Injection Wellbore Research Articles

Study on the phase state and temperature-pressure distribution of CO2 injection wellbore and its effect on tubing stress conditions

This study investigates the phenomena observed during CO₂ injection processing in wellbores, particularly the annular pressure buildup typically attributed to inadequate packer sealing. We propose that temperature, pressure, and phase changes during CO₂ injection induce equivalent stresses, leading to packer unsealing. A detailed CO₂ injection model was developed, incorporating temperature-pressure coupling and phase transitions using the state equation. The model evaluates the effects of injection temperature, pressure, and volume on CO₂ density, temperature, pressure, phase state, and velocity, and calculates the stress on the tubing at various depths. Validation against actual measurements showed errors of 1.43% for pressure and 0.66% for temperature, confirming the model's accuracy. Key findings reveal that injection temperature significantly affects CO₂ phase changes, while injection temperature and volume respectively impact stress at the wellhead and bottom. The model provides a robust tool for optimizing CO₂-EOR processes, confirming that changes in injection parameters can indeed cause packer unsealing, and its reliance on precise input data highlights the need for accurate field measurements.

Kinetics of In-Situ Calcium Magnesium Carbonate Precipitation and the Need for Desulfation in Seawater-Flooded Carbonate Reservoirs

Summary Mixing of incompatible injection and formation brines leads to the deposition of inorganic sulfate scales such as barite, celestite, and anhydrite in and around production wells. This process is well documented in seawater-flooded clastic reservoirs. One technique to avoid the resulting formation damage is to remove sulfate from seawater before injection using nanofiltration; however, this process is costly. We identify in this paper that it may not always be necessary in higher-temperature carbonate reservoirs. In this paper, we describe the use of reactive transport reservoir simulation to investigate the impact of carbon dioxide (CO2) partitioning and changes in pH, ionic concentrations, and temperature on carbonate reactivity and the sulfate scaling risk in waterflooded carbonate reservoirs. Dissolution and precipitation of calcite, dolomite, gypsum, anhydrite, barite, and celestite are all modeled and found to be coupled through (various) common ion effects. The produced brine compositions are used to calculate the saturation ratios (SRs) and mass of precipitate that may form in the production system. Sensitivity to mineral reaction kinetics, particularly for the dolomite reactions, is accounted for. Results identify that there is a strong relationship between calcite dissolution and dolomite (or other calcium/magnesium carbonate mineral) precipitation reactions, which drive each other and are affected by the availability of CO2 in the residual oil phase. This evolves over time, and as the thermal front propagates, impacts the concentration of calcium and magnesium in the brines traversing the reservoir. Temperature changes around the injection wellbore impact CO2 and mineral solubilities. The concentration of calcium in the displaced brine mix is thus determined more by contact with rock and temperature than by mixing between injection and formation brines. Depending on location relative to the thermal front, this may lead to gypsum or anhydrite precipitation, thereby stripping sulfate out of the injection brine. Thus, the sulfate scaling risk at the production wells is significantly reduced by this sulfate depletion process: The sulfate is stripped out of the seawater as it warms up in the reservoir before it mixes extensively with the formation water and significantly before any mixture of the two brines reaches the production zone. Thus, any loss of permeability is restricted to deep within the reservoir, where the pore volume (PV) that can accommodate mineral precipitation is very large. In this work, we identify that for carbonate reservoirs above 90–100°C, stripping of sulfate due to coupled mineral reactions may reduce or eliminate the need for use of a sulfate reduction plant (SRP). The process is modeled for the first time, accounting for the impact of CO2 partitioning and thermal front propagation. Knowledge of the kinetics of calcium/magnesium carbonate precipitation is shown to be critical in predicting the extent of sulfate depletion.

Basin modelling workflow applied to the screening of deep aquifers for potential CO 2 storage

The temporal and spatial scale of interest of CO 2 storage studies lies in between reservoir and basin models. While reservoir modelling software is best fitted to address some of the multiphysics issues related to the behaviour of CO 2 once injected into the subsurface (adsorption, dissolution, near injection wellbore mechanics and temperature, and, in some cases, fluid rock interaction) within a human timescale, basin modelling tools handle better the full basin volume and time-scale heterogeneities that impact the storage potential and risk associated with CO 2 injection. This study takes a basin modelling approach to provide an assessment of the influence of geological evolution on CO 2 storage capacity, both at the reservoir level, by helping to estimate the amount of CO 2 that can be stored in its connected porosity, and at the cap-rock level, by assessing the seal integrity. Our basin model also captures the evolution of the pressure plume induced by the CO 2 injection, taking into account the pressure and temperature fields, aquifer connectivity and permeability, and seal integrity, on a much shorter timescale than is usually considered by such a model. The results show the impact of basin evolution on aquifer properties and consequently on the dissipation of the induced pressure plume. They also highlight the large-scale influence of the CO 2 on the pressure field both vertically along the stratigraphic column, when the pressure plume reaches shallower aquifers through unconformities, and horizontally, when good aquifer injectivity and connectivity allows the pressure plume to dissipate widely.

Study on time-varying characteristics and flow behavior of microencapsulated polymer

Due to the challenges posed by high injection pressure and significant viscosity shear loss, conventional polymer flooding methods are unable to effectively meet the urgent demand for enhanced oil recovery in medium- and low-permeability reservoirs. Microencapsulated polymer flooding is a promising solution to address the aforementioned challenges due to its advantages of easy wellbore injection, shear resistance, and delayed thickening. However, there is a lack of research on the release behavior and time-dependent characteristics of microencapsulated polymer and its impact on flow behavior in reservoirs. To address this gap, we conducted a series of experiments, including thermal stability tests, microfluidic chip experiments, and micro-scale oil displacement experiments, to reveal the time-varying behavior generated by the triggered release of microencapsulated polymers. The results showed that microencapsulated polymer can be fully triggered after 8 days of aging at 85 °C, with a viscosity exceeding the initial viscosity by more than 25 times. The release mechanism of the polymer aligned with the Ritger-Peppas model, transitioning from super Case-II transport to anomalous transport, and finally to Fickian diffusion with increasing temperature. During the triggering process, the presence of particles stabilized shear and improved oil displacement, particularly in small pore throats. Higher triggering degrees of the solution resulted in greater flow resistance within the microchannel, effectively suppressing fluid fingering. The oil displacement effectiveness of fully triggered microencapsulated polymer was comparable to that of conventional polymers. This study provides insights into the flow behavior of microencapsulated polymer at a microscopic level, offering valuable references for its application in the field.

Experimental evaluation of cement integrity on exposure to supercritical CO2 using NMR: Application to geostorage

Carbon sequestration is one approach to achieve carbon dioxide reduction in the atmosphere. Underground storage of CO2 requires an understanding of geochemical and geomechanical alteration on the integrity of the injection wellbore. In this study, we investigate the reactivity of supercritical CO2 (scCO2) at 65 °C and 20.7 MPa on Portland class G cement plugs used for oil and gas well completion, for exposure of up to 5 weeks.For nanoporous media, such as cement, diffusion is believed to be the major mass transport mechanism (Perkins and Johnston, 1963) [1]. To quantify the extent of the alteration (mineralization/dissolution) on fluid diffusivity through the cement matrix, a novel approach based on Nuclear Magnetic Resonance (NMR) is employed to derive diffusional tortuosity. Comparing pre- and post-scCO2 exposure, deuterium oxide (D2O) intrusion profiles allow us to determine flow path alteration in the cement plugs. Additional characterizations include Fourier Transform Infrared Spectroscopy (FTIR) to observe the change in cement composition, micro X-ray Computed Tomography (μXCT), along with Scanning Electron Microscopy (SEM) and Energy Dispersive Spectroscopy (EDS) to determine invasion extent and microstructure modifications, Mercury Injection Capillary Pressure (MICP) for pore throat size distribution and BET N2 isothermal adsorption for surface area and pore size distribution.The results show that exposure to scCO2 promotes both calcium carbonate precipitation and dissolution simultaneously. However, the alteration is pore size dependent. After 5 weeks of exposure, there is evidence of carbonate dissolution in smaller pores (<30 nm) and both precipitation and dissolution in larger pores (30–200 nm). The alteration of the cement plugs leads to a decrease in the storage and connectivity of the cement. The porosity decreased from 37 to 33 % in 5 weeks, while the matrix tortuosity increased by 6 and 3 times after 2 and 5 weeks of exposure, respectively. The experimental results imply that the cement carbonate precipitation can limit the migration of scCO2 through the cement matrix.This work also highlights an alternative laboratory approach to quantify the risk associated with scCO2 exposure on Portland cement using NMR-derived tortuosity.

APPLICATION OF HYDROGELS FOR CONFORMANCE CONTROL AND FLOW DIVERSION

The use of hydrogels in the development of oil fields by the flooding method has firmly established itself in the oil industry, and this direction is constantly evolving in all oil-producing countries around the world, as evidenced by the growth of publication and patent activity on this topic. Operations for conformance control and flow diversion are impossible to imagine without the use of gel technologies today. Inorganic, organic, and hybrid gels, as well as foam gels, gel-forming and gel-dispersed systems are used.The ability to widely regulate structural-mechanical properties, thermal stability, and shear resistance through the introduction of micro- and nano-sized additives has made hydrogels indispensable tools for petroleum engineers.In this review, modern trends in the use of hydrogels for flow diversion from injection wells are identified, and the most promising directions are explored in light of depleted reservoirs and deterioration in the structure of oil reserves. Geological prerequisites for using hydrogels for flow diversion during field development are discussed, including hydrogels based on a range of acrylamide polymers, sedimentary-gel-forming and gel-dispersed compositions, as well as gels based on inorganic compounds.Various gel-forming compositions based on water-soluble and waterswelling polymers, as well as silicon and aluminum-based inorganic compounds, are used for flow diversion and conformance control. Combining gels with dispersed materials and sedimentary compositions allows for the strengthening of the structural-mechanical properties of the flow-diverting system, making it possible to apply these compositions in fractured-porous collectors. The ability to regulate the gelforming time allows for placement of the gel screen at a specified distance from the injection wellbore. This approach has firmly established itself in industrial practice and continues to be improved in terms of reducing the cost of used compositions and increasing their effectiveness.

Simulation Study of sc-CO2 Based Silylation for Decreasing Severity of Water Blockage and Salt Precipitation during Geological CO2 Storage in Deep Saline Aquifers

Deep saline aquifers are often favorable for underground CO2 sequestration due to their large capacity and relatively low likelihood for resource conflicts. However, many possible issues can arise during CO2 injection. Often these aquifers have a significant salinity level (as these often present minimal resource conflict issues) and as such salt precipitation near the injection wellbore can be problematic. Furthermore, when water blockage occurs, salt precipitation can be exacerbated since large amounts of water remain near the wellbore. Altering the rock wettability towards less water-wet can alleviate water blockage and in turn reduce the likelihood or severity of salt precipitation. Previous lab experiments have shown that supercritical CO2 (sc-CO2)-based silylation can effectively functionalize rock surfaces with hydrophobic silanes. In this study, numerical models were constructed to evaluate the combined effects of multi-phase fluid flow, water evaporation and salt precipitation assuming a change in wettability (thus impacting the relative permeability characteristics of the reservoir) resulting from the silylation process. The aim of this study is to evaluate the efficacy of this chemical treatment to address near wellbore salt precipitation induced by CO2 injection. According to the simulation results, a decrease in injectivity due to salt precipitation is more significant when water blockage is also present. Injectivity is deteriorated prominently in high salinity reservoirs with water blockage since evaporation into the injected CO2 phase will cause significant salt precipitation. In a representative formation, the injectivity decline is worse (up to 68.6% relative injectivity change (RIC)) when both salt precipitation and water blockage are considered since the latter provides more trapped brine inducing more salt accumulation around the wellbore. With hydrophobic silylation, the combined effects of salt precipitation and water blockage on RIC are decreased on an absolute basis by up to 7%. Depending on techno-economic considerations, this method is encouraged to be implemented as early as possible during a CO2 injection program to minimize salt accumulation from the outset.

A general model of radial dispersion with wellbore mixing and skin effects

Abstract. The mechanism of radial dispersion is essential for understanding reactive transport in the subsurface and for estimating the aquifer parameters required in the optimization design of remediation strategies. Many previous studies demonstrated that the injected solute firstly experienced a mixing process in the injection wellbore, then entered a skin zone after leaving the injection wellbore, and finally moved into the aquifer through advective, diffusive, dispersive, and chemical–biological–radiological processes. In this study, a physically based new model and the associated analytical solutions in the Laplace domain are developed by considering the mixing effect, skin effect, scale effect, aquitard effect, and media heterogeneity (in which the solute transport is described in a mobile–immobile framework). This new model is tested against a finite-element numerical model and experimental data. The results demonstrate that the new model performs better than previous models of radial dispersion in interpreting the experimental data. To prioritize the influences of different parameters on the breakthrough curves, a sensitivity analysis is conducted. The results show that the model is sensitive to the mobile porosity and wellbore volume, and the sensitivity coefficient of the wellbore volume increases with the well radius, while it decreases with increasing distance from the wellbore. The new model represents the most recent advancement in radial dispersion study, incorporating many essential processes not considered in previous investigations.

Pump-stopping pressure drop model considering transient leak-off of fracture network

By introducing the coupling flow expressions of main fracture-matrix, secondary fracture-matrix and main fracture-secondary fracture into the traditional main fracture material balance equation, the “main fracture—secondary fracture—matrix” leak-off coupling flow model is established. The pressure-dependent fracture width equation and the wellbore injection volume equation are coupled to solve the pressure-rate continuity problem. The simulation and calculation of the bottomhole pressure drop and fracture network closure after the pump stopping in slickwater volumetric fracturing treatment are realized. The research results show that the log-log curve of pump-stopping bottomhole pressure drop derivative presents five characteristic slope segments, reflecting four dominant stages, i.e. inter-fracture crossflow, fracture network leak-off, fracture network closure and residual leak-off, after pump shutdown. At the initial time of pump shutdown for volumetric fracturing treatment of horizontal well, the crossflow between main and secondary fractures is obvious, and then the leak-off becomes dominant. The leak-off of main and secondary fractures shows a non-uniform decreasing trend. Specifically, the leak-off of main fractures is slow, while that of secondary fractures is fast; the fracture network as a whole presents the leak-off law of fast first, then slow, until close to zero. The influence of fracture network conductivity on the shape of pressure decline curve is relatively weaker than that of fracture network size. The fracture network conductivity is positively correlated with leak-off volume and fracture closure. The secondary fracture size is positively correlated with leakoff volume and closure of the secondary fracture, but negatively correlated with closure of the main fracture. Field data validation proves that the proposed model and simulation results can effectively reflect the closure characteristics of the fracture network, and the interpretation results are reliable and can reflect the non-uniform stimulation performance of each fracturing stage of an actual horizontal well.

Simple Statistical Models for Predicting Overpressure Due to CO2 and Low-Salinity Waste-Fluid Injection into Deep Saline Formations

Deep saline aquifers have been used for waste-fluid disposal for decades and are the proposed targets for large-scale CO2 storage to mitigate CO2 concentration in the atmosphere. Due to relatively limited experience with CO2 injection in deep saline formations and given that the injection targets for CO2 sometimes are the same as waste-fluid disposal formations, it could be beneficial to model and compare both practices and learn from the waste-fluid disposal industry. In this paper, we model CO2 injection in the Patterson Field, which has been proposed as a site for storage of 50 Mt of industrial CO2 over 25 years. We propose general models that quickly screen the reservoir properties and calculate pressure changes near and far from the injection wellbore, accounting for variable reservoir properties. The reservoir properties we investigated were rock compressibility, injection rate, vertical-to-horizontal permeability ratio, average reservoir permeability and porosity, reservoir temperature and pressure, and the injectant total dissolved solids (TDS) in cases of waste-fluid injection. We used experimental design to select and perform simulation runs, performed a sensitivity analysis to identify the important variables on pressure build-up, and then fit a regression model to the simulation runs to obtain simple proxy models for changes in average reservoir pressure and bottomhole pressure. The CO2 injection created more pressure compared to saline waste-fluids, when similar mass was injected. However, we found a more significant pressure buildup at the caprock-reservoir interface and lower pressure buildup at the bottom of the reservoir when injecting CO2 compared with waste-fluid injection.

Comparative study on heat extraction from Soultz-sous-Forêts geothermal field using supercritical carbon dioxide and water as the working fluid

Energy extraction from the deep subsurface requires engineering using a working fluid circulation in well doublet. This study developed a field-scale hydro-thermal model to examine the heat extraction potential from Soultz-sous-Forêts with CO2 and water as the working fluid. A better understanding of the heat extraction mechanism is established by considering the reservoir response and the wellbore heat exchange. Sensitivity analyses are performed for different injection temperatures and flow rates for 50 years. Results show that the wellbore effect is multiple times higher than the reservoir response to the production temperature. Furthermore, lowering the injection temperature eventuates to a smaller temperature reduction at the subsurface, enhancing the overall heat extraction potential with a minor impact on thermal breakthrough. The cold region developed around the injection wellbore may affect the production fluid temperature due to its proximity to the production wellbore near the top of the reservoir. To reach higher heat extraction efficiency, it is essential to use sufficient wellbore spacing. CO2 can be used as working fluid for over 50 years as it does not show significant thermal breakthrough and temperature plume evolution in the reservoir under studied conditions. CO2 shows lower temperature reduction for all injection rates and temperatures for 50 years of operation.

Numerical Simulation of Thermo-Hydro-Mechanical Processes at Soultz-sous-Forêts

Porosity and permeability alteration due to the thermo-poro-elastic stress field disturbance from the cold fluid injection is a deciding factor for longer, more economic, and safer heat extraction from an enhanced geothermal system (EGS). In the Soultz-sous-Forêts geothermal system, faulted zones are the main flow paths, and the resulting porosity–permeability development over time due to stress reorientation is more sensitive in comparison with the regions without faulted zones. Available operational and field data are combined through a validated numerical simulation model to examine the mechanical impact on the pressure and temperature evolution. Results shows that near the injection wellbore zones, permeability and porosity values are strongly affected by stress field changes, and that permeability changes will affect the overall temperature and pressure of the system, demonstrating a fully coupled phenomenon. In some regions inside the faulted zones and close to injection wellbores, porosity doubles, whereas permeability may be enhanced up to 30 times. A sensitivity analysis is performed using two parameters which are not well discussed in the literature the for mechanical aspect, but the results in this study show that one of them impacts significantly on the porosity–permeability changes. Further experimental and field works on this parameter will help to model the heat extraction more precisely than before.

Reuse of produced water as injection water

Produced water from the petroleum industry is the huge amount of wastewater generated by it. Disposal of produced water is of utmost importance for the environment, as it is a blend of organic–inorganic, dissolved, radioactive materials, etc., thus proper treatment is required on produced water before disposing of it. If produced water is managed properly then it can be reused for various purposes within the petroleum industry or outside the petroleum industry. The focus of this paper is mainly on the utilization of produced water within the petroleum industry, for operations like injection water for water flooding, hydraulic fracturing, pressure maintenance job, EOR operations, etc. This paper describes components present in produced water and the water treatment process required for making it compatible for reuse. This paper also evaluates injection water quality and determines the effects of various contaminants present in produced water on the reservoir as well as the injection wellbore.

Progress and prospects of carbon dioxide capture, EOR-utilization and storage industrialization

Carbon dioxide capture, EOR-utilization and storage (CCUS-EOR) are the most practical and feasible large-scale carbon reduction technologies, and also the key technologies to greatly improve the recovery of low-permeability oil fields. This paper sorts out the main course of CCUS-EOR technological development abroad and its industrialization progress. The progress of CCUS-EOR technological research and field tests in China are summarized, the development status, problems and challenges of the entire industry chain of CO2 capture, transportation, oil displacement, and storage are analyzed. The results show a huge potential of the large-scale application of CCUS-EOR in China in terms of carbon emission reduction and oil production increase. At present, CCUS-EOR in China is in a critical stage of development, from field pilot tests to industrialization. Aiming at the feature of continental sedimentary oil and gas reservoirs in China, and giving full play to the advantages of the abundant reserves for CO2 flooding, huge underground storage space, surface infrastructure, and wide distribution of wellbore injection channels, by cooperating with carbon emission enterprises, critical technological research and demonstration project construction should be accelerated, including the capture of low-concentration CO2 at low-cost and on large-scale, supercritical CO2 long-distance transportation, greatly enhancing oil recovery and storage rate, and CO2 large-scale and safe storage. CCUS-EOR theoretical and technical standard system should be constructed for the whole industrial chain to support and promote the industrial scale application, leading the rapid and profitable development of CCUS-EOR emerging industrial chain with innovation.

Numerical analysis of fracture deformation and instability during CO2 geological sequestration using a THM-XFEM coupled model

Fracture deformation and instability during long-term CO2 geological sequestration in abandon reservoirs is simulated with a thermal-hydro-mechanical model. The two-phase in non-isothermal condition is used both in matrix and fracture, and thermoelastic and poroelastic deformation are all taken into account. The extended finite element method is employed to solve the strong discontinuity problem involving thermal-hydro-mechanical coupling. The S-W equation of state and transport equation are chosen to characterize CO2 phase change. CO2 geological sequestration in abandoned-fractured reservoir with high water-cut is discussed with a two-dimensional model. The analysis of fracture deformation shows that CO2 geological sequestration has a great effect on fracture deformation and instability. Fracture aperture, deformation and the effective fluid pressure in fracture are highly affected by the water residual saturation and injected temperature difference. The analysis of fracture instability presents that mode I mainly appears in the fracture propagation, and propagation prefers to occur in fracture near the injection wellbore. The higher CO2 phase pressure when cold CO2 injection into reservoirs with low water residual saturation can promote fracture propagation 1–2 years in advance. Fracture aperture is enhanced but fracture instability time would be delayed due to the thermal stress.

Sensitivity analysis of operating parameters affecting CO2 wellbore transient flow at the CaMI Field Research Station, Alberta, Canada

In this study, we report comprehensive sensitivity analysis using artificial intelligence (AI) and machine learning techniques to determine the dominant operating and formation statistical parameters affecting the transient behavior of CO2 injection wellbore (i.e., wellbore pressure and temperature). This study focuses on the CO2 injection tests undertaken at the Field Research Station (FRS) injection site in Alberta, Canada. The CO2 wellbore transient behavior is simulated using a fully coupled nonisothermal transient multiphase wellbore-reservoir flow model (Jafari Raad et al., 2021). Radial Basis Function (RBF) Neutral Network and Polynomial Regressions are employed to characterize the dependency of the monitoring functions to the model parameters. The results show that the bottom-hole pressure (BHP) shows maximum sensitivity to the injection rate and minimum sensitivity to the injection pressure. The injection rate and the permeability of the target layer show the highest non-linearity effects. For a constant injection rate, the permeability of the target layer plays the most important controlling effect on the wellbore pressure. The results show that the injection pressure and permeability of the formation layer below the target formation represent the minimum non-linearity and interaction effects. This study provides an improved understanding of operating and reservoir parameters controlling the CO2 wellbore monitoring practices in CO2 injections.

The effect of temperature on CO2 injectivity in sandstone reservoirs

Carbon Capture, Utilization and Storage (CCUS) is a pragmatic technology that could reduce anthropogenic CO2 and halt climate change. CO2 injectivity is affected by several physicochemical interactions around the injection area of the wellbore which are temperature-dependant. There is a thermal disequilibrium between the injected CO2 and the reservoir rock at the wellbore injection area which has not been thoroughly investigated. A pore-scale model was developed to predict the distance travelled by the injected fluid into the formation before thermal equilibrium is established. In the Snøhvit field where the wellhead injection temperature is 4 °C, it was found that the injected CO2 may attain supercritical state at bottomhole conditions, although a minimum temperature difference of about 40 °C may exist between the bottomhole fluid and the reservoir rock. Thermal equilibrium around the injection area was dependant on the wellhead injection temperature, the injection flow rate and reservoir shaliness.

Vertical distribution of biofilm communities along an injection wellbore in a deep petroleum reservoir

In petroleum production, microbial research has been widely carried out to serve different engineering applications. For instance, studies on microbial-induced corrosion (MIC) control and microbial-enhanced oil recovery (MEOR) focus on the microbial activities in surface pipelines and in subsurface strata (oil reservoirs), respectively. However, the living microorganisms attaching to the inner surfaces of vertical wells as biofilms has not attracted much attention In a normal water-flooded oil-production system, the water is transferred between the surface and subsurface reservoirs through the vertical wells so that the wellbore biofilms are able to constantly affect the surface and subsurface communities. Therefore, it is necessary to reveal the structure and function of the sessile community along the vertical wellbore. Since in situ sampling from underground vertical wells is technologically complex and expensive, in this study, biofilm samples were obtained during well workover from well tube segments corresponding to different original depths (approximately 0 m, 300 m, 800 m, and 1300 m). Moreover, the injection water was also sampled. The results of 16S rRNA gene library sequencing showed that the microbial community in the water phase was distinct from that found in the biofilms (dissimilarity 0.63–0.78), although they shared 200–272 OTUs. At the phylum level, the dominant phylum, Euryarchaeota , accounted for 21.5%–35.8% in the four biofilms, while only 11.7% in the water phase. Proteobacteria was the dominant phylum in the water phase (74.6%), while accounted for only 7.7%–20.1% in the biofilms. With increasing depth from 0 m to 1300 m, the richness and diversity of biofilms declined (Chao index of 608.8 to 442.4, Shannon index of 4.01 to 3.48), and the bacterial abundance of biofilms declined from 78.4% to 63.5%, while the archaeal abundance increased from 21.6% to 36.5%. The geothermal gradient, depleted oxygen and even turbulence were the significant factors affecting the depth-dependent variation in the communities. For instance, the relative abundance of the hydrogenotrophic genera increased from 8.62% to 28.8% with increasing depth. In addition, the sudden variation of wellbore biofilms suggested a presumed boundary of the microbial ecosystem around the depth of 1000 m, which is consistent with existing reports. This is the first study to directly investigate and reveal the depth-dependent distribution of the wellbore community along a deep well (depth >1300 m). The distinct and depth-dependent communities suggested that direct investigation is necessary for completely understanding and efficiently controlling microbial activities in oil production processes, including MIC control and MEOR. • Biofilms at different depths from an injection well were sampled during workover. • There are abundant microorganisms living in wellbore environments as biofilms. • Biofilm communities show a depth-dependent distribution along the deep well. • Those biofilms interact with the entire oil production system by fluid circulation. • Understanding wellbore biofilm is essential for corrosion control and oil recovery.

Transient non-isothermal coupled wellbore-reservoir modeling of CO2 injection — Application to CO2 injection tests at the CaMI FRS site, Alberta, Canada

We investigate the dynamics of a CO2 injection wellbore using a fully-coupled non-isothermal transient multiphase wellbore-reservoir flow model. The focus of this study is on the transient behavior of the wellbore parameters in injection tests undertaken at the CaMI Field Research Station (FRS) in Alberta, Canada. Wellbore transient pressure and temperature and subsequent CO2 phase behavior through the wellbore were analyzed, and the impacts of the reservoir parameters on the wellbore transient flow behavior are characterized. Our results show that the presence of gas-liquid transient flow in the wellbore and the subsequent liquid CO2 build-up in the wellbore significantly increases the bottom hole pressure. The results show that the mean permeability of the target formation layer represents the most important controlling effect on the wellbore transient functions. We used the concepts and understanding developed through the wellbore flow dynamics characterization and the sensitivity analysis to redesign injection tests to control the CO2 wellbore transient flow. We also performed history-matching of the injection tests to examine various combinations of porosity and permeability multipliers in an attempt to match the historical pressure and temperature data obtained during the CO2 injection tests. The outcomes of this study provide an improved understanding of the transient wellbore behavior during CO2 injection over certain pressure-temperature ranges. Results developed here may be used to monitor the injection performance, well and reservoir responses under different injection scenarios.

A Comprehensive Model for Simulating Supercritical-Water Flow in a Vertical Heavy-Oil Well

SummarySupercritical water has been proved effective in heavy-oil recovery. However, understanding the flow characteristics of supercritical water in the wellbore is still in the early stages. In this paper, using the theory of heat transfer and fluid mechanics and combining that with the physical properties of supercritical water, a heat-transfer model for vertical wellbore injection with supercritical water is established. The influence of heat transfer and the Joule-Thomson effect on the temperature of supercritical water are considered. Results show the following:The predicted values of pressure and temperature are in good agreement with the test values. The apparent pressure of supercritical water at the upper end of the wellbore is lower than the apparent pressure at the lower end. However, the equivalent pressure of supercritical water at the upper end of the wellbore is higher than the equivalent pressure at the lower end. The apparent pressure of supercritical water is affected by three factors: flow direction, overlying pressure, and Joule-Thomson effect. The closer to the bottom of the well, the greater the overlying pressure of the supercritical water, resulting in an increase in apparent pressure and the density of the supercritical water. As the injection time for supercritical water increases, the temperature around the upper horizontal wellbore increases.