Gaidukov L.A.,Gazpromneft |
Horizontal Wells 2017 | Year: 2017
In this paper, we presented the models of non-isothermal one-phase and two-phase inflow to horizontal well. It was illustrated that such models can be used for NIT of wells to estimate the properties of the nearwellbore zone which has low permeability compared with all other parts of reservoir. We analysed influences of the main effects which affect the wellbore temperature: Two-directional Joule-Thomson effect, heat absorbtion caused by phase transitions. We summarize the results into the table of appropriate model choice to correct interpretation of NIT for a few types of completion and a few values of gas-oil ratio in some synthetic case.
Horizontal Wells 2017 | Year: 2017
Oil fields have a wide range of reservoir property values, the size of the oil-saturated area, layered character and areal heterogeneity, etc. Unlimited variety of possible combinations of these parameters is the basis of decision limited by the possibilities of design solutions: Recovery method, selection of productive formation, well paterns and wells density grid. Oil recovery factor and investments for field development both depend on wells density grid. For horizontal and multibranch wells concept of wells density grid need an upgrade. Lots of parameters should be taken into account for quantation of horizontal and vertical wells ratio. Horizontal wells take an influence on oil recovery, which could be determined with index of real formation coverage increase by horizontal wells drainage. For any productive formation horizontal and vertical ratio in wells density grid defining will be unique. 3D modeling provides an opportunity to large-scale mathematical calculations with different wells density grids and recovery methods. Hydrodynamic modeling provides to find wells density grid for any field recovering by horizontal wells.
Escalona A.,University of Stavanger |
First Break | Year: 2013
We performed forward basin modelling along a profile in the Leeward Antilles, southern Caribbean region, to evaluate the thermal effect that the south-dipping Caribbean slab may have on the evolution of the petroleum systems in the Cenozoic basins. The basins were formed along a former volcanic island arc and back arc region, and have been filled by terrigenous and carbonate sediments since the late Eocene. Since the middle Miocene, the region has been affected by southeastward diachronous subduction of the Caribbean plate beneath South America. We modelled the effect of the subducting slab by treating it as a cold igneous intrusion that insulates the overlying sediments from the asthenosphere. Basin modelling shows that the slab effect results in a reduced transformation ratio in the lower Palaeogene source rocks and lower temperatures in the lower Miocene reservoirs. The effects of lower temperatures and reduced maturation are more pronounced in the basins to the west than in the basins to the east, which the slab has not reached. If the transformation ratio is in the range 60-90%, as modelled, the Leeward Antilles basins offer good exploration opportunities. © 2013 EAGE.
Demyanov V.,Heriot - Watt University |
Gopa K.,Roxar |
Arnold D.,Heriot - Watt University |
Elfeel M.A.,Heriot - Watt University
14th European Conference on the Mathematics of Oil Recovery 2014, ECMOR 2014 | Year: 2014
Uncertainty in the distribution of fractures has a high impact on the fluid flow in oil reservoirs. The challenge is to propagate the uncertainty in the fracture distribution patterns into the reservoir flow response. Optimisation reservoir production under this geological uncertainty would result in to more robust operational decisions to maximise recovery and minimise production costs. Commonly the uncertainty in fracture distribution is described by multiple discrete fracture network realisations (DFN) that represent a range of geologically plausible scenarios. The range of fracture distribution scenarios is captured by spatially varying properties such as facture density distribution, orientation, length etc. Fracture characteristics depend on both geomechanical factors and rock properties, which, therefore, have a high impact on the flow response. The corresponding flow response is also subject to upscaling errors introduced by the choice of the upscaling approach. Therefore, production optimisation (well placements, perforation etc.) becomes a computationally challenging task to perform over a range of possible realisations, modelling choices and upscaling methods required to account for the associated uncertainties. We propose an approach that performs well placement optimisation over a selected sub-set of the reservoir realisations, which would represent the range of uncertainties introduced by geological and upscaling factors. The sub-set of the DFN scenarios is obtained through clustering the exhaustive set of flow response realisations in a flow metric space using a multi-dimensional scaling. The obtained clusters define a limited set of flow scenarios that can be represented by a much smaller number of selected realisations, which still adequately characterise the spread of uncertainty associated with the exhaustive set. Optimisation over a limited set of selected realisations corresponding to the range of the flow response scenarios provides a set of well configurations that maximise oil recovery and minimise the costs (produced water and the number of wells). Optimisation over multiple geological scenarios with respect to the geological uncertainty identifies the most robust development decisions than the one based on the optimisation over a single scenario. Use of multi-objective optimisations provides a greater potential variability of possible solutions, which increases the confidence in the uncertainty prediction.
Lachugin D.,Rospan International |
Rusanov A.,TNNC |
Gabisiani G.,Rosneft |
Society of Petroleum Engineers - SPE Arctic and Extreme Environments Conference and Exhibition, AEE 2013 | Year: 2013
CJSC "ROSPAN INTERNATIONAL", a subsidiary of OAO "NK" Rosneft", is currently engaged in the preparation for full-scale development of oil fields in Yamal and the north of the Krasnoyarsk Territory. One of these fields - Tagulskoye, located in the north of the Krasnoyarsk Territory. Infrastructure and road network in the area of the field is absent. Transportation of goods is carried out on the winter road in the summer - water and helicopter transport. Developed by the near field - Vankorskoye, located 45 km to the north. Active research field began in 2009 with the implementation of the pilot area number 1 (section pilot development). In 2009-2010, drilled five wells, including four with horizontal shaft. Conducted in 2010-2013 set of studies aimed at reducing the geological, technological risks, optimize system design to improve the reliability of the forecast of technical and economic indicators. The article summarizes the main results of pilot projects, analyze their performance. A comparison of predicted and actual characteristics of reservoirs, mining potential wells. The approach to preparing the fields to infrastructure constraints. Copyright 2013, Society of Petroleum Engineers.
Peters E.,Technical University of Delft |
Arts R.J.,Technical University of Delft |
Brouwer G.K.,Technical University of Delft |
Geel C.R.,Technical University of Delft |
And 9 more authors.
SPE Reservoir Evaluation and Engineering | Year: 2010
In preparation for the SPE Applied Technology Workshop (ATW) held in Brugge in June 2008, a unique benchmark project was organized to test the combined use of waterflooding-optimization and history-matching methods in a closed-loop workflow. The benchmark was organized in the form of an interactive competition during the months preceding the ATW. The goal set for the exercise was to create a set of history-matched reservoir models and then to find an optimal waterflooding strategy for an oil field containing 20 producers and 10 injectors that can each be controlled by three inflow-control valves (ICVs). A synthetic data set was made available to the participants by TNO, consisting of well-log data, the structure of the reservoir, 10 years of production data, inverted time-lapse seismic data, and other information necessary for the exercise. The parameters to be estimated during the history match were permeability, porosity, and net-to gross-(NTG) thickness ratio. The optimized production strategy was tested on a synthetic truth model developed by TNO, which was also used to generate the production data and inverted time-lapse seismic. Because of time and practical constraints, a full closed-loop exercise was not possible; however, the participants could obtain the response to their production strategy after 10 years, update their models, and resubmit a revised production strategy for the final 10 years of production. In total, nine groups participated in the exercise. The spread of the net present value (NPV) obtained by the different participants is on the order of 10%. The highest result that was obtained is only 3% below the optimized case determined for the known truth field. Although not an objective of this exercise, it was shown that the increase in NPV as a result of having three control intervals per well instead of one was considerable (approximately 20%). The results also showed that the NPV achieved with the flooding strategy that was updated after additional production data became available was consistently higher than before the data became available. Copyright © 2010 Society of Petroleum Engineers.
Grokhotov E.Y.,VNIGRI |
Strukova O.V.,Roxar |
Geomodel 2013 - 15th Scientific-Practical Conference on Oil and Gas Geological Exploration and Development | Year: 2013
This paper describes the regional structural modeling of the north-eastern part of the Timan-Pechora province. Irap RMS is first used for regional structural modeling. The methods for the regional structural modeling are described, they result in clarifying of the structural and geological plan of the northern part of the Pre-Ural foredeep.
Tukhvatullina R.R.,Roxar |
ECMOR 2012 - 13th European Conference on the Mathematics of Oil Recovery | Year: 2012
Acid treatment of the bottom hole formation zone is successfully applied in oil industry to increase well production rates. The value of permeability of the bottom hole zone strongly depends on well production. Acid impacts on porous media and it increases the permeability in a neighbourhood of well. The simulation of the effect of acid injection on permeability evolution is an important task, which demands accounting of various physical phenomena in bottom hole zone. Solution is based on the numerical consideration of the mathematical model of chemical reaction in carbonate reservoir. The main aim of this study is to estimate influence of the Carbon-dioxide gas, which is one of the chemical reaction products, on the permeability of bottom hole zone and well skin-factor. Twodimensional model of two-phase flow of acid aqueous solution and gas is considered.This phenomena has effect on acid filtration in porous media and it takes into account in numerical simulation. It is shown that in some important cases neglecting of gas phase leads to significant errors in estimation of parameters of bottom hole zone.Well skin-factor after acid treatment is calculated as a function of acid volume and injection time.
Roe P.,Norwegian Computing Center |
Kjonsberg H.,Norwegian Computing Center |
74th European Association of Geoscientists and Engineers Conference and Exhibition 2012 Incorporating SPE EUROPEC 2012: Responsibly Securing Natural Resources | Year: 2012
Traditionally fault seal calculations take place directly within the simulation grid. This approach works well for grids where all the faults are aligned along the grid pillars, but implementing an algorithm that works with stair-stepped representation of the faults has proven to be very difficult. Especially the calculation of the displacement field used both indirectly in the fault seal parameter calculation and directly in the calculation of fault zone permeability is challenging. It is hard to find where the different grid layers intersect the fault trace, and the layers are not always completely represented on both sides of the fault. We present a novel algorithm where the calculation of the fault zone permeability is carried out on a 2D plane representing the fault surface. The input parameters needed for calculating the fault zone permeability are resampled from the simulation grid onto the 2D plane, while the resulting fault zone permeability is resampled back into the simulation grid, prior to calculation of the fault transmissibility. The new approach is shown to generate good results both for pillar-faulted grids, and for grids with stairstepped faults, and also works well near complex truncations.
Abrahamsen P.,Norwegian Computing Center |
Dahle P.,Norwegian Computing Center |
Integrated Reservoir Modelling: Are We Doing it Right? | Year: 2012
The use of horizontal well data in 3D reservoir modeling has become an increasingly important task as the use of horizontal wells has become common practice. Standard gridding approaches are based on the use of well picks to define the positions of stratigraphic surfaces along well bores. Horizontal wells however, are often drilled almost parallel to the stratigraphic layering so the number of horizons intersected along a horizontal well can be relatively few. Therefore, horizontal sections of the well can be used to constrain the structural position of reservoir zones. A robust, geostatistical approach has been developed to ensure consistent use of horizontal well data in the construction of 3D structural models. Kriging is used for prediction of surface location based on well picks and constraints obtained from zone logs along horizontal wells. In contrast to standard approaches, all well data (picks and constraints) from all surfaces are treated simultaneously and will have impact on all surfaces above and below. The geostatistical approach is fast and reproducible, and allows structural models to be updated continuously as new wells are drilled. The uncertainty can be evaluated by kriging error maps or by generating stochastic realizations that honor all the well data.