Geochemical scale formation and deposition in reservoir is a common problem in upstream oil and gas industry, which results in equipment corrosion, wellbore plugging, and production decline. In unconventional reservoirs, the negative effect of scale formation becomes more pronounced as it can severely damage the conductivity of hydraulic fractures. Hence, it is necessary to predict the effect of scale deposition on fracture conductivity and production performance.
In this work, an integrated reactive-transport simulator is utilized to model geochemical reactions along with transport equations in conventional and unconventional reservoirs considering the damage to the fracture and formation matrix. Hence, a compositional reservoir simulator (UTCOMP), which is integrated with IPhreeqc, is utilized to predict geochemical scale formation in formation matrix and hydraulic fractures. IPhreeqc offers extensive capabilities for modeling geochemical reactions including local thermodynamic equilibrium and kinetics. Based on the amount of scale formation, porosity, permeability, and fracture aperture are modified to determine the production loss. The results suggested that interaction of the formation water/brine and injection water/hydraulic fracturing fluid is the primary cause for scale formation. The physicochemical properties such as pressure, temperature, and
During hydraulic fracturing, precipitation of barite and dissolution of calcite are identified to be the main reactions, which occur as a result of interaction between the formation brine, formation mineral composition, and injection water/hydraulic fracturing fluid. Calcite dissolution can increase the matrix porosity and permeability while barite precipitation has an opposite effect. Therefore, the overall effect and final results depend on several parameters such as HFF composition, HFF injection rate, and formation mineral/brine. Based on the fracturing fluid composition and its invasion depth in this study, the effect of barite precipitation was dominant with negative impact on cumulative gas production. The outcome of this study is a comprehensive tool for prediction of scale deposition in the reservoir which can help operators to select optimum fracturing fluid and operating conditions.
Economic production from unconventional reservoirs requires long horizontal wells with an extensive hydraulic fracture network. However, the ultimate recovery factor under primary depletion still remains less than 10% of original oil in place.
Mixing of an asphaltenic oil with light gases (e.g., CO2) and/or depressurizing such a crude oil can lead to phase separation in which a second liquid phase L2 -highly concentrated in asphaltene- is formed. Asphaltene may precipitate or deposit out of the second liquid phase. This causes formation damage, wettability alteration, and recovery reduction. While asphaltene phase behavior have been studied under static conditions (where equilibrium is imposed), the behavior of asphaltene under dynamic flow conditions is relatively unexplored. Here, we investigate the coupling of asphaltene phase behavior and flow in porous media. As such, two asphaltenic crudes are characterized using the PC-SAFT equation-of- state. The fluid models were then used to fit the experimental asphaltene deposition data under static conditions. Subsequently, asphaltene flow and deposition was studied during miscible gas flooding where four phases (water, oil L1, gas, and second liquid L2) are present. Our results show that (i) wettability alteration increases the mixing zone and decreases both the displacement and sweep efficiencies; (ii) asphaltene deposition, hence wettability alteration and formation damage are maximal near the producer.
Lotfollahi, Mohammad (The University of Texas at Austin) | Beygi, Mohammad Reza (The University of Texas at Austin) | Abouie, Ali (The University of Texas at Austin) | Sepehrnoori, Kamy (The University of Texas at Austin) | Wheeler, Mary (The University of Texas at Austin) | DiCarlo, David A. (The University of Texas at Austin)
Tight oil reservoirs are one of the most prolific world energy resources. Economic production from tight oil formations requires long horizontal wells with an extensive hydraulic fracture network. Nevertheless, the recovery factor under primary depletion still remains less than 20% of original oil in place. Here, water flooding is limited due to low permeability and intermediate- to oil-wet nature of the rock. Surfactant flooding is promising in liquid-rich shale reservoirs by changing the wettability, favoring for counter-flow imbibition process, and reducing the residual oil saturation. This paper discusses the technical potential of surfactant flooding in tight oil reservoirs.
Surfactant flooding in a tight oil reservoir is studied using a commercial simulator. We model huff-n-puff surfactant flow in hydraulically fractured wells in the reservoir discretized in a Tartan grid. We focus on estimated ultimate recovery (EUR) in this study. Two types of surfactants were tested: surfactants A and B to alternate the wettability state to water-wet and intermediate-wet conditions respectively, without noticeable impact on the capillary number and, an ultra-low interfacial tension (IFT) surfactant C, which reduces residual oil saturation, but simultaneously straightens water-oil relative permeabilities and weakens capillary pressure forces. Due to the inherent non-uniqueness issue of forecasting of the EUR, we studied the significance of affecting parameters on EUR. We performed sensitivity analysis on capillary pressure, surfactant adsorption, surfactant injection and soaking times, non-wetting (oil) phase hysteresis, matrix permeability, fracture length, and fracture conductivity. The incremental oil recovery factor over primary production for 15 years of total production was up to 4.8% of OOIP that doubles the recovery from the primary production.
Our results indicate that wettability alteration in tight oil reservoirs is the dominant mechanism for the oil recovery through surfactant flooding. Surfactants that alter wettability towards water- and intermediate-wet conditions are more efficient due to more favorable capillary pressure and water relative permeability than those lowering the IFT to ultra-low values.
Abouie, Ali (The University of Texas at Asutin) | Korrani, Aboulghasem Kazemi Nia (The University of Texas at Austin) | Shirdel, Mahdy (The University of Texas at Austin) | Sepehrnoori, Kamy (The University of Texas at Austin)
Scale deposition in surface and subsurface production equipment is one of the common problems during oil production, resulting in equipment corrosion, wellbore plugging, decrease in production rate, and frequent remediations. In this work, a detailed procedure is presented through which a compositional wellbore simulator is developed with the capability of modeling comprehensive geochemical reactions.
The compositional wellbore simulator (UTWELL) is developed by applying different numerical approaches and flow-regime-detection methods to accurately model multiphase flow in the wellbore. In addition, several deposition mechanisms are incorporated for the transportation, entrainment, and deposition of solid particles in the wellbore. Subsequently, a geochemical module, IPhreeqc, is integrated into the wellbore model to handle homogeneous and heterogeneous, reversible and irreversible, and ion-exchange reactions under either local-equilibrium or kinetic conditions. This package provides a robust, flexible, and accurate integrated tool for mechanistic modeling of scale deposition in the wellbore.
Through our integrated simulator, deposition profiles of carbonate and sulfate scales in the wellbore are predicted for several case studies. Significant effects of physiochemical properties (such as pressure, temperature, salinity, and pH value) on the scale deposition in the wellbore are discussed. In addition, comparing simulation results with experimental data reveals that hydrocarbon-phase dissolution has a significant effect on geochemical calculations compared with the temperature/pressure variation effects.
To the best of our knowledge, there is no comprehensive simulator available in the industry through which scale deposition in the wellbore can be predicted accurately. In this paper, scale deposition profile in the wellbore is estimated by including the interaction of the hydrocarbon and aqueous phases and its effect on the aqueous-scale geochemistry (by use of a compositional wellbore simulator); effects of parameters that vary greatly in the wellbore (pressure, temperature, and pH value); and comprehensive geochemistry simulation (provided through coupling of the wellbore simulator with IPhreeqc). The outcome of this study yields a comprehensive tool for scale deposition prediction in the wellbore and will help scale deposition risk-management and mitigation plans.
Scale deposition in surface and subsurface production equipment is one of the major operational problems encountered during oil production, which results in equipment corrosion, wellbore plugging, production rate decline, and requires frequent squeeze treatments. Oil field scales mainly result from changes in the physicochemical properties (pH, temperature, and pressure), mixing with incompatible brine compositions, and mixing with inhibitors. Meanwhile, comprehensive modeling and prediction of scale formation has remained challenging due to the complexity of the geochemical reactions that occurs in real fields.
For the first time and to overcome the lack of comprehensive geochemical-based tools, a robust, accurate, and flexible coupled reservoir and wellbore model is developed, and then, integrated with a geochemical tool (i.e. IPhreeqc) to predict scale formation from injection wells through the reservoir to production wells. IPhreeqc, the United States Geological Survey (USGS) geochemical tool, has the capability of modeling homogenous and heterogeneous, reversible and irreversible, and ion-exchange reactions under non-isothermal, non-isobaric, and local equilibrium or kinetic conditions. In this work, by integrating IPhreeqc with the compositional reservoir (UTCOMP) and wellbore simulator (UTWELL), the geochemical capabilities of IPhreeqc is used in a multi-physics reservoir/wellbore models for comprehensive prediction of carbonates and sulfates scales deposition. Moreover, the effects of weak acids and hydrocarbon phase dissolution in the aqueous phase were included to accurately predict the carbonate scale profile.
To the best of our knowledge, there is no comprehensive simulator available in the industry through which scale deposition in the reservoir and wellbore can be predicted accurately. In this paper, scale deposition profile in the field is estimated by including 1) the interaction of the hydrocarbon and aqueous phases and its effect on the aqueous-scale geochemistry 2) effects of parameters that vary greatly in the field (i.e. pressure, temperature, and pH) and 3) comprehensive geochemistry simulation (provided through coupling of the simulators with IPhreeqc). The outcome of this study yields a comprehensive tool for prediction of scale deposition profile and will help scale deposition risk management and mitigation plans.
Abouie, Ali (The University of Texas at Austin) | Rezaveisi, Mohsen (The University of Texas at Austin) | Mohebbinia, Saeedeh (The University of Texas at Austin) | Sepehrnoori, Kamy (The University of Texas at Austin)
Asphaltene deposition is known to be one of the major problems in oil fields. Asphaltene precipitation and deposition from the reservoir fluid can block pore throats or change the formation wettability in the reservoir. Furthermore, asphaltene precipitation and deposition result in partial to total plugging in the wellbore. Recent studies have shown that PC-SAFT EOS is a more appropriate and comprehensive thermodynamic model for simulation of asphaltene precipitation. The main objective of this paper is to implement PC-SAFT EOS into a compositional wellbore simulator to model asphaltene precipitation. Flocculation and deposition models are also integrated with the thermodynamic model to simulate the dynamics of asphaltene deposition along the wellbore. In addition, the capabilities of PC-SAFT and common-used Peng-Robinson equation of state are compared through fluid characterization to reproduce experimental precipitation data.
The simulation results indicate asphaltene deposition profile and consequent decline in production rate. It is shown that the profile of asphaltene deposition is mostly governed by the precipitation condition and the deposition rate. Moreover, prediction capability of cubic equation of state is shown to give approximately similar results if additional precipitation data is available (e.g. lower onset pressure and maximum amount of precipitation). The prediction results of the developed tool are highly crucial to monitor the well performance, optimize the operating conditions of the field, and propose the remediation technique.
Asphaltene precipitation, flocculation, and deposition strongly depend on the pressure, temperature, and composition variations (e.g. phase instability due to CO2 injection). The effect of temperature variations on asphaltene precipitation is more complicated compared to the other factors. As temperature increases, oil density decreases while at the same time entropy of the solution increases, resulting in a counter balancing effect. Although some researchers addressed this issue in the literature, there is a lack of comprehensive model that investigates dynamic effect of temperature variations on asphaltene behavior.
In this paper, a comprehensive non-isothermal compositional EOS-based reservoir simulator is developed with the capability of modeling asphaltene phase behavior to study the effect of temperature variations on dynamics of asphaltene precipitation, flocculation, and deposition during cold/hot water injection. The results showed that effect of temperature variations might be favorable or detrimental on oil production, depending on fluid composition, direction of wettability alteration, and dynamic changes in reservoir condition. Each of these factors has a distinct effect on the asphaltene behavior, and neglecting such effects may result in a significant error in the prediction of asphaltene behavior, and consequently, oil production rate.
A successful gas injection design is a challenging task in asphaltic reservoirs. Gas injection accelerates asphaltene deposition, which results in detrimental effects on field development and ultimate oil recovery. The main objective of this paper is to provide a workflow to mitigate asphaltene problems in reservoirs during gas injection. The workflow includes data gathering, fluid characterization, and dynamic asphaltene modeling using an in-house compositional reservoir simulator. The in-house simulator is capable of modeling (1) the effects of pressure, temperature, and composition variations simultaneously on asphaltene phase behavior, (2) asphaltene precipitation, flocculation, and deposition, and (3) wettability alteration due to asphaltene deposition. Three case studies were presented to investigate the effects of gas flooding, gas override, and wettability alteration on the dynamics of asphaltene precipitation, flocculation, and deposition.
The simulation results showed that gas injection considerably increased the instability of asphaltene particles in the oil, and consequently, accelerated asphaltene precipitation and deposition in the reservoir. During miscible gas flooding, asphaltene mostly deposited at the front near the boundaries, where the front velocity was minimum. Moreover, asphaltene deposition occurred mainly in the bottom layer in the presence of gas override due to the lower velocity of the front in the bottom layer compared to the upper layer. Finally, the study revealed that wettability alteration due to asphaltene deposition had a major impact on the performance of the reservoir, specifically on the ultimate oil recovery, compared to the permeability reduction.
Selecting an appropriate Equation of State to model asphaltene precipitation in compositional wellbore/reservoir simulators is still unclear in the literature. Recent studies have shown that PC-SAFT is a more appropriate model for asphaltene precipitation compared to the commonly used solid model. The main objective of this paper is to compare the solid model and PC-SAFT in both static and dynamic asphaltene modeling. Through fluid characterization, the capabilities of both models are compared to reproduce precipitation experimental data.
The results show that both solid model and PC-SAFT are capable of accurate modeling of asphaltene precipitation. Although matching process using PC-SAFT is much easier, solid model is also able to reproduce the experimental data with the same quality as PC-SAFT, if it is tuned properly. The simulations showed that PC-SAFT is superior to solid model in terms of accuracy for extrapolation when the experimental data are not available for the simulation conditions (i.e. variation in temperature, pressure, and fluid composition in the reservoir/wellbore). However, both models are applicable for interpolation when the experimental data covers the range of simulation condition. The wellbore simulations show that although the trend of asphaltene deposition is similar for both models, solid model overestimates the amount of asphaltene precipitation and deposition in the wellbore compared to the PCSAFT model. On the other hand, since PC-SAFT uses an iterative procedure for finding the density roots, phase equilibrium calculation, and consequently, the simulation procedure takes much more computational time when PC-SAFT is used.