Africa (Sub-Sahara) Eni successfully completed a new production well in the Vandumbu field, 350 km northwest of Luanda and 130 km west of Soyo, in the West Hub of Block 15/06 offshore Angola. The VAN-102 well is being produced through the N'Goma FPSO and achieved initial production of 13,000 BOED. Production from this well and another well in the Mpungi field will bring Block 15/06 output to 170,000 BOED. Anglo African Oil & Gas encountered oil at the TLP-103C well at its Tilapia license offshore the Republic of Congo. The well intersected the targeted Djeno horizon, and wireline logging confirmed the presence of a 12-m oil column in the Djeno. Total started production from the ultra-deepwater Egina field in approximately 1600 m of water 150 km off the coast of Nigeria. At plateau, the field will produce 200,000 B/D.
Exploring the major controlling factors on resistivity depth trends in sedimentary basins is an interesting subject from both scientific and commercial perspectives. Our study aims to develop rock-physics based resistivity modeling methods and workflows that can be applied in any given sedimentary basin, through xS-integration of quantitative geological knowledge linking lithology with in-situ subsurface conditions such as temperature and salinity. In this work, we present a workflow that utilizes the Waxman-Smits model and existing wells in the target basin to perform a prediction of the horizontal resistivity depth trends at any appointed location in the basin. The workflow will be demonstrated using well data from the Norwegian Barents Sea; the predictability of our method will be presented through comparison against a real horizontal resistivity log measurement.
The methodology and workflow are general, in principle they can be applied to sedimentary basins around the world. So far, we have tested the workflow and compared the predicted horizontal resistivity depth trends against log resistivity responses acquired in wellbores across the Norwegian Continental Shelf (NCS) — the North Sea, the Norwegian Sea and the Barents Sea. Our predictions capture the overall resistivity depth trends successfully in all selected wells within each individual basin across the shelf. The predicted resistivity depth profiles can be used as a priori models in controlled source electromagnetic (CSEM) data inversion schemes, or to provide ‘what if’ scenarios as part of the reservoir property analysis and risk assessment in an exploration phase.
Presentation Date: Tuesday, October 16, 2018
Start Time: 1:50:00 PM
Location: Poster Station 22
Presentation Type: Poster
Alvarez, Pedro (RSI) | Marcy, Fanny (Engie) | Vrijlandt, Mark (Engie) | Nichols, Kim (RSI) | Keirstead, Rob (RSI) | Smith, Maggie (RSI) | Wen Tseng, Hung (RSI) | Bouchrara, Slim (RSI) | Bolivar, Francisco (RSI) | Rappke, Jochen (Engie) | MacGregor, Lucy (RSI)
We present a case study from the Hoop area of the Barents Sea, in which seismic, well log and controlled source electromagnetic (CSEM) data were integrated within a rock physics framework, to provide a robust assessment of the prospectivity of the area. Combining seismic and CSEM results can resolve the ambiguities that are present when only a single data type is considered. In this example, although seismic data identified potential hydrocarbon bearing sands, the saturation was uncertain. In this area and at shallow depth, the main focus is on (very) high oil saturations. Adding the CSEM data in this setting allows us to distinguish between high saturations (> 70%), and low and medium saturations (< 50%): it is clear that saturations similar to those observed at the nearby Wisting well (>90%) are not present in this area. However, because of limitations on the sensitivity/recoverability of the CSEM data in this high resistivity environment, it is not possible to distinguish between low and medium saturations. This remains an uncertainty in the analysis.
Presentation Date: Wednesday, September 27, 2017
Start Time: 3:30 PM
Presentation Type: ORAL
Laboratory permeability data from a wet sandstone reservoir (the Tubåen formation, Hammerfest Basin, located in the Barents Sea) subject to CO2 sequestration indicates an order of magnitude permeability variation at the same porosity. The velocity and density well data from the well, obtained prior to CO2 injection, show that at the same porosity, the samples with higher permeability have higher elastic moduli (both compressional and shear) as compared to the samples with lower permeability. To understand and quantify this effect, we fit the elastic modulus versus porosity well data with the theoretical constant-cement model theoretical curves. This theoretical rock physics analysis shows that the lower-permeability, softer samples have less contact cement that their high-permeability, stiffer counterparts. One interpretation of this meaning is that in the lower-permeability samples, part of the pore space is filled with fines that do not contribute to the grain-to-grain cementation thus reducing the stiffness (as compared to the well-cemented samples). This means, in turn, that in the softer samples, the fines partly clog the pores thus reducing the permeability. This logic is supported by the geological character of the Tubåen formation where the tidal and marine influence acts to worsen the grain sorting compared to well-sorted distributary channel sediment.
Abstract: Pressure build-up caused by large-scale CO2 injection is one of the key concerns during a carbon sequestration project, for well-known reasons such as the risk to seal integrity, fault stability and induced microseismicity, among others. Furthermore, pressure build-up is directly related with storage capacity. In this work we study the geomechanical response to the CO2 injection in the Tubåen Fm at Snøhvit. During the first stage of the project CO2 was separated from the produced gas and stored underground in the Tubåen Fm. at approximately 2600 m depth. The Tubåen Fm. corresponds to a delta plain environment dominated by fluvial distributary channels and some marine-tidal influence. The area is extensively faulted, characterized by a dominant east-west-trending fault system, but with the presence of faults at high angles to this trend, leading to complex fault interactions. Injection into the Tubåen Formation was limited by reservoir heterogeneities and reservoir compartmentalization, leading to higher than expected pressure rise during operations. This lead to a well intervention operation designed to improve injectivity and a revised injection plan, with injection into a different unit. In the present work we perform a probabilistic assessment of the mechanical deformation caused by the CO2 injection and the potential for fault leakage and contamination of the producing interval in the adjacent block. For the majority of the cases, in the range of the evaluated parameters, we found that the increase in pressure due to CO2 injection does not pose risk for fault reactivation. However, observed variations in the orientation of the maximum horizontal stress have a high impact on the potential for reactivation of the studied faults.
Simmenes, Trine (Statoil) | Hansen, Olav R. (Statoil) | Eiken, Ola (Statoil) | Teige, Gunn Mari Grimsmo (Statoil) | Hermanrud, Christian (Statoil ASA and University of Bergen) | Johansen, Stian (Statoil) | Nordgaard Bolaas, Hege Marit (Statoil) | Hansen, Hilde (Statoil)
CO2 injection implies displacement of water, and thus aquifer pressure build-up or displacement of water to other rocks. Both may be problematic. Pressure build-up may result in seal failure and / or restrict injection rates, whereas displacement of brine to other rocks may have undesired effects on the environment, such as contamination of potable drinking water. CO2 storage capacity also depends on pressure management, especially in closed systems where displaced water cannot be adequately displaced in the subsurface or vented to the surface.
Fluid pressure management at individual storage sites will be planned based on theoretical considerations as well as practical experience. The theoretical work includes analyses of widely different subjects such as stress tensor analyses, fracture propagation dynamics, reservoir connectivity and 3D permeability distributions. Practical experience will come from a growing number of injection sites, of which the experiences from the ongoing Snøhvit CO2 injection project are currently the most important.
Statoil has injected CO2 at Snøhvit since 2008. Injection took place in the Tubåen formation which underlies the Stø Formation natural gas reservoir. Fracturing of the caprock from the CO2 injection could thus result in CO2 leakage to the overlying producing reservoir. The CO2 injection resulted in an initial well pressure increase, probably caused by precipitation of salt in the near wellbore area. This challenge was resolved by injection of methylethylenglycol (MEG). Continuous downhole pressure measurements nevertheless documented a continuous pressure increase, albeit at a lower rate. This pressure increase was interpreted as evidence of insufficient far-field permeability to displace formation water laterally rather than of storage space shortage.
Thresholds for degree of fluid patchiness and Mindlin s exponent are found from the rock physics input. The estimated pressure and saturation changes are used to estimate timeshift based on RMS amplitude. This is compared to timeshift estimated from cross correlation. From this we have two independent measurements of the timeshift that can be used as a quality check of our estimated pressure and saturation cubes. We found a good agreement between the two estimating the timeshift. We have found that the pressure effect dominate the time lapse signature apart from close to the well, where both a pressure and fluid effect is estimated.
Commercial CO2 injection projects face several challenges in development and operation due to the pressure build-up caused by large-scale CO2 injection. The pressure front creates effective stress perturbations in the subsurface that can lead to dilation or slip along faults or fractures, changes in the connectivity within the injection reservoir, hydro-fracturing of the caprock and potentially microseismicity. In this work we investigate the geomechanical and fluid dynamical response to the CO2 injection at the Snøhvit site. The Snøhvit gas field is located offshore in the northern Norwegian Sea (Barents Sea). CO2 is separated from the produced gas and stored underground in the Tubåen Formation at approximately 2600 m depth. The Tubåen Fm. corresponds to a delta plain environment dominated by fluvial distributary channels and some marine-tidal influence. It is separated from the producing gas reservoir (Stø Fm.) by the Nordmela Fm. that contains wide shale layers expected to act as flow barriers. Structurally this area is faulted, characterized by a dominant east-west-trending fault system, where the majority of the faults dip toward the basin axis and define typical horsts and graben geometry. However, it also presents faults at high angles to this trend, leading to complex fault interactions. Given the geometry of major faults and fractures in and above the reservoir, available estimates of the in situ stress tensor, and reservoir characteristics, we use a fully coupled hydromechanical simulator (Geocentric) to understand the geomechanical response of the system to the CO2 injection, taking into consideration the in situ stress uncertainties. In the present work we focus in particular on addressing the potential for fault reactivation and fluid migration outside of the storage area.
Large-scale commercial CO2 injections face important technical challenges in development and operations. One of these is the pressure build-up caused by large-volume, sustained CO2 injection itself. The pressure increase creates effective stress perturbations in the subsurface transmitted by both the CO2 and other fluids (e.g., brine) that can lead to dilation or closure of faults and fractures, slip and dislocations along faults or fractures, change the connectivity within the injection reservoir, and even cause microseismic events. In the present work we investigate the potential mechanical deformation at Snøhvit, due to fluid injection. In particular we investigate the potential for fault reactivation in the context of critically stressed fracture theory and Mohr-Coulomb failure. In this context, critically stressed faults (optimally oriented for slip under the current stress state) are considered as potentially permeable. We utilize a preliminary dataset provided by Statoil R&D that includes geometry of major faults, available estimates of the in situ stress tensor, and general reservoir characteristics, as well as data available in the literature. We also incorporate the uncertainties in the in situ stress tensor.
2. SNØHVIT GAS FIELD
The Snøhvit gas field is located offshore Norway, in the Barents Sea (Figure 1). It consists of three gas reservoirs, Snøhvit, Albatross and Askeladd, discovered in the 1980s. The produced gas is processed into liquefied natural gas (LNG).