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Collaborating Authors
Results
- North America > United States > Texas (1.00)
- Europe (0.93)
- Research Report > New Finding (0.93)
- Overview (0.88)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.47)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (0.93)
Experimental Investigation of the Extent of the Impact of Halite Precipitation on CO2 Injection in Deep Saline Aquifers
Edem, Donatus (University of Salford, Manchester, United Kingdom.) | Abba, Muhammad (University of Salford, Manchester, United Kingdom.) | Nourian, Amir (University of Salford, Manchester, United Kingdom.) | Babaie, Meisam (University of Salford, Manchester, United Kingdom.) | Naeem, Zainab (University of Salford, Manchester, United Kingdom.)
Abstract A laboratory investigation was carried out to experimentally determine the extent of the salt precipitation effects on the petrophysical properties of deep saline aquifer during CO2 storage. This was performed on selected core samples using laboratory core flooding process. The petrophysical properties (Porosity, Permeability) of the core sample were measured before core flooding using Helium Porosimetry and Scanning Electron Microscopy (SEM) to determine the morphology of the core samples. The core samples were saturated with brines of different salinities (5, 15, 25, wt% NaCl) and core flooding process was conducted at a simulated reservoir pressure of 1,000 psig, temperature of 45°C, with varying injection rates of 1.0, 1.5, 2.0, 2.5 and 3.0 ml/min respectively. The obtained results indicated that the porosity and permeability decreased drastically as salinities increases, noticeably because the higher concentration of brine resulted in higher amounts of salt precipitation. Porosity reduction ranged between 0.75% to 6% with increasing brine salinity while permeability impairment ranged from 10% to 70% of the original permeability. The SEM images of the core samples after the flooding showed that salt precipitation not only plugged the pore spaces of the core matrix but also showed significant precipitation around the rock grains thereby showing an aggregation of the salts. This clearly proved that the reduction in the capacity of the rock is associated with salt precipitation in the pore spaces as well as the pore throats. Higher injection rates induced higher salt precipitation which caused reduction in porosity and permeability. This is attributed to the fact that; the higher injection of CO2 vaporizes the formation brine more significantly and thereby increasing brine concentration by removing the water content and enhancing precipitation of salt. These findings provide meaningful understanding and evaluation of the extent of salt precipitation on CO2 injectivity in saline reservoirs. The insight gained could be useful in simulation models to design better injectivity scenarios and mitigation techniques
- North America > United States (0.46)
- Europe > Netherlands (0.28)
- Europe > Norway > Barents Sea > Hammerfest Basin > License 100 > Block 7121/7 > Snøhvit Field > Stø Formation (0.99)
- Europe > Norway > Barents Sea > Hammerfest Basin > License 100 > Block 7121/7 > Snøhvit Field > Nordmela Formation (0.99)
- Europe > Norway > Barents Sea > Hammerfest Basin > License 100 > Block 7121/5 > Snøhvit Field > Stø Formation (0.99)
- (30 more...)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- (4 more...)
Abstract This study attempts to describe and model the process leading to the genesis of the tilted oil-water contact (OWC) observed in the lower part of the Thamama Group in an offshore Abu Dhabi field. Post-oil-migration deformation is thought to be the mechanism that produced a tilted OWC dipping towards the Northeast. Deciphering the tectonic evolution from Jurassic to Paleocene times confirms a long and complex structural history combining burial, halokinesis, uplift and tilting. Diapiric activity was probably established in the eastern accumulation by pre-Jurassic times, followed by localized salt-related doming in both parts of the field. During the mid-Eocene occurred a late tilting of the northeastern part of the field, enhancing the curvature of the area. This late tilting caused oil saturation redistribution. In uplifted areas of the field, water saturationdecreased along the drainage curve whereas in areas brought structurally closer to the Free Water Level (FWL), water saturation increased along a scanned imbibition curve. The objective of this study is to retrace the saturation history of the field using lab-measured bounding capillary pressures. This workflow ensures the correct initialization of the dynamic reservoir model and reproduces the observed field behavior. Drainage and imbibition capillary pressures are available for different rock types (RT), measured under various experimental set-ups (mercury injection, porous plate, centrifuge). This study reconciles lab measurements with wireline logs and Dean-Stark data to produce a representative capillary pressure curve for each RT. Next, the structural deformation history is representedas a series of elementary geometric transformations (localized subsidence and global translation) to restore the reservoir in its pre-deformation state. Wireline log saturationsare matched to capillary-based water saturations by adjusting the present day free water level (FWL) and the change of FWL due to seepage. The dynamic model is then initialized by enumeration with the original water saturation and let to equilibrate for 40,000 years. The fluid redistribution and pressures are then monitored to confirm that equilibrium has been attained. This equilibration step ensures that the fluids are at their correctstate of relative permeability and capillary pressure at the start of simulation, something that is not garanteed in the case of direct enumeration of the final saturations. The implications of such procedure on the dynamic behaviorare explored by simulating 50 years of production history and compa. This study greatly improved the saturation modelling by moving from synthetic porosity-bin functions to physics and texture based capillary pressures. The proposed workflow enhanced the history-match quality and reproduced observed field behaviors such as the high water-cut development in the Northeast. A tilted OWC might increase the in-place however extracting those resources might prove more challenging in the face of the low oil mobility. The oil below OWC might not be recovered under conventional waterflood methods and would warrant an EOR implementation. In the future, an appraisal well is planned in the Northeast to assess the volume and mobility of the oil below OWC. It is the first time an integrated workflow, combining SCAL and structural geology, is proposed to correctly initialize the dynamic model for reservoirs that experienced a post-migration deformation, hence making the present study unique.
- North America > United States > Texas (0.93)
- Europe (0.93)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.37)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Arabian Gulf (0.28)
- Phanerozoic > Mesozoic (1.00)
- Phanerozoic > Cenozoic > Paleogene > Eocene > Bartonian (0.34)
- Geology > Structural Geology > Tectonics (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- Geology > Geological Subdiscipline (1.00)
- North America > United States > Colorado > Spindle Field (0.99)
- Europe > Denmark > North Sea > Danish Sector > Central Graben > Block 5604/29 > South Arne Field (0.99)
- Asia > Middle East > UAE > Abu Dhabi > Arabian Gulf > Rub' al Khali Basin > Zakum Concession > Zakum Field > Upper Zakum Field > Thamama Group Formation (0.99)
- (5 more...)
- Information Technology > Software Engineering (0.60)
- Information Technology > Artificial Intelligence > Representation & Reasoning > Model-Based Reasoning (0.41)
A Three-Phase Study on Preflush Stage in Sandstone Acidizing: Experimental and Modeling Analysis of Evolved Carbon Dioxide in a Hydrocarbon and Aqueous Environment
Muhemmed, Sajjaat (Texas A&M University) | Kumar, Harish (Texas A&M University) | Cairns, Nicklaus (Texas A&M University) | Nasr-El-Din, Hisham A. (Texas A&M University)
Summary Limited studies have been conducted in understanding the mechanics of preflush stages in sandstone-acidizing processes. Among those conducted in this area, all efforts have been directed toward singular aqueous-phase scenarios. Encountering 100% water saturation (Sw) in the near-wellbore region is seldom the case because hydrocarbons at residual or higher saturations can exist. Carbonate-mineral dissolution, being the primary objective of the preflush stage, results in carbon dioxide (CO2) evolution. This can lead to a multiphase presence depending on the conditions in the porous medium, and this factor has been unaccounted for in previous studies under the assumption that all the evolved CO2 is dissolved in the surrounding solutions. The performance of a preflush stage changes in the presence of multiphase environments in the porous media. A detailed study is presented on the effects of evolved CO2 caused by carbonate-mineral dissolution, and its ensuing activity during the preflush stages in matrix acidizing of sandstone reservoirs. Four Carbon Tan Sandstone cores were used toward the purpose of this study, of which two were fully water saturated and the remaining two were brought to initial water saturation (Swi) and residual oil saturation to waterfloods (Sorw) before conducting preflush-stage experiments. The preflush-stage fluid, 15 wt% hydrochloric acid (HCl), was injected in the concerning cores while maintaining initial pore pressures of 1,200 psi and constant temperatures of 150°F. A three-phase-flow numerical-simulation model coupled with chemical-reaction and structure-property modeling features is used to validate the conducted preflush-stage coreflood experiments. Initially, the cores are scanned using computed tomography (CT) to accurately characterize the initial porosity distributions across the cores. The carbonate minerals present in the cores, namely calcite and dolomite, are quantified experimentally using X-ray diffraction (XRD). These measured porosity distributions and mineral concentrations are populated across the core-representative models. The coreflood effluents' calcium chloride and magnesium chloride, which are acid/carbonate-mineral-reaction products, as well as spent-HCl concentrations were measured. The pressure drop across the cores was logged during the tests. These parameters from all the conducted coreflood tests were used for history matching using the numerical model. The calibrated numerical model was then used to understand the physics involved in this complex subsurface process. In fully water-saturated cores, a major fraction of unreacted carbonate minerals still existed even after 40 pore volumes (PV) of preflush acid injection. Heterogeneity is induced as carbonate-mineral dissolution progresses within the core, creating paths of least resistance, leading to the preferential flow of the incoming fresh acid. This leads to regions of carbonate minerals being untouched during the preflush stimulation stage. A power-law trend, P = aQ, is observed between the stabilized pressure drops at each sequential acid-injection rate vs. the injection rates, where P is the pressure drop across the core, Q is the sequential flow rate, and a and b are constants, with b < 1. An ideal maximum injection rate can be deduced to optimize the preflush stage toward efficient carbonate-mineral dissolution in the damaged zone. An average of 25% recovery of the oil in place (OIP) was seen from preflush experiments conducted on cores with Sorw. In cores with Swi, the oil saturation was reduced during the preflush stage to a similar value as in the cores with Sorw. The oil-phase-viscosity reduction caused by CO2 dissolution in oil and the increase in saturation and permeability to the oil phase resulting from oil swelling by CO2 are inferred as the main mechanisms for any additional oil production beyond residual conditions during the preflush stage. The potential of evolved CO2, a byproduct of the sandstone-acidizing preflush stage, toward its contribution in swelling the surrounding oil, lowering its viscosity, and thus mobilizing the trapped oil has been depicted in this study.
- Europe (1.00)
- North America > United States > Texas (0.93)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Mineral > Carbonate Mineral (1.00)
- North America > United States > Texas > Fort Worth Basin > Katz Field (0.99)
- Asia > China > Shanxi > Ordos Basin (0.99)
- Asia > China > Shaanxi > Ordos Basin (0.99)
- Asia > China > Gansu > Ordos Basin (0.99)
- Well Completion > Acidizing (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- (3 more...)
A Three-Phase Study on Preflush Stage in Sandstone Acidizing: Experimental and Modeling Analysis of Evolved Carbon Dioxide in a Hydrocarbon and Aqueous Environment
Muhemmed, Sajjaat (Texas A&M University) | Kumar, Harish (Texas A&M University) | Cairns, Nicklaus (Texas A&M University) | Nasr-El-Din, Hisham A. (Texas A&M University)
Summary Limited studies have been conducted in understanding the mechanics of preflush stages in sandstone-acidizing processes. Among those conducted in this area, all efforts have been directed toward singular aqueous-phase scenarios. Encountering 100% water saturation (Sw) in the near-wellbore region is seldom the case because hydrocarbons at residual or higher saturations can exist. Carbonate-mineral dissolution, being the primary objective of the preflush stage, results in carbon dioxide (CO2) evolution. This can lead to a multiphase presence depending on the conditions in the porous medium, and this factor has been unaccounted for in previous studies under the assumption that all the evolved CO2 is dissolved in the surrounding solutions. The performance of a preflush stage changes in the presence of multiphase environments in the porous media. A detailed study is presented on the effects of evolved CO2 caused by carbonate-mineral dissolution, and its ensuing activity during the preflush stages in matrix acidizing of sandstone reservoirs. Four Carbon Tan Sandstone cores were used toward the purpose of this study, of which two were fully water saturated and the remaining two were brought to initial water saturation (Swi) and residual oil saturation to waterfloods (Sorw) before conducting preflush-stage experiments. The preflush-stage fluid, 15 wt% hydrochloric acid (HCl), was injected in the concerning cores while maintaining initial pore pressures of 1,200 psi and constant temperatures of 150°F. A three-phase-flow numerical-simulation model coupled with chemical-reaction and structure-property modeling features is used to validate the conducted preflush-stage coreflood experiments. Initially, the cores are scanned using computed tomography (CT) to accurately characterize the initial porosity distributions across the cores. The carbonate minerals present in the cores, namely calcite and dolomite, are quantified experimentally using X-ray diffraction (XRD). These measured porosity distributions and mineral concentrations are populated across the core-representative models. The coreflood effluents' calcium chloride and magnesium chloride, which are acid/carbonate-mineral-reaction products, as well as spent-HCl concentrations were measured. The pressure drop across the cores was logged during the tests. These parameters from all the conducted coreflood tests were used for history matching using the numerical model. The calibrated numerical model was then used to understand the physics involved in this complex subsurface process. In fully water-saturated cores, a major fraction of unreacted carbonate minerals still existed even after 40 pore volumes (PV) of preflush acid injection. Heterogeneity is induced as carbonate-mineral dissolution progresses within the core, creating paths of least resistance, leading to the preferential flow of the incoming fresh acid. This leads to regions of carbonate minerals being untouched during the preflush stimulation stage. A power-law trend, P = aQ, is observed between the stabilized pressure drops at each sequential acid-injection rate vs. the injection rates, where P is the pressure drop across the core, Q is the sequential flow rate, and a and b are constants, with b < 1. An ideal maximum injection rate can be deduced to optimize the preflush stage toward efficient carbonate-mineral dissolution in the damaged zone. An average of 25% recovery of the oil in place (OIP) was seen from preflush experiments conducted on cores with Sorw. In cores with Swi, the oil saturation was reduced during the preflush stage to a similar value as in the cores with Sorw. The oil-phase-viscosity reduction caused by CO2 dissolution in oil and the increase in saturation and permeability to the oil phase resulting from oil swelling by CO2 are inferred as the main mechanisms for any additional oil production beyond residual conditions during the preflush stage. The potential of evolved CO2, a byproduct of the sandstone-acidizing preflush stage, toward its contribution in swelling the surrounding oil, lowering its viscosity, and thus mobilizing the trapped oil has been depicted in this study.
- Europe (1.00)
- North America > United States > Texas (0.93)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Mineral > Carbonate Mineral (1.00)
- North America > United States > Texas > Fort Worth Basin > Katz Field (0.99)
- Asia > China > Shanxi > Ordos Basin (0.99)
- Asia > China > Shaanxi > Ordos Basin (0.99)
- Asia > China > Gansu > Ordos Basin (0.99)
- Well Completion > Acidizing (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- (3 more...)
Workflow for Upscaling Wettability from the Nanoscale to Core Scale
Rücker, Maja (Imperial College London / Shell Global Solutions International B.V.) | Bartels, Willem-Bart (Utrecht University / Shell Global Solutions International B.V.) | Bultreys, Tom (Imperial College London / Ghent University) | Boone, Marijn (Tescan XRE) | Singh, Kamaljit (Heriot-Watt University / Imperial College London) | Garfi, Gaetano (Imperial College London) | Scanziani, Alessio (Imperial College London) | Spurin, Catherine (Imperial College London) | Yesufu-Rufai, Sherifat (Imperial College London) | Krevor, Samuel (Imperial College London) | Blunt, Martin J. (Imperial College London) | Wilson, Ove (Shell Global Solutions International B.V.) | Mahani, Hassan (Shell Global Solutions International B.V.) | Cnudde, Veerle (Utrecht University / Ghent University) | Luckham, Paul F. (Imperial College London) | Georgiadis, Apostolos (Imperial College London / Shell Global Solutions International B.V.) | Berg, Steffen (Imperial College London / Utrecht University)
Wettability is a key factor influencing multiphase flow in porous media. In addition to the average contact angle, the spatial distribution of contact angles throughout the porous medium is important, as it directly controls the connectivity of wetting and nonwetting phases. The controlling factors may not only relate to the surface chemistry of minerals but also to their texture, which implies that a length-scale range from nanometers to centimeters has to be considered. So far, an integrated workflow addressing wettability consistently through the different scales does not exist. In this study, we demonstrate that such a workflow is possible by combining microcomputed tomography (μCT) imaging with atomic-force microscopy (AFM). We find that in a carbonate rock, consisting of 99.9% calcite with a dual-porosity structure, wettability is ultimately controlled by the surface texture of the mineral. Roughness and texture variation within the rock control the capillary pressure required for initializing proper crude oil-rock contacts that allow aging and subsequent wettability alteration. AFM enables us to characterize such surface-fluid interactions and to investigate the surface texture. In this study, we use AFM to image nanoscale fluid-configurations in 3D at connate water saturation and compare the fluid configuration with simulations on the rock surface, assuming different capillary pressures.
- Europe > United Kingdom > England (0.46)
- North America > United States > Texas (0.28)
- Geology > Mineral (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.34)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Multiphase flow (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- (2 more...)
Summary The objective of this research is to determine the physicochemical processes underlying water and solute transport in organic-rich source rocks. To achieve this goal, a custom-designed experimental apparatus was constructed to conduct flow tests, founded on a high-pressure triaxial assembly. The apparatus is capable of maintaining core samples at reservoir pressure, temperature, and confining stress. We conducted several 120-day low-salinity osmotic tests in low-clay, organic-rich Eagle Ford carbonate-shale samples. Test results showed gradual, slow increase of pressure within the samples. Because this pressure behavior could not be explained properly with classical models, we formulated a mass-transport mathematical model that relies on fundamental chemical osmosis principles driving low-salinity brine into high-salinity core samples. Our mathematical model was articulated to simulate flow into the core as a 3D porous medium rather than transport across a thin, molecule-selective membrane. The model is dependent on the following principles: The low-salinity brine selectively enters the pores by diffusion mass transport, and the pre-existing, ionized dissolved salt molecules within the core are restrained by internal electrostatic forces to counterdiffuse in the direction opposite to that of the low-salinity-brine molecules entering the pore network. Critical model input data, such as permeability, porosity, and rock compressibility, were obtained from flow experiments on twin cores, and the diffusion coefficient was chosen by history matching. The strengths of the numerical simulation include reliance on mass-transport fundamental principles; not requiring the use of an ambiguously defined membrane-efficiency term; and relying on chemical-potential gradient as the driving force for the low-salinity brine to enter the high-salinity core, generating osmotic pressure within the pore network. The latter implies that osmotic pressure is the consequence of water entering the cores, not the cause. Results of this research have provided a more plausible explanation of pore-scale mass transport in organic-rich shales, and provide useful insights for design of effective enhanced-oil-recovery (EOR) processes.
- North America > United States > Texas (0.94)
- Europe (0.67)
- Asia (0.67)
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.89)
- Geophysics > Borehole Geophysics (0.93)
- Geophysics > Seismic Surveying (0.68)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > California > San Joaquin Basin (0.99)
In making the petrophysical calculations of lithology, net pay, porosity, water saturation, and permeability at the reservoir level, the development of a complete petrophysical database is the critical first step. This section describes the requirements for creating such a database before making any of these calculations. The topic is divided into four parts: inventory of existing petrophysical data; evaluation of the quality of existing data; conditioning the data for reservoir parameter calculations; and acquisition of additional petrophysical data, where needed. The overall goal of developing the petrophysical database is to use as much valid data as possible to develop the best standard from which to make the calculations of the petrophysical parameters. Inventory of Existing Petrophysical Data To start the petrophysical calculations, the data that have been gathered previously from various wellbores throughout the reservoir must be identified, organized, and put into electronic form for future calculations.
- North America > United States > Texas (1.00)
- Asia > Malaysia (0.93)
- North America > United States > Alaska > North Slope Borough > Prudhoe Bay (0.68)
- (2 more...)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geology > Mineral > Silicate > Phyllosilicate (0.71)
- (2 more...)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Surface Seismic Acquisition (0.46)
- South America > Ecuador > Pastaza > Oriente Basin > Block 10 > Villano Field (0.99)
- North America > United States > Wyoming > Greater Green River Basin > Carter Creek Field (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- (33 more...)
- Well Drilling > Drilling Operations > Coring, fishing (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (10 more...)
Abstract A high level screening has been performed of UKCS oil fields to identify the most likely LSWF candidates utilising screening criteria with a focus on kaolinite clay content. The screening results suggest that approximately 57% of the fields have 6 % or higher kaolinite clay content. Of these fields 26 % were water-wet and 74 % were mixed-wet in terms of wettability. This suggests that a significant number of fields would fall within the eligibility for consideration of LSWF EOR although their suitability will depend on field maturity (current recovery factor and facilities constraints). The difficulty in applying LSWF in tertiary mode unlike secondary mode, is in obtaining a reasonable prediction of how the reservoir is likely to respond. The question of core availability and quality has been raised in a number of studies in terms of LSWF and electrical property testing. We propose a methodology which can be applied to compensate for the lack of usable core based on petrophysical log response. The logs can be utilised to determine the clay types present (including fractions) from which the cation exchange capacity can be calculated. Selected compositions from anonymised field data from core was used to provide quality control the log derived values. The most likely recovery mechanism, multi-component ion exchange (MIE), requires the input of key electrical properties into the models (cation exchange capacity, reactive surface area, activation energy and mineral fraction) in order to predict the response of the reservoir to LSWF. In this study the effect of clay content on the reservoir response was modelled indirectly by altering the cation exchange capacity relative to the clay mineral fraction present in the reservoir to determine its effect. Utilising a mechanistic modelling approach, homogeneous Cartesian models were run in the compositional finite difference reservoir simulator GEM to assess the impact on oil recovery. The simulated coreflood tests reveal that under secondary LSWF recovery was 68.4 % compared to 63.6 % for formation water (high salinity). The conservative nature of the relative permeability curves limited the incremental recovery. An analysis of the tertiary recovery utilising a coreflood based on Fjelde et al. (2012) revealed that cation exchange impacts the predicted recovery by up to 2.65 % OOIP for the range of 5 - 30 % clay content. Given that the recovery under tertiary conditions is considered in the literature to be between 6 and 12 %, this is significant and highlights that if idealised data is selected rather than real field data, then significant potential exists to under or over-predict the incremental recovery.
- Europe > United Kingdom > North Sea (0.50)
- Europe > Norway > North Sea (0.40)
- Europe > Netherlands > North Sea (0.40)
- (2 more...)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.66)
- North America > United States > Alaska > North Slope Basin > Prudhoe Bay Field (0.99)
- North America > United States > Alaska > North Slope Basin > Duck Island Field > Endicott Field > Kekiktuk Formation (0.99)
- Europe > United Kingdom > Atlantic Margin > West of Shetland > Faroe-Shetland Basin > Rona Ridge > Block 206/9 > Clair Field (0.99)
- (7 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Core analysis (1.00)
Abstract Mærsk Olie og Gas AS as operator for the Danish Underground Consortium (DUC) has successfully planned and delivered an Observation and Monitoring well in the Halfdan field located in the southern part of the Danish North. Although not entirely unique to the industry (for further examples see Richardson, 1977; Widmyer, 1987; Wannell & Ezekwe, 1992) this will be the first well of its kind for Mærsk Oil and the DUC placed in a chalk reservoir. This paper describes the planning and execution phases of the monitoring and observation well legs, summarizing the formation evaluation results primarily related to remaining oil saturations. The data derived from the evaluation program enables an evaluation of the success of the novel wells pattern design in the Halfdan field, enabling optimization of the reservoir recovery, in addition to confirming the vertical extent of the hydrocarbon column. As oil and gas fields mature, the monitoring of production-induced changes becomes crucial to sustain, optimize, and improve production levels. Enhanced recovery techniques are applied to extend the field life, as a result reservoir behavior, including vertical and lateral sweep, becomes more complex and challenging to model. Water injection is a common practice used to maintain the reservoir pressure and enhance oil sweep; yet sweep efficiency is not always equal, with water tending to move heterogeneously through the reservoir seeking higher permeability pathways and leaving trapped/un-swept oil behind. The fluid movement and distribution within the reservoir characterises the efficiency of the production system. Such inherently complex and capital intensive nature of understanding and optimising the recovery mechanism behoves the developer to acquire information to evaluate and enhance the recovery mechanism targeting maximising returns. Monitoring and Observation wells allow the detection of in-situ fluids, enabling modification and enhancement of the dynamic modelling, assist with evaluation of the applied IOR technique, and lay the foundation for potential future EOR opportunities. The two-pronged well provides an early indication of the recovery mechanism success in terms of sweep efficiency, and is a guide to further performance optimisation; additionally it is an opportunity to identify and develop any un-swept volume. The Halfdan field is situated in the Danish North Sea Central Graben approximately 250 kilometers off the West coast of Denmark, and is located between the Dan and Skjold fields. The Halfdan reservoir is Maastrichtian and Danian aged chalk characterised with relatively high porosity (25-35%) and low permeability (0.5-2 mD). Halfdan was discovered in 1998 with a 30,000 ft long horizontal well drilled from the Dan field. The first vertical well was completed in 1999. First production from Halfdan was obtained in late 1999. A slant observation and monitoring well on the Halfdan field was drilled between neighbouring injector and producer horizontal wells respectively, the first such well in the Danish North Sea sector. The objectives were to assess the vertical and lateral sweep efficiency in the field, in addition the saturation change is planned to be monitored in time lapse fashion as the water flood matures around the monitoring well. To allow this, well completion is optimised by installing fiber-glass casing over the reservoir section. A fit for purpose logging and coring program was designed to meet the primary objectives. Logging included pulse neutron as well as formation pressure, PVT sampling and multi depth and frequency resistivity logging. Coring consisted of both specialised sponge and conventional cores. The core analysis program was designed to define the current reservoir properties and their hysteresis, deuterium oxide mud tracer was also added to assess invasion profile.
- Geology > Geological Subdiscipline (0.46)
- Geology > Rock Type > Sedimentary Rock (0.34)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Time-Lapse Surveying > Time-Lapse Seismic Surveying (0.68)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.35)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/5 > Greater Ekofisk Field > Tor Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/5 > Greater Ekofisk Field > Tor Field > Ekofisk Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Tor Field > Tor Formation (0.99)
- (12 more...)
- Well Drilling > Drilling Operations > Coring, fishing (1.00)
- Well Drilling > Casing and Cementing > Casing design (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (5 more...)