Injection Reservoir Research Articles

Numerical study of CO2-enhanced coalbed methane recovery

Although CO2-enhanced coalbed methane (CO2-ECBM) recovery has been comprehensively investigated, fewer scholars have taken the effect of temperature into account, which brought a large deviation for the study of the influence of CO2-ECBM. In this work, a hydraulic-mechanical-thermal coupled model of CO2-ECBM is established, it combines binary gases (CO2 and CH4) infiltration and diffusion, where non-isothermal adsorption is also considered. The effect of injection pressure and reservoir initial temperature on CO2-ECBM was simulated by the finite element simulation software COMSOL Multiphysics, results show that: the injection of CO2 into coalbed has a good effect on enhancing the production of CH4, and both the CO2 storage rate and CH4 production rate increase with the increase of injection pressure. The effect of initial reservoir temperature on CO2-ECBM is obvious. Since the amount of adsorbed gas in coal decreases with the increase of temperature, the CO2 storage rate and CH4 production rate decrease with the increase of initial reservoir temperature. In the gas extraction process without CO2 injection, the variation of permeability is competition result of two types of factors: the coal matrix shrinkage caused by temperature reduction and gas desorption increase, the other is the coal matrix expansion caused by gas pressure decrease, so the permeability follows the rule of first decreasing and then increasing with the extraction time. The injection of CO2 has a great influence on the permeability of coalbed, adsorption of CO2 by the coal matrix causes the permeability to drop rapidly.

Laboratory investigation of oil recovery by CO2 foam in a fractured carbonate reservoir using CO2-Soluble surfactants

Miscible CO2 flooding has been used as an EOR method for carbonate reservoirs which hold around 60% of the world's oil reserves. However, natural fractures, unfavorable mobility ratio and gravity segregation in carbonate reservoirs often lead to premature CO2 breakthrough and bypassed oil. To remedy this situation, CO2 foam has been used to reduce the mobility of the injected CO2. Typically, this employed a water soluble surfactant for foam propagation. However, surfactant transport in the aqueous phase was often hindered by surfactant adsorption and undesirable chemical reactions with reservoir minerals. In this study, we investigated whether CO2-soluble surfactants were more effective than water-soluble surfactant in oil recovery of fractured carbonate reservoirs under miscible conditions.A series of corefloods were conducted to determine the oil recovery factor (RF), speed of foam propagation and foam strength in artificially fractured carbonate cores at 35 °C (308.15 K) and 1500 psi (1.034*107 Pa) which was above minimum miscibility pressure. Silurian Dolomite outcrop with permeability of 150 md and West Texas Wasson crude were used. The cores were intermediate-wet indicated by both qualitative and quantitative tests. Three different surfactants were compared including an anionic water-soluble surfactant and other two nonionic CO2 soluble surfactants (2-ethyl-1-hexanol with different ethylene oxide groups) with distinct degree of solubility in CO2. Phase behavior experiments indicated these surfactants did not lower the interfacial tension significantly between the crude and water.RF of CO2 flooding was only 24% due to the heterogeneous nature of the fractured core. Co-injection of CO2 and water increased the RF to 35%, which was further increased to 54% when a water-soluble only surfactant presented. However, use of CO2 foam by the two CO2-soluble surfactants increased the RF to 71% and 92% respectively, with a higher RF for the surfactant that partitioned more to the CO2 phase. Also, pressure drop in different sections of the core confirmed that the surfactant which partitioned more into the CO2 phase gave a faster-propagating and stronger foam.These results educated that the partitioning of surfactant into the CO2 phase has several advantages. First, it allows surfactant to be transported in the CO2 phase ahead of the aqueous phase thus leading to faster foam propagation. Second, it generated a stronger foam. The combined effect of the two leaded to higher RF in current scenarios. Several hypotheses based on literature were raised and listed to further interpret the observations. Our results also reinforce that the so-called optimal CO2 soluble surfactant is case dependent and is the function of injection strategy, reservoir environment, and operation pressure or rates as well as other specific conditions. One could tailor a surfactant with suitable solubility in the CO2 phase to optimize oil recovery in fractured carbonates. We believed the results were encouraging enough to warrant further R&D and eventual field piloting.

Modeling of Gas Hydrate Formation Upon Injection of Carbon Dioxide Gas into A Natural Reservoir

This paper presents the results of numerical modeling of gas hydrate formation upon injection of carbon dioxide into a finite-length reservoir saturated with methane and water. It is shown that at different stages, hydrate formation can occur on both the frontal surface and in a reservoir region of finite length. The effects of pressure at the reservoir boundaries and the effects of the permeability and initial water saturation of the reservoir on the hydrate formation process were studied. The dependences of the time of the complete conversion of water into gas hydrate in the entire reservoir on the injection pressure and reservoir permeability were obtained.

Impacts of SO2 gas impurity within a CO2 stream on reservoir rock of a CCS pilot site: Experimental and modelling approach

In order to evaluate chemical impacts of SO2 impurity on reservoir rock during CO2 capture and storage in deep saline aquifers, several batch reactor experiments were performed on laboratory scale using core rock samples from the pilot CO2 injection site in Heletz. In this experiment, the samples were exposed to pure N2(g), pure CO2(g), and CO2(g) with an impurity of 1.5% SO2(g) under reservoir conditions for pressure and temperature (14.5 MPa, 60 °C). Based on the set-up and the obtained experimental results, a batch chemical model was established using the numerical simulation program TOUGHREACT V3.0-OMP. Comparing laboratory and simulation data provides a better understanding of the rock-brine-gas interactions. In addition, it offers an evaluation of the capability of the model to predict chemical interactions in the target injection reservoir during exposure to pure and impure CO2. The best match between the geochemical model and experimental data was achieved when the reactive surface area of minerals in the model was adjusted in order to calibrate the kinetic rates of minerals. The simulations indicated that SO2(g) tends to dissolve rather quickly and oxidizes under a kinetic control. Hence, it has a stronger effect on the acidity of the brine than pure CO2(g) and as a result, increased mineral dissolution and caused the precipitation of sulfate and sulfide minerals. Ankerite, dolomite, and siderite, the most abundant carbonates in the sandstone rock sample, are subject to stronger dissolution in the presence of SO2 gas. The performed simulations confirmed a slower dissolution rate for ankerite and siderite than for dolomite. The model reproduced the precipitation of pyrite and anhydrite as observed in the laboratory. The dissolution of dolomite observed in the batch reaction test with pure N2 is assumed to be due to slight contamination with oxygen and modelling supported this. The inclusion of SO2 increased the porosity over that of the pure CO2 case, and is thus considered to increase the permeability and injectivity of the reservoir as well. Exposure to SO2 also increased the concentration of trace elements. The calibrated kinetic parameters determined in this study will be used to model the injection and long-term behavior of CO2 at the Heletz field site, and may be used for similar geologic reservoirs.

Sensitivity analysis of coupled processes and parameters on the performance of enhanced geothermal systems

3-D modeling of coupled thermo-hydro-mechanical (THM) processes in enhanced geothermal systems using the control volume finite element code was done. In a first, a comparative analysis on the effects of coupled processes, operational parameters and reservoir parameters on heat extraction was conducted. We found that significant temperature drop and fluid overpressure occurred inside the reservoirs/fracture that affected the transport behavior of the fracture. The spatio-temporal variations of fracture aperture greatly impacted the thermal drawdown and consequently the net energy output. The results showed that maximum aperture evolution occurred near the injection zone instead of the production zone. Opening of the fracture reduced the injection pressure required to circulate a fixed mass of water. The thermal breakthrough and heat extraction strongly depend on the injection mass flow rate, well distances, reservoir permeability and geothermal gradients. High permeability caused higher water loss, leading to reduced heat extraction. From the results of TH vs THM process simulations, we conclude that appropriate coupling is vital and can impact the estimates of net heat extraction. This study can help in identifying the critical operational parameters, and process optimization for enhanced energy extraction from a geothermal system.

A new approach to characterize the performance of heavy oil recovery due to various gas injection

The performance of CO2 injection into a semi-heavy oil reservoir was investigated at reservoir conditions, using highly permeable sandstone in a complete series of PVT tests and coreflooding experiments. Analysis of involved parameters such as: injection rate, injectant type and reservoir pressure were also considered. Oil viscosity reduction and oil swelling are the most influential mechanisms of enhanced oil recovery in this process. The results demonstrated that CO2 injection would decrease the interfacial tension for the high permeable medium in the absence of capillarity, but this reduction may not improve the recovery drastically. One of the main important aspects of this work is the introduction of a new empirical combined dimensionless group (dissolution number, Ndis) that helps prediction of oil recovery in any other heavy oil reservoir with high permeability of porous media. In this case, a more precise analysis could be performed by applying the dissolution number instead of capillary and/or Bond number.

Analytical modelling of cyclic steam stimulation (CSS) process with a horizontal well configuration

In this study, a new semi‐analytical model has been developed to model heavy oil production using cyclic steam stimulation (CSS) and horizontal wells. In order to predict oil production, the governing equations of heat and fluid flow in cylindrical coordinate were solved. Average temperature in the formation during the soak period was calculated by solving the transient heat transfer equations. The heat transfer model was then coupled to a fluid inflow model to predict the fluid rates. The developed model is validated with the fine grid numerical simulation of the problem using a commercial numerical simulator. The robustness of the model was tested by comparing the model results with the results from the numerical simulator by changing various parameters such as: steam injection rates, reservoir permeability, relative permeability, oil viscosity, and reservoir thermal diffusivity. With some reasonable assumptions, it was seen that the results from the developed model are very close to the results obtained using the numerical simulator. This paper presents the model development in detail and outlines the steps involved in predicting the performance of a CSS process for a horizontal well configuration.

The Australian South West Hub Project: Developing a Storage Project in Unconventional Geology

The South West Hub project, through three generations of modelling based on new 2D and 3D seismic data and core/log information from four new wells is demonstrating that carbon dioxide storage is possible in an environment where there is no regional shale layer acting as a traditional seal. This paper summarises the work that has been undertaken in a collaborative manner into “unconventional geology” exploring migration assisted trapping in an on-shore saline aquifer by Government, private sector contractors and researchers in the south west of Western Australia.Carbon Capture and Storage (CCS), which involves capturing carbon dioxide that would otherwise be emitted to the atmosphere and injecting it to be stored in deep geological formations, is a potential stepping stone to maintaining energy security while reducing the carbon footprint of Australia's energy sources. CCS is the only technology available to make deep cuts in greenhouse gas emissions while still using the fossil fuels that power much of today's energy infrastructure. At a State level, the Western Australian Greenhouse Strategy incorporates CCS and is helping to address the need for a long-term commitment to climate change and cleaner energy.The Western Australia Department of Mines and Petroleum (DMP) started investigating the Lesueur site, near large CO2 emission sources (the industrial centres of Kwinana and Collie in the South West of Western Australia) in 2007 and developed the South West Hub (SW Hub) project concept in 2010 with the support of local industrial partners. The project was designated an “Australian Flagship” project in 2011 and has received substantial funding and support from the Federal Government, through the Department of Industry Innovation and Science) the Western Australia State Government and industry.The SW Hub Project is progressing data acquisition and analysis aimed at establishing confidence in storage associated with migration assisted trapping (MAT) in unconfined saline aquifers. The storage complex has no regional shale layer and consists of the Lower Lesueur (Wonnerup Member) as the injection reservoir, the Upper Lesueur (Yalgorup Member) with its numerous paleosol baffles as the lower confining layer and the basal shale part of the Eneabba Formation as the upper confining layer. The injection reservoir is a heterogeneous sandstone that is over 1500 m thick with varying permeability layers that should support residual and solubility trapping.From the very onset, the SW Hub Project has followed a rigorous stage gated decision making program. The project has been divided into phases and each phase involves targeted data acquisition plans to address technical gaps or uncertainties. These uncertainties have been documented in an Uncertainty Management Plan (UMP) and drive all technical work. “Decision Gates” ensure that, only on increased confidence of success would the project move to the next phase. The project processes are consistent with the DNV CO2QUALSTORE steps and the workflows defined in the EU Directive 2009/31/EC guidance document.Under the first phase of the new data acquisition program (2011-12), new geological data was gathered through 100km of targeted 2D seismic lines and one deep exploration well drilled to 2,945 metres. Multiple modelling scenarios with differing assumptions on the geological properties supported the storage concept and identified no “show stoppers”. Notwithstanding, uncertainty planning required additional data to address the gaps identified. Under the next phase of the development program (2013-15), 3D seismic was acquired over 115km2 and additional wells planned. The area of interest is dominated by farming activity and not all landowners provided consent to acquire the seismic data. As such, while high fold data has been acquired over the deeper Wonnerup Member reservoir sections, the shallower Yalgorup Member was not as well illuminated. The drilling strategy was adapted to maximise geological coverage particularly across the shallower reservoirs. Three wells were drilled using a combination of mineral and water well drilling rigs with a deeper well to be considered following model updates.Significant technical work has also been done to support this development through a range of research projects launched under the auspices of the Australian National Low Emissions Coal research and development program (ANLEC R&D). These projects are focused on reservoir characterisation and either consider more fundamental physics based questions or delve significantly deeper into specific geology and geophysics domains using laboratory and modelling efforts.Clear decision criteria to support additional investment in a drilling and testing program have been defined and will be addressed by modelling. The paper will explain the project challenges and the decision making rationale, highlighting the importance of good processes, long term planning, and extensive stakeholder management supported by a robust technical program.Results to date support MAT and validation of the SW Hub storage concept will substantially increase the number of geologic sites that can be considered for safe storage around the world. There is significant international interest in the project field and research activities.

Assessing CO2 Storage Capacity of a Steeply Dipping, Fault Bounded Aquifer and Effect of Impurity in CO2 Stream

A small scale injection project into an offshore aquifer near shoreline has begun which is seeking the connection with a capture project in Korea. The Pohang basin was selected as a site for a small-scale pilot project and detailed site characterization has been undertaken to establish a geological model for the site since 2013. A potential reservoir for CO2 injection was found at a depth more than 730 meters in the southern offshore part of the Pohang basin from seismic surveys and one exploration well. The seismic interpretation revealed the reservoir is a steeply dip and horizontally fault bounded aquifer. In this study, numerical reservoir simulations were carried out for assessing CO2 storage capacity especially in the dipping reservoir regarding the reactivation pressure of the bounded faults. At the same time, to investigate the effect of impurity in CO2 stream was one of our goals. Captured CO2 streams contain various levels of impurity which vary depending on the combustion technology and CO2 sources. Specifically for geological storage, the non-condensable gases in CO2 streams are not favorable because they can decrease density of the injected CO2 stream and can affect buoyancy of the plume. The effect of the non-condensable gases on storage capacity, injectivity and plume migrations were tested in the reservoir.

Numerical Simulation Study on Mitigation of the Pressure Build-up in the Geological Formation During Injection of CO2

The injection of supercritical CO2 into the deep underground increases the pore pressure in the geologic formation, first locally around the injection point, later spreads radially throughout the formation. The range of pressure increase depends on the injection rate, injectivity and reservoir volume. The increase of pressure in the reservoir may cause several problems, including fracturing of sealing layer, fault reactivation and changes in other hydrogeological conditions. In order to reduce the pressure buildup in the reservoir during CO2 injection, two methods were studied in this paper by numerical simulations using the TOUGH2 code. One describes production of formation water as proposed by Buscheck et al. in 2014 (dual-mode well), and the second method describes production of formation water via a second well during CO2 injection. We employed a simple reservoir model based on available data of the CCS demonstration project at the Tomakomai area in Hokkaido, Japan. The efficiency and influence of two reservoir volumes, and a hypothetical placed production well, on pressure build-up in the storage formation were tested. Two models with different volumes, and an injection rate of 1 Mt/yr were applied and three cases were simulated for each model. The first case only considered injection of CO2 for 100 years without production. The second case examined the dual-mode well, in which formation water was produced for 5 years prior to the start of CO2 injection for 100 years. The last (third) case assumed utilization of an observation well for producing water in parallel with CO2 injection. Judging from the results, the following conclusion can be drawn: 1) The dual-mode well with short duration of water production (5 years) was not so effective to maintain the reservoir pressure in the large reservoir volume considered here. The method would be better suited for smaller reservoir, otherwise a very long-term production would be necessary. 2) Water production in parallel with injection was very effective in order to maintain the reservoir pressure and to avoid harmful effects on the overlying seal layers and other hydrogeological conditions. The methods can be applied to make CCS technology much more sufficient through increasing the effective capacity of injectable CO2. It may also lead to more opportunities related to site selection. However, it has to be emphasized, that the effectiveness of the production strategies investigated here may highly depend on site conditions. Therefore, the results obtained in this study should be regarded as a preliminary evaluation for the Tomakomai site specifications. Further investigations would be necessary, when more data become available through the site investigation and even operations.

Pressure Monitoring to Detect Fault Rupture Due to CO2 Injection

The capacity for fault systems to be reactivated by fluid injection is well-known. In the context of CO2 sequestration, however, the consequence of reactivated faults with respect to leakage and monitoring is poorly understood. Using multi-phase fluid flow simulations, this study addresses key questions concerning the likelihood of ruptures, the timing of consequent upward leakage of CO2, and the effectiveness of pressure monitoring in the reservoir and overlying zones for rupture detection. A range of injection scenarios was simulated using random sampling of uncertain parameters. These include the assumed distance between the injector and the vulnerable fault zone, the critical overpressure required for the fault to rupture, reservoir permeability, and the CO2 injection rate. We assumed a conservative scenario, in which if at any time during the five-year simulations the critical fault overpressure is exceeded, the fault permeability is assumed to instantaneously increase. For the purposes of conservatism we assume that CO2 injection continues ‘blindly’ after fault rupture. We show that, despite this assumption, in most cases the CO2 plume does not reach the base of the ruptured fault after 5 years. One possible implication of this result is that leak mitigation strategies such as pressure management [1] have a reasonable chance of preventing a CO2 leak.A very simple algorithm for detecting rupture, based on analysis of pressure data collected at the injection well, detects 100% of the ruptures. The algorithm is purely empirical and does not require a numerical or analytical model of the injection reservoir. However, this technique produces unacceptably high percentage of false positives (18%). We expect that in more realistic scenarios where multiple types of data are collected the rate of false positives would decrease. Regardless, our results suggest that for the class of scenarios we have considered the risk of undetected fault ruptures is low and the length of time available for mitigation is relatively long.The size of the ‘rupture detection’ footprint is significantly larger within the reservoir than in the overlying aquifers. In all layers the area near the fault zone is the first to respond and so would be easily detected if monitoring wells were placed near the fault. However, if the fault zone location is unknown a priori it will be unlikely to be intensively monitored and so these pressure changes may go undetected. Fortunately in the reservoir the pressure perturbation is also evident at the injection well and so the rupture can be detected even without an independent monitoring well network.

Investigation of Depth and Injection Pressure Effects on Breakdown Pressure and Fracture Permeability of Shale Reservoirs: An Experimental Study

The aim of this study was to identify the influence of reservoir depth on reservoir rock mass breakdown pressure and the influence of reservoir depth and injecting fluid pressure on the flow ability of reservoirs before and after the hydraulic fracturing process. A series of fracturing tests was conducted under a range of confining pressures (1, 3, 5 and 7 MPa) to simulate various depths. In addition, permeability tests were conducted on intact and fractured samples under 1 and 7 MPa confining pressures to determine the flow characteristic variations upon fracturing of the reservoir, depending on the reservoir depth and injecting fluid pressure. N2 permeability was tested under a series of confining pressures (5, 10, 15, 20 and 25 MPa) and injection pressures (1–10 MPa). According to the results, shale reservoir flow ability for gas movement may reduce with increasing injection pressure and reservoir depth, due to the Klinkenberg phenomenon and pore structure shrinkage, respectively. The breakdown pressure of the reservoir rock linearly increases with increasing reservoir depth (confining pressure). Interestingly, 81% permeability reduction was observed in the fractured rock mass due to high (25 MPa) confinement, which shows the importance of proppants in the fracturing process.

A rock physics and seismic reservoir characterization study of the Rock Springs Uplift, a carbon dioxide sequestration site in Southwestern Wyoming

We present a reservoir geophysics study, including rock physics modeling and seismic inversion, of a carbon dioxide sequestration site in Southwestern Wyoming, namely the Rock Springs Uplift, and build a petrophysical model for the potential injection reservoirs for carbon dioxide sequestration. Our objectives include the facies classification and the estimation of the spatial model of porosity and permeability for two sequestration targets of interest, the Madison Limestone and the Weber Sandstone. The available dataset includes a complete set of well logs at the location of the borehole available in the area, a set of 110 core samples, and a seismic survey acquired in the area around the well. The proposed study includes a formation evaluation analysis and facies classification at the well location, the calibration of a rock physics model to link petrophysical properties and elastic attributes using well log data and core samples, the elastic inversion of the pre-stack seismic data, and the estimation of the reservoir model of facies, porosity and permeability conditioned by seismic inverted elastic attributes and well log data. In particular, the rock physics relations are facies-dependent and include granular media equations for clean and shaley sandstone, and inclusion models for the dolomitized limestone. The permeability model has been computed by applying a facies-dependent porosity-permeability relation calibrated using core sample measurements. The study shows that both formations show good storage capabilities. The Madison Limestone includes a homogeneous layer of high-porosity high-permeability dolomite; the Weber Sandstone is characterized by a lower average porosity but the layer is thicker than the Madison Limestone.

CO2 storage in depleted gas reservoirs: A study on the effect of residual gas saturation

Abstract Depleted gas reservoirs are recognized as the most promising candidate for carbon dioxide storage. Primary gas production followed by injection of carbon dioxide after depletion is the strategy adopted for secondary gas recovery and storage practices. This strategy, however, depends on the injection strategy, reservoir characteristics and operational parameters. There have been many studies to-date discussing critical factors influencing the storage performance in depleted gas reservoirs while little attention was given to the effect of residual gas. In this paper, an attempt was made to highlight the importance of residual gas on the capacity, injectivity, reservoir pressurization, and trapping mechanisms of storage sites through the use of numerical simulation. The results obtained indicated that the storage performance is proportionally linked to the amount of residual gas in the medium and reservoirs with low residual fluids are a better choice for storage purposes. Therefore, it would be wise to perform the secondary recovery before storage in order to have the least amount of residual gas in the medium. Although the results of this study are useful to screen depleted gas reservoirs for the storage purpose, more studies are required to confirm the finding presented in this paper.

A risk map methodology to assess the spatial and temporal distribution of leakage into groundwater from Geologic Carbon Storage

The risks to potable aquifers due to brine leakage through plugged and abandoned (P&A) wells is highly uncertain and a potentially significant contributor to the risk profile in Geologic Carbon Storage (GCS). This uncertainty stems from the unknown location of wells and the large variance of P&A wellbore permeability, making the spatial assessment of P&A brine leakage risk challenging. A new methodology is presented to generate “risk maps”, or spatial distributions of brine leakage risk to groundwater resources as defined with no-impact or Maximum Contaminant Level (MCL) thresholds. The methodology utilizes probability theory, thereby avoiding the use of computationally expensive Monte Carlo simulations while maintaining flexibility in modeling techniques. These maps provide quantitative probabilities of risk as a function of time to inform site selection and monitoring during and post-injection, conducive to the US EPA’s permitting of class-VI wells and the so-called “area of review”, AoR. As a demonstration of the methodology, a numerical model of a hypothetical fully-coupled system spanning from the injection reservoir to the USDW is used to assess the evolution of brine leakage through P&A wells. Risk maps of CO2 leakage can also be generated with this methodology for a comprehensive assessment of GCS leakage risk.

South West Hub Project, Western Australia: appraising ‘migration-assisted' containment for carbon storage in sandstone strata

The South West Hub project (SW Hub) managed by the Department of Mines and Petroleum (DMP) Carbon Strategy Branch, is continuing to build confidence in storage associated with migration assisted trapping (MAT) in unconfined saline aquifers. The area of interest is in the Harvey and Waroona Shires near large CO2 emission sources in the industrial centres of Kwinana and Collie. The injection target is the Lower Lesueur sandstone, a 1500 m thick reservoir with varying permeability layers that should support residual and solubility trapping. The storage complex has no regional shale layer and depends on MAT for primary containment, with the 600 m thick Upper Lesueur with its numerous paleosol baffles as the lower confining layer and the basal shale part of the Eneabba Formation as the upper confining layer. Detailed models have been built based on new 2D/3D seismic surveys and core/log data from the drilling of four wells over a five year period. The results, which include extensive sensitivity analysis, indicate that commercial quantities of CO2 may be injected safely with the plume remaining within the injection reservoir. Uncertainties do remain and the next stage of the program is aimed at reducing these. Significant technical work has also been done through research projects executed by the National Geosequestration Laboratory (NGL) and funded by the Australian National Low Emissions Coal research and development program (ANLEC R&D). This paper will summarise the geological setting, the technical workflow/activities and assurance processes together with the significant community and stakeholder management efforts undertaken.

An Improved Steam Injection Model with the Consideration of Steam Override

The great difference in density between steam and liquid during wet steam injection always results in steam override, that is, steam gathers on the top of the pay zone. In this article, the equation for steam override coefficient was firstly established based on van Lookeren’s steam override theory and then radius of steam zone and hot fluid zone were derived according to a more realistic temperature distribution and an energy balance in the pay zone. On this basis, the equation for the reservoir heat efficiency with the consideration of steam override was developed. Next, predicted results of the new model were compared with these of another analytical model and CMG STARS (a mature commercial reservoir numerical simulator) to verify the accuracy of the new mathematical model. Finally, based on the validated model, we analyzed the effects of injection rate, steam quality and reservoir thickness on the reservoir heat efficiency. The results show that the new model can be simplified to the classic model (Marx-Langenheim model) under the condition of the steam override being not taken into account, which means the Marx-Langenheim model is corresponding to a special case of this new model. The new model is much closer to the actual situation compared to the Marx-Langenheim model because of considering steam override. Moreover, with the help of the new model, it is found that the reservoir heat efficiency is not much affected by injection rate and steam quality but significantly influenced by reservoir thickness, and to ensure that the reservoir can be heated effectively, the reservoir thickness should not be too small.

A Comparison Study between the Newly Developed Vertical Wells Steam Assisted Gravity Drainage and the Conventional SAGD Process

A numerical simulation study using the CMG-STAR Simulator was performed to compare the performance of the newly developed process (VWSAGD) utilizing vertical wells to enhance heavy oil recovery during steam assisted gravity drainage against the conventional steam assisted gravity drainage process which utilized horizontal wells (HWSAGD) under the same operating conditions. Two identical reservoir models were simulated for the two processes using 3-Dimensional, black heavy oil model (14° API). Each reservoir type consists of 49 × 49 × 20 grid blocks on a 5-acre model, which incorporated a typical heavy oil reservoir rock and fluid properties taken from the SPE case study, stspe001.dat (CMG 2015 release). A sensitivity analysis for both processes was performed for the grid density, soaking time, steam quality, bottom hole producing pressure, steam injection rate, reservoir thickness, reservoir area, and horizontal to vertical permeability anisotropy. More preferable reservoir conditions are those such as high horizontal to vertical permeability ratio, thick reservoir oil zones, as well as improved reservoir recovery for the VWSAGD process. Under unfavorable conditions such as thin reservoir oil zones, an improved reservoir recovery response was limited for the VWSAGD process and could be uneconomical in real field cases. Finally, the simulation results from this study include cumulative recoveries, Steam oil ratios, produced water-oil ratios, pressure and temperature distributions, and production rates. In addition, the results from this study have shown that the new VWSAGD process is more favorable than the conventional HWSAGD process.

A New Steam Assisted Gravity Drainage Process Utilizing Vertical Wells

A novel process utilizing vertical wells to enhance heavy oil recovery during steam assisted gravity drainage has been developed. In the vertical well steam assisted gravity drainage (VWSAGD) process shown in Figure 1, the vertical well includes two production strings which are separated by three packers (one dual and two single packers): the short injection string (SIS) is attached to the bottom of the annulus and completed in the top quarter of the perforated formation, while the long production string (LPS) is attached to the bottom of the production tubing and completed in the bottom quarter of the perforated formation. The new process (VWSAGD) requires an initial start-up period (warm-up stage) where the steam is injected into both of the injection strings and production string for a specified period of time of about 14-30 days; then both strings are closed to injection for a specified time period of approximately 7 - 10 days (soaking period). After the initial warm-up and the soaking period, the long production string is opened for production, and the short injection string is opened to continuous steam injection for the rest of the specified simulation time. A commercial simulator (CMG-STAR Simulator) was used to study the performance of the new VWSAGD process. A sensitivity analysis was performed for the grid density, soaking time, steam quality, bottom hole producing pressure, steam injection rate, reservoir thickness, reservoir area, and horizontal to vertical permeability anisotropy. The results of this study have shown that the new VWSAGD process is more preferable for reservoir conditions such as high horizontal to vertical permeability ratio and thick reservoir oil zones.

Numerical Modeling of CO2 and Brine Leakage through Open Fracture in a Fault Zone: Open Channel Flow or Darcy Flow

Understanding fluids migration and leakage risk along the fault zone is necessary to guarantee the safety of CO2 geological storage. The validity of Darcy’s law gets challenged in dealing with the flow in open fractures since the occurring of turbulence flow. In this study, we develop a 2D model with usage of T2Well, an integrated wellbore-reservoir simulator, to investigate the leakage problem along open fractures which are embedded in a fault zone from the deep injection reservoir to shallow aquifers. The results record a positive feedback of gas expansion and pressure response in fracture, which causes a quick downward propagation of highly gas saturated zone from the top of fracture and an easy gas breakthrough in the shallower aquifers. The decreasing of aperture size of fracture significantly enhances the leakage rates in fracture, but with less influences as aperture increases. In comparison, the Equivalent Porous Media models show a good approximation with the momentum model of large apertures but poor for the small one. Nevertheless, the differences are small in terms of final CO2 distribution among various aquifers, suggesting that Darcy’s law may be still “effective” in solving flow problem along fractures in a constant injection system at a large time scale.