Injection Wellbore Research Articles

Flow simulation of the mixture system of supercritical CO2 & superheated steam in toe-point injection horizontal wellbores

Conventional heavy oil recovery method of saturated steam injection at heel-point of horizontal wellbores is facing comparatively more serious fingering phenomenon. With this, oil companies are now actively developing new recovery method of supercritical CO2 - superheated steam injection in horizontal wellbores with toe-point injection technique.Firstly, considering the heat exchange between the inner tubing (IT) and annuli, a pipe flow model comprised of energy and momentum conservation equations is developed for the mixture flow in both IT and annuli. Then, coupled with the S-R-K real gas model, variable mass flow model and transient heat transfer model in oil layer, a comprehensive mathematical model is established. Numerical solutions of the mixture flow in toe-point injection wellbores are obtained through straight forward numerical method. Finally, model validation and sensitivity analysis are conducted.The results show that: (1). there exists a good agreement between predicted results and field data. The predicted temperature is higher when the heat exchange between IT and annuli is neglected. The predicted temperature is lower when the friction loss item is considered in the energy balance equation. (2). the temperature of the mixture increases when the mixture flows from toe-point to heel-point in annuli due to heat flow from IT to annuli. (3). While the absorption rate of the mixture in formation increases with increasing of the content of supercritical CO2, it can be offset by the decrease of temperature and enthalpy of the mixture. (4). Both of the mixture temperature and formation mixture absorption rate increase with increasing of injection pressure.

COUPLED NUMERICAL SIMULATION OF FRACTURING MULTILAYER RESERVOIR FLOW WITH LEAN-STRATIFIED WATER INJECTION

Many multilayer sandstone reservoirs have reached extreme high water content and high recovery stage after long time waterflooding. These inner LPTOLs have been the main potential reserves. Lean-stratified water injection is one of the most important technologies to increase production and develop potential for multilayer oilfields with extreme high water content. However, traditional models cannot entirely solve the inner boundary conditions of lean-stratified water injection. Therefore, we established the injection wellbore constraint equations, which were coupled with the oil/water two-phase numerical reservoir models. Upon an embedded fracture model for simulating hydraulic fractures, a method to simulate the reservoir with horizontal fractures is shown. The influences of reservoir and fluid, horizontal fractures, and injection-production characteristics are analyzed for oil production and water-content dynamic. Considering the specific situation of lean-stratified water injection wells, the influences of different segments numbers, modes of combination in segment layers, and rhythm characteristics of remaining oil reserves and distribution are evaluated.

A numerical study on the feasibility of evaluating CO2injection wellbore integrity through casing deformation monitoring

AbstractDistributed sensing technologies have been increasingly used for downhole monitoring in the oil field in recent years. A casing deformation monitoring system based on distributed strain sensors has been developed and proposed for wellbore integrity monitoring. However, due to the lack of field data on casing deformation induced by various exploration and development activities, the relationship between casing deformation and wellbore integrity remains unclear. To study the feasibility of evaluating short‐term CO2injection wellbore integrity through casing deformation monitoring, a staged finite element analysis is conducted for an existing well in the Weyburn field to study the relationship between casing deformation and wellbore integrity during CO2injection. The model is generated with HypermeshTMand the analysis is conducted with AbaqusTM. The staged finite element model applies loads and materials in multiple steps to replicate the actual drilling process. The wellbore stress, casing strain, and interface gap distance change at the surface casing shoe and production casing shoe are calculated. A parametric study is also conducted to study the effect of various parameters on CO2injection wellbore integrity in the Weyburn field. The result shows that the casing deformation can be correlated to the wellbore integrity by cement expansion/shrinkage through its effect on the interface gap distance change and the stress difference between wellbore components induced by CO2injection. © 2017 Society of Chemical Industry and John Wiley & Sons, Ltd.

Epoxy resin‐cement paste composite for wellbores: Evaluation of chemical degradation fostered carbon dioxide

AbstractExcessive carbon dioxide (CO2) environmental emission can be partially solved using carbon geological storage technologies. Up‐to‐date materials in CO2 injection wells are strongly susceptible to acidic attacks causing their irreversible damage over a long time scale. This study investigates degradation by CO2 of epoxy resin‐cement paste composites at elevated pressure (50 bar) and temperature (70°C) to mimic wellbore conditions. The effect of epoxy resins on cement carbonation was evaluated by phenolphthalein test, field emission scanning electron microscopy (FESEM), atomic force microscopy (AFM), Fourier transform infrared spectroscopy (FTIR), thermogravimetric analysis (TGA), and numerical simulations. According to electronic‐structure‐based molecular dynamics simulations, the epoxy resin forms a separate phase that blocks potential reaction sites between the cement and CO2. Thanks to CO2‐phobic behavior, the resin repels CO2 and minimizes cement damage due to degradation process. The optimal content of epoxy resin in the cement paste was up to 30% w/w. The reported results provide clear guidelines for further evolution of reinforced cements for use in CO2 injection wellbores. © 2017 Society of Chemical Industry and John Wiley & Sons, Ltd.

Large Rock Mass Experimentation @ Mont Terri Underground Research Laboratory – CO2 Containment Assurance Experiments

The Mont Terri Underground Research Laboratory (MT-URL) and Consortia affords member organizations the opportunity to bridge the gap between bench and large field scale experiments. At this underground test site, CCP4 (CO2 Capture Project Phase 4) partners, a four company collaboration that includes BP, Chevron, Petrobras and Suncor, along with the Swiss Topographic Survey (swisstopo) who operates the laboratory, are conducting 1) an experiment that focuses on the mitigation of pressure leakages associated with CO2 containment in near wellbore injection well systems using novel sealants and, if resources are available, 2) a fractured caprock breach sealing experiment.The mock well system experiment for CO2 breach mitigation is of immediate interest. This experiment, designated CS-A, is operational with equipment installation accomplished late 2nd quarter 2015 and experimental protocols that commenced late December 2015 scheduled to run through the summer of 2017. Sealant testing is scheduled to begin in late 2016. The objective is to assess the ability to characterize and seal induced leaks at micro annular interfaces (casing, cement and country rock) using novel sealants with determination of the long term sealing integrity. The 2nd experiment is in an earlier stage of development, having been scoped in 2014 for costing and resource alignment. This second project requires additional participants to spread costs before the final design is set.

An object-based modeling and sensitivity analysis study in support of CO2 storage in deep saline aquifers at the Shenhua site, Ordos Basin

The Shenhua Carbon Capture and Storage (CCS) project at the Shenbei Slope injection site in North Yulin is the first 100,000 ton/year scale CCS pilot project in China with an injection operation lasting nearly 3 years. While the project turned into an operational success with 300,000 tons of CO2 being sequestered, several aspects of reservoir dynamic behavior and the role of reservoir heterogeneity are not clearly understood. For example, although there was an initial period of wellhead pressure (WHP) increase at the injection well, WHP incrementally declined for most of the time. The majority of CO2 was received by the topmost sandstone of the Liujiagou formation in the injection interval instead of the lowermost limestone of the Majiagou formation, suggesting strong reservoir heterogeneity. Knowledge of the key reservoir processes and properties that resulted in these observations would help for predicting long-term storage safety and aiding the design of a larger-scale CCS operation at the same site. In this study, we investigate various object-based models and important reservoir parameters to determine aspects of heterogeneity that have the most impact on pressure behavior at the injection well and the observed plume dynamics after injection. Simulation results suggest that the extent of CO2 plume is most sensitive to the geometry of fluvial channels, and specifically, the amount of connected sandbodies that facilitate lateral fluid migration. Along with the injection rate, sandbody permeability plays a significant role in determining pressure near the injection well and in the reservoir. Further work will incorporate the dynamics of CO2 flow down the injection wellbore to derive a more accurate representation of injection rate under the reservoir condition. As drilling and analog data also suggest that fractures may exist in the Liujiagou formation, future work will also construct geomechanical models to investigate the effect of fractures on injection and storage.

Numerical modeling on in-situ combustion process in the Chichimene field: Ignition stage

In this paper were evaluate the ignition behavior of the in-situ combustion (ISC) process in the Chichimene field using a reservoir commercial software. To development this study, the reactions of partial oxidation were represented by a single reaction in which oil reacts with oxygen and produces oxygenated oil. To achieve this, experimental evaluations were carried out in order to determine the stoichiometric coefficients and the kinetic parameters of the proposed reaction. In this approach was using a numerical model based on mass and energy balances to the closeness of the injection wellbore in order to adjust the frequency factor of the reservoir numerical model. The results indicated that is possible simulate the ignition stage of ISC process in a commercial software by using just one reaction, and for the specific case of Chichimene field this numerical model show that it will present a short ignition delayed which indicate high probability to get a spontaneous ignition to the current reservoir conditions and the distance at which ignition occurs can be modified by the air injection rate.

Coupled numerical simulation of multi-layer reservoir developed by lean-stratified water injection

Lean-stratified water injection is one of the most important technologies to increase production and develop potentials for the oilfield with extreme high water content. However, traditional models cannot entirely solve the inner boundary conditions of lean-stratified water injection. Therefore, we established the injection wellbore constraint equations, which were coupled with the oil/water two-phase numerical reservoir models, and then the seven diagonal form sparse coefficient matrix was solved by block precondition of generalized minimal residual algorithm. Considering the specific situation of lean-stratified water injection wells, reservoir geology and production schemes of the middle part of the sixth Oilfield in Xing Shugang, three mechanism models of multi-layer heterogeneous reservoir were constructed to simulate the lean-stratified water injection. The influences of different segments numbers, modes of combination in segment layer and rhythm characteristics of remaining oil reserves and distribution are evaluated.

Prediction of CaCO3 scaling in water injection wellbore

This paper conducts a study on the CaCO3 scaling in water injection wellbore. With the combined effect of fluid flow and heat transfer on scaling taken into consideration, a mathematical model for predicting the scaling of CaCO3 was developed, which is based on the model for the calculation of deposition and removal mass rates. The scaling prediction software of water injection well was developed. The software was used to predict the scaling in a water injection wellbore of low permeability reservoir in Shengli Oilfield. The prediction result is in good agreement with measurement result. It is also found that the scale layer thickness increases with the increase of water injection time and scale-forming ions concentration, while it decreases with the increase of daily water injection rate. As a consequence, in order to reduce scaling in the wellbore, it is reasonable to shorten the water injection times, increase water injection rate and purify the injection water.

Development of a semi-analytical method to calculate depth-dependent temperature and stress changes: investigation of micro-seismicity at Unterhaching Uha GT-2 geothermal well

Since October 2007 when the hydrothermal production of geothermal energy from the deep underground started at Unterhaching, near Munich (Germany), several micro-seismic events have been observed. Three of the five strongest events, with local magnitudes (ML) ranging from 2.0 to 2.4, occurred in 2008 and were partially felt by the residents. The reasons for these events are not clear. These micro-seismic events could have been induced by a variety of factors. The strongest micro-seismic event was observed soon after the injection of cold water, pointing to an intrinsic relationship between micro-seismic event and cold water injection. One of the possible reasons for the observed micro-seismic events could be the reinjection of cooled thermal water into the hotter underground inducing stress redistribution and shear failures in the reservoir formations around the injection wellbore Uha GT-2. To justify this reason, further investigation will be carried out in another simulation study to verify whether the shear failures induced by cold water injection were the major cause for the occurrence of these micro-seismic events. Nevertheless, before the simulation of shear failures, temperature profiles in both the wellbore and surrounding rocks as well as their corresponding thermal stresses during cold water injection should be established in this study. In this paper, a new semi-analytical simulation method has been developed to calculate simultaneously the temperature profiles in the wellbore and the surrounding rock formations and also determine the corresponding thermal stresses in the surroundings near wellbore field and subsequently verified by analytical solution. Results show that great tensile thermal stresses in the reservoir were initiated by the injection of the cooled thermal water in the injection wellbore Uha GT-2. The results of the simulated thermal stresses indicate a great potential for the ensuing shear failures to affect an extensive area and could be used as input data for the planned shear failure simulations in the future.

Numerical Simulation of Stress Change during Wellbore Injection

The important matter during any process in the well is wellbore integrity. Regarding to the geomechanics of the well, high bottom-hole pressure and low temperature could lead to the fracturing. The stress near the wellbore is a function of the flow and temperature, and it precisely determined to avoid the wellbore failure. The objective of this paper is to simulate stress change in the well for the injection. In order to analyze the stress in the wellbore a finite volume analysis has done for the wellbore. The stress equation relates to flow equation with the equation of principle stress. It means that the pressure is a key parameter for determination of the stress. The procedure which has to be followed is transforming the equations to weak form, meshing the defined shape and programing to obtain the values for each node. The result for the stress is obtained for some meshed bodies. The accuracy enhanced by choosing smaller mesh sizing.

Development of connected permeability in massive crystalline rocks through hydraulic fracture propagation and shearing accompanying fluid injection

AbstractThe ability to generate deep flow in massive crystalline rocks is governed by the interconnectivity of the fracture network and its permeability, which in turn is largely dependent on the in situ stress field. The increase of stress with depth reduces fracture aperture, leading to a decrease in rock mass permeability. The frequency of natural fractures also decreases with depth, resulting in less connectivity. The permeability of crystalline rocks is typically reduced to about 10−17–10−15 m2 at targeted depths for enhanced geothermal systems (EGS) applications, that is, >3 km. Therefore, fluid injection methods are required to hydraulically fracture the rock and increase its permeability. In the mining sector, fluid injection methods are being investigated to increase rock fragmentation and mitigate high‐stress hazards due to operations moving to unprecedented depths. Here as well, detailed understanding of permeability and its enhancement is required. This paper reports findings from a series of hydromechanically coupled distinct‐element models developed in support of a hydraulic fracture experiment testing hypotheses related to enhanced permeability, increased fragmentation, and modified stress fields. Two principal injection designs are tested as follows: injection of a high flow rate through a narrow‐packed interval and injection of a low flow rate across a wider packed interval. Results show that the development of connected permeability is almost exclusively orthogonal to the minimum principal stress, leading to strongly anisotropic flow. This is because of the stress transfer associated with opening of tensile fractures, which increases the confining stress acting across neighboring natural fractures. This limits the hydraulic response of fractures and the capacity to create symmetric isotropic permeability relative to the injection wellbore. These findings suggest that the development of permeability at depth can be improved by targeting a set of fluid injections through smaller packed intervals instead of a single longer injection in open boreholes.

Geochemical effects of an oxycombustion stream containing SO2 and O2 on carbonate rocks in the context of CO2 storage

This paper describes the effects of the injection of a CO2-dominated gas mixture into a geologic reservoir rock through experimental work in the context of limiting greenhouse gas emissions into the atmosphere. The injected gas mixture consists of the exhaust fumes from an oxyboiler without desulphurisation with the following mole fraction composition: CO2=0.82, SO2=0.04, O2=0.04, N2=0.04 and Ar=0.06. Corresponding experiments using pure CO2 and N2 were performed as a benchmark. The rock sample was obtained by drilling to a depth of 4600m into a low-porosity dolostone reservoir containing micrometric to centimetric fractures in the south-west of France (northern Pyrenees). The fracture network represents the primary volume available for CO2 storage and is partly filled with dolomite separated from the rock matrix by a thin layer of calcite covering the wall rocks. Experimental reactivity of the rock was tested in 2-cm3 batch reactors in the presence of saline water (25g/l NaCl) and a gas phase (pure N2, pure CO2 and gas mixture). Chemical analyses of the reacting solutions indicated that the mineralogic assemblage during exposure to pure CO2 was in equilibrium with the aqueous solution. Raman analyses of the gas phase revealed only the presence of CO2. Optical and electronic microscopy of the resultant solid phases indicated partial dissolution of carbonates and oxidation of the pyrite surfaces. In the presence of the gas mixture, important mineralogic alteration occurred together with the consumption of half of the O2 and total consumption of the SO2. This high reactivity with the gas mixture leads to the complete dissolution of calcite and partial dissolution of dolomite and the precipitation of anhydrite and barite, particularly in the zones where the calcite was initially present. Similarly, pyrite was completely oxidised to hematite. Analyses of the rock samples indicated partial alteration of the clay minerals in the matrix to potassic beidellite in the experiment involving pure CO2 and solely to vermiculites in the gas mixture experiment. In conclusion, the presence of SO2 in the injection stream associated with the presence of O2 results in an early strong acidification of the water, which was buffered by the significant reactivity of the carbonates (dissolution of all of the calcite and 6% of the dolomite) and partial alteration of the clay minerals (87% of illite and 100% of smectite) to vermiculites. Pyrite and aqueous Fe from clays were completely oxidised by O2, resulting in hematite and Fe3+. The mineralogic alteration and consequent volume changes under experimental conditions led to a slight increase in the porosity of the dolomite matrix and an average pore volume loss of 11% in the fractures caused by the replacement of calcite with anhydrite. Due to its high reactivity with carbonate, SO2 can react early during the injection phase. The spatial distribution of calcite in the fractures of the reservoir has to be considered as one of the primary parameters controlling the evolution of the reservoir in terms of injectivity and petrophysical properties, particularly in the zone near the injection wellbores. The integrity of the calcite-rich caprock is, however, ensured due to its thickness (more than 1000m) and its calcite content, which leads to pH buffering and anhydrite precipitation, which, in turn, induces a porosity reduction and a possible coating of the rock formation.

The Performance of a High Paraffin Reservoir Under Non-isothermal Waterflooding

This study analyzes the performance of a high paraffin reservoir under cold waterflooding for 17 years using a 3-D finite difference simulator and analytical solution of injection wellbore temperature profile to upgrade reservoir management strategies. The reservoir has been marked by injectivity issues, early injection rate decline by half initial values and low incremental recovery, hence subject to alternate developmental schemes. The influence of cold waterflooding is assessed from simulated temperature maps due to nonisothermal injection and solution of injection well temperature profile.

Simulation of Formation Damage after Long-Term Water Flooding

Water flooding is a commonly used technology for enhancing oil recovery. Its main mechanism is to maintain higher pressure to sweep oil towards production wells. However, the strong water flooding will cause higher compression pressure around the injection wellbore. This high pressure in the reservoir causes stress redistribution and higher stress near the wellbore which induces material damage and permeability change. We developed a fluid-solid coupling finite element model to simulate and quantitatively analyze the pressure evolution in the reservoir as well as damage and permeability change in the formation during long-term water flooding process. The obtained results offer theoretical understanding of the benefits (pore pressure increase in the simulation domain), rock damage, permeability change of long-term water flooding, and the insights of how to detect and prevent wellbore failure and collapse due to water flooding.

From geology to economics: Technico-economic feasibility of a biofuel-CCS system

This paper presents a method to estimate the technical and economic feasibility of capturing and geologically storing CO2 resulting from biomass fermentation. The methodology is applied to the case of bio-refineries in the Paris Basin, France. The first step is to build a 3D geological model of the area studied and to choose the optimal injection location from geological and environmental constraints. Then, based on this information, the design of the CCS system (pipeline length, number and type of wellbores, surface equipment …) and the estimation of the technical feasibility (sufficient storage capacity, risk analysis and management …) can be performed. The last step is the estimation of the environmental benefits of this system (through a carbon and energy footprint) and its economic long term feasibility thanks to a discounted cash flow analysis. The impact of geological constraints on the economic feasibility of the system is estimated through a sensitivity assessment on the number of required injection wellbores.

Risk management in a large-scale CO2 geosequestration pilot project, Illinois, USA

Risk management in a large-scale CO2 geosequestration pilot project, Illinois, USA

An experimental and numerical investigation into the impact of dissolution/precipitation mechanisms on CO 2 injectivity in the wellbore and far field regions

Carbon dioxide capture and storage (CCS) technology is gaining credibility as the best short to medium term solution for significantly reducing net carbon emissions into the atmosphere. From a capacity point of view, deep saline aquifers offer the greatest potential for CO 2 storage. In this respect, well injectivity is considered a key technical and economical issue. Rock/fluid interactions – dissolution/precipitation of minerals, in particular carbonates – are currently considered as one of the principal reasons for wellbore injectivity changes in aquifers. This research investigated the mechanisms involved in injectivity losses through experimental and theoretical methods. The impact on injectivity of permeability changes occurring at various distances from the wellbore was studied using an idealised CO 2 injection well flow model. A new experimental set-up was used to investigate the effect on dissolution/precipitation mechanisms of the pressure and temperature changes that the fluid is subjected to as it advances from the wellbore. Numerical modelling of the injection wellbore has shown that changes in the petrophysical properties of the reservoir several metres away from the wellbore can still have a significant impact on injectivity. As indicated by the experimental research carried out, pressure and temperature gradients that exist inside the reservoirs may lead to re-precipitation in the far field, however no significant permeability and porosity changes were detected to suggest major losses of injectivity due to these effects.

Calculation model of on-way parameters and heating radius in a superheated steam injection wellbore

Abstract As superheated steam is a single-phase gas, it does not fit theories of ordinary steam heat loss calculation models based on two-phase flow. By using the PVT data of superheated steam, this paper builds a calculation model of on-way parameters in the superheated steam injection wellbore. The superheated steam heating area and heating radius formulae are presented. The calculated results for on-the-way change of steams in Well X16 of the Kenneyak oilfield fit well with the field test results. The analysis shows that the temperature of superheated steam varies greatly with heat transfer, the pressure varies greater than for ordinary steam, the steam quality is high when reaching the bottom hole, the steam enthalpy is much higher than for ordinary steam, and the heating radius is wider.

Sulfide Remediation by Pulsed Injection of Nitrate into a Low Temperature Canadian Heavy Oil Reservoir

Sulfide formation by oil field sulfate-reducing bacteria (SRB) can be diminished by the injection of nitrate, stimulating the growth of nitrate-reducing bacteria (NRB). We monitored the field-wide injection of nitrate into a low temperature (approximately 30 degrees C) oil reservoir in western Canada by determining aqueous concentrations of sulfide, sulfate, nitrate, and nitrite, as well as the activities of NRB in water samples from 3 water plants, 2 injection wells, and 15 production wells over 2 years. The injection water had a low sulfate concentration (approximately 1 mM). Nitrate (2.4 mM, 150 ppm) was added at the water plants. Its subsequent distribution to the injection wells gave losses of 5-15% in the pipeline system, indicating that most was injected. Continuous nitrate injection lowered the total aqueous sulfide output of the production wells by 70% in the first five weeks, followed by recovery. Batchwise treatment of a limited section of the reservoir with high nitrate eliminated sulfide from one production well with nitrate breakthrough. Subsequent, field-wide treatment with week-long pulses of 14 mM nitrate gave breakthrough at an additional production well. However, this trend was reversed when injection with a constant dose of 2.4 mM (150 ppm) was resumed. The results are explained by assuming growth of SRB near the injection wellbore due to sulfate limitation. Injection of a constant nitrate dose inhibits these SRB initially. However, because of the constant, low temperature of the reservoir, SRB eventually grow back in a zone further removed from the injection wellbore. The resulting zonation (NRB closest to and SRB further away from the injection wellbore) can be broken by batch-wise increases in the concentration of injected nitrate, allowing it to re-enter the SRB-dominated zone.