Modeling of Creep-Compacting Outcrop Chalks Injected with Ca-Mg-Na-Cl Brines at Reservoir Conditions

SPE Journal ◽  
2019 ◽  
Vol 24 (06) ◽  
pp. 2889-2910 ◽  
Author(s):  
Pål Østebø Andersen ◽  
Dhruvit Satishchandra Berawala
Keyword(s):  
Dissolution Rate ◽  
Oil Recovery ◽  
Injection Rate ◽  
Mineral Dissolution ◽  
Experimental Conditions ◽  
Compaction Rate ◽  
Compaction Behavior ◽  
Explicit Analytical Solution ◽  
Reservoir Conditions ◽  
Chalk Compaction

Summary Numerical and analytical 1D solutions are presented to interpret the link between geochemical alterations and creep compaction (compaction under constant effective stress) in chalk cores. Chemically reactive flow enhancing chalk compaction is of significant importance for enhanced oil recovery (EOR), compaction, and subsidence in North Sea chalk reservoirs. The focus of this study is on Ca-, Mg-, and NaCl brines that interact with the chalk by the dissolution of calcite and the precipitation of magnesite. An explicit analytical solution is derived for the steady–state ion and dissolution–rate distributions at a given injected composition and injection rate. A mathematical description of creep compaction is proposed on the basis of applied affective stresses and rock ability to carry these stresses as a function of porosity. The reaction and compaction models are then coupled as follows: The compaction rate is assumed, which is enhanced by the dissolution rate, which can vary spatially. Furthermore, the solid volume changes by mineral dissolution and precipitation. Brine–dependent and nonuniform compaction is hence built into the model by means of the dissolution–rate distribution. The model is validated and parameterized against data from a total of 22 core samples from two chalk types (Åalborg and Liege) where reactive and inert brines were injected from ambient to Ekofisk–reservoir conditions (130°C). Experimentally measured effluent concentrations, distributions in mineralogy after flooding, and creep–compaction behavior were matched. Our model is the first to link a vast set of data on this subject and predict performance under new experimental conditions. This also represents a first step in upscaling such results from the laboratory toward the field. Our interpretations indicate that the two chalk types would respond differently chemically and by compaction to changes in the concentration and injection rate. Brines injected through Liege chalk appeared to approach stable oversaturation, while in Åalborg, the equilibrium condition was in agreement with geochemical calculations.

scholarly journals Quick, Easy and Economic Mineralogical Studies of Flooded Chalk for EOR Experiments Using Raman Spectroscopy

2018 ◽  
Author(s):  
Laura Borromeo ◽  
Nina Egeland ◽  
Mona Wetrhus Minde ◽  
Udo Zimmermann ◽  
Sergio Andò ◽  
...  
Keyword(s):  
Raman Spectroscopy ◽  
Effective Stress ◽  
Oil Recovery ◽  
Secondary Growth ◽  
Mineral Dissolution ◽  
Petroleum Exploration ◽  
Reservoir Conditions ◽  
Electron Microscopes ◽  
Non Destructive

Understanding the chalk-fluid interactions and the associated mineralogical and mechanical alteration at sub-micron scale are major goals in Enhanced Oil Recovery. Mechanical strength, porosity, and permeability of chalk are linked to mineral dissolution that occurs during brine injections, and affect the reservoir potential. This paper presents a novel "single grain" methodology to recognize the varieties of carbonates in rocks and loose sediments: Raman spectroscopy is a non-destructive, quick, and user-friendly technique representing a powerful tool to identify minerals down to 1 µm. An innovative working technique for oil exploration is proposed, as the mineralogy of micron-sized crystals grown in two flooded chalk samples (Liége, Belgium) was successfully investigated by Raman spectroscopy. The drilled chalk cores were flooded with MgCl2 for c. 1.5 (Long Term Test) and 3 years (Ultra Long Term Test) under North Sea reservoir conditions (Long Term Test: 130°C, 1 PV/day, 9.3 MPa effective stress; Ultra Long Term Test: 130°C, varying between 1-3 PV/day, 10.4 MPa effective stress). Raman spectroscopy was able to identify the presence of recrystallized magnesite along the core of the Long Term Test up to 4 cm from the injection surface, down to the crystal size of 1-2 µm. In the Ultra Long Term Test core the growth of MgCO3 affected nearly the entire core (7 cm). In both samples, no dolomite or high-magnesium calcite secondary growth could be detected when analysing 557 and 90 Raman spectra on the Long and Ultra Long Term Test, respectively. This study can offer Raman spectroscopy as a breakthrough tool in petroleum exploration of unconventional reservoirs, due to its quickness, spatial resolution, and non-destructive acquisition of data. These characteristics would encourage its use coupled with electron microscopes and energy dispersive systems or even electron microprobe studies.

Effect of CO2 on Heavy Oil Recovery and Physical Properties in Huff-n-Puff Processes Under Reservoir Conditions

2018 ◽  
Vol 140 (7) ◽  
Author(s):  
Songyan Li ◽  
Binfei Li ◽  
Qiliang Zhang ◽  
Zhaomin Li ◽  
Daoyong Yang
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Viscosity Reduction ◽  
Residual Oil ◽  
Numerical Techniques ◽  
Weak Stability ◽  
Experimental Conditions ◽  
Reservoir Conditions ◽  
Fluid Properties ◽  
Recovery Mechanisms

In this paper, experimental and numerical techniques have been utilized to quantify heavy oil properties in CO2 huff-n-puff processes under reservoir conditions. Experimentally, fluid properties together with viscosity reduction of heavy oil and interfacial properties between CO2 and heavy oil have been quantified, while five cycles of CO2 huff-n-puff processes have been conducted to determine oil recovery together with component variation of produced and residual oils. Theoretically, numerical simulation has been conducted to analyze the underlying recovery mechanisms associated with the CO2 huff-n-puff processes. CO2 huff-n-puff processes are only effective in the first two cycles under the existing experimental conditions, while the effective sweep range is limited near the wellbore region, resulting in poor oil recovery in the subsequent cycles. As for produced oil, its viscosity, density, resin and asphaltene contents, and molecular weight of asphaltene are reduced, whereas, for the residual oil, they are increased. The asphaltene component in the residual oil shows weak stability compared to that of the produced oil, while the ultimate oil recovery after the fifth CO2 cycle of huff-n-huff processes is measured to be 31.56%.

Determination of Optimum Parameters for Anaerobic Thermophilic Bacterium Injection using Commercial Simulator: Core Flooding Validation and Sensitivity

2020 ◽  
Author(s):  
A. Koto
Keyword(s):  
Oil Recovery ◽  
Simulation Experiment ◽  
Previous Experiment ◽  
Core Sample ◽  
Thermophilic Bacterium ◽  
Injection Rate ◽  
Core Flooding ◽  
Optimum Parameters ◽  
Result Show

The objective of this paper is to determine the optimum anaerobic-thermophilic bacterium injection (Microbial Enhanced Oil Recovery) parameters using commercial simulator from core flooding experiments. From the previous experiment in the laboratory, Petrotoga sp AR80 microbe and yeast extract has been injected into core sample. The result show that the experiment with the treated microbe flooding has produced more oil than the experiment that treated by brine flooding. Moreover, this microbe classified into anaerobic thermophilic bacterium due to its ability to live in 80 degC and without oxygen. So, to find the optimum parameter that affect this microbe, the simulation experiment has been conducted. The simulator that is used is CMG – STAR 2015.10. There are five scenarios that have been made to forecast the performance of microbial flooding. Each of this scenario focus on the injection rate and shut in periods. In terms of the result, the best scenario on this research can yield an oil recovery up to 55.7%.

scholarly journals Experimental study of the supercritical CO 2 diffusion coefficient in porous media under reservoir conditions

2019 ◽  
Vol 6 (6) ◽  
pp. 181902 ◽  
Author(s):  
Junchen Lv ◽  
Yuan Chi ◽  
Changzhong Zhao ◽  
Yi Zhang ◽  
Hailin Mu
Keyword(s):  
Porous Media ◽  
Diffusion Coefficient ◽  
Oil Recovery ◽  
Carbon Capture ◽  
Carbon Capture And Storage ◽  
Elevated Pressure ◽  
Experimental Results ◽  
Saturated Porous Media ◽  
Reservoir Conditions ◽  
The Impact

Reliable measurement of the CO 2 diffusion coefficient in consolidated oil-saturated porous media is critical for the design and performance of CO 2 -enhanced oil recovery (EOR) and carbon capture and storage (CCS) projects. A thorough experimental investigation of the supercritical CO 2 diffusion in n -decane-saturated Berea cores with permeabilities of 50 and 100 mD was conducted in this study at elevated pressure (10–25 MPa) and temperature (333.15–373.15 K), which simulated actual reservoir conditions. The supercritical CO 2 diffusion coefficients in the Berea cores were calculated by a model appropriate for diffusion in porous media based on Fick's Law. The results show that the supercritical CO 2 diffusion coefficient increases as the pressure, temperature and permeability increase. The supercritical CO 2 diffusion coefficient first increases slowly at 10 MPa and then grows significantly with increasing pressure. The impact of the pressure decreases at elevated temperature. The effect of permeability remains steady despite the temperature change during the experiments. The effect of gas state and porous media on the supercritical CO 2 diffusion coefficient was further discussed by comparing the results of this study with previous study. Based on the experimental results, an empirical correlation for supercritical CO 2 diffusion coefficient in n -decane-saturated porous media was developed. The experimental results contribute to the study of supercritical CO 2 diffusion in compact porous media.

scholarly journals Study Rheological Behavior of Polymer Solution in Different-Medium-Injection-Tools

Polymers ◽  
2019 ◽  
Vol 11 (2) ◽  
pp. 319 ◽  
Author(s):  
Bin Huang ◽  
Xiaohui Li ◽  
Cheng Fu ◽  
Ying Wang ◽  
Haoran Cheng
Keyword(s):  
Molecular Weight ◽  
Polymer Solution ◽  
Oil Recovery ◽  
Injection Pressure ◽  
Injection Rate ◽  
Injection Velocity ◽  
Structural Parameter ◽  
Local Perturbation ◽  
Polymer Injection ◽  
Single Pipe

Previous studies showed the difficulty during polymer flooding and the low producing degree for the low permeability layer. To solve the problem, Daqing, the first oil company, puts forward the polymer-separate-layer-injection-technology which separates mass and pressure in a single pipe. This technology mainly increases the control range of injection pressure of fluid by using the annular de-pressure tool, and reasonably distributes the molecular weight of the polymer injected into the thin and poor layers through the shearing of the different-medium-injection-tools. This occurs, in order to take advantage of the shearing thinning property of polymer solution and avoid the energy loss caused by the turbulent flow of polymer solution due to excessive injection rate in different injection tools. Combining rheological property of polymer and local perturbation theory, a rheological model of polymer solution in different-medium-injection-tools is derived and the maximum injection velocity is determined. The ranges of polymer viscosity in different injection tools are mainly determined by the structures of the different injection tools. However, the value of polymer viscosity is mainly determined by the concentration of polymer solution. So, the relation between the molecular weight of polymer and the permeability of layers should be firstly determined, and then the structural parameter combination of the different-medium-injection-tool should be optimized. The results of the study are important for regulating polymer injection parameters in the oilfield which enhances the oil recovery with reduced the cost.

scholarly journals A Numerical Method for Computing Recovery of Oil By Hot Water Injection in a Radial System

1965 ◽  
Vol 5 (02) ◽  
pp. 131-140 ◽  
Author(s):  
K.P. Fournier
Keyword(s):  
Thermal Expansion ◽  
Oil Recovery ◽  
Viscosity Ratio ◽  
Water Injection ◽  
Injection Rate ◽  
Heat Losses ◽  
Hot Water ◽  
Radial System ◽  
System Equation ◽  
Finite Difference Equations

Abstract This report describes work on the problem of predicting oil recovery from a reservoir into which water is injected at a temperature higher than the reservoir temperature, taking into account effects of viscosity-ratio reduction, heat loss and thermal expansion. It includes the derivation of the equations involved, the finite difference equations used to solve the partial differential equation which models the system, and the results obtained using the IBM 1620 and 7090–1401 computers. Figures and tables show present results of this study of recovery as a function of reservoir thickness and injection rate. For a possible reservoir hot water flood in which 1,000 BWPD at 250F are injected, an additional 5 per cent recovery of oil in place in a swept 1,000-ft-radius reservoir is predicted after injection of one pore volume of water. INTRODUCTION The problem of predicting oil recovery from the injection of hot water has been discussed by several researchers.1–6,19 In no case has the problem of predicting heat losses been rigorously incorporated into the recovery and displacement calculation problem. Willman et al. describe an approximate method of such treatment.1 The calculation of heat losses in a reservoir and the corresponding temperature distribution while injecting a hot fluid has been attempted by several authors.7,8 In this report a method is presented to numerically predict the oil displacement by hot water in a radial system, taking into account the heat losses to adjacent strata, changes in viscosity ratio with temperature and the thermal-expansion effect for both oil and water. DERIVATION OF BASIC EQUATIONS We start with the familiar Buckley-Leverett9 equation for a radial system:*Equation 1 This can be written in the formEquation 2 This is sometimes referred to as the Lagrangian form of the displacement equation.

Liquid antisolvent recrystallization and solid dispersion of flufenamic acid with polyvinylpyrrolidone K-30

2021 ◽  
Vol 0 (0) ◽  
Author(s):  
Rahul Kumar ◽  
Sanjay Kumar ◽  
Pranava Chaudhari ◽  
Amit K. Thakur
Keyword(s):  
Particle Size ◽  
Dissolution Rate ◽  
Solid Dispersion ◽  
Fine Particles ◽  
Xrd Analysis ◽  
Solution Concentration ◽  
Injection Rate ◽  
Size Reduction ◽  
Flufenamic Acid ◽  
Particle Size Reduction

Abstract Flufenamic acid (FFA) is a Biopharmaceutical Classification System- II (BCS-II) class drug with poor bioavailability and a lower dissolution rate. Particle size reduction is one of the conventional approaches to increase the dissolution rate and subsequently the bioavailability. The use of the liquid antisolvent method for particle size reduction of FFA was studied in this work. Ethanol and water were used as solvent and antisolvent, respectively. Experimental parameters such as solution concentration (10–40 mg/ml), flow rate (120–480 ml/h), temperature (298–328 K) and stirring speed (200–800 rpm) were investigated. Furthermore, the solid dispersion of FFA was prepared with polyvinylpyrrolidone K-30 (PVP K-30) with different weight ratios (1:1, 1:2, 1:3 and 1:4) and samples were characterized using SEM, FTIR and XRD techniques. The experimental investigation revealed that higher values of concentration, injection rate, stirring speed, along with lower temperature favored the formation of fine particles. SEM analysis revealed that the morphology of raw FFA changed from rock-like to rectangular-like after liquid antisolvent recrystallization. FTIR analysis validated the presence of hydrogen bonding between FFA and PVP in solid dispersion. XRD analysis showed no significant change in the crystallinity of the processed FFA.

Application of Hybrid Biosystems for Stimulation of Oil Production

2021 ◽  
Author(s):  
Baghir Alakbar Suleimanov ◽  
Sabina Jahangir Rzayeva ◽  
Ulviyya Tahir Akhmedova
Keyword(s):  
Oil Recovery ◽  
Single Phase ◽  
Experimental Studies ◽  
Oil Production ◽  
Pore Channel ◽  
Subcritical Region ◽  
Slippage Effect ◽  
Liquid Systems ◽  
Reservoir Conditions

Abstract Microbial enhanced oil recovery is considered to be one of the most promising methods of stimulating formation, contributing to a higher level of oil production from long-term fields. The injection of bioreagents into a reservoir results in the creation of oil-dicing agents along with significant amount of gases, mainly carbon dioxide. In early, the authors failed to study the preparation of self-gasified biosystems and the implementation of the subcritical region (SR) under reservoir conditions. Gasified systems in the subcritical phase have better oil-displacing properties than non-gasified systems. The slippage effect determines the behavior of gas–liquid systems in the SR under reservoir conditions. Slippage occurs more easily when the pore channel has a smaller average radius. Therefore, in a heterogeneous porous medium, the filtration profile of gasified liquids in the SR should be more uniform than for a degassed liquid. The theoretical and practical foundations for the preparation of single-phase self-gasified biosystems and the implementation of the SR under reservoir conditions have been developedSR under reservoir conditions. Based on experimental studies, the superior efficiency of oil displacement by gasified biosystems compared with degassed ones has been demonstrated. The possibility of efficient use of gasified hybrid biopolymer systems has been shown.

The Research and Evaluation of Finely Layered Water Injection Standard in Low-Permeability Reservoirs - A Case from Block A in one Low-Permeability Reservoir

2014 ◽  
Vol 1073-1076 ◽  
pp. 2310-2315 ◽  
Author(s):  
Ming Xian Wang ◽  
Wan Jing Luo ◽  
Jie Ding
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Injection Pressure ◽  
Injection Rate ◽  
Low Permeability ◽  
Reservoir Permeability ◽  
Engineering Parameters ◽  
The Common ◽  
Common Problems ◽  
Low Permeability Reservoirs

Due to the common problems of waterflood in low-permeability reservoirs, the reasearch of finely layered water injection is carried out. This paper established the finely layered water injection standard in low-permeability reservoirs and analysed the sensitivity of engineering parameters as well as evaluated the effect of the finely layered water injection standard in Block A with the semi-quantitative to quantitative method. The results show that: according to the finely layered water injection standard, it can be divided into three types: layered water injection between the layers, layered water injection in inner layer, layered water injection between fracture segment and no-fracture segment. Under the guidance of the standard, it sloved the problem of uneven absorption profile in Block A in some degree and could improve the oil recovery by 3.5%. The sensitivity analysis shows that good performance of finely layered water injection in Block A requires the reservoir permeability ratio should be less than 10, the perforation thickness should not exceed 10 m, the amount of layered injection layers should be less than 3, the surface injection pressure should be below 14 MPa and the injection rate shuold be controlled at about 35 m3/d.

Sign in / Sign up

Export Citation Format

Share Document