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Collaborating Authors
Europe
Abstract In this paper we are continuing our previous works (SPE-143142 and WHOC11-353) to investigate the best development options for a major heavy oil reservoir within the GCC region. In the early stage of this work the most applicable EOR methods were selected, and several simulation runs were conducted to find the optimal injection scenarios and rank them based on the oil recovery factor (ORF). In this paper a comparative study and a sensitivity analysis of various operational conditions and reservoir parameters were conducted in order to (1) find the optimum conditions to achieve a high RF and (2) understand the effect of reservoir heterogeneity on the reservoir performance. The investigated operational parameters are the Steam injection rate, injection swapping time and the perforation location. The investigated reservoir parameters are oil viscosity, initial water saturation, porosity and permeability. In addition to investigating these reservoir parameters, the oil price sensitivity was investigated to evaluate the financial feasibility of the selected recovery methods within a historical and forecasted oil price range. The preliminary results show that the RF is very sensitive to the oil viscosity value and the relation between them is a nonlinear relation. The Simulation results also indicate that the increase in the porosity and permeability accelerates performance; however, the opposite is not true for the initial water saturation value. From an economic perspective, production acceleration would improve overall project economics by mitigating the negative impact of discounting on the revenue stream due to the low oil price. Economically, all successive scenarios support a successful investment at the lowest (expected) oil price; in contrast, the continuous steam and hot-water flooding development options show a high economic risk after the second year, at all oil price scenarios.
- Europe (0.46)
- Asia (0.46)
- North America > Canada (0.28)
- Europe > United Kingdom > Atlantic Margin > West of Shetland > Faroe-Shetland Basin > Rona Ridge > P1368 S > Block 205/26b > Lincoln Field (0.91)
- Europe > United Kingdom > Atlantic Margin > West of Shetland > Faroe-Shetland Basin > Rona Ridge > P1368 S > Block 205/26b > Greater Warwick Area (0.91)
Abstract Significant reduction in well productivity of gas-condensate reservoirs occurs owing to reduced gas mobility arising from the presence of condensate/water liquid phases around the wellbore. As wettability modifiers, fluorinated chemicals are capable of delivering a good level of oil and water repellency to the rock surface, making it intermediate gas-wet and alleviating such liquid blockage. The main objective of this experimental work has been to propose an effective chemical treatment process for carbonate rocks, which have received much less attention in comparison to sandstone rocks. Screening tests, including contact angle measurements and compatibility tests with brine, were performed using mainly anionic and nonionic fluorosurfactants. On positively charged carbonate surfaces the anionic chemicals were sufficiently effective to repel the liquid phase, whilst the nonionic chemicals showed an excellent stability in brine media. A new approach of combining anionic and nonionic chemical agents is proposed, to benefit from these two positive features of an integrated chemical solution. A number of low and high permeability carbonate cores have been successfully treated using chemicals selected through screening tests. Optimization of solvent composition and filtration of the solution before injecting chemicals into the core proved very effective in reducing/eliminating the risk of possible permeability damage due to deposition of large chemical aggregates on the rock surface. The chemical solution optimized in this study can be applied as an efficient wettability modifier for mitigating the negative impact of condensate/water banking in carbonate gas-condensate reservoirs.
- North America > United States > Texas (0.69)
- North America > United States > California (0.68)
- Europe > Norway > North Sea > Central North Sea (0.28)
- Research Report > New Finding (0.48)
- Overview > Innovation (0.34)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.36)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.34)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.71)
- North America > United States > Mississippi > Pond Field (0.99)
- North America > United States > California > San Joaquin Basin > Cal Canal Field (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > PL 479 > Block 6506/12 > Åsgard Field > Smørbukk Field > Åre Formation (0.99)
- (9 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Abstract There may be various drivers to implement Produced Water Re-Injection (PWRI). However, re-injecting produced water from the same field cannot replace the voidage created by production, especially early in the life of the field, since most of that voidage is created by hydrocarbon extraction. Thus seawater may have to be considered to "top up" PWRI. This raises the question of what are the implications for scale control of mixing potentially incompatible brines before injection, compared to the conventional injection scenario where the mixing takes place in the reservoir. A study was set up to consider scale management during the life cycle of four offshore fields. The available data included analysis of formation and produced water and seawater compositions, and the time evolution of the produced water – seawater split in the injection system. The tools used included thermodynamic scale prediction and reservoir simulation calculations. Thus the evolution of the scale risk over the entire water cycle – from injection, through the reservoir, to production could be evaluated. The produced water compositions and the results of the calculations show that the scale risk at the producers is much lower than if only seawater had been injected. Calculations were also performed to identify whether bullhead application of scale inhibitor would provide adequate protection for the wells. This was important, as some of the wells are subsea completions. The clear conclusion was that any residual scale risk at the producer wells could be managed by bullhead squeezing. However, the corollary is that the scale risk at the injectors is much higher. The trigger for scale precipitation in this scenario is brine mixing, but instead of that happening in the reservoir, here it occurs before injection. Thus the location of greatest scale risk is moved much further upstream in the flow process.
- Europe > United Kingdom (0.46)
- North America > United States (0.46)
- Europe > Norway (0.28)
- Europe > Denmark (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (0.36)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 21/10 > Forties Field > Forties Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 019 > Block 7/12 > Ula Field > Ula Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > King Lear Area > Block 7/12 > Ula Field > Ula Formation (0.99)
- Europe > Denmark > North Sea > Danish Sector > Norwegian-Danish Basin > Siri Canyon > Block 5604/20 > Siri Field (0.98)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)
Abstract Time-lapse (4D) seismic data can be integrated into history matching by comparing predicted and observed data in various domains. These include the time domain (time traces), seismic attributes, or petro-elastic properties such as acoustic impedance. Each domain requires different modelling methods and assumptions as well as data handling workflows. The aim of this work is to investigate the degree to which the choice of domain influences theoutcome of history matching on the choice of best model and associated uncertainties. Another aspect of history matching is that long simulations often pose an obstacle for an automatic approach. In this study we use appropriately upscaled models manageable in the automatic history matching loop. We apply manual and assisted seismic history matching to the Schiehallion field. In the assisted approach, the optimization loop is driven by a stochastic algorithm, while the manual workflow is based on a qualitative comparison of 4D seismic maps. By upscaling we obtained an order of magnitude gain in performance. Accurate upscaling was ensured by thorough volume and transmissibility calculation within regions. The parameterisation of the problem is based on a pattern of seismically derived geobodies with specified transmissibility multipliers between the regions. Seismic predictions are made through petro-elastic modelling, 1D convolution, coloured inversion and calculation of different attributes. We were able to achieve a reasonable match of production and 4D seismic data using coarse scale models in manual and assisted approaches. We observed that the misfit surfaces are different when working in the various seismic domains considered. Use of equivalent domains for observed and predicted data was found to give a more unique misfit response and better result. Accurate comparison of predicted and observed 4D seismic data in different domains is necessary for tackling non-uniqueness of the inverse problem and hence reducing the uncertainty of field development predictions.
- Europe > United Kingdom > Atlantic Margin > West of Shetland (0.35)
- North America > United States > Texas > Harris County > Houston (0.28)
- Geophysics > Time-Lapse Surveying > Time-Lapse Seismic Surveying (1.00)
- Geophysics > Seismic Surveying (1.00)
- North America > United States > Louisiana > East Gulf Coast Tertiary Basin > Bay Marchand Field (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 22/7 > Nelson Field > Forties Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 22/6a > Nelson Field > Forties Formation (0.99)
- (17 more...)
- Reservoir Description and Dynamics > Reservoir Simulation > History matching (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Four-dimensional and four-component seismic (1.00)
Abstract This presentation outlines an integrated workflow that incorporates 4D seismic data into the Ekofisk field reservoir model history matching process. Successful application and associated benefits of the workflow benefits are also presented. A seismic monitoring programme has been established at Ekofisk with 4D seismic surveys that were acquired over the field in 1989, 1999, 2003, 2006 and 2008. Ekofisk 4D seismic data is becoming a quantitative tool for describing the spatial distribution of reservoir properties and compaction. The seismic monitoring data is used to optimize the Ekofisk waterflood by providing water movement insights and subsequently improving infill well placement. Reservoir depletion and water injection in Ekofisk lead to reservoir rock compaction and fluid substitution. These changes are revealed in space and time through 4D seismic differences. Inconsistencies between predicted 4D differences (calculated from reservoir model output) and actual 4D differences are therefore used to identify reservoir model shortcomings. This process is captured using the following workflow: (1) prepare and upscale a geologic model, (2) simulate fluid flow and associated rockphysics using a reservoir model, (3) generate a synthetic 4D seismic response from fluid and rock physics forecasts, and (4) update the reservoir model to better match actual production/injection data and/or the 4D seismic response. The above-mentioned Seismic History Matching (SHM) workflow employs rock-physics modeling to quantitatively constrain the reservoir model and develop a simulated 4D seismic response. Parameterization techniques are then used to constrain and update the reservoir model. This workflow updates geological parameters in an optimization loop through minimization of a misfit function. It is an automated closed loop system, and optimization is performed using an in-house computer-assisted history matching tool using evolutionary algorithm. In summary, the Ekofisk 4D SHM workflow is a multi-disciplinary process that requires collaboration between geological, geomechanical, geophysical and reservoir engineering disciplines to optimize well placement and reservoir management.
- North America > United States > Texas (0.68)
- Europe > Norway > North Sea > Central North Sea (0.27)
- Geology > Structural Geology (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geophysics > Time-Lapse Surveying > Time-Lapse Seismic Surveying (1.00)
- Geophysics > Seismic Surveying (1.00)
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6507/8 > Heidrun Field > Åre Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6507/8 > Heidrun Field > Tilje Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6507/8 > Heidrun Field > Ile Formation (0.99)
- (22 more...)
- Reservoir Description and Dynamics > Reservoir Simulation > History matching (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Four-dimensional and four-component seismic (1.00)
- Information Technology > Modeling & Simulation (1.00)
- Information Technology > Artificial Intelligence > Representation & Reasoning (1.00)
- Information Technology > Artificial Intelligence > Machine Learning > Evolutionary Systems (0.88)
- Information Technology > Artificial Intelligence > Machine Learning > Statistical Learning (0.68)
Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the EAGE Annual Conference & Exhibition incorporating SPE Europec held in Copenhagen, Denmark, 4-7 June 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract In-well flow measurement remains as one of the most difficult tasks in the oil and gas industry, mainly due to the challenging conditions of the downhole environment. When made successfully, however, it plays a major role in monitoring and optimizing well performance, especially for the wells equipped with advanced completion devices. The increasing demand for in-well flow measurement is also driven by other factors including zonal production allocation in multizone completions as well as reliable commingled production, reduction of surface well tests and facilities, and detection of production anomalies. This paper provides a closer look at one of the state-of-art in-well flow measurement technologies: optical, strain-based, phase flow rate measurements via turbulent structure velocity and sound speed of the turbulent flow. It is an introduction to how this flow measurement technology works and how it is applied to different flow applications from single-phase injectors to multiphase producers. Specific field examples representing different flow applications are also referenced to published material. The strong and weak points of the technology are explored, and in the process, an operation envelope is produced for the use of this technology. The system response to the presence of advanced completion devices are also discussed, guidelines are given, and recommendations are made based on field and lab tests. Understanding a technology's strong and weak points before implementation is essential to ensuring that informed and successful decisions can be made concerning its use for a given application. This process is often mutually beneficial to both operators and equipment manufacturers since collaborations can lead to advancement of technology and, as a result, provide even more reliable solutions. Background The use of the phrase "intelligent well" was not common a decade ago. The reason is hidden in its definition.
- North America > United States > Texas (1.00)
- Asia > Middle East (1.00)
- Europe > United Kingdom (0.68)
- Europe > Denmark > Capital Region > Copenhagen (0.24)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Ship Shoal South Addition > Block 359 > Mahogany Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Ship Shoal South Addition > Block 349 > Mahogany Field (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Peterhead Graben > P.986 > Blocks 19/10 > Buzzard Field > Kimmeridge Formation > Buzzard Sandstone (0.99)
- (10 more...)
Summary Desktop computing is undergoing a revolution with parallel processing on workstations. Parallel streamline simulators have been developed for shared memory architecture systems. In this paper, we discuss the implementation and performance analysis of a shared memory architecture commercial parallel streamline simulator based on native threading technology for both Windows and Linux operating systems. In general the streamline simulation algorithm is relatively straightforward to parallelize, however, there are several challenges that require special attention in order to avoid computing bottlenecks and inconsistent results. Repeatability of parallel simulation results is a well-known challenge. A data-accumulation scheduling algorithm designed to ensure repeatable results independent of the number of processing units has been implemented. The algorithm is supplemented by an efficient loadbalancing algorithm, to minimize processor idle time. Parallel scalability for various model characteristics and streamline solver options is analyzed. We have observed almost linear scalability up to 10 threads and a speed up factor of three to seven for simulation runs using a 1D explicit upwind finite difference solver to solve the transport problem along streamlines. The front tracking solver is inherently fast and does not gain significantly from parallelization. The run time of a serial simulation using the front-tracking solver is less than that of a parallel explicit solver run using up to 12 threads. The memory consumption of the front tracker is slightly higher than the explicit solver but overall streamline simulations are very memory efficient, enabling large geo-scale models to be simulated efficiently on 64-bit workstations. Complex three-phase blackoil simulation problems require a larger number of timesteps steps and speedup degrades as run time becomes dependent on the efficiency of the pressure solver. The results produced by our parallel streamline simulator are repeatable for any number of threads, and the algorithm used to achieve repeatability has little impact on performance.
- North America > United States (0.68)
- Europe (0.68)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 050 > Block 34/10 > Gullfaks Field > Statfjord Group (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 050 > Block 34/10 > Gullfaks Field > Lunde Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 050 > Block 34/10 > Gullfaks Field > Lista Formation (0.99)
- (2 more...)
Abstract One of the major issues with the development of unconventional ultratight shale-gas reservoirs is related to concerns about underdisplacing or overdisplacing hydraulic proppant-fracture treatments in multiple-zone completions in horizontal wells. In recent years, a very large number of multistage propped-fracture treatments in horizontal wells in ultratight shale-gas reservoirs have been overdisplaced to obtain a clean wellbore and avoid problems with the hardware (especially pump-down plugs) used for rapid multizone completions. Because cleanout treatments can usually be avoided by these overdisplacements, multiple treatment stages can be performed more quickly, which saves time and minimizes other added costs. However, this practice might result in poor communication between the propped fractures placed in the reservoir and the wellbore. In some situations, such as when the rock strength is sufficient to prevent closure of nonpropped fracture areas, overdisplacing a treatment could result in a very high conductivity region at the wellbore. There is certainly a limit to the length of an unpropped fracture that could stay open for a significant time. This mechanism is similar to what has been seen in some wells with proppant production, where well productivity has increased following proppant production. Proppant production might create some open channels in the proppant pack near the perforations that remain open. This paper discusses current overdisplacement practices and tries to address if and when overdisplacing fractures in shale- or tight-gas reservoirs could have a net positive or a negative effect on production.
- North America > United States > Texas (1.00)
- Europe (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.78)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- Europe > Denmark > North Sea > Danish Sector > Central Graben > Block 5505/17 > Dan Field (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Field > Barnett Shale Formation (0.98)
Wettability Determination by Equilibrium Contact Angle Measurements: Reservoir Rock- Connate Water System With Injection of CO2
Shojai kaveh, N.. (Defalt University of Technology) | Berentsen, C. W. (Defalt University of Technology) | Rudolph, E. S. (Defalt University of Technology) | Wolf, K-H. A. (Defalt University of Technology) | Rossen, W. R. (Defalt University of Technology)
Abstract The injection of carbon dioxide (CO2) into depleted gas reservoirs and aquifers offer options for CO2-storage. CO2 sequestration is largely controlled by the interactions between CO2, reservoir fluid(s) in place and rock. In particular, the wettability of the rock matrix is a key factor for the fluid distribution and fluid displacement. In this study, the wetting behavior of CO2-Bentheimer sandstone-water systems was investigated by means of visual contact-angle measurements. The experiments were conducted in a modified pendant drop cell (PDC) that allows captive-bubble contact-angle measurements at elevated temperatures and pressures. Contact angle measures were peformed with water that was fully (pre)-saturated with CO2. Multiple experiments were performed at constant temperature of 318K and pressures varying between 0.1-12 MPA which represent typical in-situ reservoir conditions. The experimental data shows that the contact angle and the size of the bubble converge to equilibrium in time. During this convergence period, the contact angle and the bubble size generally show a slight change as function of time. This can be contributed to the mass transfer and reduction in density of the CO2 during re-equilibration of the system. The experimental data shows a larger dependency of the contact angle on bubble size than on pressure. However, for bubbles with similar size, contact angle shows a slight increase as a function of pressure. However, for bubbles with similar size, contact angle shows a slight increase as function of pressure. All data shows that Bentheimer-water-CO2 systems remain water-wet even at high pressure.
- Europe (1.00)
- North America > United States > Texas (0.28)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
Abstract Statistical correlations in flowrate fluctuations between wells from many fields appear to bear out the expectation that the hydraulic conductivities of faults and fractures in reservoirs can be influenced by geomechanical perturbations due to production operations: the fluctuations are characterised by high correlations over very large separation distances between wells; and those correlations appear to be stress-related and fault-related. An entirely separate relationship derived from observations in multiple fields is a strong bias of directionalities shown by injected fluids towards the local orientation of modern-day major principal horizontal principal stress axis (SHmax). These two sets of independent field observations provide mutually supporting observational evidences for the general geomechanical sensitivity of faults and fractures. However, whilst peaks in flowrate correlations are observed at about 30° to SHmax, the preferred flooding directionalities are at smaller angles to SHmax. A recently proposed machanism is able to explain the orientational relationships in both sets of data. It involves interacting, stress-aligned, compliant micro-cracks near a critical density; there is a large background of observations of shear-wave splitting in many types of formations that supports the prevalence of such micro-cracks. As a practical low-cost tool, analysis of flowrate correlations can provide valuable information about the major reservoir pathways as an adjunct to reservoir characterisation studies. This information can aid history-matching of reservoir models, particularly those involving fractures. The technique is also well-suited to monitoring reservoir behaviour in time-lapse fashion.
- Europe > United Kingdom (1.00)
- North America > United States > Gulf of Mexico > Central GOM (0.28)
- Europe > Norway > North Sea > Northern North Sea (0.28)
- Europe > Norway > North Sea > Central North Sea (0.28)
- Geology > Structural Geology > Fault (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.68)
- Geology > Structural Geology > Tectonics > Plate Tectonics > Earthquake (0.47)
- Geophysics > Seismic Surveying > Passive Seismic Surveying (0.46)
- Geophysics > Seismic Surveying > Seismic Processing (0.34)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > South Eugene Island Basin > Eugene Island South (0.99)
- North America > United States > California > Santa Maria Basin (0.99)
- North America > United States > California > Monterey Formation (0.99)
- (13 more...)