphate scaling is the chemical incompatibility between the injected seawater, which is high in sulphate ions, and the formation water, which originally contains high concentrations of barium, calcium, and/or strontium ions 6–9. A reliable model capable of predicting such scaling problems may be helpful in planning a waterflood scheme. It may also aid in selection of an effective scale prevention technique through the prediction of scaling tendency, type, and potential severity. A reliable predictive model must use well-known values of the model coefficients. The mathematical model for sulphate scaling contains two phenomenological parameters: the kinetics coefficient from active mass low of chemical reaction showing how fast the reaction and precipitation occurs, and the formation damage coefficient reflecting the permeability decrease due to sulphate salt deposit 10–15. Both coefficients are phenomenological parameters depending on rock surface mineralogy, pore space structure, temperature and brine ionic strength. Therefore, they cannot be calculated theoretically for natural reservoirs and must be determined from laboratory corefloods. Reagent and deposition concentration profiles during reactive flows are non-uniform. So, the sulphate damage parameters cannot be directly calculated from laboratory measurements. They must be determined from laboratory coreflood data using solutions of inverse problems. The quasi steady state commingled corefloods by sea- and formation waters were performed by numerous authors 16–19. The kinetics coefficient can be calculated from breakthrough concentration in quasi steady state coreflood with commingled injection of sea- and formation waters. Then the formation damage coefficient can be determined from pressure drop increase during flooding 20,21. The pressure drop measurements are simple and robust while breakthrough concentration determination is a cumbersome laboratory procedure. Therefore, often concentration data are unavailable 17. Availability of the method for characterisation of scaling damage system from pressure measurements would simplify the laboratory procedure on sulphate scaling studies. This is the subject of the current paper. Based on analytical model for commingled coreflood by sea- and formation waters, the current paper develops a method to determine two scaling damage parameters from pressure measurements during two floods with different "formation water : seawater" ratios. P. Bedrikovetsky, M. Marotti, I.A. Lima Neto, and T. Carageorgo

Laboratory and well-history based predictions of productivity decline due to oilfield scaling: analytical modelling and field study

2009 APPEA Conference, Darwin, Northern Territory, May 31-June 3, 2009T. Carageorgos, M. Marotti, R. Monteiro and P. Bedrikovetsk

Characterisation of formation damage during reactive flows in porous media

Abstract not availableAlexandre Vaz, Daniel Maffra, Themis Carageorgos, Pavel Bedrikovetsk

Pore scale visualization and simulation of miscible displacement process under gravity domination

This paper presents both visualization and flow simulation of glass micromodel experiments which are performed to visualize the gravity dominated miscible gas displacement process. This approach enables to simulate the exact porous pattern on which the micromodel experiments are performed. At first, a porous pattern for experiments was constructed and then etched onto a glass plate. An experiment was performed at 45o dip angle at injection rate of 0.002 ml/min to visualize the displacement of two miscible fluids under gravity domination. Butanol and Iso-octane were selected as in situ and injected fluids respectively. The mobility and density ratio of these two fluids are comparable with medium API oil and CO2 at reservoir conditions. For simulation, the porous pattern was exported to the finite element analysis software, COMSOL Multiphysics, so that simulations of micromodel experiments were performed for the same porous pattern as used for experiments. To simulate miscible displacement, the Navier-Stokes and continuity equations were used to calculate pressure and velocity fields in the solute and solvent regions, while the convection-diffusion equation was used to calculate solute concentration in the mixture during the displacement. The experimental visual results were processed and compared with the simulation results indicating a good match between experiments and simulation. The validated model can be used to simulate and to find the optimized conditions and controlling parameters at different conditions for the gravity assisted miscible displacement process.Zeeshan Mohiuddin, Manouchehr Haghighi, Yvonne Stokes, Themis Carageorgos and Danny Gibbin

Enhancement of CBM well fracturing through stimulation of cleat permeability by ultra-fine particle injection

A. Keshavarz, A. Badalyan, T. Carageorgos, P. Bedrik¬ovetsky and R. Johnso

Three New Methods to Characterise Sulphate Scaling Damage from Coreflood Pressure Measurements

SPE paper 113502http://store.spe.org/2008-SPE-International-Oilfield-Corrosion-Conference-P149.asp

Graded proppant injection into coal seam gas and shale gas reservoirs for well stimulation

Low productivity indices are observed in many moderate-to low-permeability coal bed methane (CBM) and shale gas (SG) reservoirs due to low aperture and poor connectivity of natural cleats. A method is proposed for injection of graded proppant particles into a cleat system below the fracturing pressure to keep coal cleats and shale fractures open during water-gas production. Graded proppant injection in CBM and SG reservoirs can: stimulate a stress sensitive cleat system below the fracturing pressure; enhance fracturing treatment by invading cleats, lowering fluid leak-off, and maintaining aperture during production; and provide a periodic or remedial treatment to counter effective stress on the cleats improving production by maintaining cleat aperture. Laboratory tests on bituminous coal core flooding with water under increasing pore pressure with graded proppant injection at the maximum pore pressure (minimum effective stress) have been carried out at different ionic strengths and high pH of the injected water. Proppant particles penetrate deeper into coal matrix at low ionic strength of injected water corresponding to electrostatic particle-particle and particle-coal repulsion. No particle agglomeration and formation of particle-formed cake at the entrance of coal cleats are observed at these conditions. Coal permeability increases by about 2.2 times as the result of a single-sized small particle injection. Followed injection of larger particles leads to a greater enhancement of coal core permeability. An overall increase of coal core permeability after graded proppant injection is about 2.7 times. The proposed method can significantly increase very low productivity index in stress sensitive coals and shales without hydraulic fracturing. It can be also used as a non-damaging leak-off additive during hydraulic fracturing stimulation treatments and to aid long-term conductivity.Alireza Keshavarz, Alexander Badalyan, Themis Carageorgos, Pavel Bedrikovetsky, and Ray Johnson Jr

Determining model parameters for non-linear deep-bed filtration using laboratory pressure measurements

Particle capture in porous media and the consequent permeability reduction occur in oilfields during water injection or produced water re-injection, migration of mobilized reservoir fines, and invasion of drilling and completion fluids into formations. Reliable modelling-based prediction of particle propagation in natural reservoirs is an essential step in the planning and design of waterflooding. The mathematical model for suspension-colloidal transport in natural reservoirs contains two empirical functions of retained particle concentration. The filtration function expresses the particle capture rate. The formation-damage function determines the permeability decline due to particle capture and retention. Previous works developed an inverse-problem solution to recover both functions from breakthrough concentration and the pressure drop. The present paper develops a new method that determines the filtration and formationdamage functions from pressure measurements only. The method uses pressure data at an intermediate point of the porous column (core), which supplements pressure measurements at the core inlet and outlet. The proposed method furnishes two retained-concentration functions for filtration and formation-damage. The method is validated by comparison with laboratory experiments. A high fit with the pressure data at three core points was observed. Moreover, the fitted model predicts the pressure measured at other core points with high precision.A. Vazb, P. Bedrikovetsky, P.D. Fernandes, A. Badalyan, T. Carageorgo