CO2 Injection Tests Research Articles

Insights into CO2 huff-n-puff mechanisms from laboratory experiment and single-well pilot test in the Lucaogou tight oil reservoir, Jimsar sag, China

CO2 huff-n-puff has been accepted as an effective technique to improve oil recovery in tight oil reservoirs. Even though CO2 EOR mechanisms were extensively investigated from laboratory experiments, the links of experimental results to field-scale performance have not been widely investigated as few pilot tests were conducted. In this study, laboratory experiments and CO2-huff-n-puff pilot test were performed. First, phase behaviors of the Lucaogou crude oil and oil-CO2 mixtures were investigated via Pressure-Volume-Temperature (PVT) tests including flash evaporation, constant composition extension (CCE), and CO2 injection and slim tube tests, respectively. Experimental results showed that due to the higher concentration of the intermediate components, the saturation pressure of the Lucaogou crude oil is 6.18 MPa, which is much smaller than the initial and current formation pressures. The oil viscosity decreased from 24.8 mPa s to 3.0 mPa s and swelling factor increased to 1.848 after about 85 mol% CO2 dissolved. Moreover, slim tube test showed the minimum miscible pressure of the Lucaogou crude oil is 24.28 MPa, which is smaller than the current formation pressure, indicating multi-contact miscibility could be reached easily. Second, fracturing fluid imbibition and CO2 huff-n-puff experiments were carried out to evaluate the performance of CO2 EOR after fracturing. The oil recovery factor increased after imbibition time and the number of huff-n-puff cycles, and was impacted by petrophysical properties, like porosity and pore structure. In addition, performance of CO2 huff-n-puff pilot test in the J30 well was reported. Approximately 1.9% of original oil in place was recovered after one huff-n-puff cycle, showing a significant potential of CO2 EOR in the Lucaogou tight formation. Analysis of oil production rate, composition and density of produced oil shows the dominant EOR mechanisms in the early production stage were miscibility and CO2 vaporization, then viscosity reduction. Findings from this study will provide insights on CO2 EOR in tight oil reservoirs.

A numerical modelling study to support design of an in-situ CO2 injection test facility using horizontal injection well in a shallow-depth coal seam

Previous projects on CO2 storage in coal often reported the challenges associated with coal swelling and swelling-induced loss of gas injectivity. Since coal seams are typically thin, commonly used vertical wells only intersect a target reservoir over a small contact area, placing constraints on CO2 injectivity in addition to those resulting from coal swelling. This leaves the storage reservoirs largely under-utilized and, therefore, questions the viability of this technology. To address the challenges/limitations of the current practice, a novel in-situ CO2 injection test is planned using horizontal injection wells in Mikolow, Poland. This paper presents the pre-operational simulation studies conducted to assist the design and operation of the in-situ test. An existing dual-porosity model that is built on a coupled thermo-hydro-chemical-mechanical (THCM) modelling framework is employed in this study. Sensitivity of the model parameters and validity of the model are tested. Several simulation scenarios are developed in reference to the selected test site for various horizontal well configurations and gas injection conditions. From the results and analyses, it is evident that by varying the coal-CO2 contact area via the length of the horizontal injection well, as well as the operating conditions including fixed pressure, and fixed rate injection scenarios, the targeted amount (between 1 to 10 tonnes) of CO2 can be injected into the seam without significant loss of permeability or injectivity, yielding sustained gas injection. Moreover, the spread of CO2 is predicted to be contained within the model domain suggesting no significant concern of spread exceeding the test area.

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.

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.

Experimental assessment of the hydro-mechanical behaviour of a shale caprock during CO2 injection

The presented experimental study focuses on the hydro-mechanical characterisation of a shale caprock (Opalinus Clay) in contact with carbon dioxide. The objective of this paper, consists in the evaluation of the material's sealing capacity in terms of entry-pressure, mechanical behaviour and sensitivity of the transport properties to chemo-mechanical effects induced by gaseous and liquid CO2 injection. Two types of Opalinus Clay core samples are tested; shaly and carbonate-rich. The sealing capacity has been evaluated on the shaly OPA according to the stepwise and the residual methods and compared to the results from mercury intrusion porosimetry. The obtained results and the differences associated to the different involved physical processes are discussed and compared with literature data. Injection tests carried out in saturated and unsaturated conditions have revealed that sub-critical CO2 propagation in a water saturated material is not associated with generation of fractures. On the other hand, the generation of capillary forces is affecting the mechanical behaviour beside the sealing capacity. The impact of chemical effects on the permeability of both types of OPA is analysed with long-term CO2 injection tests, where no significant variations of permeability are measured during the exposure time investigated. The challenges related to this type of analysis with laboratory scale experiments are illustrated and new insights on the behaviour of Opalinus Clay when subjected to injection of a non-wetting fluid are highlighted.

The CSIRO In-Situ Laboratory: a field laboratory for derisking underground gas storage

The industry in western Australia has committed to addressing their carbon emissions in response to the governments aspiration of net zero greenhouse gas emissions by 2050. Natural gas will play an important role in the transition to a fully renewable energy market but will require the geological storage of carbon dioxide to limit emissions and enable the production of blue hydrogen. Underground storage of energy in general (e.g. natural gas, hydrogen, compressed air) will be needed increasingly for providing options for temporary storage of energy from renewable resources and for energy export. Storage operations would need to provide adequate monitoring systems in compliance with yet to be defined regulations and to assure the public that potential leakage or induced seismicity could be confidently detected, managed and remediated. The In-Situ Laboratory in the southwest of western Australia was established in 2019 as a research field site to support low emissions technologies development and provides a unique field site for fluid injection experiments in a fault zone and testing of monitoring technologies between 400m depth and the ground surface. The site currently consists of three wells instrumented with fibre optics, pressure, temperature and electric resistivity sensors as well as downhole geophones. A controlled release of CO2 and various water injection tests have demonstrated the ability to detect pressure and temperature effects associated with fluid injection. Future experiments planned at the site will help in improving the sensitivity of monitoring technologies and could contribute to defining adequate monitoring requirements for carbon dioxide, hydrogen and other energy storage operations.

Design considerations for using Distributed Acoustic Sensing for cross‐well seismics: A case study for CO2 storage

ABSTRACTDownhole monitoring with fibre‐optic Distributed Acoustic Sensing (DAS) systems offers unprecedented spatial resolution. At the same time, costs are reduced since repeated wireline surveys can be replaced by the permanent installation of comparatively cheap fibre cables. However, the single component nature of fibre data requires novel approaches when designing a monitoring project such as cross‐well seismics. At the example of the shallow CO2 injection test site in Svelvik, Norway, we model the evolution of velocity changes during CO2 injection based on rock physics theory. Different cross‐well seismic design scenarios are then considered to evaluate the best design and the limits of this method to detect containment breach. We present a series of evaluation tools to compare the effect of different well spacings for cross‐well seismic tomography. In addition to travel‐times, we also consider characteristic amplitude changes along the fibre unique to DAS strain measurements, which might add a constraint to the inversion. We also compare the effect of using helical fibres instead of classical straight fibres. We thus present a toolbox to evaluate and compare different monitoring design options for fibre optic downhole installations for cross‐well monitoring.

ANALISIS PENGARUH INJEKSI CO2 TERHADAP RECOVERY FACTOR MENGGUNAKAN SIMULASI CMG DI LAPANGAN X

X-Field is located in South Sumatra, where there are several gas fields with considerable CO2 gas potential. In this field, no research has been conducted on CO2 injection neither in the laboratory nor simulation. Therefore, the purpose of this study is to analyze the effect of CO2 injection on the value of recovery factor with one-dimensional simulation using CMG. To be able to make an accurate simulation model, it is necessary to do validation by comparing the results obtained with the CO2 injection test from experiments in the laboratory. Laboratory experimental data used in this study is from Vulin’s literature. The result of recovery factor for X-field is 98.80%. From the results of this study, it is known that the injection rate of CO2 has no effect on changes in recovery factor. However, the difference of CO2 injection pressure in these two samples influences the change in recovery factor. The higher injection pressure of CO2 in an immiscible condition is, the higher the value of the recovery factor is achieved. In addition, the difference in oil composition in these two samples affects the value of MMP, where the higher the intermediate component of a reservoir fluid is, the lower the MMP will be. X-field has a high intermediate component fraction, therefore the value of MMP obtained is lower than the MMP from Vulin’s literature. The value of MMP in X-field is 2610.68 psia

Impact of CO2 Injection Speed on CO2 Behavior in Two Types of Sandstone

CO2 injection speed (FR) is one of important factor to control the CO2 flow mechanism in sandstone. In this study, we conducted two CO2 injection experiments into different types of sandstone with changing FR under reservoir P-T conditions (40°C and 10 MPa). This study used high-permeable Berea-sand stone (10 mD) and ultra-low permeable-Ainoura sandstone (0.01mD) for CO2 injection tests and estimated CO2 saturation (SCO2) and differential pressure (DP) between up- and down-stream of sandstones. Injected CO2 penetrates water-saturated sample and replaced resident brine in pore-spaces. Increasing FR, CO2 flows the pathway, which is formed by former injected CO2 with replacing brine in pore with increasing SCO2 and DP. In this study, these parameters showed different changes between Berea and Ainoura with increasing FR. In case of Berea, they showed small changes of both of vales under lower FR and rapidly increased up to around 50% for SCO2 and 0.5MPa for DP at the highest FR. While, these parameters of Ainoura indicated large values at lowest FR, over 20% for SCO2 and 0.3MPa for DP and reached near 60% for SCO2 and 0.9 MPa for DP at high FR. We investigated electrical resistivity and SCO2 relation based on Archie’s law. RI of both samples illustrated near-linear relation between 90 and 50% of SCO2. Over 50% of SCO2, RI of Ainoura sandstone departed from Archie’s model. It is considered that the difference of RI-Sw relations between Berea and Ainoura sandstone is caused by differences of rock texture. These experimental campaigns clearly pointed out the importance of FR and absolute permeability (and pore structure) to predict CO2 flow mechanisms in porous sandstone. It is also indicated that electrical properties (resitivity and RI) have large potential to estimate SCO2 and to elucidate the CO2 flow in the sandstone sample.

Application of single-well push-drift-pull tests using dual tracers (SF6 and salt) for designing CO2 leakage monitoring network at the environmental impact test site in Korea

A single-well push-drift-pull tracer test using two different tracers (SF6 and salt) was performed at the Environmental Impact Test (EIT) site to determine suitable locations for monitoring wells and arrange them prior to artificial CO2 injection and leak tests. Local-scale estimates of hydraulic properties (linear groundwater velocity and effective porosity) were obtained at the study site by the tracer test with two tracers. The mass recovery percentage of the volatile tracer (SF6) was lower than that of the non-volatile tracer (salt) and increased drift time may make degassing of SF6 intensified. The CO2 leakage monitoring results for both unsaturated and saturated zones suggest that the CO2 monitoring points should be located near points at which a high concentration gradient is expected. Based on the estimated hydraulic properties and tracer mass recovery rates, an optimal CO2 monitoring network including boreholes for monitoring the unsaturated zone was constructed at the study site.

Reactive transport simulation to assess geochemical impact of impurities on CO2 injection into siliciclastic reservoir at the Otway site, Australia

It is generally recognized that the removal of impurities from CO2 obtained from coal-fired flue gas carbon capture systems can significantly increase the cost of Carbon Capture and Storage (CCS). During the period from September to December 2014, the CO2CRC in collaboration with Callide Oxyfuel Services Pty Ltd conducted a series of CO2 injection tests into the Paaratte formation (Otway Basin, Victoria, Australia) utilizing product CO2 (near food grade) and product CO2 with added impurities (nominal SO2: 67ppmv, O2: 6150ppmv and NOx: 9ppmv) from the Callide Oxyfuel Project. The purpose of the injection testing was to assess the geochemical effect of the CO2 injected with water on the siliciclastic reservoir. The geochemical test, which was designed and conducted by CO2CRC, consists of water production, Test 1 (injection of CO2-saturated water without impurities), and Test 2 (injection of CO2-saturated water with impurities). In this paper, 2-D radial reactive transport simulations of injection tests were carried out using TOUGHREACT, including: (1) simulation of the pre-injection period from Otway Stage 2B Test in 2011 to the start of the geochemical test; (2) simulations of the pure CO2 and the impure CO2 cases; (3) long-term simulation of the impure CO2 case; and (4) simulations of injection of CO2-saturated water with various impurity concentrations. The numerical model was able to reproduce the observed geochemical changes during the geochemical test. The results indicate that there were negligible differences between the pure CO2 and the impure CO2 cases for both changes in water chemistry and mineralogy, if SO2 or O2 was less than 1000ppmv. Based on this evaluation of both field test results and simulations, by extrapolation it is concluded that co-injection of impurity gases (up to 1000ppmv SO2 and 1000ppmv O2) with CO2 would have insignificant impacts on the reservoir at the Otway site. In the long-term simulation, the distribution area of residual gas in the reservoir was small and the pH of the formation water was near neutral after 1000 years. Moreover, it was predicted that the water disturbed by CO2 impurities would come close to the initial geochemical conditions in the long-term, and that it is highly probable that the long-term impact after 1000 years would become much less compared to the short-term impact in the test period. The method and model presented here was suitable for the Otway site test and would be applicable to other CO2 storage sites with similar conditions.

Feasibility assessment of heavy-oil recovery by CO2 injection after cold production with sands: Lab-to-field scale modeling considering non-equilibrium foamy oil behavior

With notion to the potential use of cyclical CO2 injection as a follow-up post-CHOPS (Cold Heavy Oil Production with Sand) EOR option, a comprehensive core-to-field scale study was performed to investigate the non-equilibrium CO2 behavior. PVT lab measurements of both CO2 injection and depletion tests were performed and modeled under highly controlled conditions and at different temperatures to obtain equilibrium properties. To address the kinetics of the non-equilibrium process, a 1.5-m multiple pressure-port core holder was designed to measure the differential pressure in the various sections of the sand-pack during CO2 depletion tests. Oil and gas volumes and the signature of pressures along the core holder length were recorded at each trial.Next, the CO2 depletion experiments were numerically simulated and the parameters of reaction kinetics used to model the liberation of dissolved CO2 gas to trapped CO2 bubbles and then to free CO2 gas non-equilibrium foamy oil depletion) were determined. The grid sensitivity of the reaction kinetics was investigated and a power-law core-to-field scaling rule was developed and numerically validated. The scaling rule was then used to upscale the reaction parameters for a previously history matched CHOPS field with 15 wells in Alberta (Rangriz Shokri and Babadagli, 2012, 2014). Lastly, the economic feasibility assessment of cyclic CO2 stimulation as a follow-up field-scale post-CHOPS option was determined under different oil price scenarios to optimize the operating conditions and the selection of the best possible field development strategies.

Oxygen isotopes as a tool to quantify reservoir-scale CO2 pore-space saturation

Structural and residual trapping of carbon dioxide (CO2) are two key mechanisms of secure CO2 storage, an essential component of Carbon Capture and Storage technology. Estimating the amount of CO2 that is trapped by these two mechanisms is a vital requirement for accurately assessing the secure CO2 storage capacity of a formation, but remains a key challenge. Here, we review recent field and laboratory experiment studies and show that simple and relatively inexpensive measurements of oxygen isotope ratios in both the injected CO2 and produced water can provide an assessment of the amount of CO2 that is stored by residual and structural trapping mechanisms. We find that oxygen isotope assessments provide results that are comparable to those obtained by geophysical techniques. For the first time we assess the advantages and potential limitations of using oxygen isotopes to quantify CO2 pore-space saturation based on a comprehensive review of oxygen isotope measurements from reservoir waters and various global CO2 injection test sites. We further summarise the oxygen isotope composition of captured CO2 in order to establish the controls on this fingerprint.

Design and and Construction of Groundwater Monitoring Network at Shallow-depth CO2 Injection and Leak Test Site, Korea

The effectiveness of CO2 leakage characterization is highly dependent on reasonable monitoring network designs for detecting the CO2 leakage under various hydrogeological conditions. Also, the migration of CO2 through heterogeneous subsurface is very difficult to predict because small differences in material properties may result in vastly different migration patterns. Therefore, like other environmental contaminants, it is necessary to design optimized groundwater monitoring network to effectively characterize the migration of the CO2. Main objectives of this study is to construct optimized groundwater monitoring network considering hydrogeological characteristics in field-scale transport of CO2 originated from artificially-injected CO2 at the environmental impact monitoring test site in Eumseong, Korea (K-COSEM). 24 monitoring wells were installed at the site aligned with the regional groundwater flow direction. Various hydraulic tests were performed to estimate the hydraulic characteristics such as hydraulic conductivity, effective porosity, and groundwater velocity. Groundwater monitoring network for CO2 injection and leak test constructed with regard of the heterogeneity understood through the various field tests. Three multi-depth monitoring well nests each of them was composed of four monitoring well units drilled with different depths (each 18, 22, 26, 30 m deep) have been installed along the groundwater flow direction and dedicated to depth-discrete water quality monitoring in saturated zone. Additional, four multi-depth monitoring well nests each of them was composed of four unsaturated-zone monitoring well units drilled with different depths (each 5, 8, 11, 14 m deep) were also installed with a distance of 1.25 m away between saturated zone monitoring wells and were dedicated to depth-discrete gas monitoring in unsaturated zone. By these efforts, effective groundwater monitoring network for temporal and spatial CO2 leakage detection and groundwater safety management have been designed and constructed at the test site.

2D Reactive Transport Simulations of CO2 Streams Containing Impurities in a Saline Aquifer, Heletz, Israel

In order to evaluate the chemical impacts of CO2 stream impurities on reservoir rocks, 2D reactive transport simulations using the code TOUGHREACT V3.0 were performed. The underlying reservoir properties are based on in-situ data from the CO2 injection test site Heletz, Israel. Two different CO2 compositions (mole fractions 99% CO2 + 1% SO2 and 98.8% CO2 + 1% SO2 + 0.2% NO2, respectively) were chosen to represent oxidising impurities. Different modelling approaches, namely trace gas transport (TGT) and additional brine injection (ABI), were applied to investigate the influence of these modelling approaches on qualitative and quantitative simulation results. The simulations using either approach show an accumulation of SO2 and NO2 close to the injection well due to the preferential dissolution of these acidic impurities compared to CO2. Both modelling approaches indicate the same general chemical impact and related mineral reactions. Within the affected rock volume a distinct ankerite to anhydrite conversion occurs, which slightly enhances porosity. While the same qualitative conclusions independently from the chosen modelling approach were obtained, the quantitative magnitude of mineral conversion and the spatial extent of impurity affected rock material depend on the chosen modelling approach and thus need further investigation with respect to e.g. validation by field test data.

Stepping into the Same River Twice: Field Evidence for the Repeatability of a CO2 Injection Test

A single well characterisation test was conducted at the CO2CRC Otway storage site in Victoria, Australia, in 2011 and repeated in 2014. The near-well permeability was found to have declined nearly 60% since the 2011 test, while the residual saturation inferred from a variety of techniques was lower in 2014. There was a significant change in water chemistry, suggesting an alteration of near-well reservoir properties. Possible reasons for these changes are explored, and the implications for other field tests are discussed.

Detection of carbon dioxide leakage during injection in deep saline formations by pressure tomography

AbstractCO2 injected into storage formations may escape to the overlying permeable layers. Mixed‐phase diffusivity, namely the ratio of hydraulic conductivity and specific storage of the phase mixture, declines with increasing CO2 saturation. Thus, it can be an indicator of CO2 leakage. In this study, we perform interference brine or CO2 injection tests in a synthetic model, including a storage reservoir, an above aquifer, and a caprock. Pressure transients derived from an observation well are utilized for a travel‐time based inversion technique. Variations of diffusivity are resolved by inverting early travel time diagnostics, providing an insight of plume development. Results demonstrate that the evolution of CO2 leakage in the above aquifer can be inferred by interpreting and comparing the pressure observations, travel times, and diffusivity tomograms from different times. The extent of the plume in reservoir and upper aquifer are reconstructed by clustering the time‐lapse data sets of the mixed‐phase diffusivity, as the diffusivity cannot be exactly reproduced by the inversion. Furthermore, this approach can be used to address different leaky cases, especially for leakage occurring during the injection.

Using time-lapse VSP data to constrain velocity-saturation relations

Quantitative interpretation of time-lapse seismic data is an ongoing challenge. Understanding the velocity-saturation relations and changes caused by CO2 injection play an important role for the application of seismic monitoring techniques to carbon dioxide storage projects.High uncertainties associated with well log measurements affected by borehole conditions can affect our ability to constrain a rock physics model. Seismic measurements, such as Vertical Seismic Profile (VSP), that span both the near-well region and far beyond the borehole can provide good control for correcting these measurements and reducing the uncertainties thereafter.In this paper, we analyse the observed time delays in time-lapse VSP data from the Frio CO2 injection test site by employing an integrated approach of rock physics and seismic forward modelling to reduce uncertainties in the choice of the dry frame modulus and velocity-saturation relations. First, we confirmed the quality of pre-injection well logs velocities with VSP data. Afterwards, we use inverse Gassmann relations to calculate the dry frame properties of the reservoir with different input parameters for the grain moduli with fluid substitution applied for uniform saturation of brine and CO2. Finally, forward modelling of the results is implemented to compare the response with field VSP data.Our investigation shows that VSP data can help constrain the choice of dry frame modulus, and thus the velocity-saturation relation. The rock physics model best matches the VSP results using large grain moduli and uniform saturation for fluid substitution.

Field testing of modular borehole monitoring with simultaneous distributed acoustic sensing and geophone vertical seismic profiles at Citronelle, Alabama

ABSTRACTA modular borehole monitoring concept has been implemented to provide a suite of well‐based monitoring tools that can be deployed cost effectively in a flexible and robust package. The initial modular borehole monitoring system was deployed as part of a CO2 injection test operated by the Southeast Regional Carbon Sequestration Partnership near Citronelle, Alabama. The Citronelle modular monitoring system transmits electrical power and signals, fibre‐optic light pulses, and fluids between the surface and a reservoir. Additionally, a separate multi‐conductor tubing‐encapsulated line was used for borehole geophones, including a specialized clamp for casing clamping with tubing deployment. The deployment of geophones and fibre‐optic cables allowed comparison testing of distributed acoustic sensing. We designed a large source effort (>64 sweeps per source point) to test fibre‐optic vertical seismic profile and acquired data in 2013. The native measurement in the specific distributed acoustic sensing unit used (an iDAS from Silixa Ltd) is described as a localized strain rate. Following a processing flow of adaptive noise reduction and rebalancing the signal to dimensionless strain, improvement from repeated stacking of the source was observed. Conversion of the rebalanced strain signal to equivalent velocity units, via a scaling by local apparent velocity, allows quantitative comparison of distributed acoustic sensing and geophone data in units of velocity. We see a very good match of uncorrelated time series in both amplitude and phase, demonstrating that velocity‐converted distributed acoustic sensing data can be analyzed equivalent to vertical geophones. We show that distributed acoustic sensing data, when averaged over an interval comparable to typical geophone spacing, can obtain signal‐to‐noise ratios of 18 dB to 24 dB below clamped geophones, a result that is variable with noise spectral amplitude because the noise characteristics are not identical. With vertical seismic profile processing, we demonstrate the effectiveness of downgoing deconvolution from the large spatial sampling of distributed acoustic sensing data, along with improved upgoing reflection quality. We conclude that the extra source effort currently needed for tubing‐deployed distributed acoustic sensing vertical seismic profile, as part of a modular monitoring system, is well compensated by the extra spatial sampling and lower deployment cost as compared with conventional borehole geophones.

Parametric study of oil recovery during CO2 injections in fractured chalk: Influence of fracture permeability, diffusion length and water saturation

Experimental secondary and tertiary CO2 injection tests in fractured, strongly water-wet, chalk core samples were performed to investigate the influence of fracture permeability, diffusion length and initial water saturation on the oil recovery potential. Liquid CO2 was injected in partially oil and brine saturated core plugs and larger blocks at miscible condition with the oil phase (n-Decane) at 20 °C and 90 bar. High final oil recoveries, up to 100%OOIP, were observed during secondary miscible CO2 injections in whole, unfractured core samples within 2 pore volumes (PV) injected. High recoveries were also observed in fractured systems (79–93%OOIP), but recovery was less efficient in terms of PV injected (4–12) as a result of increased system permeability and increased diffusion length. Tertiary CO2 injections in core samples after waterfloods were less efficient in terms of final oil recoveries (62–69%OOIP) compared to secondary CO2 injections. Additional oil recovery during tertiary CO2 injection ranged from 0% to 15%OOIP. An adverse effect of water was observed both during secondary and tertiary CO2 injections, where higher water saturation decreased the oil recovery efficiency by diffusion, indicative of a water shielding effect.