scholarly journals Capillary processes increase salt precipitation during CO2 injection in saline formations

2018 ◽  
Vol 852 ◽  
pp. 398-421
Author(s):  
Helena L. Kelly ◽  
Simon A. Mathias
Keyword(s):  
High Salinity ◽  
Volume Fraction ◽  
Injection Rate ◽  
Injection Well ◽  
Co2 Injection ◽  
Salt Precipitation ◽  
Injection Wells ◽  
Tenfold Increase ◽  
Entry Pressure ◽  
Injection Rates

An important attraction of saline formations for CO2 storage is that their high salinity renders their associated brine unlikely to be identified as a potential water resource in the future. However, high salinity can lead to dissolved salt precipitating around injection wells, resulting in loss of injectivity and well deterioration. Earlier numerical simulations have revealed that salt precipitation becomes more problematic at lower injection rates. This article presents a new similarity solution, which is used to study the relationship between capillary pressure and salt precipitation around CO2 injection wells in saline formations. Mathematical analysis reveals that the process is strongly controlled by a dimensionless capillary number, which represents the ratio of the CO2 injection rate to the product of the CO2 mobility and air-entry pressure of the porous medium. Low injection rates lead to low capillary numbers, which in turn are found to lead to large volume fractions of precipitated salt around the injection well. For one example studied, reducing the CO2 injection rate by 94 % led to a tenfold increase in the volume fraction of precipitated salt around the injection well.

CALCULATION OF OPTIMAL INJECTION RATE FOR DISPERSED WATERFLOODING SYSTEM

2017 ◽  
pp. 63-67
Author(s):  
L. A. Vaganov ◽  
A. Yu. Sencov ◽  
A. A. Ankudinov ◽  
N. S. Polyakova
Keyword(s):  
Injection Rate ◽  
Oil Field ◽  
Injection Well ◽  
Water Migration ◽  
Mutual Location ◽  
Optimal Injection ◽  
Technical Measures ◽  
Injection Rates

The article presents a description of the settlement method of necessary injection rates calculation, which is depended on the injected water migration into the surrounding wells and their mutual location. On the basis of the settlement method the targeted program of geological and technical measures for regulating the work of the injection well stock was created and implemented by the example of the BV7 formation of the Uzhno-Vyintoiskoe oil field.

Successful Development and Deployment of a Novel Chemical Package for Stimulation of Injection wells, Offshore UK

2021 ◽  
Author(s):  
Dennis Alexis ◽  
Gayani Pinnawala ◽  
Do Hoon Kim ◽  
Varadarajan Dwarakanath ◽  
Ruth Hahn ◽  
...  
Keyword(s):  
Product Quality ◽  
Injection Well ◽  
Concentrated Solutions ◽  
Successful Development ◽  
Injection Wells ◽  
Polymer Injection ◽  
Remediation Process ◽  
Field Location ◽  
Stimulation Of ◽  
Injection Rates

Abstract The work described in this paper details the development of a single stimulation package that was successfully used for treating an offshore horizontal polymer injection well to improve near wellbore injectivity in the Captain field, offshore UK. The practice was to pump these concentrated surfactant streams using multiple pumps from a stimulation vessel which is diluted with the polymer injection stream in the platform to be injected downhole. The operational challenges were maintaining steady injection rates of the different liquid streams which was exacerbated by the viscous nature of the concentrated surfactants that would require pre-dilution using cosolvent or heating the concentrated solutions before pumping to make them flowable. We have developed a single, concentrated liquid blend of surfactant, polymer and cosolvent that was used in near-wellbore remediation. This approach significantly simplifies the chemical remediation process in the field while also ensuring consistent product quality and efficiency. The developed single package is multiphase, multicomponent in nature that can be readily pumped. This blend was formulated based on the previous stimulation experience where concentrated surfactant packages were confirmed to work. Commercial blending of the single package was carried out based on lab scale to yard scale blending and dilution studies. About 420 MT of the blend was manufactured, stored, and transported by rail, road and offshore stimulation vessel to the field location and successfully injected.

scholarly journals Global Sensitivity Analysis to Assess Salt Precipitation for CO2 Geological Storage in Deep Saline Aquifers

Geofluids ◽  
2017 ◽  
Vol 2017 ◽  
pp. 1-16 ◽  
Author(s):  
Yuan Wang ◽  
Jie Ren ◽  
Shaobin Hu ◽  
Di Feng
Keyword(s):  
Sensitivity Analysis ◽  
Global Sensitivity Analysis ◽  
Injection Rate ◽  
Injection Well ◽  
Saline Aquifers ◽  
Salt Precipitation ◽  
Empirical Parameter ◽  
Global Sensitivity ◽  
Morris Method ◽  
Input Variables

Salt precipitation is generated near the injection well when dry supercritical carbon dioxide (scCO2) is injected into saline aquifers, and it can seriously impair the CO2 injectivity of the well. We used solid saturation (Ss) to map CO2 injectivity. Ss was used as the response variable for the sensitivity analysis, and the input variables included the CO2 injection rate (QCO2), salinity of the aquifer (XNaCl), empirical parameter m, air entry pressure (P0), maximum capillary pressure (Pmax), and liquid residual saturation (Splr and Sclr). Global sensitivity analysis methods, namely, the Morris method and Sobol method, were used. A significant increase in Ss was observed near the injection well, and the results of the two methods were similar: XNaCl had the greatest effect on Ss; the effect of P0 and Pmax on Ss was negligible. On the other hand, with these two methods, QCO2 had various effects on Ss: QCO2 had a large effect on Ss in the Morris method, but it had little effect on Ss in the Sobol method. We also found that a low QCO2 had a profound effect on Ss but that a high QCO2 had almost no effect on the Ss value.

An Active Method for Characterization of Flow Units Between Injection/Production Wells by Injection-Rate Design

2011 ◽  
Vol 14 (04) ◽  
pp. 433-445 ◽  
Author(s):  
Kun-Han Lee ◽  
Antonio Ortega ◽  
Amir Mohammad Nejad ◽  
Iraj Ershaghi
Keyword(s):  
Reservoir Characterization ◽  
Injection Rate ◽  
High Permeability ◽  
Injection Wells ◽  
Flow Units ◽  
Weight Factors ◽  
Production Wells ◽  
Preferential Flows ◽  
Injection Rates

Summary This paper presents a novel data-mining method to characterize the flow units between injection and production wells in a waterflood, using carefully implemented variations in injection rates. The method allows the computation of weight factors representing the influence of any of the injectors surrounding a given producer. The weight factors are used to characterize the effective contribution of injection wells to the total gross production in surrounding production wells. A wavelet approach is used to design the perturbation in the injection rates and to analyze the observed variations in the gross production rates. Tracking the contribution of injectors to various producers can help in balancing voidage replacement in waterflood optimization. A second application is reservoir characterization, in which information provided by the proposed procedure can help in mapping high-permeability flow units such as channels and fractures as well as flow barriers between wells. The method was calibrated and tested successfully for simulated line-drive and five-spot patterns with various assumed flow units and flow-heterogeneity conditions. The paper also includes a case study for a tight-formation waterflood in which the weight factors are intended to delineate the pattern of natural high-permeability channels causing preferential flows.

scholarly journals Modeling Transient Flow in CO2 Injection Wells by Considering the Phase Change

Processes ◽  
2021 ◽  
Vol 9 (12) ◽  
pp. 2164
Author(s):  
Nian-Hui Wan ◽  
Li-Song Wang ◽  
Lin-Tong Hou ◽  
Qi-Lin Wu ◽  
Jing-Yu Xu
Keyword(s):  
Transient Flow ◽  
Maximum Error ◽  
Injection Rate ◽  
Co2 Injection ◽  
Injection Wells ◽  
Transient Model ◽  
Pressure Profiles ◽  
Wellbore Temperature ◽  
Temperature And Pressure

A transient model to simulate the temperature and pressure in CO2 injection wells is proposed and solved using the finite difference method. The model couples the variability of CO2 properties and conservation laws. The maximum error between the simulated and measured results is 5.04%. The case study shows that the phase state is primarily controlled by the wellbore temperature. Increasing the injection temperature or decreasing the injection rate contributes to obtaining the supercritical state. The variability of density can be ignored when the injection rate is low, but for a high injection rate, ignoring this may cause considerable errors in pressure profiles.

Migration and Storage Mechanisms of CO2 with Different Injection Rates

2012 ◽  
Vol 588-589 ◽  
pp. 15-20 ◽  
Author(s):  
Gao Fan Yue ◽  
Hai Long Tian ◽  
Tian Fu Xu ◽  
Fu Gang Wang
Keyword(s):  
Greenhouse Effect ◽  
Migration Velocity ◽  
Injection Rate ◽  
Injection Well ◽  
Geological Sequestration ◽  
Sequestration Of Co2 ◽  
And Storage ◽  
Injection Rates

Geological sequestration of CO2 in deep saline formations has been considered as an effective way to mitigate the greenhouse effect. With different rates of injection to a storage formation, the migration and storage mechanisms of CO2 are different. In this paper, we simulated the migration of CO2 based on a generic geological reservoir under simplified conditions. The results show that higher injection rate will lead to higher migration velocity and farther distance from the injection well, while it has no influence on dissolution amount when the total amounts of injected CO2 are equal.

A Model for Water Injection Into Frac-Packed Wells

2010 ◽  
Vol 13 (03) ◽  
pp. 449-464 ◽  
Author(s):  
Ajay Suri ◽  
Mukul M. Sharma
Keyword(s):  
Water Injection ◽  
Horizontal Stress ◽  
Injection Rate ◽  
Injection Wells ◽  
Solids Concentration ◽  
Sand Control ◽  
Injection Water ◽  
Large Injection ◽  
Minimum Horizontal Stress ◽  
Injection Rates

Summary Frac packs are increasingly being used for sand control in injection wells in poorly consolidated reservoirs. This completion allows for large injection rates and longer injector life. Many of the large offshore developments in the Gulf of Mexico and around the world rely on these completions for waterflooding and pressure maintenance. The performance of these injectors is crucial to the economics of the project because well intervention later in the life of the field is expensive and undesirable. For the first time, we present a model for water injection in frac-packed wells. The frac pack and the formation are plugged because of the deposition of particles from the injected water, and their effective permeability to water is continuously reduced. However, as the bottomhole pressure (BHP) reaches the frac-pack widening pressure, the frac-pack width increases and a channel that accommodates additional injected particles is created. Injectivity depends on the interstitial velocity of the injected water in the frac pack, volume concentration of the solids in the injected water, injection rate, injection-water temperature, size of proppants in the frac pack, width and length of the frac pack, and the initial minimum horizontal stress. In case of frac packs with large proppant size and high injection rates, the plugging of the frac pack is found to be negligible except in the building of a filter cake at the frac-pack walls. In the case of narrow frac packs with small proppant, significant plugging is expected, which leads to sharp permeability decline of the frac pack and a rapid rise in the BHP. The long-term injectivity of a frac-packed injector depends primarily on the filtration coefficient value of the frac pack, solids concentration in the injected water, and the injection rate. Frac packs are expected to maintain higher injectivities compared to any other completions such as openhole, cased-hole, perforated, or gravel packs.

Estimates of Fracture Lengths in an Injection Well by History Matching Bottomhole Pressures and Injection Profile

2011 ◽  
Vol 14 (04) ◽  
pp. 385-397 ◽  
Author(s):  
Ajay Suri ◽  
Mukul M. Sharma ◽  
Ekwere J. Peters
Keyword(s):  
History Matching ◽  
Injection Rate ◽  
Propagation Model ◽  
Injection Well ◽  
Permeability Reduction ◽  
Injection Wells ◽  
History Match ◽  
Transient Model ◽  
Solids Deposition ◽  
Filtration Model

Summary An injection-well model is presented and used to history match a field injector's bottomhole pressures (BHPs) and injection profile (injection rate into each layer), taking into account plugging of formation caused by suspended solids in the injection water, poro- and thermoelastic stresses, injector shut-ins/restarts, and changes in both the injection rates and the average reservoir pressure. Fracture lengths and injection profile are estimated for a field injector as a case study. The injection-well fracture model is very similar to the Perkins and Gonzalez (1985) model except that it has integrated a more comprehensive and experimentally tested internal filtration model (Rajagopalan and Tien 1976; Pang and Sharma 1997; Gadde and Sharma 2001; Suri 2000; Wennberg and Sharma 1997) for calculating permeability reduction. It has also added a pressure-transient model that makes the earlier reservoir flow models more accurate. The solids deposition is modeled using a filtration model (Rajagopalan and Tien 1976). The fluid flow in the reservoir is modeled using three approximated composite zones with uniform saturations and average mobilities, and the pressure for the fractured wellbore is calculated with the help of Gringarten's (1974) infinite-conductivity solution. The induced-fracture lengths are calculated on the basis of the Perkins and Gonzalez fracture-propagation model (1985) that accounts for the thermal and poroelastic stresses. The model is developed into a semianalytical numerical simulator that can predict and history match an injector's daily BHP, fracture lengths, and injection profile. Future estimates of pump pressures, BHP, injectivity, skin, front locations, fracture lengths, and injection profile can be obtained from this model. Both short-term pressure transients and long-term pseudosteady pressures observed over several years of injection can be history matched to capture effects that are important at both short and long time scales. Finally a field-case injection-well study is presented in which BHP and injectivity are history matched over a period of 3 years. We show that the model can be used to estimate the minimum horizontal stresses in the layers if they are not known. Estimates of fracture lengths, fraction of flow, permeability reduction, and skin and front locations are also obtained. There is significant uncertainty in the results because of uncertainty in the model inputs and in the completeness of the physics of the model of fracturing itself. Both the solids deposition and the opening/closing of the injection-induced fractures had to be accounted for to obtain the history match. The layer/sand stresses and the water quality are the most important parameters that determine the well's injectivity, fracture growth, and injection profile. Microseismic surveys and PLTs are needed to confirm fracture lengths in injection wells.

Geoengineering and Economic Assessment of a Potential Carbon Capture and Storage Site in Southeast Queensland, Australia

2009 ◽  
Vol 12 (05) ◽  
pp. 660-670 ◽  
Author(s):  
Yildiray Cinar ◽  
Peter R. Neal ◽  
William G. Allinson ◽  
Jacques Sayers
Keyword(s):  
Carbon Capture ◽  
Carbon Capture And Storage ◽  
Injection Well ◽  
Reservoir Engineering ◽  
Co2 Injection ◽  
Storage Site ◽  
Fracture Gradient ◽  
And Storage ◽  
Southeast Queensland ◽  
Injection Rates

Summary This paper presents geoengineering and economic sensitivity analyses and assessments of the Wunger Ridge flank carbon capture and storage (CCS) site. Both geoengineering and economics are needed to derive the number of wells required to inject a certain amount of CO2 for a given period. A numerical reservoir simulation examines injection rates ranging from 0.5 to 1.5 million tonnes of CO2 year for 25 years of injection. Primary factors affecting the ability to inject CO2 include permeability, formation fracture gradient, aquifer strength, and multiphase flow functions. Secondary factors include the solubility of CO2 in the formation brine, injection well location with respect to the flow barriers/low-permeability aquifers, model geometry including faults, grid size and refinement, and injection well type. Less significant factors include hydrodynamic effects. The economics are assessed using an internally developed technoeconomic model. The model optimizes the CO2 injection cost on the basis of geoengineering data and recent equipment costs. The overall costs depend on the initial costs of CO2 separation and source-to-sink distances and their associated pipeline costs. Secondary cost variations are highly dependent on fracture gradient, permeability, and CO2 injection rates. Depending on the injection characteristics, the specific cost of CO2 avoided is between AUS 62 and 80 per tonne. Introduction Australia's fossil-fuel fired power plants emit 194 million tonnes of CO2 each year (Mt CO2/yr), and approximately 26 Mt/yr of this comes from southeast Queensland. A multidisciplinary study has recently identified the onshore Bowen basin as having potential for geological storage of CO2 (Sayers et al. 2006a). In that paper, geological containment and injectivity and reservoir engineering simulation sensitivities showed that a target injection rate of 1.2 Mt CO2/yr over a 25-year project life span could be achieved (i.e., equivalent to injecting the emissions from a 400 MW gas based power station). This study further examines reservoir engineering and economics sensitivities.

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