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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. Source


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. Source


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. Source


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. Source


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. Source

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