Injection Wellbore Research Articles

Prediction of Heavy Oil Steam Stimulation Based on Data-Driven and Mechanism Model

In the middle and late stages of heavy oil development, formulating a scientific and reasonable mining plan is the key to improving oilfield efficiency. At present, steam stimulation is still the main development method of heavy oil. The determination of its production is not only limited by boiler conditions, surface pipelines, and wellbore conditions but also by the steam absorption capacity of the formation. Therefore, local analysis cannot achieve the best effect in the whole process of steam stimulation. The mechanism model is the most commonly used method to predict heavy oil production, but too many idealized assumptions make the prediction results quite different from the actual production situation. With the rapid development of machine learning, people can achieve rapid prediction of production through field data. However, when the range of the actual parameter is small, the generalization ability of the model is weak and overfitting occurs. Based on the above background, this paper conducts a coupling study on surface steam pipeline flow, steam injection wellbore flow, and formation flow from the perspective of data-driven. Firstly, based on the correlation coefficient and the feature selection of Random Forest, the importance of the characteristics affecting liquid production and water content was ranked. Secondly, through the comparison of five typical machine learning algorithms, we select the optimal prediction model and optimal characteristics suitable for the sample of this paper. Finally, because of the poor generalization ability of the prediction model, we sampled the mechanism model and increased the diversity of steam dryness samples. We find that the accuracy of the optimal prediction model is improved and the generalization ability of the model is improved after the training of new samples. This paper provides a new idea for the production prediction of heavy oil steam stimulation reservoirs, which is helpful for the efficient development of heavy oil reservoirs.

Pore-Scale Grain-Binding Cement Dissolution in Sandstone Rocks and its Effect on CO2 Injectivity

CO2 geological storage in depleted oil and gas reservoirs and saline aquifers is currently one of the most economical methods to mitigate CO2 emissions, mainly because of available geological data from oil and gas exploration and production in the last decades as well as abandoned wellbore facilities. Four main factors dictate the safe and economical CO2 storage and selection of a suitable storage site: while wellbore and cap rock integrity are critical to the security of stored CO2, storage capacity and CO2 injectivity are among the main factors driving the cost of storage per ton of CO2. Low or reduced CO2 injectivity at injection wellbore can significantly increase the compression costs of the project. In worst-case scenarios, a blockage can increase injection pressures above rock fracture pressure, thus critically jeopardising further injection in the same well. The global abundance, high storage capacity and potentially low chemical reactivity of sandstone reservoirs make them great candidates for CO2 geological storage sites. The matrix of siliciclastic rocks is mainly made of quartz grains, and there is negligible chemical reactivity in contact with carbonic acid formed during the injection. However, the most common cementing agents in these rocks (e.g. calcite, dolomite and, to some extent, clays) react with carbonic acid. These reactions lead to mechanisms like cement dissolution, mineral deposition, and sand fine migration (sand mobilisation). Depending on the volumetric percentage of the binding cement, its geometrical distribution within the matrix and pore (and throat) size distribution of the rock, fine migration and binding cement dissolution can enhance or impair CO2 injectivity [1,2]. Despite numerous studies regarding the effect of CO2 injection on fine migration and injectivity, there is still no consensus regarding the impact of intergranular cement dissolution on CO2 injectivity. In this study, we have focused on the effect of binding cement dissolution on pore morphology in a typical sandstone (Berea) and demonstrating how the observations of CO2 injectivity change at the core scale alone could be misleading and explain some apparent discrepancies reported in the literature. We cut three slices of this core for X-ray micro-computed tomography (MicroCT) imaging. The first slice was cut from the original clean core. After performing a coreflood experiment with carbonated water through the rest of the core, two other pieces were cut from the inlet and outlet of the core. To represent the extreme dissolution conditions (lowest pH) during CO2 injection, a batch of North Sea brine fully saturated with CO2 was prepared and injected through the core at typical reservoir conditions (50°C and 2.6×107 Pa). Three 3D models are reconstructed from images of the prepared rock slices to represent the pore structure of the rock before injection and the inlet and outlet of the core subjected to CW injection. Avizo (a commercial software) is used to calculate the permeability and velocity fields in these models. The comparison of results from micro-CT imaging and the coreflood experiment shows how single-scale studies (either core or pore-scale) of CO2 injectivity can lead to a misleading conclusion about the effect of fine migration on permeability at larger scales.

A silicate based sealant to plug seepage behind the casing

In a previous project, a silicate based sealant was developed and applied to the case of a clayey sandstone formation with the objectives of plugging the surroundings of a well typically within a radius of 1 m. Here, we report experiments conducted at the Mont Terri Underground Research Laboratory (MT-URL) focusing on the mitigation of pressure leakages associated with CO2 containment in near wellbore injection well systems. This work was performed under the auspices of the CO2 Capture Project (CCP), a three-company collaboration comprising Chevron, BP and Petrobras. The CCP effort is directed to develop more cost effective and efficient processes for CO2 concentration, capture and sequestration applied to the energy, refining, chemical and power generation industries in order to reduce greenhouse gas emissions. The experimental set-up installed at the underground test site mimics an injection well with the objectives of testing various sealants able to contain losses associated with delaminations that may occur at various well boundaries such as cement to casing and cement to caprock. Cement and caprock may also be micro-fractured. The tested sealant takes advantage of the properties of alkaline silicate solutions forming a gel after addition of an acid in appropriate strength and quantity. With a viscosity close to water, it can easily be injected in a liquid state and does not need to be activated after injection. The gelation time can be adjusted and is mostly sensitive to temperature. We tested two formulations of the sealant in a 1 m interval of the well system. The sealing capacity is evaluated by comparing flowrates at constant imposed pressure before and after injection of the sealant. Typically, a decrease by a factor of 10 of these flowrates is an indication of a good sealing performance. The first formulation proved to be efficient only for a limited time smaller than 1 month. The second improved formulation proved to be efficient for a period larger than one month.

A prediction of breakdown pressure from damaged deviated well

It has been proved that formation damage is an important reason of abnormal high breakdown pressure (BP), but few quantitative prediction model considering formation damage has been established. In this paper, formation is considered as homogeneous linear elastic small deformation material, an arbitrary deviated well is taken as the research object, in-situ stress and the wellbore injection pressure in the surroundings of borehole wall are calculated on the base of elastic mechanics. Additional fracturing fluid infiltration pressure is calculated based on the empirical relationship of permeability and porosity combined with Darcy’s law of fracturing fluid in poro-elastic media. Based on the stress superposition principle as well as the tensile stress failure criterion, the breakdown pressure prediction model of deviated open hole well with damage is established for the first time, and influence of formation damage on breakdown pressure is quantitatively simulated. For a given in-situ stress regime, the results display breakdown pressure of both damaged well and undamaged well increases with the increase of deviation angle and azimuth angle, the former is always higher than the latter. Moreover, the BP and additional BP Increment is not large when deviation or azimuth angle is less than 30°. On the other hand, additional BP increment rapidly rises more when damaged permeability ratio is less than 0.135 and it can even reach 10MPa in this example.

Cement Integrity Loss due to Interfacial Debonding and Radial Cracking during CO2 Injection

Cement provides zonal isolation and mechanical support, and its integrity is critical to the safety and efficiency of the CO2 injection process for geologic carbon storage. This work focuses on interfacial debonding at wellbore interfaces and radial cracking in cement during CO2 injection. It adopts the definition of the energy release rate (ERR) to characterize the propagation of cracks. Based on the finite element method, the proposed model estimates the ERRs of both types of cracks with practical wellbore configurations and injection parameters. Further parametric studies reveal the effects of cement’s mechanical and thermal properties and the crack geometry on crack propagation. Simulation results show that the ERRs of interfacial and radial cracks would surpass 100 J/m2 with typical cement properties. The cement’s thermal expansion coefficient is the most influential factor on the ERR, followed by its Young’s modulus, Poisson’s ratio, and thermal conductivity. The initial sizes and positions of the cracks are also important parameters for controlling crack propagation. Moreover, non-uniform in situ stresses would accelerate crack propagation at the interfaces. These findings are valuable and could help to optimize cement sheath design in order to ensure the long-term integrity of wells for geological carbon storage.

A Hybrid Optimization Methodology Identifying Optimal Operating Conditions for Carbon Dioxide Injection in Geologic Carbon Sequestration

Prior to determining the optimal operating parameters for CO2 injection, conditions for both injection wellbore and storage formation should be evaluated; the build-up pressure induced by the CO2 injection could promote fractures in the storage formation, even collapsing the wellbore. In this study, a hybrid optimization methodology, which combined the proxy modeling and multi-objective optimization, was engaged in searching appropriate operating conditions for CO2 injection. The study utilized a fully coupled wellbore-reservoir (WR) model to simulate the CO2 injection scenarios. Three responses, such as pressure, temperature, and CO2 mass flow rate at the bottom-hole of injection wellbore, were investigated. To reduce the computational cost, the statistical proxy models were developed for approximating three responses. The developed fine-tuned proxy models revealed four influential factors; wellhead pressure, injected CO2 temperature, wellbore diameter, and permeability of a storage formation were significant in predicting three responses. Among these four influential factors, permeability was treated to be an uncertainty factor, while the other three factors were treated as tuning factors. According to acquired optimal solution sets, the optimum values for wellhead pressure and injected CO2 temperature were distributed around 10.0 MPa and 35 °C, respectively. For the wellbore diameter, its mean of optimal solutions was 0.1 m, and more solutions were concentrated at this mean value with a decrease in permeability.

Residual mechanical strength evaluation of corroded tubing in cryogenic carbon dioxide injection wellbore

Carbon dioxide injection or storage in mature or partially depleted oil reservoirs is an effective way to reduce carbon dioxide emissions and improve oil recovery. However, the corrosion defects greatly reduce the residual mechanical strength of the tubing with the effect of frost heaving force, which seriously limits the carbon dioxide enhanced oil recovery technology widely application. Therefore, the residual mechanical strength of corroded tubing in cryogenic carbon dioxide injection well is investigated in this paper. The results indicate that: (a) The residual mechanical strength of corroded tubing with the effect of frost heaving force is about 68% less than that without frost heaving force. (b) The effect of corrosion depth and location are sensitive, while the corrosion shape is relatively weak. (c) It is a meaningful method to increase working pressure to improve the residual mechanical strength of corroded tubing in the frozen section.

Theoretical modeling of the effect of temperature on CO2 injectivity in deep saline formations

AbstractWell injectivity and storage capacity defines the storage potential of a CO2 capture, utilization, and storage (CCUS) facility. Formation temperature has high impact on the phase behavior and flow properties of CO2 such as density and viscosity. The effect of temperature on CO2 injectivity, especially in the wellbore injection inlet, is not well understood. We investigated the thermal behavior of CO2 from the wellhead to the reservoir using simple theoretical models that capture the major heat transfer mechanisms. The effect of CO2 injection flow rate and injection time on the temperature of CO2 were studied. We found that for the same initial CO2 injection temperature and formation intake temperature, the injected CO2 in the well is cooler than the surrounding formation from the wellhead to the bottomhole. The temperature difference increased with increasing injection flow rate and injection time. The results show that although CO2 may attain supercritical state at bottomhole, the temperature difference between CO2 in the wellbore and the reservoir could be significant. The results also suggest that CO2 could attain thermal equilibrium with the reservoir at a flow distance of about 600 ft into the formation depending on the injection flow rate and reservoir temperature. The thermal disequilibrium of CO2 in the wellbore vicinity where fluxes are also high could affect CO2 injectivity and the mobility of CO2 during CCUS and enhanced oil recovery (EOR) operations. The present findings provide vital understanding of the effect of thermal instability on CO2 injectivity especially in the wellbore injection inlet. © 2020 Society of Chemical Industry and John Wiley & Sons, Ltd.

Calculation of temperature profile in injection wells

Injection wells have long been an essential asset in enhanced oil recovery, wastewater disposal and carbon dioxide sequestration in petroleum industries. The temperature profile of fluid flow in the injection well is one of the main parameters of interest for petroleum engineers to determine optimum injection conditions and wellbore completion design especially in thermal injection projects and deep wells. In this study, the calculation involved in determining the temperature profile along the depth of wellbore has been revised to be newer and more robust via solving governing wellbore equations. The wellbore is segmented into discrete counterparts for it to be solved simultaneously in terms of mass, momentum and energy balance via wellbore governing equations. Five injection cases from the literatures, incompressible and compressible fluid flows, were used to confirm that the procedure is reproducible in terms of its behaviour, which is similar to field data. The new results acquired from the new procedure are in good agreement with field data collected with a maximum absolute error less than 3 °C.

Interferometric time-lapse velocity analysis: application to a salt-water disposal well in British Columbia, Canada

SUMMARY We investigate the possibility of passive monitoring of a salt-water disposal well in British Columbia, Canada, using continuously recorded ambient seismic noise. We find seismic velocity variations induced by a reduction of injection pressure in an effort to mitigate an elevated level of seismicity, most likely associated with the disposal of salt water. The relative velocity variations are derived from time-shifts measured between consecutive cross-correlation functions for each station pair in a surface array composed of five broad-band seismometers. The probable driving mechanisms responsible for the velocity changes are reduced pore pressures and/or lowered poroelastic stresses beyond the injection wellbore, respectively. Hydrologic data (e.g. snow and rainfall), noise energy trends and fluctuations in the incident direction of dominant noise sources do not correlate with the estimated relative velocity variations. Velocity variations are detected ahead of the zone of induced seismicity, thus indicating that seismic interferometry may aid in mitigation efforts to reduce the risk of induced seismicity by (1) providing verifiable and repeatable measurements of physical changes within the surrounding area and (2) providing hard constraints for modelling efforts to constrain how and where pore-pressure fronts change.

An integrated evaluation of enhanced oil recovery and geochemical processes for carbonated water injection in carbonate rocks

During carbonated water injection and CO2-WAG scenarios for enhanced oil recovery, dynamic transfer of CO2 from aqueous phase into resident oil can cause complex pH variations, which can affect mineral dissolution around wellbore and precipitation in reservoir. Also, transfer of CO2 from carbonated water into live oil can liberate light components of the oil, which would create gas phase in-situ. In this investigation, a novel methodology was developed to numerically simulate these complex processes in an integrated approach. This study could present one step closer to realistic evaluations of dynamic CO2 transfer from carbonated water to resident oil and consequent interactions with the reactive minerals in a carbonate reservoir.Taking account of the data of coreflood experiments performed on a carbonate rock under 3100 psi and 100 °C, profiles of ionic concentration of produced brine and rock weight during carbonated water injection into a dry core (in the absence of oil) were history-matched to tune reaction parameters. Calcite reaction parameters (surface area and activation energy) were tuned to match profile of concentration of Ca++. Also, for additional oil recovery and dP profiles, secondary and tertiary carbonated water injection experiments were matched simultaneously to obtain relative permeability curves and CO2 mass transfer parameters. This new approach is called co-history-matching. Using the tuned parameters in a radial sector model, a series of simulations was performed to analyse change in rock porosity and enhanced oil recovery for large scales for carbonated water injection. Results of the large-scale model have demonstrated that minerals dissolution takes place mostly in vicinity of the injection wellbore. However, the simulation results demonstrated that injection of short cycle of carbonated water followed by plain water would alleviate the dissolution issue, while significant additional oil recovery is achieved.

A new methodology to assess the maximum CO2 geosequestration capacity of shale reservoirs with SRV based on wellbore pressure

Shale reservoirs are promising geological sites for CO2 storage due to their high total organic content (TOC) and the large-scale hydraulic fracturing operations. In order to critically evaluate a potential storage reservoir, fast, robust tools are needed to assess the CO2 storage capacity. Based on our previous work, an efficient method based on semi-analytical solution for calculating the maximum CO2 storage capacity in shale formations is derived, based on the injection wellbore pressure. The new methodology fully reflects the flow, diffusion, and adsorption processes of CO2 in shales. It also simulates natural fractures, hydraulic fractures, and the stimulated reservoir volume (SRV). The semi-analytical solution utilizing a Laplace transform and Stehfest numerical inversion is developed to evaluate the wellbore pressure and storage capacity in shale formations, which is verified using numerical simulations. A case study of the derived method on the Bakken Shale shows that the CO2 storage capacity is strongly controlled by the CO2 injection rate, adsorption index, and storage ratio. It is also found that the effective diffusion coefficient and mobility ratio affect the CO2 storage capacity during different periods of the CO2 storage process.

Hydromechanical modelling of CO2 sequestration using a component-based multiphysics code

Geologic carbon dioxide sequestration (GCS) is a complex process with coupled multiphysics mechanisms, including non-linear solid deformations and fluid flow. When applying a finite-element method to solve such a complex problem, implementing and solving non-linear partial differential equations with sophisticated material models pose great challenges. In this work, a generic component-based multiphysics analysis code – Albany – is introduced for the modelling and analysis of GCS problems. The component-based approach allows the application code development effort to focus on writing physics models. A notable feature of Albany is the powerful automatic differentiation utilities that can be used to calculate automatically system Jacobians and consistent tangents. Two numerical problems, namely, wellbore injection and carbon dioxide transport in a confined underground channel, are developed to demonstrate the performance of the Albany analysis framework. The results are verified against and matched well with those from Comsol – a robust commercial multiphysics finite-element package. The numerical results are also thoroughly analysed to gain insights into distribution profiles and temporal evolutions of pore pressure and displacement fields during a GCS process.

Cyclic CO2 – H2O injection and residual trapping: Implications for CO2 injection efficiency and storage security

To meet the Paris Agreement target of limiting global warming to 2 °C or below it is widely accepted that Carbon Capture and Storage (CCS) will have to be deployed at scale. For the first time, experiments have been undertaken over six cycles of water and supercritical CO2 injection using a state of the art high flow rig recreating in-situ conditions of near wellbore injection into analogue storage reservoir rocks. The results show that differential pressure continuously increases over multiple injection cycles. Our interpretation is that multiple cycles of injection result in a reduced effective permeability due to increased residual trapping acting as a barrier to flow resulting in reduced injectivity. This is supported by numerical modelling and field observations that show CO2 injectivity and its variation over time will be affected by multiple cycles of injection. These results suggest that loss of injectivity must be incorporated into the injection strategy and that careful management of cyclic injection will create the opportunity to increase residual trapping.

Fully coupled wellbore-reservoir simulation of supercritical CO2 injection from fossil fuel power plant for heat mining from geothermal reservoirs

Abstract The concept of injecting supercritical CO2 (sCO2) into a geothermal reservoir was computationally investigated to assess its performance in terms of the benefit of using CO2 captured from fossil power plants for geothermal heat mining. A coupled wellbore-reservoir system was simulated considering the flow of pure sCO2 in an injection well, the interaction of sCO2 and water in a permeable reservoir, and the flow of the two-phase mixture of sCO2 and water in a production well. Results of simulations indicate that this CO2 application is capable of providing a good source of renewable energy. It was found that for a reservoir with a 0.08 km3 volume, about 8–9 MWth could be extracted in a steady state fashion for a 30-year lifetime operation. This is approximately equivalent to 100 MWth/km3. A sensitivity analysis provided information on the impact of certain parameters on the performance of the integrated system. The injection flowrate, the distance between the production and injection wellbores and the penetrating depth of the production wellbore into the reservoir have a first order impact on the pressure management of the reservoir. Additionally, CO2 injection temperature has a large effect on the thermosiphon characteristics of the system.

Investigation on the Relationship between Wellhead Injection Pressure and Injection Rate for Practical Injection Control in CO2 Geological Storage Projects

The existing investigations on the maximum allowable wellhead injection pressure have found the upper limit of wellhead injection pressure, which, however, cannot provide a practical operational designing scheme of wellhead injection parameters for CO2 geological storage projects. Therefore, this work firstly proposes the complete constraint conditions of wellbore injection to realize the whole process of forward and inverse calculations of wellbore pressure and then applies it to explore the relationship between wellhead injection pressure and injection rate. The results show that the wellhead injection pressure and the injection rate are a pair of mutually constrained physical quantities. For a certain injection project, the allowable wellhead injection pressure and injection rate separately form a continuous interval. Change of one quantity within its allowable interval will also change the other within its interval, both jointly forming a closed region. Thus, controlling the wellhead injection parameters in this closed region can simultaneously ensure the effectiveness and safety of injection. Subsequently, this work further studies the factors of impacting the relationship between wellhead injection pressure and injection rate and finds that all the temperature of injected fluid, the parameters of saturation, and the characteristic parameters of reservoirs only change their upper and lower limits to some extent but have no essential effects on their relationship. Application of this theory and method in Shenhua CCS demonstration project obtained the relationship diagram of wellhead injection pressure and injection rate, which found that its actual injection parameters just fall into the closed region of the relationship diagram, effectively verifying the reliability of this work.

Acoustic emission characterization of microcracking in laboratory-scale hydraulic fracturing tests

Understanding microcracking near coalesced fracture generation is critically important for hydrocarbon and geothermal reservoir characterization as well as damage evaluation in civil engineering structures. Dense and sometimes random microcracking near coalesced fracture formation alters the mechanical properties of the nearby virgin material. Individual microcrack characterization is also significant in quantifying the material changes near the fracture faces (i.e. damage). Acoustic emission (AE) monitoring and analysis provide unique information regarding the microcracking process temporally, and information concerning the source characterization of individual microcracks can be extracted. In this context, laboratory hydraulic fracture tests were carried out while monitoring the AEs from several piezoelectric transducers. In-depth post-processing of the AE event data was performed for the purpose of understanding the individual source mechanisms. Several source characterization techniques including moment tensor inversion, event parametric analysis, and volumetric deformation analysis were adopted. Post-test fracture characterization through coring, slicing and micro-computed tomographic imaging was performed to determine the coalesced fracture location and structure. Distinct differences in fracture characteristics were found spatially in relation to the openhole injection interval. Individual microcrack AE analysis showed substantial energy reduction emanating spatially from the injection interval. It was quantitatively observed that the recorded AE signals provided sufficient information to generalize the damage radiating spatially away from the injection wellbore.

Hydraulic fracturing with leakoff in a pressure-sensitive dual porosity medium

Hydraulic fracturing is a key method in the stimulation of shale gas reservoirs. Shale gas formations often contain natural fractures which are fluid-pressure sensitive and dilate in response to the inflation of the fracture, increasing fluid loss and slowing down and potentially prematurely arresting fracture propagation. Models typically assume 1-D single-porosity/permeability (Carter) leakoff perpendicular to the hydraulic fracture. However, the leakoff process in naturally fractured formations is considerably more complex. In this study, we present an hydraulic fracturing model based on the PKN-formalism which accommodates leakoff into a pressure-sensitive dual porosity medium. Proppant transport is accommodated by introducing empirical constitutive equations to determine the proppant distribution during the hydraulic fracturing treatment. The model is solved numerically and is validated against known small and large time asymptotic solutions. The model is capable of providing a rapid estimation of the morphology of hydraulic fractures in naturally fractured formations and the corresponding proppant distribution. The simulation results illustrate that the leakoff into a dual porosity medium, where fracture permeability is a strong function of applied fluid pressure, results in a reduced length of the propagating fracture due to the fugitive fluid leakoff from the fracture into the surrounding formation and that this in turn results in a reduced maximum width during the treatment. The ability to infuse proppants in fluid-driven fractures penetrating large distances from the injection wellbore is further limited by premature screen-out. This may compromise the ultimate efficiency of the final hydraulic fracture regarding gas recovery. Reduced propagation and premature screen-out are limited by low permeability and large spacing of the natural fractures. The presence of an existing network of natural fractures, including those adjacent to the hydraulic fracture that may become propped, aids in the recovery of the resource by reducing diffusion lengths of the hydrocarbon to the main fracture.

Type curve analysis of multi-phase flow of multi-component thermal fluid in toe-point injection horizontal wells considering phase change

Huge amount of works were done on modeling of wet steam flow in the conventional heel-point injection horizontal wellbores. With the rapid development of technology, new technology of superheated steam – non-condensing gases (SNG) injection coupled with toe-point injection wellbores was adopted in oil field.In this paper, a series of works were done on modeling of SNG flow in a horizontal wellbore with toe-point injection technique. The two-phase flow model was embedded in this SNG model for describing the phase change phenomenon. Firstly, a hydraulics model comprised of mass, momentum and energy conservation equations was developed. Then, coupled with the seepage model in oil layer, a wellbore/formation coupled model was established. Thirdly, straight forward numerical method was adopted to solve the model. Finally, model verification and sensitivity analysis were conducted sequentially.Results show that: (1) The SNG temperature in annuli has an increase at the heel-point due to heat conduction from IT to annuli. (2) When the mass injection rate is kept unchanged, the SNG temperature at a certain place in annuli decreases with increasing of the mass content of non-condensing gases. (3) The SNG in IT undergoes phase change into saturated state at the distance of 150 m. Then, from the distance of 150 m–200 m, the gas content in the mixture system gets an increase and the superheat degree is equal to zero. (4) Phase change occurs again in annuli when the SNG reaches the distance of 110 m where the wet fluid turns into superheated state, after which the superheated degree of SNG increases continuously as SNG is flowing to the heel-point.

Applicable scope of oxygen-reduced air flooding and the limit of oxygen content

The mechanisms of oxygen-reduced air flooding (ORAF) and the explosion limit and the corrosion control approaches were studied based on the pilots of oxygen-reduced air flooding (ORAF) in the Dagang, Changqing and Daqing oil fields in China. On the foundation of indoor investigations and pilots, the explosion limits, oxygen reduction limits and corrosion control approaches were clarified. When the temperature of reservoir is equal to and higher than 120 °C, there is a violent reaction between oxygen and crude oil, that means the effect of low temperature oxidation would be fully taken use of to enhance oil recovery by air flooding directly; nitrogen dominated immiscible flooding with oxygen-reduced air should be applied in cases where reservoir temperature is below 120 °C with little oxygen consumption and little heat generated. The oxygen-reduced air flooding is suitable for 3 types of reservoirs: low permeability reservoir, water flooding development reservoir of high water-cut and high temperature and high salinity reservoir. In the process of development, in order to ensure safety, the oxygen reduction limits should be controlled fewer than 10%, while oxygen-reduced air can obviously reduce the corrosion rate of pipes; The surface pipelines and injection wells don't need to consider about oxygen corrosion with no water, special materials and structure of pipe or corrosion inhibitor can be applied to the surface pipelines and injection wellbores with water. Air/oxygen-reduced air is a low-cost displacement medium and it could be applied in many special conditions of low permeability reservoir for energy supplement, huff and puff and displacement, that means oxygen-reduced air flooding has become the most potential strategic technology in 20 years.