Near-surface monitoring for the ZERT shallow CO2 injection project

As part of a collaborative effort operated by the Zero Emission Research and Technology Center (ZERT), a series of two shallow releases of CO₂ was performed at a test site in Bozeman, MT. The purpose of the experiment was to simulate possible leakage scenarios from a carbon capture and storage operation in order to further develop and verify monitoring technologies used to characterize and quantify the release of CO₂. The project included collaboration with several research groups and organizations. Presented here are the results of soil–gas monitoring conducted by researchers from the National Energy Technology Laboratory, including CO₂ flux measurement, soil–gas analysis, perfluorocarbon tracer monitoring, and soil resistivity measurements. Together, these methods proved to be effective in detecting and characterizing leakage in the near-surface.     

Lessons learned from natural and industrial analogues for storage of carbon dioxide

The deployment of CCS (carbon capture and storage) at industrial scale implies the development of effective monitoring tools. Noble gases are tracers usually proposed to track CO₂. This methodology, combined with the geochemistry of carbon isotopes, has been tested on available analogues.At first, gases from natural analogues were sampled in the Colorado Plateau and in the French carbogaseous provinces, in both well-confined and leaking-sites. Second, we performed a 2-years tracing experience on an underground natural gas storage, sampling gas each month during injection and withdrawal periods.In natural analogues, the geochemical fingerprints are dependent on the containment criterion and on the geological context, giving tools to detect a leakage of deep-CO₂ toward surface. This study also provides information on the origin of CO₂, as well as residence time of fluids within the crust and clues on the physico-chemical processes occurring during the geological story.The study on the industrial analogue demonstrates the feasibility of using noble gases as tracers of CO₂. Withdrawn gases follow geochemical trends coherent with mixing processes between injected gas end-members. Physico-chemical processes revealed by the tracing occur at transient state.These two complementary studies proved the interest of geochemical monitoring to survey the CO₂ behaviour, and gave information on its use.     

Coda-wave interferometry analysis of time-lapse VSP data for monitoring geological carbon sequestration

Injection and movement/saturation of carbon dioxide (CO₂) in a geological formation will cause changes in seismic velocities. We investigate the capability of coda-wave interferometry technique for estimating CO₂-induced seismic velocity changes using time-lapse synthetic vertical seismic profiling (VSP) data and the field VSP datasets acquired for monitoring injected CO₂ in a brine aquifer in Texas, USA. Synthetic VSP data are calculated using a finite-difference elastic-wave equation scheme and a layered model based on the elastic Marmousi model. A possible leakage scenario is simulated by introducing seismic velocity changes in a layer above the CO₂ injection layer. We find that the leakage can be detected by the detection of a difference in seismograms recorded after the injection compared to those recorded before the injection at an earlier time in the seismogram than would be expected if there was no leakage. The absolute values of estimated mean velocity changes, from both synthetic and field VSP data, increase significantly for receiver positions approaching the top of a CO₂ reservoir. Our results from field data suggest that the velocity changes caused by CO₂ injection could be more than 10% and are consistent with results from a crosswell tomogram study. This study demonstrates that time-lapse VSP with coda-wave interferometry analysis can reliably and effectively monitor geological carbon sequestration.     

A solution against well cement degradation under CO2 geological storage environment

Capturing and storing carbon dioxide (CO₂) underground for thousands of years is one way to reduce atmospheric greenhouse gases, often associated with global warming. Leakage through wells is one of the major issues when storing CO₂ in depleted oil or gas reservoirs. CO₂-injection candidates may be new wells, or old wells that are active, closed or abandoned. In all cases, it is critical to ensure that the long-term integrity of the storage wells is not compromised. The loss of well integrity may often be explained by the geochemical alteration of hydrated cement that is used to isolate the annulus across the producing/injection intervals in CO₂-related wells. However, even before any chemical degradation, changes in downhole conditions due to supercritical CO₂ injections can also be responsible for cement debonding from the casing and/or from the formation, leading to rapid CO₂ leakage. A new cement with better CO₂ resistance is compared with conventional cement using experimental procedure and methodology simulating the interaction of set cement with injected, supercritical CO₂ under downhole conditions. Geochemical experimental data and a mechanical modeling approach are presented. The use of adding expanding property to this new cement to avoid microannulus development during the CO₂ injection is discussed.     

Seismic detection of CO2 leakage along monitoring wellbores

A pilot carbon dioxide (CO₂) sequestration experiment was carried out in the Michigan Basin in which ～10,000 tonnes of supercritical CO₂ was injected into the Bass Island Dolomite (BILD) at 1050 m depth. A passive seismic monitoring (PSM) network was operated before, during and after the ～17-day injection period. The seismic monitoring network consisted of two arrays of eight, three-component sensors, deployed in two monitoring wells at only a few hundred meters from the injection point. 225 microseismic events were detected by the arrays. Of these, only one event was clearly an injection-induced microearthquake. It occurred during injection, approximately 100 m above the BILD formation. No events, down to the magnitude ?3 detection limit, occurred within the BILD formation during the injection. The observed seismic waveforms associated with the other 224 events were quite unusual in that they appear to contain dominantly compressional (P) but no (or extremely weak) shear (S) waves, indicating that they are not associated with shear slip on faults. The microseismic events were unusual in two other ways. First, almost all of the events occurred prior to the start of injection into the BILD formation. Second, hypocenters of the 94 locatable events cluster around the wells where the sensor arrays were deployed, not the injection well. While the temporal evolution of these events shows no correlation with the BILD injection, they do correlate with CO₂ injection for enhanced oil recovery (EOR) into the 1670 m deep Coral Reef formation that had been going on for ～2.5 years prior to the pilot injection experiment into the BILD formation. We conclude that the unusual microseismic events reflect degassing processes associated with leakage up and around the monitoring wells from the EOR-related CO₂ injection into the Coral Reef formation, ～700 m below the depth of the monitoring arrays. This conclusion is also supported by the observation that as soon as injection into the Coral Reef formation resumed at the conclusion of the BILD demonstration experiment, seismic events (essentially identical to the events associated with the Coral Reef injection prior to the BILD experiment) again started to occur close to a monitoring arrays. Taken together, these observations point to vertical migration around the casings of the monitoring wellbores. Detection of these unusual microseismic events was somewhat fortuitous in that the arrays were deployed at the depth where the CO₂ undergoes a strong volume increase during transition from a supercritical state to a gas. Given the large number of pre-existing wellbores that exist in depleted oil and gas reservoirs that might be considered for CO₂ sequestration projects, passive seismic monitoring systems could be deployed at appropriate depths to systematically detect and monitor leakage along them.     

Application of crosswell seismic tomography using difference analysis with data normalization to monitor CO2 flooding in an aquifer

A pilot-scale experiment for carbon dioxide (CO₂) sequestration was undertaken at the Nagaoka test field in Japan. Time-lapse crosswell seismic tomography was conducted to detect and monitor the movement of CO₂ injected into an aquifer. We applied difference analysis with data normalization (DADN) to the time-lapse data to eliminate false images that were apparent in a conventionally processed difference section. Conventional difference analysis calculates travel-time delays after inversion, whereas the DADN method calculates them from raw travel-time records before inversion. Thus, fewer errors are generated with the DADN method compared to a conventional inversion analysis. We applied the DADN method to time-lapse tomography data recorded before and after the injection of CO₂ and computed the velocity variation in a subsurface section, which clearly showed the distribution of CO₂ flooding within a high permeability zone in the aquifer and showed no CO₂ leakage into the caprock. Our results also show the maximum velocity decrease as a result of CO₂ injection was about 9%, which is close to the results obtained in laboratory experiments. Finally, numerical simulations were inverted to test the effectiveness of the conventional and DADN methods in dealing with noise. These tests showed that the DADN method effectively reduces unique coherent noise for particular receiver and source combinations. We concluded that the DADN method provides useful data for monitoring the flow of CO₂ sequestered in underground aquifers.     

CO2SINK—From site characterisation and risk assessment to monitoring and verification: One year of operational experience with the field laboratory for CO2 storage at Ketzin, Germany

The CO₂SINK pilot project at Ketzin is aimed at a better understanding of geological CO₂ storage operation in a saline aquifer. The reservoir consists of fluvial deposits with average permeability ranging between 50 and 100 mDarcy. The main focus of CO₂SINK is developing and testing of monitoring and verification technologies. All wells, one for injection and two for observation, are equipped with smart casings (sensors behind casing, facing the rocks) containing a Distributed Temperature Sensing (DTS) and electrodes for Electrical Resistivity Tomography (ERT). The in-hole Gas Membrane Sensors (GMS) observed the arrival of tracers and CO₂ with high temporal resolution. Geophysical monitoring includes Moving Source Profiling (MSP), Vertical Seismic Profiling (VSP), crosshole, star and 4-D seismic experiments. Numerical models are benchmarked via the monitoring results indicating a sufficient match between observation and prediction, at least for the arrival of CO₂ at the first observation well. Downhole samples of brine showed changes in the fluid composition and biocenosis. First monitoring results indicate anisotropic flow of CO₂ coinciding with the “on-time” arrival of CO₂ at observation well one (Ktzi 200) and the later arrival at observation well two (Ktzi 202). A risk assessment was performed prior to the start of injection. After one year of operations about 18,000 t of CO₂ were injected safely.     

Chromatographic partitioning of impurities (H2S) contained in a CO2 stream injected into a deep saline aquifer: Part 2. Effects of flow conditions

Laboratory experiments reported in a companion paper were carried out to examine the chromatographic partitioning of impurities contained in a stream of CO₂ injected into a deep saline aquifer. The solubility of the impurity gas in the CO₂ stream compared to that of CO₂, the in situ conditions of pressure, temperature and water salinity, and the concentration of the impurity gas affect the partitioning of the two gases. For CO₂ streams containing H₂S, numerical simulations reported here have successfully replicated the laboratory results including the breakthrough of CO₂ ahead of H₂S. Sensitivity analysis performed with the numerical model has shown that flow conditions, controlled by such parameters as medium permeability, pressure gradient, dispersion, gas mobility and flow direction, affect the breakthrough time and separation of the two gases, leading to delayed or earlier breakthrough, and increasing or decreasing the time lag between the breakthrough of the two gases. Vertical bottom-up flow leads to earlier breakthrough, while top-down flow leads to delayed breakthrough. These results are important in establishing monitoring strategies at CO₂ storage sites and in evaluating the risks associated with the possible leakage of injected CO₂ that contains impurities.     

Chromatographic partitioning of impurities contained in a CO2 stream injected into a deep saline aquifer: Part 1. Effects of gas composition and in situ conditions

A series of laboratory experiments were carried out to examine the chromatographic partitioning of impurities contained in a stream of CO₂ injected into a deep saline aquifer. The experiments were carried out under static (no flow) and dynamic conditions, mainly with H₂S as the impurity in the CO₂ stream, for 2%, 5% and 30% concentrations, and for in situ conditions of high pressure, temperature and water salinity, and also for pure water at a lower pressure and temperature. In addition, experiments were conducted using CH₄, N₂ and SO₂ at 5% concentration as the ‘Impurity’ in the CO₂ stream. The experiments show that gases in an impure stream of CO₂ being injected into a deep saline aquifer will chromatographically partition at the leading edge of the gas advancing through the water-saturated porous medium as a result of differential solubility in aquifer water. The solubility of the impurity gas in the CO₂ stream compared to that of CO₂ is the most dominant factor in regard to the breakthrough time and initial gas concentrations in the effluent. The in situ conditions of pressure, temperature and water salinity also affect the chromatographic partitioning of CO₂ and impurities contained in the injection stream through their general effect on the solubility of all gases. The concentration of the impurity gas in the feed gas stream has a secondary effect on the breakthrough and time lag decreasing with increasing concentration of the impurity gas. These experimental findings are significant for understanding the fate of the injected CO₂ and associated impurities contained in an injection stream, in devising monitoring procedures and protocols, and in developing emergency response plans in case of leakage of CO₂ and associated impurities.     

Methodology for CO2 chain analysis

The paper presents a methodology for CO₂ chain analysis with particular focus on the impact of technology development on the total system economy. The methodology includes the whole CO₂ chain; CO₂ source, CO₂ capture, transport and storage in aquifers or in oil reservoirs for enhanced oil recovery. It aims at supporting the identification of feasible solutions and assisting the selection of the most cost-effective options for carbon capture and storage. To demonstrate the applicability of the methodology a case study has been carried out to illustrate the possible impact of technology improvements and market development. The case study confirms that the CO₂-quota price to a large extent influence the project economy and dominates over potential technology improvements. To be economic feasible, the studied chains injecting the CO₂ in oil reservoirs for increased oil production require a CO₂-quota price in the range of 20–27 €/tonne CO₂, depending on the technology breakthrough. For the chains based on CO₂ storage in saline aquifers, the corresponding CO₂-quota price varies up to about 40 €/tonne CO₂.     

Certification framework based on effective trapping for geologic carbon sequestration

We have developed a certification framework (CF) for certifying the safety and effectiveness of geologic carbon sequestration (GCS) sites. Safety and effectiveness are achieved if CO₂ and displaced brine have no significant impact on humans, other living things, resources, or the environment. In the CF, we relate effective trapping to CO₂ leakage risk which takes into account both the impact and probability of leakage. We achieve simplicity in the CF by using (1) wells and faults as the potential leakage pathways, (2) compartments to represent environmental resources that may be impacted by leakage, (3) CO₂ fluxes and concentrations in the compartments as proxies for impact to vulnerable entities, (4) broad ranges of storage formation properties to generate a catalog of simulated plume movements, and (5) probabilities of intersection of the CO₂ plume with the conduits and compartments. We demonstrate the approach on a hypothetical GCS site in a Texas Gulf Coast saline formation. Through its generality and flexibility, the CF can contribute to the assessment of risk of CO₂ and brine leakage as part of the certification process for licensing and permitting of GCS sites around the world regardless of the specific regulations in place in any given country.     

Role and impact of CO2–rock interactions during CO2 storage in sedimentary rocks

Before implementing CO₂ storage on a large scale its viability regarding injectivity, containment and long-term safety for both humans and environment is crucial. Assessing CO₂–rock interactions is an important part of that as these potentially affect physical properties through highly coupled processes. Increased understanding of the physical impact of injected CO₂ during recent years including buoyancy driven two-phase flow and convective mixing elucidated potential CO₂ pathways and indicated where and when CO₂–rock interactions are potentially occurring. Several areas of interactions can be defined: (1) interactions during the injection phase and in the near well environment, (2) long-term reservoir and cap rock interactions, (3) CO₂–rock interactions along leakage pathways (well, cap rock and fault), (4) CO₂–rock interactions causing potable aquifer contamination as a consequence of leakage, (5) water–rock interactions caused by aquifer contamination through the CO₂ induced displacement of brines and finally engineered CO₂–rock interactions (6). The driving processes of CO₂–rock interactions are discussed as well as their potential impact in terms of changing physical parameters. This includes dissolution of CO₂ in brines, acid induced reactions, reactions due to brine concentration, clay desiccation, pure CO₂–rock interactions and reactions induced by other gases than CO₂. Based on each interaction environment the main aspects that are possibly affecting the safety and/or feasibility of the CO₂ storage scheme are reviewed and identified. Then the methodologies for assessing CO₂–rock interactions are discussed. High priority research topics include the impact of other gaseous compounds in the CO₂ stream on rock and cement materials, the reactivity of dry CO₂ in the absence of water, how CO₂ induced precipitation reactions affect the pore space evolution and thus the physical properties and the need for the development of coupled flow, geochemical and geomechanical models.     

Screening and selection of sites for CO2 sequestration based on pressure buildup

This paper presents a simple methodology for estimating pressure pressure buildup due to the injection of supercritical CO₂into a saline formation, and the limiting pressure at which the formation starts to fracture. Pressure buildup is calculated using the approximate solution of Mathias et al. [Mathias, S.A., Hardisty, P.E., Trudell, M.R., Zimmerman, R.W., 2009. Approximate solutions for pressure buildup during CO₂ injection in brine aquifers. Transp. Porous Media. doi:10.1007/s11242-008-9316-7], which accounts for two-phase Forchheimer flow (of supercritical CO₂ and brine) in a compressible porous medium. Compressibility of the rock formation and both fluid phases are also accounted for. Injection pressure is assumed to be limited by the pressure required to fracture the rock formation. Fracture development is assumed to occur when pore pressures exceed the minimum principal stress, which in turn is related to the Poisson’s ratio of the rock formation. Detailed guidance is also offered concerning the estimation of viscosity, density and compressibility for the brine and CO₂. Example calculations are presented in the context of data from the Plains CO₂ Reduction (PCOR) Partnership. Such a methodology will be useful for screening analysis of potential CO₂ injection sites to identify which are worthy of further investigation.     

The Climate Value of Cycling

The reduction of CO₂ emissions constitutes one of the largest challenges of the current era. Sustainable transportation, and especially cycling, can contribute to the mitigation of CO₂ emissions since cycling possesses an intrinsic zero‐emission value. Few studies have been conducted that appraise the CO₂ reduction potential of cycling. Opportunity costs enable the estimation of avoided CO₂ emissions resulting from bicycle trips. The methodology developed in this research allows the attribution of a climate value to cycling by substituting bicycle trips with their most likely alternative transportation modes and calculating the resulting additional CO₂ emissions. The methodology uses data on the current modal shares of cycling mobility, the competition of cycling with other transportation modes, and CO₂ emission factors to calculate the climate value of cycling. When it is assumed that the avoided CO₂ emissions of cycling mobility could be traded on financial carbon markets, the climate value of cycling represents a monetary value. Application of the methodology to the case of Bogotá, Colombia — a city with a current bicycle modal share of 3.3% on a total of 10 million daily trips — results in a climate value of cycling of 55,115 tons of CO₂ per year, corresponding to an economic value of between 1 and 7 million US dollars when traded on the carbon market.     

CO2 transportation for carbon capture and storage: Sublimation of carbon dioxide from a dry ice bank

Climate change is being caused by greenhouse gases such as carbon dioxide (CO₂). Carbon capture and storage (CCS) is of interest to the scientific community as one way of achieving significant global reductions of atmospheric CO₂ emissions in the medium term. CO₂ would be captured from large stationary sources such as power plants and transported via pipelines under high pressure conditions to underground storage. If a downward leakage from a surface transportation system module occurs, the CO₂ would undergo a large temperature reduction and form a bank of “dry ice” on the ground surface; the sublimation of the gas from this bank represents an area source term for subsequent atmospheric dispersion, with an emission rate dependent on the energy balance at the bank surface. Gaseous CO₂ is denser than air and tends to remain close to the surface; it is an asphyxiant, a cerebral vasodilator and at high concentrations causes rapid circulatory insufficiency leading to coma and death. Hence a subliming bank of dry ice represents safety hazard. A model is presented for evaluating the energy balance and sublimation rate at the surface of a solid frozen CO₂ bank under different environmental conditions. The results suggest that subliming gas behaves as a proper dense gas (i.e. it remains close to the ground surface) only for low ambient wind speeds.     

The role of optimality in characterizing CO2 seepage from geologic carbon sequestration sites

Storage of large amounts of carbon dioxide (CO₂) in deep geologic formations for greenhouse-gas mitigation is gaining momentum and moving from its conceptual and testing stages towards widespread application. In this work we explore various optimization strategies for characterizing surface leakage (seepage) using near-surface measurement approaches such as accumulation chambers and eddy covariance towers. Seepage characterization objectives and limitations need to be defined carefully from the outset especially in light of large natural background variations that can mask seepage. The cost and sensitivity of seepage detection are related to four critical length scales pertaining to the size of the: (1) region that needs to be monitored; (2) footprint of the measurement approach, and (3) main seepage zone; (4) region in which concentrations or fluxes are influenced by seepage. Seepage characterization objectives may include one or all of the tasks of detecting, locating, and quantifying seepage. Each of these tasks has its own optimal strategy. Detecting and locating seepage in a region in which there is no expected or preferred location for seepage nor existing evidence for seepage requires monitoring on a fixed grid, e.g., using eddy covariance towers. The fixed-grid approaches needed to detect seepage are expected to require large numbers of eddy covariance towers for large-scale geologic CO₂ storage. Once seepage has been detected and roughly located, seepage zones and features can be optimally pinpointed through a dynamic search strategy, e.g., employing accumulation chambers and/or soil-gas monitoring. Quantification of seepage rates can be done through measurements on a localized fixed grid once the seepage is pinpointed. Background measurements are essential for seepage detection in natural ecosystems. Artificial neural networks are considered as regression models useful for distinguishing natural system behavior from anomalous behavior suggestive of CO₂ seepage without need for detailed understanding of natural system processes. Because of the local extrema in CO₂ fluxes and concentrations in natural systems, simple steepest-descent algorithms are not effective and evolutionary computation algorithms are proposed as a paradigm for dynamic monitoring networks to pinpoint CO₂ seepage areas.     

Corrective measures based on pressure control strategies for CO2 geological storage in deep aquifers

A prerequisite to the wide deployment at an industrial scale of CO₂ geological storage is demonstrating that potential risks can be efficiently managed. Corrective measures in case of significant irregularities, such as CO₂ leakage, are hence required as advocated by the recent European directive on Carbon Capture and Storage operations. In this regard, the objective of the present paper is to investigate four different corrective measures aiming at controlling the overpressure induced by the injection operations in the reservoir: stopping the CO₂ injection and relying on the natural pressure recovery in the reservoir; extracting the stored CO₂ at the injection well; extracting brine at a distant well while stopping the CO₂ injection, and extracting at a distant well without stopping the CO₂ injection. The efficiency of the measures is assessed using multi-phase fluid flow numerical simulations. The application case is the deep carbonate aquifer of the Dogger geological unit in the Paris Basin. A comparative study between the four corrective measures is then carried using a cost-benefit approach. Results show that an efficient overpressure reduction can be achieved by simply shutting-in the well. The overpressure reduction can be significantly accelerated by means of fluid extraction but the adverse consequences are the associated higher costs of the intervention operations.     

Comparison of data-based methods for monitoring of air leakages into oxyfuel power plants

Air leakages compromise the CO₂ capture rate and auxiliary power consumption of oxyfuel power plants. Constructive measures can significantly improve the leakage rate in newly built plants. However, the mitigation of increasing leakage rates during the plant lifetime is crucial for high plant efficiency. In this paper, we apply three statistical methods on experimental process data gathered in an air leakage test in Vattenfall's Oxyfuel Pilot Plant in Schwarze Pumpe, Germany. The performance of the methods in identifying increasing leakage rates and localizing the leakage source is investigated. It was found that all three methods can identify and localize even small increases of the leakage rate. A combination of all three methods allows taking advantage of the individual features of each method. Additional installation of CO₂, O₂, H₂O, and SO₂ measurements in the oxidizer can considerably enhance localization performance. Finally, it is shown that the results can be transferred to commercial-scale oxyfuel pilot plants by generating training data with thermodynamic plant models.     

A response surface methodology to address uncertainties in cap rock failure assessment for CO2 geological storage in deep aquifers

Cap rock failure assessment, either tensile fracturing or shear slip reactivation of pre-existing fault, is a key issue for preventing CO₂ leakage from deep aquifer reservoirs up to the surface. For an appropriate use in risk management, the uncertainties associated with such studies should be investigated. Nevertheless, uncertainty analysis requires multiple simulations and a direct use of conventional numerical approaches might be too computer time consuming. An alternative is to use conventional analytical models, but their assumptions appear to be too conservative. An intermediate approach is then proposed based on the response surface methodology, consisting in estimating the effective stress state after CO₂ injection as a linear combination of the most influential site properties based on a limited number of numerical simulations. The decision maker is provided with three levels of information: (1) the identification of the most important site properties; (2) an analytical model for a quick assessment of the maximal sustainable overpressure and (3) a simplified model to be used in a computationally intensive uncertainty analysis framework. This generic methodology is illustrated with the Paris Basin case using a large-scale hydromechanical model to assess cap rock failure in the injector zone.     

Value of information analysis for adequate monitoring of carbon dioxide storage in geological reservoirs under uncertainty

As monitoring is essential for the proper management of geological storage of carbon dioxide (CO₂), the ability to value information from monitoring is indispensable to adequately design a monitoring program. It is necessary to judge whether the expected improvement in management is worth the cost of monitoring. The value of information (VOI) is closely related to the possible increase in expected utility gained by gathering the information, the concept of which can be applied to such judgement. Although VOI analysis has been extensively studied in the context of decision analysis, its application to the management of carbon dioxide capture and storage (CCS) operations is rare. This paper introduces and discusses the methodology of VOI analyses in the context of monitoring CO₂ storage. A motivating problem with discrete probabilities is used to illustrate the concept of VOI. It is demonstrated that information is not always of value; for information to be worthwhile, monitoring under uncertainty must satisfy certain conditions. This concept is then extended to continuous probability distributions. The effects of prior uncertainty and information reliability on the VOI are examined. It is shown that an excessive improvement in information accuracy yields little value and that the optimal level of reliability can be inferred. VOI analyses provide quantitative insights into the value of information-gathering activities and therefore can be an objective means to adequately design and impartially justify a monitoring program.