Sleipner Field Research Articles

Long-term Behavior of CO2 Stored on a Large Scale in the Utsira Formation, the North Sea, Norwegian Continental Shelf

Subsurface storage of CO2 has a long history on the Norwegian continental shelf; in the Sleipner Field (North Sea) since 1996 and the in Snøhvit field (Barents Sea) since 2008. Several studies have pointed out the large carbon storage potential on the Norwegian continental shelf, especially in deep saline aquifers. The Norwegian Petroleum Directorate (NPD) has, for the last two years, interpreted relevant data on the Norwegian continental shelf in order to classify potential sites for CO2 storage. The CO2 storage atlas for the Norwegian North Sea indicates possible storage sites, and estimated storage capacity.The Utsira Formation is considered to be a part of a saline aquifer together with Skade Formation. The Skade & Utsira Formations are distal deposits in a great delta-complex, with sands coming from the west throughout Miocene and up into the Pliocene. On British sector sands in Miocene are named Hutton sands (informal).To estimate the capacity of CO2 storage in the Utsira formation, a reservoir model covering 1400 km2 in the south part and located in the Norwegian sector, was built to simulate the long-term behaviour of CO2 injection. The simulations estimated the amount of CO2 which can be injected into the formations. They also illustrated the distribution of the CO2 plume in the reservoir formations.With a bottom-hole pressure (BHP) change constraint of 10 bars and no water production, more than 145 Mt CO2 could be injected and stored in the segment model with 4 or 5 injection wells and 50 years injection period. There are no indications that CO2 will migrate to the shallower parts of the formation in the west after 8000 years of simulation.

Spatial and temporal evolution of injected CO2 at the Sleipner Field, North Sea

Time‐lapse, three‐dimensional (3D) seismic surveys have imaged an accumulation of injected CO2 adjacent to the Sleipner field in the North Sea basin. The changing pattern of reflectivity suggests that CO2 accumulates within a series of interbedded sandstones and mudstones beneath a thick caprock of mudstone. Nine reflective horizons within the reservoir have been mapped on six surveys acquired between 1999 and 2008. These horizons have roughly elliptical planforms with eccentricities ranging between two and four. In the top half of the reservoir, horizon areas grow linearly with time. In the bottom half, horizon areas initially grow linearly for about eight years and then progressively shrink. The central portions of deeper reflective horizons dim with time. Amplitude analysis of horizons above, within, and below the reservoir show that this dimming is not solely caused by acoustic attenuation. Instead, it is partly attributable to CO2 migration and/or CO2 dissemination, which reduce the impedance contrast between sandstone and mudstone layers. Growth characteristics and permeability constraints suggest that each horizon grows by lateral spreading of a gravity current. This model is corroborated by the temporal pattern of horizon velocity pushdown beneath the reservoir. Horizon shrinkage may occur if the distal edge of a CO2‐filled layer penetrates the overlying mudstone, if the buoyant plume draws CO2 upward, or if the effective permeability of deeper mudstone layers increases once interstitial brine has been expelled. Topographic control is evident at later times and produces elliptical planforms, especially toward the top of the reservoir. Our results show that quantitative mapping and analysis of time‐lapse seismic surveys yield fluid dynamical insights which are testable, shedding light on the general problem of CO2 sequestration.

4D Joint Stratigraphic Inversion of Prestack Seismic Data: Application to the CO2Storage Reservoir (Utsira Sand Formation) at Sleipner Site

Seismic monitoring is commonly used in the oil industry to follow the evolution of reservoir properties during production. We present a methodology of time-lapse (or 4D) stratigraphic inversion, which is able to provide an estimation of P- and S-wave impedance variations in the reservoir by inverting prestack time-lapse seismic data. The 4D inversion is implemented in the time domain and requires a time scaling law for each repeated seismic dataset in order to adjust the arrival times of homologous events observed in the so-called reference and monitor datasets. This operation is often referred to as the warping problem. The 4D inversion is a 3-step methodology. The first step consists in inverting each seismic vintage independently, thus providing as many P- and S-wave impedance distributions as datasets considered. The second step uses the available P-wave impedance information to solve the warping problem which is crucial to the third and final step: the joint inversion of all available seismic vintages.This 4D inversion sequence was applied to seismic datasets recorded on the Norwegian CO<sub>2<sub/> storage reservoir of Sleipner field located in the North Sea. The latter is becoming a reference industrial site for the long-term storage of carbon dioxide (CO<sub>2<sub/>) in a saline aquifer, the Utsira sand formation. We focused our 4D inversion study on the 1994 and 2006 vintages acquired two years before and ten years after the beginning of CO<sub>2<sub/> injection, respectively. The warping correction resulted in a time-scaling law with a maximum pushdown effect of about 45 ms at the base of the Utsira aquifer. The joint 4D inversion results show more consistency than the single 3D inversion results: the 4D inversion notably provides P-wave impedances for the CO<sub>2<sub/> -saturated sandstones which are close to the values derived from rock physics studies.

Seismic characterization of thin beds containing patchy carbon dioxide-brine distributions: A study based on numerical simulations

We studied the seismic attenuation and velocity dispersion effects produced by wave-induced fluid flow in weakly consolidated sandstones containing patchy carbon dioxide [Formula: see text]-brine distributions. The analysis also focuses on the velocity pushdown because of the presence of this gas, as well as on the role of the wave-induced fluid flow (mesoscopic) effects on the amplitude variation with angle (AVA) seismic response of thin layers containing [Formula: see text], such as those found at the Utsira Sand, Sleipner field, offshore Norway. We found that this loss mechanism may play a key role on conventional surface seismic data, suggesting that further data analysis may provide useful information on the characteristics of the fluid distributions in these environments. Numerical experiments let us observe that although mesoscopic effects can be very significant in this kind of media, the seismic response of a given isolated thin layer computed considering such effects is very similar to that of a homogeneous elastic thin layer with a compressional velocity equal to that of the original porous rock averaged in the effective data bandwidth. This suggests that the thin-bed prestack spectral inversion method published by the authors could be used to estimate representative compressional velocities and layer thicknesses in these environments. In effect, results using realistic synthetic prestack seismic data show that isolated [Formula: see text]-bearing thin beds can be characterized in terms of their thicknesses and representative compressional velocities. This information can be qualitatively related to [Formula: see text] saturations and volumes; thus, the prestack spectral inversion method could find application in the monitoring of the evolution of [Formula: see text] plumes at injection sites similar to that at the Sleipner field.

AVA inversion of the top Utsira Sand reflection at the Sleipner field

Amplitude variation with angle (AVA) inversion is performed on the top Utsira Sand reflector at the Sleipner field, North Sea, Norway. This interface is of particular interest because of the accumulation of [Formula: see text] injected from a point deeper in the Utsira Sand. The focus is on the postmigration processing of angle gathers together with the actual inversion procedure. The processing treats amplitude extraction, offset-to-angle mapping, and global scaling in detail. Two algorithms are used for the inversion of AVA data, one that assesses uncertainties and one fast least-squares variant. Both are very suitable for this type of problem because of their covariance matrices and built-in regularization. In addition, two three-parameter approximations of the Zoeppritz equations are used. One is linear approximation and the other is quadratic. The results show significant signals for all three elastic parameters, but the substitution of brine by [Formula: see text] using Gassmann’s equation indicates that the contrasts in S-wave impedance and density are overestimated. For the contrasts in P-wave impedance the results are in agreement with the fluid substitution. A simple sensitivity analysis shows that the offset-to-angle mapping and the damping factor in the inversion are the most plausible explanations of the discrepancy.

Estimation of permeability anisotropy using seismic inversion for the CO2 geological storage site of Sleipner (North Sea)

Since 1996, more than 11 Mt of CO2 have been injected into a deep saline aquifer, the Utsira Sand formation, at the Norwegian Sleipner field. An unexpected application of the extensive seismic monitoring program over this field leads to the estimation of the depth dependence of the permeability anisotropy (strength and direction). Time-lapse seismic monitoring is used to follow the displacement of the injected CO2, considered as a permeability tracer. The upper half of the Utsira sand formation exhibits large anisotropy, with a ratio ζ between the maximum and minimum horizontal permeabilities larger than six. In contrast, ζ can be as small as two in the lower half. The direction of the maximum horizontal permeability does not exhibit substantial depth dependence and lies between N18°E and N34°E. This is in agreement with previous authors who pointed out a clear CO2 plume structure markedly elongated in the north-northeast–south-southwest direction. The small topographical trap at the top of the Utsira sand formation is a minor extrinsic cause of the measured permeability anisotropy, compared to the intrinsic effect of the formation permeability. This permeability information is crucial for reservoir simulation and for forecasting of the CO2 plume expansion for different scenarios of injection.

Modeling of CO2 storage in aquifers

Storage of CO2 in geological formations is a means of mitigating the greenhouse effect. Saline aquifers are a good alternative as storage sites due to their large volume and their common occurrence in nature. The first commercial CO2 injection project is that of the Sleipner field in the Utsira Sand aquifer (North Sea). Nevertheless, very little was known about the effectiveness of CO2 sequestration over very long periods of time. In this way, numerical modeling of CO2 injection and seismic monitoring is an important tool to understand the behavior of CO2 after injection and to make long term predictions in order to prevent CO2 leaks from the storage into the atmosphere. The description of CO2 injection into subsurface formations requires an accurate fluid-flow model. To simulate the simultaneous flow of brine and CO2 we apply the Black-Oil formulation for two phase flow in porous media, which uses the PVT data as a simplified thermodynamic model. Seismic monitoring is modeled using Biot's equations of motion describing wave propagation in fluid-saturated poroviscoelastic solids. Numerical examples of CO2 injection and time-lapse seismics using data of the Utsira formation show the capability of this methodology to monitor the migration and dispersal of CO2 after injection.

Numerical analysis of wave-induced fluid flow effects on seismic data: Application to monitoring of CO2storage at the Sleipner field

[1] In this work we analyze how patchy distributions of CO2 and brine within sand reservoirs may lead to significant attenuation and velocity dispersion effects, which in turn may have a profound impact on surface seismic data. The ultimate goal of this paper is to contribute to the understanding of these processes within the framework of the seismic monitoring of CO2 sequestration, a key strategy to mitigate global warming. We first carry out a Monte Carlo analysis to study the statistical behavior of attenuation and velocity dispersion of compressional waves traveling through rocks with properties similar to those at the Utsira Sand, Sleipner field, containing quasi-fractal patchy distributions of CO2 and brine. These results show that the mean patch size and CO2 saturation play key roles in the observed wave-induced fluid flow effects. The latter can be remarkably important when CO2 concentrations are low and mean patch sizes are relatively large. To analyze these effects on the corresponding surface seismic data, we perform numerical simulations of wave propagation considering reservoir models and CO2 accumulation patterns similar to the CO2 injection site in the Sleipner field. These numerical experiments suggest that wave-induced fluid flow effects may produce changes in the reservoir's seismic response, modifying significantly the main seismic attributes usually employed in the characterization of these environments. Consequently, the determination of the nature of the fluid distributions as well as the proper modeling of the seismic data constitute important aspects that should not be ignored in the seismic monitoring of CO2 sequestration problems.

A workflow for handling heterogeneous 3D models with the TOUGH2 family of codes: Applications to numerical modeling of CO 2 geological storage

This paper is addressed to the TOUGH2 user community. It presents a new tool for handling simulations run with the TOUGH2 code with specific application to CO 2 geological storage. This tool is composed of separate FORTRAN subroutines (or modules) that can be run independently, using input and output files in ASCII format for TOUGH2. These modules have been developed specifically for modeling of carbon dioxide geological storage and their use with TOUGH2 and the Equation of State module ECO2N, dedicated to CO 2–water–salt mixture systems, with TOUGHREACT, which is an adaptation of TOUGH2 with ECO2N and geochemical fluid–rock interactions, and with TOUGH2 and the EOS7C module dedicated to CO 2–CH 4 gas mixture is described. The objective is to save time for the pre-processing, execution and visualization of complex geometry for geological system representation. The workflow is rapid and user-friendly and future implementation to other TOUGH2 EOS modules for other contexts (e.g. nuclear waste disposal, geothermal production) is straightforward. Three examples are shown for validation: (i) leakage of CO 2 up through an abandoned well; (ii) 3D reactive transport modeling of CO 2 in a sandy aquifer formation in the Sleipner gas Field, (North Sea, Norway); and (iii) an estimation of enhanced gas recovery technology using CO 2 as the injected and stored gas to produce methane in the K12B Gas Field (North Sea, Denmark).

Layer spreading and dimming within the CO2 plume at the sleipner field in the north sea

The CO2 plume at Sleipner has been imaged on 3D seismic surveys as a series of bright sub-horizontal reflections. Nine discrete CO2 rich layers are inferred to have accumulated between a series of intra-reservoir mudstones beneath a substantial reservoir topseal. Time-lapse changes in reflectivity and in the lateral extent of these layers provide useful information about CO2 flow within the reservoir. The deepest CO2 layers within the growing plume have acoustically dimmed, stopped growing, and some have shrunk. Shallower layers have continued to grow. A combination of numerical flow models and analytical solutions of layer spreading yields useful insights into plume development. The observed seismic dimming and shrinkage of the deeper layers are, at least in part, caused by a reduction in the amount of CO2 trapped in the deeper plume. This is probably due to increases in the effective permeability of thin intra-reservoir mudstones. These changes reduce net flux of CO2 into the deeper layers of the plume with a corresponding increase of CO2 flux towards the top of the reservoir

Post-stack stratigraphic inversion workflow applied to carbon dioxide storage: application to the saline aquifer of Sleipner field‡

In the Norwegian North Sea, the Sleipner field produces gas with a high CO2 content. For environmental reasons, since 1996, more than 11 Mt of this carbon dioxide (CO2) have been injected in the Utsira Sand saline aquifer located above the hydrocarbon reservoir. A series of seven 3D seismic surveys were recorded to monitor the CO2 plume evolution. With this case study, time-lapse seismics have been shown to be successful in mapping the spread of CO2 over the past decade and to ensure the integrity of the overburden. Stratigraphic inversion of seismic data is currently used in the petroleum industry for quantitative reservoir characterization and enhanced oil recovery. Now it may also be used to evaluate the expansion of a CO2 plume in an underground reservoir. The aim of this study is to estimate the P-wave impedances via a Bayesian model-based stratigraphic inversion. We have focused our study on the 1994 vintage before CO2 injection and the 2006 vintage carried out after a CO2 injection of 8.4 Mt. In spite of some difficulties due to the lack of time-lapse well log data on the interest area, the full application of our inversion workflow allowed us to obtain, for the first time to our knowledge, 3D impedance cubes including the Utsira Sand. These results can be used to better characterize the spreading of CO2 in a reservoir. With the post-stack inversion workflow applied to CO2 storage, we point out the importance of the a priori model and the issue to obtain coherent results between sequential inversions of different seismic vintages. The stacking velocity workflow that yields the migration model and the a priori model, specific to each vintage, can induce a slight inconsistency in the results.

Time-lapse tomographic inversion using a Gaussian parameterization of the velocity changes

Most seismic studies of changes in traveltimes are of a qualitative nature and a major challenge in four dimensions is to use the information contained in time shifts to quantify the nature of velocity changes in the subsurface layers. We propose a 4D tomographic inversion method that uses time shifts from prestack seismic data to estimate parameters describing the 2D velocity field after changes have occurred. Prestack data allow for the usage of many offsets, thus increasing the information input for the inversion. The velocity changes are parameterized by a chosen number of Gaussian functions in two dimensions and weighted least-squares inversion is used to estimate the parameters describing these functions. We have found that the parameters describing the position and shape of the Gaussian velocity anomalies can be estimated with this method for simple synthetic cases. For more complex cases with overlapping Gaussian functions, resolution of the parameters can be difficult and in these cases our recommendation is to find the best fit for a simple smooth anomaly to a more complex real world. The method is tested on a real data set from a [Formula: see text] injection project above the Sleipner field in the North Sea, where quantification of changes is important for monitoring purposes. We have found that the noise levels in prestack traveltime data are on the high side for large-scale analysis; however, we estimate reasonable [Formula: see text] layer thickness and velocity compared to previous work in a nearby area.

An introduction to this special section: CO2 sequestration

Carbon capture and sequestration (CCS) technologies were formally addressed on the international stage 18 years ago at the First International Conference on Carbon Dioxide Removal in Amsterdam. The first commercial application of CCS technologies was deployed by Statoil in 1996 at the Sleipner gas field in the North Sea. Widespread deployment of large-scale [Formula: see text] sequestration efforts can only proceed if storage permanence is assured. The current definition of storage permanence is that 99% of injected [Formula: see text] remain securely confined after 100 years (see Carbon Sequestration Technology Roadmap and Program Plan, 2007, available at http://www.netl.doe.gov/technologies/carbon_seq/refshelf/project%20portfolio/2007/2007Roadmap.pdf). However, storage permanence cannot be assured without development of reliable and highly accurate leakage monitoring, plume detection and monitoring, and volume accounting technologies.

CO2 plume imaging using 3D pre-stack stratigraphic inversion: A case study on the Sleipner field

CO2 plume imaging using 3D pre-stack stratigraphic inversion: A case study on the Sleipner field

Bayesian closed-skew Gaussian inversion of seismic AVO data for elastic material properties

Bayesian closed-skew Gaussian inversion is defined as a generalization of traditional Bayesian Gaussian inversion, which is used frequently in seismic amplitude-versus-offset (AVO) inversion. The new model captures skewness in the variables of interest; hence, the posterior model for log-transformed elastic material properties given seismic AVO data might be a skew probability density function. The model is analytically tractable, and this makes it applicable in high-dimensional 3D inversion problems. Assessment of the posterior models in high dimensions requires numerical approximations, however. The Bayesian closed-skew Gaussian inversion approach has been applied on real elastic material properties from a well in the Sleipner field in the North Sea. A comparison with results from traditional Bayesian Gaussian inversion shows that the mean square error of predictions of P-wave and S-wave velocities are reduced by a factor of two, although somewhat less for density predictions.

Estimation of thickness and velocity changes of injected carbon dioxide layers from prestack time-lapse seismic data

In this study, we bring together the two main categories of time-lapse seismic analysis — amplitude analysis and time-shift analysis — to estimate simultaneously the changes in thickness and velocity of a 4D seismic anomaly. The methodology is applied to time-lapse seismic monitoring of carbon dioxide [Formula: see text] storage at Sleipner field, Norway, that shows significant 4D effects. The 4D anomalies resulting from [Formula: see text] injection appear as a multilayer reflection pattern within the relatively shallow Utsira Sand. This multireflective appearance within the sand layer is interpreted as [Formula: see text] layers trapped below thin shale layers. Because most of the [Formula: see text] layers are believed to be thin [Formula: see text], the interference between top and base of these layers needs to be taken into account in 4D seismic analysis. By studying the reflected event from a horizon below the Utsira Sand, we estimate 4D traveltime shifts caused by the presence of the [Formula: see text] layer above thishorizon. We then combine these traveltime shifts with measured amplitude changes for the top and base of the [Formula: see text] layer to estimate velocity and thickness changes for the thin [Formula: see text] layer. In 1999, after three years of injection, the most likely velocity change was around [Formula: see text] and the thickness of the [Formula: see text] layer was around [Formula: see text]. In 2001, the corresponding velocity change and thickness estimates were [Formula: see text] and [Formula: see text], respectively. Finally, in 2002, the most likely velocity change was [Formula: see text] and the thickness of the [Formula: see text] layer was [Formula: see text]. It is not straightforward to apply this method to a stack of [Formula: see text] layers because 4D time shifts below the Utsira Sand only provide information about the average time shift for all layers. The amplitude information for each individual [Formula: see text] layer cannot be resolved without knowing the velocity change within each layer. However, our result from a single [Formula: see text] layer may be used to constrain the velocity changes for the multilayer [Formula: see text] case.

Feasibility of Reproduction of Stored CO2 from the Utsira Formation at the Sleipner Gas Field

The feasibility to recover stored CO2 from the Utsira formation at Sleipner has been studied by reservoir simulation of a 15 years injection (until 2011) and a subsequent scenario where the CO2 is produced from a horizontal well under the cap rock. There are three important aspects related to the recovery of the stored CO2: Performance of temporary storage of CO2 for EOR purposes. Reproduction of mobile CO2 from formations that turn out to be less suitable for storage than anticipated. The reproduction simulation can resemble an open leaking well. Data from pre-injection seismic, well logs and petrophysical data are used to build a reservoir model. The Utsira formation is intersected by thin horizontal discontinuous shale layers that impede the vertical migration and cause entrapment of the CO2 in flat plumes. The transport properties of these shales are obtained by history matching the size of the plumes observed from seismic monitoring. To accommodate the necessary amount of CO2 the lateral size of the model had to be 5.2 km×7.9 km. To minimize numerical dispersion a relatively fine grid was required giving 2.1 million grid blocks in the model. The CO2 plume may be reached by a new well from the Sleipner A platform or through a sidetrack of the existing CO2 injection well and convert it to a producer. Placement of the producer is optimized for maximum reproduction by utilizing the local topography of the top seal. A producer could be drilled to avoid penetration of the cap-rock close to or above the CO2 plume and thereby avoid a potential leakage point after abandonment. The formation is high-permeable and relatively flat. The injected CO2 will therefore accumulate in thin plumes with large lateral extensions. Accordingly, recovery efficiency is low and the formation is less suitable for reproduction of CO2 compared to formations with a significant dome seal or dipping structures sealed by faults. The results give an important confirmation that it is possible to reproduce a significant amount of the mobile CO2 as a remediation option if a serious lack of integrity of the cap rock is detected.

Monitoring gas production and C O2 injection at the Sleipner field using time-lapse gravimetry

Thirty seafloor gravity stations have been placed above the carbon dioxide [Formula: see text] injection site and producing gas reservoir at the Sleipner Øst Ty field. Gravity and depth measurements from 2002 and 2005 reveal vertical changes of the permanently deployed benchmarks, probably caused by seafloor erosion and biologic activity (fish). The original gravity data have been reprocessed, resulting in slightly different gravity-change values compared with earlier published results. Observed gravity changes are caused by height variances, gas production and water influx in the Ty Formation, and [Formula: see text] injection in the Utsira Formation. Simultaneous matches to models for these effects have been made. The latest simulation model of the Ty Formation was fitted by permitting a scale factor, and the gravity contribution from the [Formula: see text] plume was determined by using the plume geometry as observed in 4D seismic data and varying the average density. The best-fit vertical gravity gradient is [Formula: see text], and the response from the Ty Formation suggests more water influx than expected in the presurvey simulation model. The best-fit average density of [Formula: see text] is [Formula: see text]. Estimates of the reservoir temperature combined with the equation of state for [Formula: see text] indicate an upper bound on [Formula: see text] density of [Formula: see text]. The gravity data suggest a lower bound of [Formula: see text] at 95% confidence.

Ormen Lange Langeled Development

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 18961, "The Ormen Lange Langeled Development," by Tom Rotjer, Hydro, prepared for the 2007 Offshore Technology Conference, Houston, 30 April-3 May. The full-length paper provides a summary of the challenges of executing the Ormen Lange Langeled project. The three main features of the project-execution phase are the Ormen Lange offshore development, the Ormen Lange onshore development, and the Langeled gas-export system including the gas-receiving facility in the UK. Introduction The Ormen Lange gas field was discovered by Hydro in 1997. The development of the field, 120 km off the midwest coast of Norway, is the largest industrial project in Norway. As of January 2007, the Ormen Lange Langeled project is more than 90% complete, within budget, and on schedule for gas export by October 2007. When Ormen Lange comes on stream in October 2007, the project will contribute to the increase of Norwegian gas export by 25%. The peak annual gas production from the field of 22×109 std m3 is equivalent to the total annual energy consumption in Norway. Gas from Ormen Lange will be able to meet as much as 20% of the UK gas demand. Production life is estimated to be 30 to 40 years. Ormen Lange's gas-export pipeline, Langeled, from Nyhamna in Norway to Easington on the east coast of England, is the world's longest subsea pipeline, with 42- and 44-in.-diameter pipes and a total length of 1200 km. The Ormen Lange field will contribute significantly to Norway becoming the second largest exporter of natural gas in the world. Project Management The Ormen Lange Langeled field-development project is organized with a multicompany integrated project team headed by Hydro. Shell is responsible for subsurface and drilling of production wells and for preparing for operations. Statoil is responsible for the execution of the Langeled project. Because of the shear size and complexity of the project, it was organized into the following three major subprojects with different focuses and challenges.The Ormen Lange offshore project consists of subsea installations approximately 120 km offshore, with templates, manifolds, and pipelines.The Ormen Lange onshore project consists of the gas-processing facilities at Nyhamna.The Langeled project consists of the 1200-km gas-export transportation system, the tie-in to the Sleipner field, and the Easington gas-reception terminal in the UK. Hydro organized a common project for the execution of the field development and the transportation system to secure the integrity of the Ormen Lange Langeled project from reservoir to market. The Langeled-project organization has been staffed with personnel from both Statoil and Hydro.

Effective pressure or what is the effect of pressure?

Using time-lapse seismics as a reservoir-monitoring tool, geophysics can help distinguish different reservoir production scenarios. For example, Eiken et al. (2000) successfully detected fluid-saturation changes after CO2 injection using time-lapse seismics at Sleipner Field. Over the cycle of a reservoir life, oil saturation usually decreases, reservoir pressure declines, and gas breakout may occur. These changes cause rock property changes that are detectible in time-lapse seismics. Therefore, it is important to understand the effects of pressure and saturation changes on rock properties. While the effects of saturation changes are often well described by Gassmann (1951), Brown and Korringa (1975), and Mavko (1975), the effects of pressure changes are less understood. Here we focus on understanding the effects of fluid pressure on velocities.