Gullfaks Field Research Articles

Digital twin-driven energy modeling of Hywind Tampen floating wind farm

This paper presents energy modeling of Hywind Tampen floating wind farm based on digital twin technology. Upon its completion, the Hywind Tampen wind farm is the largest floating wind farm in the World and the first floating wind farm to supply electricity for oil and gas fields. The wind farm is located about 140 km off the Norwegian coast with water depth between 260 and 300 m and consists of eleven wind turbines with a capacity of 8.6 MW each. Together with ten gas turbines, it will supply electricity for two oil and gas fields at the Norwegian Continental Shelf (NCS), namely the Gullfaks field with three platforms and the Snorre field with two platforms. In this paper, digital twins of the wind turbines and the oil platforms are created in Unity 3D. Energy from the wind farm is modeled from the first principle and is calculated using inputs from the historic weather data all year round. Simulation results show the wind farm can supply up to one-third of the total electricity needed by the oil and gas platforms almost constantly, which associated with reduction of 200,000 tonnes of CO2 emissions and 1000 tonnes of NOx emissions annually.

Improving the Recovery of Hydrocarbons in a Well in the Gullfaks Field by Injecting Sequestrated CO2

The Gullfaks field was discovered in 1978 in the Tampen area of the North Sea and it is one of the largest Norwegian oil fields located in Block 34/10 along the western flank of the Viking Graben in the northern North Sea. The Gullfaks field came on stream in 1986 and reached a peak of production in 2001. After some years, a decrease in production was noticed due to the decrease in pressure in the well. The goal of this paper is to improve the production of a well located in Gullfaks field by injecting CO2 through coiled tubing. The use of the CO2 injection method is due to the fact that it is a greenhouse gas, and its production in the atmosphere contributes to global warming. It is important to reduce its emission into the atmosphere and to boost the production of oil in the well. The CO2 is injected through the coil tubing to lighten the hydrostatic column and allow the fluid to move from the tubing to the surface. The completion and PVT data are processed in Pipesim and Prosper softwares. By integrating a number of calculations by using the nodal analysis methods and gas injection methods, the results obtained show that the well is not producing and by injecting sequestrated CO2 at the flow rate of 1.482 MMScft/d with an injection pressure of 2500 psig, the oil flow rate provided by the coiled tubing gas injection is 900 Stb/d. The profitability of the project is achieved over a period of 20 years with a net present value (NPV) of $11948858.5 and a return on investment after 5 years 2 weeks.

All-Electric Boosting-Control System Simplifies, Improves Operating Processes

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 31943, “Introduction to New Technology Applications, Data-Acquisition Capabilities, and Features of the All-Electric Boosting Control System,” by Kjetil Bergtun, Carsten Mahler, and Trond Melheim, OneSubsea. The paper has not been peer reviewed. Copyright 2022 Offshore Technology Conference. Reproduced by permission. The complete paper describes an all-electric system (AES) and how its implementation will simplify operating processes, reduce topside and subsea weight and cost, and lower the risk of hazardous fluids escaping into the ocean. The authors place special focus on the electrical actuators that were introduced in this project as well as the challenges faced during project execution. Vigdis Field The Vigdis field was discovered in 1986 between the Snorre, Statfjord, and Gullfaks fields in the Tampen area of the North Sea. The development consisted of seven subsea templates and two satellite wells producing to the Snorre A (SNA) facility, which contains a dedicated processing module for Vigdis. In 2002 the plan for development and operation of the Vigdis extension was approved. An unprocessed wellstream is transported from Vigdis to the Snorre A platform by two flowlines. Stabilized oil is transported by pipeline from Snorre A to Gullfaks A for storage and export (offloading). The second platform (SNB) in the Snorre field is 11 km north of SNA. The Snorre field is approximately 130 km from the Norwegian coast, nearly at the same latitude as Florø. When the Vigdis field came onstream in 1997, recoverable resources were estimated at 200 million bbl of oil. The field has now produced 394 million bbl, and recoverable resources have been increased to 455 million bbl of oil. Production from the field was limited by the capacity of the production lines and pressure drop across the topside chokes. Reservoir deliverability was limited by low reservoir pressure in some parts of the field, together with increasing water cut, leading to reduced energy into the system, which in turn caused dropping wellhead pressures.

3-D seismic interpretation of stratigraphic and structural features in the Upper Jurassic to Lower Cretaceous sequence of the Gullfaks Field, Norwegian North Sea: A case study of reservoir development

The 3-D seismic dataset is a key tool to analyze and understand the mechanism of structural and stratigraphic hydrocarbon (HC) trapping in the subsurface. Conventionally used subsurface seismic characterization methods for fractures are based on the theory of effective anisotropy medium. The aim of this work is to improve the structural images with dense sampling of 3-D survey to evaluate structural and stratigraphic models for reservoir development to predict reservoir quality. The present study of the Gullfaks Field, located in the Norwegian North Sea Gullfaks sector, identifies the shallowest structural elements. The steepness of westward structural dip decreases eastward during the Upper Jurassic to Lower Cretaceous deposition. Reservoir sands consist of the Middle Jurassic deltaic deposits and Lower Jurassic fluvial channel and delta plain deposits. Sediment supply steadily prevails on sea-level rise and the succession displays a regressive trend indicated by a good continuous stacking pattern. The key factor for the development of reservoirs in the Gullfaks Field is fault transmissibility with spatially distributed pressure. The majority of mapped faults with sand-to-sand contacts are non-sealing, which provide restriction for the HC flow between the fault blocks. The traps for HC accumulation occur between the post-rift and syn-rift strata, i.e. antiform set by extensional system, unconformity trap at the top of syn-deposition, and structural trap due to normal faults. Overall reservoir quality in the studied area is generally excellent with average 35% porosity and permeability in the Darcy range. Our findings are useful to better understand the development of siliciclastic reservoirs in similar geological settings worldwide.

Field observations of reservoir souring development and implications for the Extended Growth Zone (EGZ) souring model

Microbial generation of H2S in-situ due to injection of seawater, so-called reservoir souring, can induce severe negative impact in terms of health, safety, maintenance and economics in mature oil fields. Historical H2S data have been collected for decades at the Norwegian Continental Shelf fields. The Gullfaks field in the North Sea has been negatively impacted by severe H2S production, whereas another comparable North Sea field, called Field B, only has minor H2S challenges. The difference in cumulative H2S development in Gullfaks wells are described as Type I, II and III by an empirical classification. Type I wells show rapid increase in the H2S concentration produced (<1 year or <1 mill. Sm3produced water), whereas Type III show a significant delay and slowly rising H2S production (>10years or >10 mill. Sm3produced water). Type II can be considered as a mixture of Type I and III. To understand the difference between these types, a microbial reservoir souring model called the Extended Growth Zone (EGZ) model has previously been introduced. Differences in H2S development described by the three different well types are supported by the consequences of the EGZ model for both fields on field, platform/installation and well level. The results support that the overall drainage water injection strategy implemented is the single-most important cause governing the development of produced H2S over the lifespan of a field: •High H2S production is expected when cold seawater is injected directly into oil bearing zones (Type I behavior). •Relatively lower H2S production is expected when cold seawater is injected in the water zone below oil bearing zones (Type III behavior). The EGZ model describes the development of reservoir souring based on two main hypotheses (1) Degradation of crude oil as carbon source (2) The importance of temperature on the rate of H2S generation as summarized: •The expected H2S development according to the EGZ model agrees with observed data from Gullfaks both on platform level (GFA>GFC>GFB) and for individual wells. •The observed slow development of H2S for Field B observed for platform and well bore level is explained by the presence of Type III wells only. •Type III wells in Gullfaks and Field B behave similarly within the uncertainty range for H2S production.

E&amp;P Notes (February 2021)

E&amp;P Notes (February 2021)

Ranking and selecting fault models using flow-indicator fault properties and simple streamline simulations

Fault zones in porous sandstones are commonly divided into two parts: a fault core and a damage zone. Both fault-zone elements could influence subsurface fluid flow and should be incorporated in a geologically realistic model. The fault core can be implemented in the model as a transmissibility multiplier (TM), while the damage zone can be implemented by modifying the grid permeability in the cells adjacent to the model faults. Each of the input parameters used in calculating the TM and damage-zone permeability modification is subject to geological uncertainty. Here an iterative workflow is employed to define probability distribution functions for each of the input parameters, with the result being many fault-model realizations. Here two methods are examined for ranking and selecting the fault-model realizations for further analysis: (i) calculating the flow-indicator fault properties (effective cross-fault transmissibility and effective cross-fault permeability) from the static model; and (ii) employing a simplified flow-based connectivity calculation, returning dynamic measures of model connectivity. The aims are to outline the methodology and workflow used, evaluate the impact of the different input parameters on the results, and examine the results of the static and dynamic approaches to understand how the ranking and selection of models compares between the two. Our results are dependent on the structural model. In a strongly compartmentalized model based on the Gullfaks Field, North Sea, fluid-flow-indicator fault properties are weakly correlated with measures of dynamic behaviour. In particular, models with low fault transmissibility show a much greater range of dynamic behaviour, and are less predictable, than models with high fault transmissibility. In a weakly compartmentalized model with strongly channelized fluvial facies based on the Whitley Bay area in NE England, there was a strong correlation between flow-indicator fault properties and measures of dynamic behaviour. We ascribe these results to the greater complexity of flow paths expected when a highly compartmentalized model contains faults that are likely to be baffles to cross-fault flow. Thematic collection: This article is part of the Fault and top seals collection available at: https://www.lyellcollection.org/cc/fault-and-top-seals-2019

Technology Focus: Subsea Systems (August 2020)

Despite uncertainties related to oil and gas industry dynamics and new requirements to reduce CO2 emissions, energy demand is expected to continue to grow. It is also expected that the mix of energy shares will change significantly in the next 10-20 years. Natural gas and renewables (wind and solar) gradually will represent a larger part of the energy mix, balanced by a drop in reliance upon fossil fuels such as oil and coal. Some of the largest reserves of natural gas are located under deep waters, far from shore or any other existing infrastructure. Examples of areas where such field development is under way include western Australia, the North Sea, the Mediterranean, and southeast Africa. Among the many challenges often experienced in such fields is the requirement to transport gas in ultralong pipelines back to shore; in some instances, tie-backs are 100- to 250-km long and water depths can reach more than 2000 m. Subsea gas-compression technologies have been developed, tested, and successfully deployed in recent years, and operators now are using these technologies to make remote subsea gas fields profitable. Systems for subsea gas compression have reached Technical Readiness Level 7. After being in operation at the Gullfaks field and at the Åsgard field in the North Sea for several years, these technologies are now being considered for future field developments, not only in the North Sea but also in other parts of the world. In the Åsgard subsea-compression system, the gas condensate is separated subsea so that the gas can be compressed by a centrifugal compressor and the liquids can be pumped. Gas and liquid then are commingled downstream of the compressor station, and the mix travels in a pipeline to a processing facility 40 km away. The Gullfaks compression system uses a multiphase compressor technology that has been developed to handle mixtures of gas and liquid; hence, no separation or liquid pumps are required subsea. The result is that the weight and volume per unit of compression power are greatly reduced and the system becomes relatively small and less complex. Both operational experience and studies of future offshore gas-field developments are showing that subsea gas-compression systems not only reduce investment costs but also increase recovery significantly. New solutions, supported through relevant field studies, will be analyzed in the studies presented in this section.

Subsea Multiphase Gas Compression System Offers Competitive Advantage

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 29391, “Bringing Forward the Next-Generation Multiphase Compressor,” by John Olav Fløisand, Bernt Helge Torkildsen, Joakim Almqvist, SPE, and Hans Fredrik Lindøen-Kjellnes, OneSubsea, prepared for the 2019 Offshore Technology Conference, Houston, 6-9 May. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. In 2015, the world’s first subsea multiphase gas compression system was installed offshore Norway. The system comprises two-off 5-MW machines configurable for serial or parallel compression. This system has now gained considerable and valuable operational experience. The multiphase compressor not only ensures efficient power system compatibility but also can contribute to stepout topologies because of the low transmission frequency required for the power supply. Minimizing the complexity of both process and power architecture is crucial in terms of cost, robustness, and system reliability. Gullfaks Subsea Compression The realization of the subsea multiphase gas compression system was made possible through major technology investments during 2007-2012, including facilities, design models, and engineering as well as component and full-assembly qualification testing. This extensive technology-qualification program made the technology robust and reliable and enabled the engineering, procurement, and construction delivery of the subsea multiphase compression system to the Gullfaks field in March 2015 per schedule (Fig 1). The dynamic commissioning of the Gullfaks subsea wet-gas-compression (WGC) system was begun in July 2017. The work was first performed on both compressors in single mode to verify control-system functionality. Different wells and production lines were used to reach desired operation points. After initial commissioning, the compressors were run first in single mode and later in parallel at different suction-pressure setpoints. The system has been operating successfully since its commissioning in 2017. The subsea compressor system is boosting multiphase gas, increasing the production from several wells, and has recently achieved Technology Readiness Level 7. The system flexibility is exploited in extended ways compared with the initial project phase approach and allows the operator to take advantage of many opportunities, including increased oil recovery. Some key achievements of the system include increased oil production by kicking off dead wells and enabling stable well backpressures.

Burrowed matrix powering dual porosity systems – A case study from the Maastrichtian chalk of the Gullfaks Field, Norwegian North Sea

Abstract Chalk reservoirs are commonly modelled as dual-porosity systems, in which a very porous but low permeable matrix is intersected by highly permeable vugs and fractures from which oil and gas can be produced. The Gullfaks Field in the Norwegian North Sea contains such a reservoir, which is producing from Maastrichtian chalk in addition to the conventional Triassic and Jurassic siliciclastic reservoirs. However, in comparison to the prolific chalk fields in the southern North Sea (e.g. Ekofisk, Valhall), chalk reservoirs in the northern part (e.g. Oseberg and Gullfaks fields) experience challenged production due to reservoir presence and quality related to depositional facies and structural conditions. Analyses of cores from three wells in the Maastrichtian Shetland Group of the Gullfaks Field reveal that this interval is completely bioturbated during several stages, e.g. mottling with diffuse bioturbated texture in an early softground stage that became subsequently overprinted by more discrete burrows with active and passive fill and different rock properties during the stiffground and firmground stages of the ooze. A rich and moderately diverse trace-fossil assemblage consists of abundant Zoophycos, common Chondrites, Taenidium, Thalassinoides and Virgaichnus, and rare Nereites, Planolites, Spirophyton and Teichichnus. Ichnological features allow the differentiation of five recurrent ichnofabrics (Thalassinoides, Zoophycos, Chondrites, Nereites and Zoophycos-Taenidium ichnofabrics) with variable influence on porosity and permeability. The Thalassinoides ichnofabric in chalk has the highest impact on improving reservoir quality, whereas Zoophycos and partly Chondrites ichnofabrics, in marly chalk and chalky marlstone respectively, contribute to creating potential reservoir zones if burrow density is high enough. Thin-section analysis of the different ichnofabrics illustrates the negative or positive effect of burrows on porosity distribution, whereas micro-CT imaging reveals an intriguing system of partly open micro-burrows (e.g. Virgaichnus) within the matrix, which serves as source for porosity. This burrow porosity provides a connection in the matrix that hosts open vugs and fractures, thus improving oil production.

3-D mechanical analysis of complex reservoirs: a novel mesh-free approach

SUMMARYBuilding geomechanical models for induced seismicity in complex reservoirs poses a major challenge, in particular if many faults need to be included. We developed a novel way of calculating induced stress changes and associated seismic moment response for structurally complex reservoirs with tens to hundreds of faults. Our specific target was to improve the predictive capability of stress evolution along multiple faults, and to use the calculations to enhance physics-based understanding of the reservoir seismicity. Our methodology deploys a mesh-free numerical and analytical approach for both the stress calculation and the seismic moment calculation. We introduce a high-performance computational method for high-resolution induced Coulomb stress changes along faults, based on a Green's function for the stress response to a nucleus of strain. One key ingredient is the deployment of an octree representation and calculation scheme for the nuclei of strain, based on the topology and spatial variability of the mesh of the reservoir flow model. Once the induced stress changes are evaluated along multiple faults, we calculate potential seismic moment release in a fault system supposing an initial stress field. The capability of the approach, dubbed as MACRIS (Mechanical Analysis of Complex Reservoirs for Induced Seismicity) is proven through comparisons with finite element models. Computational performance and suitability for probabilistic assessment of seismic hazards are demonstrated though the use of the complex, heavily faulted Gullfaks field.

Quantification of uncertainty in 3-D seismic interpretation: implications for deterministic and stochastic geomodeling and machine learning

Abstract. In recent years, uncertainty has been widely recognized in geosciences, leading to an increased need for its quantification. Predicting the subsurface is an especially uncertain effort, as our information either comes from spatially highly limited direct (1-D boreholes) or indirect 2-D and 3-D sources (e.g., seismic). And while uncertainty in seismic interpretation has been explored in 2-D, we currently lack both qualitative and quantitative understanding of how interpretational uncertainties of 3-D datasets are distributed. In this work, we analyze 78 seismic interpretations done by final-year undergraduate (BSc) students of a 3-D seismic dataset from the Gullfaks field located in the northern North Sea. The students used Petrel to interpret multiple (interlinked) faults and to pick the Base Cretaceous Unconformity and Top Ness horizon (part of the Middle Jurassic Brent Group). We have developed open-source Python tools to explore and visualize the spatial uncertainty of the students' fault stick interpretations, the subsequent variation in fault plane orientation and the uncertainty in fault network topology. The Top Ness horizon picks were used to analyze fault offset variations across the dataset and interpretations, with implications for fault throw. We investigate how this interpretational uncertainty interlinks with seismic data quality and the possible use of seismic data quality attributes as a proxy for interpretational uncertainty. Our work provides a first quantification of fault and horizon uncertainties in 3-D seismic interpretation, providing valuable insights into the influence of seismic image quality on 3-D interpretation, with implications for deterministic and stochastic geomodeling and machine learning.

Incorporating critical fault properties controlling hydrocarbon accumulation in 3D basin and petroleum system modelling: a case study in the northern North Sea

Fault properties are very important parameters in migration and accumulation of hydrocarbons in sedimentary basins. However, there are still several different schools of thought on how to incorporate such prospect-bounding fault properties into petroleum system migration and modelling studies. This paper investigates how shale gouge ratio (SGR), which defines the sealing/non-sealing capacity of faults, can be incorporated in basin modelling using the Gullfaks, Visund, Kvitebjorn and Huldra fields in the northern North Sea as a case study. The paper also presents the results from the most likely model representing the present day reality in the basin by varying the faults properties defined by SGR until the reserves-in-place in the four fields are obtained. Our results show that gas accumulations are more sensitive to SGR than the oil accumulations. The oil accumulation in the Gullfaks field is controlled by three main faults. The first fault bounding the field is a non-sealing fault with SGR = 10%. The second fault located further south in the field is a sealing fault, and the third fault located in the north is a non-sealing fault. A NE–SW non-sealing trending fault controls the hydrocarbon accumulation in the Visund field. In the Kvitebjørn field, another NE–SW trending fault surrounding the field with an SGR of 30% controls the hydrocarbon accumulation. The gas-in-place in the Huldra field is controlled by two N–S trending faults. The first fault is located in the west of the field and is defined by SGR of 40%, while the second fault is defined as open. Analysis of the burial history curves of the most likely petroleum system model obtained after the fault properties modelling shows that the Late Jurassic to Early Cretaceous uplift in the basin is more pronounced in the footwall of the triple rift graben system in the basin. In the same period, the axis of the graben system is characterized by non-deposition of sediments.

Time lapse (4D) and AVO analysis: A case study of Gullfaks field, Northern North Sea

A 4D seismic or time lapse survey has been used to investigate the amplitude versus offset (AVO) effects on seismic data in order to identify anomalies in the Gullfaks field for three different reservoir intervals namely the Tarbert, Cook and Statfjord reservoirs. Repeatability analysis has shown that the earlier seismic vintages are the most unreliable for amplitude anomaly analysis as normalised root-mean square (NRMS) values are greater than 50%. This is above the threshold of good and medium repeatability. Fluid substitution models show increases in both P-wave velocity and density for increasing water saturations with a maximum change of 7.33% in the P-wave velocity, and this is in line with predictions from previous work using the Biot - Gassman equations. AVO modelling for the top Tarbert Formation interface produced scenarios of increasing amplitudes with offset for the presence of hydrocarbons, which dim out with 100% brine saturation. This correlates to class III gas sands for different situations of varying Poisson’s ratio across an interface, which has been previously modelled. Two anomalies were identified with one being related to increasing pressure due to water injection correlating to poor permeability around injector well 34/10-B-33. The second anomaly is a case of potential unswept hydrocarbons that displayed a consistent bright spot throughout all of the seismic vintages (in-inlines and crosslines). AVO attribute analysis of this event produced a class II anomaly. However, when comparing near and far offset seismic data, dimming effect was observed producing contrasting evidence. The dimming offset is viewed to have been as a result of poor repeatability values at far offsets. The modelling of the fluid contents in the studied formations to conform to existing literatures justifies the efficacy of the method.

2D and 3D seismic simulation for fault modeling: exploratory revision from the Gullfaks field

2D and 3D seismic data have emerged as a key tool in the oil and gas industry to visualize and understand subsurface morphology and boundaries. In addition to providing excellent structural images, the dense sampling of 2D and 3D survey can sometimes make it possible to map reservoir quality and the distribution of hydrocarbon with well-marked limitations. Here we use 2D and 3D seismic data to map and interpret basic structures and fault lines to construct 2D and 3D base fault models of the Gullfaks field, while avoiding common pitfalls. This work also highlights important concepts and principles that allow selection, interpretation and simulation of particular areas containing hydrocarbon traps through the comparison of different maps such as time structure, amplitude and coherence. The field covers an area of approximately 50 km2 entirely confined within block 34/10 in the Norwegian sector of the North Sea. The area of the seismic lines extends to 4875 m laterally and vertically up to 4.5 s. Based on all the selected horizons, constructed maps and dominant fault construction models (2D and 3D), we show the presence of a major fault that cuts five horizons of the area of interest. The structural features include antiform and a set of extensional faults with master, antithetic and synthetic faults with opposite sense of shear (dip direction and angle ~60°). Ductile deformation at the bottom of seismic lines shows the fluctuation of amplitude of acoustic signals in seismic lines. Our results demonstrate uplift along the major fault during extension indicated by chaotic distortion at the bottom, which reveals a gas trap. In the Gullfaks field, termination of fault movement and subsequent deformation appears to have occurred for a long period of time. This illustrates the use of 2D and 3D visualization with horizon attributes that can conveniently provide massive amounts of data which elucidates the trapping mechanism of faults.

Statoil: Subsea Compression Systems To Extend Field Life

A closer look at the design and construction of Statoil's subsea gas compression systems in the åsgard and Gullfaks fields, the first of their kind in the oil and gas industry.

Megaspores and associated palynofloras of Middle Jurassic fluvio-deltaic sequences in North Yorkshire and the northern North Sea: a biofacies-based approach to palaeoenvironmental analysis and modelling

Outcrops of the Early Bajocian, Gristhorpe Member (Ravenscar Group) in North Yorkshire have been subjected to a multi-disciplinary analysis which establishes a key reference section at Yons Nab. Eight micro-biofaces types (MBs) are defined based on counts of transitional marine microfaunas, megaspores and plant-derived debris. Associated palynofloral associations (PAs) are used to qualify the micro-biofacies defined to provide an integrated model for interpreting salinity–freshwater trends associated with deltaic progradation and retreat. Megaspore and small-spore trends within the delta-plain are shown to have been closely linked to peat-mires forming in topographic lows, with variations across the delta-plain attributable to the presence of the semi-permanent and seasonal water tables. A reconstruction of the floodplain–peat-mire depositional setting is proposed where the composition of host vegetation (e.g. ferns, lycopsids) varied in relation to groundwater levels. Biostratigraphic correlation within the Gristhorpe Member is attempted using the base of ‘established’ delta-plain deposition (megaspore dominant MBs/spore-dominant PAs) and the top and base agglutinated foraminifera-dominant MBs (brackish). Using these criteria the Gristhorpe Member is modelled in terms of a southward progradation of delta-plain facies into a bay-fill sequence, which persisted at Yons Nab. With the delta-plain established, the MB/PA trends and sedimentology suggest a northward shift towards the higher delta-plain, with seasonal standing water only. The MB/PA model was tested on core samples from the coeval lower Brent Group from northern North Sea well 34/10-B-12 (Gullfaks Field); MB/PA trends are shown to compare closely with those of the Gristhorpe Member at Yons Nab, with the same megaspore/small-spore associations developed within similar lithofacies. On this basis transitional marine, bay-fill and delta-plain deposition are defined in the cored section. These comparative data suggest that the dispersal of megaspore and miospore host floras occurred effectively across the Mid North Sea High, and that they colonized the same niche habitats associated with bay-fill and delta-plain development.

Controls on CO2 fate and behavior in the Gullfaks oil field (Norway): How hydrogeochemical modeling can help decipher organic-inorganic interactions

Oil degradation in the Gullfaks field led to hydrogeochemical processes that caused high CO2 partial pressure and a massive release of sodium into the formation water. Hydrogeochemical modeling of the inorganic equilibrium reactions of water-rock-gas interactions allows us to quantitatively analyze the pathways and consequences of these complex interconnected reactions. This approach considers interactions among mineral assemblages (anorthite, albite, K-feldspar, quartz, kaolinite, goethite, calcite, dolomite, siderite, dawsonite, and nahcolite), various aqueous solutions, and a multicomponent fixed-pressure gas phase (CO2, CH4, and H2) at 4496-psi (31-mPa) reservoir pressure. The modeling concept is based on the anoxic degradation of crude oil (irreversible conversion of n-alkanes to CO2, CH4, H2, and acetic acid) at oil-water contacts. These water-soluble degradation products are the driving forces for inorganic reactions among mineral assemblages, components dissolved in the formation water, and a coexisting gas at equilibrium conditions. The modeling results quantitatively reproduce the proven alteration of mineral assemblages in the reservoir triggered by oil degradation, showing (1) nearly complete dissolution of plagioclase; (2) stability of K-feldspar; (3) massive precipitation of kaolinite and, to a lesser degree, of Ca-Mg-Fe carbonate; and (4) observed uncommonly high CO2 partial pressure (61 psi [0.42 mPa] at maximum). The evolving composition of coexisting formation water is strongly influenced by the uptake of carbonate carbon from oil degradation and sodium released from dissolving albitic plagioclase. This causes supersaturation with regard to thermodynamically stable dawsonite. The modeling results also indicate that nahcolite may form as a CO2-sequestering sodium carbonate instead of dawsonite, likely controlling CO2 partial pressure.

Attenuation (1/Q) estimation in reflection seismic records

Despite its numerous potential applications, the lack of a reliable method for determining attenuation (1/Q) in seismic data is an issue when utilizing attenuation for hydrocarbon exploration. In this paper, a new method for measuring attenuation in reflection seismic data is presented. The inversion process involves two key stages: computation of the centroid frequency for the individual signal using a variable window length and fast Fourier transform; and estimation of the difference in the centroid frequency and travel time for paired incident and transmitted signals. The new method introduces a shape factor and a constant which allows several spectral shapes to be used to represent a real seismic signal without altering the mathematical model. Application of the new method to synthetic data shows that it can provide reliable estimates of Q using any of the spectral shapes commonly assumed for real seismic signals. Tested against two published methods of Q measurement, the new method shows less sensitivity to interference from noise and change of frequency bandwidth. The method is also applied to a 3D data set from the Gullfaks field, North Sea, Norway. The trace length is divided into four intervals: AB, BC, CD, and DE. Results show that interval AB has the lowest 1/Q value, and that interval BC has the highest 1/Q value. The values of 1/Q measured in the CDP stack using the new method are consistent with those measured using the classical spectral ratio method.

Relating 4D seismics to reservoir geomechanical changes using a discrete element approach

ABSTRACTA modified discrete element method is briefly introduced and used for modelling reservoir geomechanical response during fluid injection and depletion. The modified approach works as a continuum method until some local failure is initiated, after which it behaves like a discrete element method on a polygonal lattice. The method is advantageous for modelling fracture developments in rocks. It is applied here to synthetic models of two reservoirs taken from the North Sea (Gullfaks and Elgin‐Franklin). For Gullfaks, two cases of water injection were modelled, one with low horizontal effective stress and the other with low vertical effective stress. Vertical fractures are developed in the first case, whereas horizontal fractures are developed in the second case. This would not have been seen using traditional methods. Based on 4D seismics data for the Gullfaks field, one may envision that horizontal fractures could have been formed. The Elgin‐Franklin synthetic model is used to study various scenarios of changing stress field around the depleting reservoir. Based on 4D seismics data from this field, one may see changes that could be interpreted in terms of possible fault reactivation.