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Laoroongroj A.,Imperial College London | Zechner M.,Imperial College London | Clemens T.,OMV e and P | Gringarten A.,Imperial College London
74th European Association of Geoscientists and Engineers Conference and Exhibition 2012 Incorporating SPE EUROPEC 2012: Responsibly Securing Natural Resources | Year: 2012

Laboratory experiments and simulations showed that for an Austrian oil reservoir, oil recovery can be significantly increased using polymers. One of the key design parameters for optimizing displacement efficiency while minimizing costs is the in-situ viscosity of the polymer solutions. Whereas the viscosity of polymer solutions can be measured at surface, the viscosity in the reservoir is difficult to estimate due to degradation of the polymers during the injection process. In addition, polymers exhibit non-Newtonian behaviours resulting in different viscosities of the polymer solutions depending on the shear rate in the reservoir. For the Austrian reservoir, water injection fall off tests were available. A simulation model was calibrated with these tests, and used to simulate injections of polymer solutions followed by fall offs. Simulation results indicate that water injection and fall off tests followed by a series of polymer injection and fall off tests can be interpreted to determine the in-situ viscosity of polymer solutions and the radius of the polymer front with reasonable accuracy, even in the case of non-Newtonian shear-thinning behaviour. Being able to determine the in-situ viscosity allows modifying the injection programme ( changing pumps, modifying perforations) if the degradation of the polymer viscosity is found to be significant, and adjusting the polymer concentration to improve stability and efficiency of the displacement process.


Spoerker H.F.,OMV E and P | Tuschl T.,University of Leoben
SPE/IADC Drilling Conference, Proceedings | Year: 2010

Conventional assumptions of how a gas kick develops in the wellbore mostly refer to one "dry gas bubble" over a wellbore length equivalent to the total influx volume and - while fulfilling all requirements for volumetric/hydraulic well control calculations - are clearly unrealistic. However, modeling the system of gas entering the annulus out of a porous medium and with drilling mud moving in most cases under turbulent flow conditions is highly complex and computer-power intensive. The paper describes the driving mechanisms of gas entering into the wellbore, the methodology used for simulating and visualizing the percolation of gas after the well has been shut in and the influence that gas distribution/movement has on the chemical buffering of sour gas influxes in high-pH drilling fluids. It is part of a multi-year research project aimed at understanding the well bore / gas influx system in more detail and allowing a better definition of the behaviour of high-strength steel drill pipe in potentially sour environments. As the buffer reaction between the sour gas influx and the (generally) caustic drilling mud is heavily influenced by the initial distribution of the gas into the mud, the generation of bubbles (i.e. active surfaces) and the kinetic energy transferred to the system during the mixing process, the results of this study form the basis for subsequent high-definition simulators. Copyright 2010, IADC/SPE Drilling Conference and Exhibition.


Kornberger M.,OMV e and P | Thiele M.R.,Stanford University
SPE Reservoir Evaluation and Engineering | Year: 2014

Active well-rate management to promote the efficient use of injected fluids and to demote fluid cycling is a simple way to increase recovery in brown fields while minimizing costs and preserving existing field/well-fluid-handling constraints. In this work, we present the application of an efficient flow-based surveillance technique to drive rate-management decisions for the 8th Tortonian reservoir in the Vienna basin, Austria. The 8th Tortonian is a typical example of a decade-long peripheral waterflood on a long, steady decline for which it is difficult to justify expensive drilling/ workover programs. Active rate management to improve pattern sweep presents an inexpensive solution to increase recovery. In case of the 8th Tortonian, EUR 10 000 (USD 13,000) was spent to modify well rates, resulting in approximately 5700-m3 (approximately 35,000-STB) incremental oil recovered during a 30- month period. The current oil rate remains higher than the oil rate before the start of the project. Our approach takes advantage of streamline-derived well-allocation factors (WAFs) to quantify injector/producer connections. It is simple and efficient to estimate WAFs with total historical well-fluid rates, well locations, and a geological model. With the WAFs, the ratio of produced oil to injected water (efficiency) of each injector/producer pair can be estimated. Well-pair efficiencies are the starting point for the rate-management approach described in this work. A simple, single-homogeneous-layer system was used in conjunction with historical rates and well locations to estimate the WAFs for the 8th Tortonian reservoir. Connections were compared with available tracer data, and an area of interest was subsequently selected in which both streamlines and tracer data confirmed oil recovery by injected water. A key constraint was to maintain the total gross rate of the area selected at current capacity. New target rates were determined and implemented, resulting in a 30% increase of oil rate during a 30-month period. Considering the simplicity and efficiency of the approach, this is a notable result. The production response of the selected wells showed an increased recovery in conjunction with a relatively constant water cut, suggesting contact with previously unswept oil. All operations and modifications were performed at minimal cost. There were no perforation changes or acidizing jobs involved, and rate changes were obtained simply by changing pump sizes or increasing the number of strokes by changing the V-belt pulley. Copyright © 2014 Society of Petroleum Engineers.


Zoellner P.,TDE Thonhauser Data Engineering GmbH | Thonhauser G.,TDE Thonhauser Data Engineering GmbH | Lueftenegger M.,OMV E and P | Spoerker H.F.,OMV E and P
SPE/IADC Drilling Conference, Proceedings | Year: 2011

One essential element of real-time drilling monitoring is wellbore hydraulics reflected by fluid flow and pressure response. Issues related to pipe wash-outs, cuttings accumulations and well control create a significant source of drilling related problems and consequent lost time. In addition to lost time incidents, the optimum processes to clean and condition the hole in relation to hydraulics are a significant potential in avoiding hidden lost time. This paper outlines a concept and several case studies to monitor drilling hydraulics by analysing fluid flow in relation to pump pressure and other relevant sensor channels. Objective of this work is to early recognize the on-set of hydraulics related problems to take preventive action. The concept is based on recognizing variations in expected behaviour of rig sensor responses using hybrid algorithms, which link analytic, statistic and knowledge based concepts. With a large number of data at a high degree of operational detail, generated using automated operations recognition, it is possible to identify patterns, which allow the early detection of a number of problems, such as pipe washouts, circulation losses, as well as stuck pipe. The analysis of routine drilling operations, like pump start-up, allow the optimization of the drilling process to avoid hidden lost time. The interpretation of the related patterns allows optimizing pump start-up procedures and shows trends in changing wellbore behaviour over time. The concept is implemented by a hydraulics monitoring screen fed by the results of the automated analysis, which outlines the ideal operating window to enable the drilling personnel to act on the information generated. Copyright 2011, SPE/IADC Drilling Conference and Exhibition.


Potsch K.,OMV E and P | Toplack P.,OMV E and P | Gumpenberger T.,OMV E and P
75th European Association of Geoscientists and Engineers Conference and Exhibition 2013 Incorporating SPE EUROPEC 2013: Changing Frontiers | Year: 2013

The injection of CO2 underground has been investigated by many scientists, be it for sequestration or enhanced oil recovery. When CO2 enters the reservoir, the main questions, into which phase the CO2 concentrates first (oil or water) and in which amounts it is going into solution, will be answered. Both, numerical and experimental studies in the literature report two different diffusion parameters, differing by more than one order of magnitude. These findings are confirmed in our experiments. In the literature, rapid dissolution is attributed to the appearance of natural convection due to density differences of the CO2-enriched liquid, entrailing a faster mixing, sometimes being called super-diffusion. This paper reviews the physical effects appearing during CO2 injection and investigates the mathematical basis for the determination of solubility and diffusivity together with the assumptions made in this case. We come to the conclusion that a parabolic diffusion law cannot explain the two different diffusion constants, but a hyperbolic law can. In a detailed dimensional analysis of the Navier-Stokes equation dimensionless groups are formed, the magnitude of which determines the importance of the different terms, in our case the importance of convection. Using the parameters of our physical setup we find that the convection is only prevalent in a thin layer close to the interface of gas and liquid. This is in contrast to present belief. Stability considerations for the onset of convection complete the scope of this work. Copyright © (2012) by the European Association of Geoscientists & Engineers All rights reserved.


Chu W.-N.,OMV E and P | Steckhan J.,OMV E and P
Proceedings - SPE Annual Technical Conference and Exhibition | Year: 2011

Low-resistivity pay (LRP) has been a challenging problem in formation evaluation for many years. This is because conventional petrophysical interpretations are unable to identify pay intervals in low-resistivity reservoirs. This paper lays out a robust workflow for identifying LRP in thinly laminated sands with silty and/or shaly layers. The workflow is essentially a two-step process which integrates data from gas while drilling (GWD), conventional logs and nuclear magnetic resonance (NMR) logs which identify potential pay intervals for further examination using wireline formation tester (WFT). This approach allows one not only to identify pay intervals but also their phase and their flow characteristics without the need of a conventional drill-stem-test (DST). It is common for LRP to have high water saturation (60-70%) computed by conventional petrophysical interpretation while producing sustained water-free oil for few years. A petrophysical study was undertaken to integrate core data analyses including conventional, NMR and mercury injection capillary pressure (MICP). Data from over 100 sidewall cores (SWC) were examined. This novel approach for estimating irreducible water saturation (Swi) was developed based on 1. A good relationship was recognized between Swi from capillary pressure data as compared to that estimated from NMR de-saturated core. 2. A correlation was established between Swi of de-saturated core and T2, LM. 3. A validation was performed for zones producing water-free oil to link between NMR-MICP core analysis and NMR logs, using the following two methods for estimating S wi from a. capillary pressure data that is computed with knowledge of the height above free water level (FWL), b. T2, LM of NMR logs using the correlation developed in Step 2. The benefits of this methodology are that it improves decision in well completion, predicts well performance accurately and reduces uncertainty in reserve estimation. In addition, it allows the user not only to identify zones of pay that would have been missed using conventional analysis, but also to estimate FWL elevations with higher accuracy from a saturation height model (SHM). Saturation profiles derived by this approach and those ones modeled from saturation height equations based on MICP capillary pressure data can be fitted better due to substantial reduction in uncertainties of log derived saturation data. Consequently the initialization of in-place volumes for hydrocarbons will be enhanced. Copyright 2011, Society of Petroleum Engineers.


Hujer W.H.,OMV e and P | Finkbeiner T.,OMV e and P | Persaud M.,OMV e and P
EAGE Workshop on Geomechanics in the Oil and Gas Industry | Year: 2014

The results indicate that a strong correlation exists between Equotip Leeb hardness and UCS derived from scratch-test data for different lithologies. Tests on full cores also fit into the correlation. Larger variations in data range were encountered in coarse-grained sandstones, sandstones characterized by high amounts of clay minerals and fines as well as in lithologies that exhibit high rock strengths. Further in-house research is planned to find individual correlations or other testing devices for those lithologies. The results show that the Equotip can be used for estimating UCS from lithologies where representative plugging is not possible. The method is fast and equipment costs and logistics are low. Scratch tests derived UCS can be used for calibration. Estimating UCS from hardness testing cannot replace triaxial, hollow cylinder or scratch tests but can complement those tests, especially if data is needed urgently or other testing is not possible. Copyright © (2014) by the European Association of Geoscientists & Engineers All rights reserved.


Chu W.-C.,Pioneer Natural Resources Inc. | Steckhan J.,OMV e and P
SPE Reservoir Evaluation and Engineering | Year: 2016

A robust work flow is established to identify low-resistivity pay (LRP) in thinly laminated sands with silty and/or shaly layers. The work flow integrates data from gas-while-drilling, conventional logging, and nuclear-magnetic-resonance (NMR) logging for picking intervals for further examination with a wireline formation tester (WFT). A mini-drill-stem test (DST) is performed by means of a WFT equipped with either a single probe (SP) or a dual packer (DP) to determine the fluid type and productivity of each individual level. Two field examples are presented to compare well performance predicted by the microscale mini-DSTs with macroscale production tests. In both cases, the traditional DST is eliminated from the drilling/completion program. The final verification consists of comparing contributions of individual levels derived from the mini-DSTs with production logs. In the first case, mini-DSTs are able to provide the fluid type and individual-level transmissibility (kh/l) for eight out of 13 distinct levels. A cost-effective approach of running mini-DSTs by means of a WFT equipped with a single probe is demonstrated to investigate multiple levels in the thin-hydrocarbon reservoir sequence. Guidelines are provided as to when a WFT with a DP is to be deployed to perform a mini-DST in a laminated formation. In the second case, the same work flow was applied to derive the fluid type and transmissibility for two wells consisting of more than 30 distinct levels in the same field. After integrating mini-DST results from the two wells 750m apart, a framework is constructed to establish both vertical and lateral heterogeneities of thinly laminated reservoirs. The integration helps visualize the multiple-layer reservoir. Our examples confirm that mini-DSTs effectively define individual- layer producibilities in multiple-layered reservoirs. The benefits are illustrated through case histories that demonstrate our ability to manage expectations of well performance in thin hydrocarbon- reservoir sequences. © Copyright 2016 Society of Petroleum Engineers.


Ondracek W.,OMV E and P | Liebl W.,PETROM E and P
72nd European Association of Geoscientists and Engineers Conference and Exhibition 2010: A New Spring for Geoscience. Incorporating SPE EUROPEC 2010 | Year: 2010

It is technically and financially a challenging task to produce mature assets economically, and mature oilfield operators like OMV have to stretch themselves to the limits to succeed: an average performance in delivering production rates, recoveries and CAPEX / OPEX spending will not be good enough - we have to arrive at 'Production Excellence'. In the past mature field operations have been built upon strong functional structures. Our approach and success was based on a hierarchical organisation and experienced people to run the field operations. As OMV E&P started to introduce business processes in the late 90ies, our processes supported the old system: thinking remained functional. Today, however, we look for 'Production Excellence', which does not only mean first class performance in operations but also effective control of cost and production, continuous identification and realization of opportunities to increase the value of our assets and finally the improvement of the Key Performance Indicators (KPIs) of our activities. To achieve this, we developed a new Produce Process Management System which stretches across organisational boundaries and assures that everyone in the organisation sees the full picture. We closely cooperated with operational key personnel to define a new process, which provides the link to organisation, supports collaboration and integration of disciplines visualizes and controls information flow, and measures time and cost of process activities. © 2010, European Association of Geoscientists and Engineers.


Chu W.-C.,Pioneer Natural Resources Inc. | Steckhan J.,OMV E and P
Proceedings - SPE Annual Technical Conference and Exhibition | Year: 2014

A robust workflow is established to identify low-resistivity pay in thinly laminated sands with silty and/or shaly layers. The workflow integrates data from gas-while-drilling, conventional logging and nuclear magnetic resonance (NMR) logging for picking intervals for further examination using a wireline formation tester (WFT). A mini-DST is performed by means of a WFT equipped with either a single probe or a dual packer to determine the fluid type and productivity of each individual level. Two field examples are presented to compare well performance predicted by the micro-scale mini- DSTs with macro-scale production tests. In both cases, the traditional DST is eliminated from the drilling/completion program. The final verification consists of comparing individual level contributions derived from the mini-DSTs with production logs. In the first case, mini-DSTs are able to provide the fluid type and individual level transmissibility (kh//x) for 8 out of 13 distinct levels. A cost-effective approach of running mini-DSTs by means of a WFT equipped with a single probe is demonstrated to investigate multiple levels in the thin hydrocarbon reservoir sequence. Guidelines are provided when a WFT with a dual packer is deployed to perform a mini-DST in the laminated formation. In the second case, the same workflow was applied to derive the fluid type and transmissibility for two wells consisting of more than 30 distinct levels in the same field. After integrating mini-DST results from the two wells located 750 m apart, a framework is constructed to establish both vertical and lateral heterogeneities of thinly laminated reservoirs. The integration helps visualize a multiple-layered reservoir. Our examples confirm mini-DSTs effectively define individual layer producibilities in multiple-layered reservoirs. The benefits are illustrated through case histories that demonstrate our ability to manage expectations of well performance in thin hydrocarbon reservoir sequences. Copyright © 2014, Society of Petroleum Engineers.

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