Cold-water injection into single- and two-phase geothermal reservoirs

1990 ◽  
Vol 26 (2) ◽  
pp. 331-338 ◽  
Author(s):  
S. K. Garg
Keyword(s):  
Cold Water ◽  
Water Injection ◽  
Two Phase ◽  
Geothermal Reservoirs

Negative-Saturation Approach for Compositional Flow Simulations of Mixed CO2/Water Injection Into Geothermal Reservoirs Including Phase Appearance and Disappearance

SPE Journal ◽  
2012 ◽  
Vol 17 (02) ◽  
pp. 502-522 ◽  
Author(s):  
Hamidreza Salimi ◽  
Karl-Heinz Wolf ◽  
Johannes Bruining
Keyword(s):  
Energy Production ◽  
Single Phase ◽  
Storage Capacity ◽  
Co2 Storage ◽  
Water Injection ◽  
Phase Flow ◽  
Two Phase ◽  
Solution Approach ◽  
Geothermal Reservoirs ◽  
Compositional Flow

Summary Cold mixed CO2/water injection into hot-water reservoirs can be used for simultaneous geothermal-energy (heat) production and subsurface CO2 storage. This paper studies this process in a 2D geothermal homogeneous reservoir, a layered reservoir, and a heterogeneous reservoir represented by a stochastic-random field. We give a set of simulations for a variety of CO2/water-injection ratios. In this process, often regions of two-phase flow are connected to regions of single-phase flow. Different systems of equations apply for single-phase and two-phase regions. We develop a solution approach, called the nonisothermal-negative-saturation (NegSat) solution approach, to solve efficiently nonisothermal compositional flow problems (e.g., CO2/water injection into geothermal reservoirs) that involve phase appearance, phase disappearance, and phase transitions. The advantage of this solution approach is that it circumvents using different equations for single-phase and two-phase regions and the ensuing unstable switching procedure. In the NegSat approach, a single-phase multicomponent fluid is replaced by an equivalent fictitious two-phase fluid with specific properties. The equivalent properties are such that the extended saturation of a fictitious gas is negative in the single-phase aqueous region. We discuss the salient features of the simulations in detail. When two phases are present at the injection side, heterogeneity and layering lead to more CO2 storage compared with the homogeneous case because of capillary trapping. In addition, layering avoids movement of the CO2 to the upper part of the reservoir and thus reduces the risk of leakage. Our results also show that heterogeneity and layering change the character of the solution in terms of useful-energy production and CO2 storage. The simulations can be used to construct a plot of the recovered useful energy vs. maximally stored CO2. Increasing the amount of CO2 in the injection mixture leads to bifurcation points at which the character of the solution in terms of energy production and CO2 storage changes. For overall injected-CO2 mole fractions less than 0.04, the result with gravity is the same as the result without gravity. For larger overall injected-CO2 mole fractions, however, the plot without gravity differs from the plot with gravity because of early breakthrough of a supercritical-CO2 tongue near the caprock. The plot of the useful energy (exergy) vs. the CO2-storage capacity in the presence of gravity shows a Z-shape. The top horizontal part represents a branch of high exergy recovery and a relatively lower storage capacity, whereas the bottom part represents a branch of lower exergy recovery and a higher storage capacity.

Thermal coupling may control mechanical stability of geothermal reservoirs during cold water injection

2013 ◽  
Vol 64 ◽  
pp. 117-126 ◽  
Author(s):  
Silvia De Simone ◽  
Victor Vilarrasa ◽  
Jesús Carrera ◽  
Andrés Alcolea ◽  
Peter Meier
Keyword(s):  
Mechanical Stability ◽  
Cold Water ◽  
Water Injection ◽  
Thermal Coupling ◽  
Geothermal Reservoirs

Nonisothermal Single- and Two-Phase Flow Through Consolidated Sandstones

1976 ◽  
Vol 16 (03) ◽  
pp. 137-146 ◽  
Author(s):  
N. Arihara ◽  
H.J. Ramey ◽  
W.E. Brigham
Keyword(s):  
Heat Loss ◽  
Two Phase Flow ◽  
Cold Water ◽  
Water Injection ◽  
Injection Rate ◽  
Hot Water ◽  
Fluid Injection ◽  
Phase Flow ◽  
Two Phase ◽  
The Core

Abstract This study concerns nonisothermal single- and two-phase flow of a single-component fluid (water) in consolidated porous media. Linear flow experiments through cylindrical consolidated cores were performed. Both natural (Berea) and synthetic cement-consolidated performed. Both natural (Berea) and synthetic cement-consolidated sand cores were used. Fabrication of the synthetic sandstones was important to permit reproducible fabrication of high-porosity, low-permeability sandstones with thermowells, pressure ports, and glass-tube capacitance probe guides cast in place. Both hot-fluid and cold-water injection experiments were carried out in natural and synthetic sandstones. The thermal efficiency of hot-water and cold-water injection was found to depend on heat injection rate: the higher the heat injection rate, the higher the thermal efficiency. One important result of this study is that much of the previous work with nonisothermal single-phase flow in unconsolidated sands may be extended to consolidated sandstones despite the differences in the isothermal flow characteristics of these systems. In two-phase boiling flow experiments, hot, compressed liquid water entered the upstream end of the core, moved downstream, started vaporizing, and flowed through the remainder of the core as a mixture of steam and liquid water. Significant decreases in both temperature and pressure occurred within the two-phase region. Even for large temperature changes, it was found that two-phase flow can be nearly isenthalpic and steady state if heat transfer between the core and the surroundings is at a low level. Introduction Geothermal energy is being given much attention as a new source of energy. Prime questions in geothermal energy extraction are (1) how much energy can be recovered, and (2) how fast can it be extracted? To find useful answers to these questions, the basic nature of the boiling flow of water in porous media must be understood. Literature on oil recovery by hot-fluid injection and underground combustion presents some of the important features of nonisothermal, two-phase flow that appear pertinent to geothermal reservoirs. The injection of hot water to effect oil recovery was commonly considered before 1930. In 1930, Barb and Shelley mentioned a rumor that hot-water flooding had been tried in New York State and abandoned because of excessive cost. The heating and economic results of hot-water injection were evaluated in this pioneering study. pioneering study. The next study of heat transport in a formation caused by hot-fluid injection was presented by Stovall in 1934. Both laboratory and field experiments were described. Field determination of both wellbore heat losses and vertical losses from a heated formation were described in this remarkable study. Apparently, the next study of vertical heat loss on hot-fluid injection was published by Lauwerier in 1955. It was assumed that injection rate, Vw, and temperature, Ti, would remain constant; thermal conductivity in the direction of flow was zero; and the thermal conductivity in the flooded layer perpendicular to the direction of flow was infinite so that the temperature in the flooded layer, T1, was always constant at a given location in the flooded zone. Prats has called the latter condition the "Lauwerier assumption." The conductivity in the overburden and underburden, 2, was assumed to be finite and constant. The loss of heat from the injected fluid to the adjacent strata resulted in a decrease in temperature in the direction of flow. Lauwerier derived the temperature both in the injection interval and the adjacent strata as a function of time and distance. In 1959, Marx and Langenheim presented a solution for a heat-loss problem related to the one considered by Lauwerier, but where the heated region remained at a constant temperature equal to the injection temperature. Vertical heat loss reduced the size of the heated region. SPEJ P. 137

scholarly journals Study on Thermo-Hydro-Mechanical Coupling and the Stability of a Geothermal Wellbore Structure

Energies ◽  
2021 ◽  
Vol 14 (3) ◽  
pp. 649
Author(s):  
Xiaolin Huan ◽  
Gao Xu ◽  
Yi Zhang ◽  
Feng Sun ◽  
Shifeng Xue
Keyword(s):  
Effective Stress ◽  
Cold Water ◽  
Drilling Fluid ◽  
Water Injection ◽  
Coupled Model ◽  
In Situ Stress ◽  
Excess Pore Pressure ◽  
Mechanical Coupling ◽  
Open Hole ◽  
Cement Sheath

For processes such as water injection in deep geothermal production, heat transfer and fluid flow are coupled and affect one another, which leads to numerous challenges in wellbore structure safety. Due to complicated wellbore structures, consisting of casing, cement sheaths, and formations under high temperature, pressure, and in situ stress, the effects of thermo-hydro-mechanical (THM) coupling are crucial for the instability control of geothermal wellbores. A THM-coupled model was developed to describe the thermal, fluid, and mechanical behavior of the casing, cement sheath, and geological environment around the geothermal wellbore. The results show that a significant disturbance of effective stress occurred mainly due to the excess pore pressure and temperature changes during cold water injection. The effective stress gradually propagated to the far-field and disrupted the integrity of the wellbore structure. A serious thermal stress concentration occurred at the junction of the cased-hole and open-hole section. When the temperature difference between the injected water and the formation was up to 160 °C, the maximum hoop tensile stress in the granite formation reached up to 43.7 MPa, as high as twice the tensile strength, which may increase the risk of collapse or rupture of the wellbore structure. The tensile radial stress, with a maximum of 31.9 MPa concentrated at the interface between the casing and cement sheath, can cause the debonding of the cementing sheath. This study provides a reference for both the prediction of THM responses and the design of drilling fluid density in geothermal development.

Analytical Rate-Transient Analysis and Production Performance of Waterflooded Fields with Delayed Injection Support

2021 ◽  
pp. 1-23
Author(s):  
Daniel O'Reilly ◽  
Manouchehr Haghighi ◽  
Mohammad Sayyafzadeh ◽  
Matthew Flett
Keyword(s):  
Steady State ◽  
Transient Analysis ◽  
Water Injection ◽  
Data Interpretation ◽  
Production Performance ◽  
Production Data ◽  
Reservoir Properties ◽  
Two Phase ◽  
Production Forecasting ◽  
Rate Transient Analysis

Summary An approach to the analysis of production data from waterflooded oil fields is proposed in this paper. The method builds on the established techniques of rate-transient analysis (RTA) and extends the analysis period to include the transient- and steady-state effects caused by a water-injection well. This includes the initial rate transient during primary production, the depletion period of boundary-dominated flow (BDF), a transient period after injection starts and diffuses across the reservoir, and the steady-state production that follows. RTA will be applied to immiscible displacement using a graph that can be used to ascertain reservoir properties and evaluate performance aspects of the waterflood. The developed solutions can also be used for accurate and rapid forecasting of all production transience and boundary-dominated behavior at all stages of field life. Rigorous solutions are derived for the transient unit mobility displacement of a reservoir fluid, and for both constant-rate-injection and constant-pressure-injection after a period of reservoir depletion. A simple treatment of two-phase flow is given to extend this to the water/oil-displacement problem. The solutions are analytical and are validated using reservoir simulation and applied to field cases. Individual wells or total fields can be studied with this technique; several examples of both will be given. Practical cases are given for use of the new theory. The equations can be applied to production-data interpretation, production forecasting, injection-water allocation, and for the diagnosis of waterflood-performanceproblems. Correction Note: The y-axis of Fig. 8d was corrected to "Dimensionless Decline Rate Integral, qDdi". No other content was changed.

scholarly journals Investigation of Water Composition on Formation Damage and Related Energy Recovery from Geothermal Reservoirs: Geochemical and Geomechanics Insights

Energies ◽  
2021 ◽  
Vol 14 (21) ◽  
pp. 7415
Author(s):  
Ilyas Khurshid ◽  
Imran Afgan
Keyword(s):  
Geothermal Energy ◽  
Water Injection ◽  
Formation Damage ◽  
Breakdown Pressure ◽  
Geothermal Reservoirs ◽  
Water Composition ◽  
Porosity Reduction ◽  
Reduction Case ◽  
Formation Porosity

The main challenge in extracting geothermal energy is to overcome issues relating to geothermal reservoirs such as the formation damage and formation fracturing. The objective of this study is to develop an integrated framework that considers the geochemical and geomechanics aspects of a reservoir and characterizes various formation damages such as impairment of formation porosity and permeability, hydraulic fracturing, lowering of formation breakdown pressure, and the associated heat recovery. In this research study, various shallow, deep and high temperature geothermal reservoirs with different formation water compositions were simulated to predict the severity/challenges during water injection in hot geothermal reservoirs. The developed model solves various geochemical reactions and processes that take place during water injection in geothermal reservoirs. The results obtained were then used to investigate the geomechanics aspect of cold-water injection. Our findings presented that the formation temperature, injected water temperature, the concentration of sulfate in the injected water, and its dilution have a noticeable impact on rock dissolution and precipitation. In addition, anhydrite precipitation has a controlling effect on permeability impairment in the investigated case study. It was observed that the dilution of water could decrease formation of scale while the injection of sulfate rich water could intensify scale precipitation. Thus, the reservoir permeability could decrease to a critical level, where the production of hot water reduces and the generation of geothermal energy no longer remains economical. It evident that injection of incompatible water would decrease the formation porosity. Thus, the geomechanics investigation was performed to determine the effect of porosity decrease. It was found that for the 50% porosity reduction case, the initial formation breakdown pressure reduced from 2588 psi to 2586 psi, and for the 75% porosity reduction case it decreased to 2584 psi. Thus, geochemical based formation damage is significant but geomechanics based formation fracturing is insignificant in the selected case study. We propose that water composition should be designed to minimize damage and that high water injection pressures in shallow reservoirs should be avoided.

scholarly journals Numerical Simulation of Two-Phase Flows in Heterogeneous Porous Media

2020 ◽  
Vol 21 (2) ◽  
pp. 339
Author(s):  
I. Carneiro ◽  
M. Borges ◽  
S. Malta
Keyword(s):  
Porous Media ◽  
Oil Recovery ◽  
Flow Behavior ◽  
Water Injection ◽  
Heterogeneous Porous Media ◽  
Flow In Porous Media ◽  
High Porosity ◽  
Two Phase ◽  
Recovery Method ◽  
Porosity And Permeability

In this work,we present three-dimensional numerical simulations of water-oil flow in porous media in order to analyze the influence of the heterogeneities in the porosity and permeability fields and, mainly, their relationships upon the phenomenon known in the literature as viscous fingering. For this, typical scenarios of heterogeneous reservoirs submitted to water injection (secondary recovery method) are considered. The results show that the porosity heterogeneities have a markable influence in the flow behavior when the permeability is closely related with porosity, for example, by the Kozeny-Carman (KC) relation.This kind of positive relation leads to a larger oil recovery, as the areas of high permeability(higher flow velocities) are associated with areas of high porosity (higher volume of pores), causing a delay in the breakthrough time. On the other hand, when both fields (porosity and permeability) are heterogeneous but independent of each other the influence of the porosity heterogeneities is smaller and may be negligible.

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