This paper presents the first application of a Dual Electrical Submersible Pump (ESP) system in an onshore well in OMV. It describes the whole process starting with the selection of the technology and candidate wells to the installation of the equipment and the start-up phase. Challenges in the operations as well as the methods for production allocation are addressed. Commingled production was seen as a key approach for production acceleration in the development of a field with multiple-stacked reservoirs. To proof this idea, a number of candidate wells and technologies were screened and the concept of "Dual ESP" was finally selected for a pilot in the well Erdpress 6. The design process required simulations and preparative selective production tests. Production allocation was crucial to evaluate the performance of the pilot; therefore several techniques were used, like fingerprinting based on chromatography and chloride content. The Dual ESP system was a completely new approach in producing multiple targets in one well. The selective production tests proved to be essential for an optimum design of the ESPs. Two different methods were used to allocate the production rates to the respective intervals. The most significant finding was that results of the nodal analysis could be verified by chemical fingerprints. This also proved that the investment in downhole sensors was valuable. Interferences between the two pumps could be determined with the information of the sensors resulting in adjustments in the ESP settings. The conclusions from that pilot are that the application of the Dual ESP system is fulfilling the expectations from a technical point of view and that the information gathered prior to the design was crucial. However it is obvious that the application of this expensive technology has to be evaluated and justified in every technical and economical aspect. In the case of this pilot, an unexpected steep water cut rise impaired the forecasted profitability. The use of the Dual ESP system was an exceptional approach to tackle the concept of commingled production. This paper covers the whole process from design to operation and shares the experiences and lessons learned to support future applications.
OMV-AUT is running the Schönkirchen-Reyersdorf and the Tallesbrunn gas storage facilities with capacities of 1.77 respectively 0.3 billion m3 in the Vienna basin. These facilities at depths between 1000 and 1300 meters are former sandstone gas reservoirs operated with traditional external gravel packed (GP) vertical wells. Increasing gas demand and the urge to increase efficiency prompted an effort to adapt the whole system to a state of the art operation by making full use of available technology. This included:Application of a novel low damage drill-in fluid systemRecompleting former inside as outside casing gravel packsDrilling high performance horizontal wellsCompleting these horizontals with an expandable sand screen (ESS) respectively with a horizontal open hole gravel pack (HOHGP) During the project, new field quality control procedures were established and laboratory tests run to demonstrate the potential of the mud system. The mud system used had been designed for oil wells, but never before proved for gas storage. Despite many simultaneous changes in parameters, well tests confirm the assumption of substantial gains due to meticulous QC, intense cooperation and modern technology. Introduction Basically the goal was to achieve a higher performance with less wells and concurrent reduction of the injection and withdrawal times. In the beginning existing wells were converted from inside casing GP (ICGP) to open-hole GP (OHGP) in order to gain experience with the new drilling/ workover fluid before establishing horizontal wells with big bore state of the art completions and subsequently a significant reduction of the number of wells by replacing existing wells by new horizontal wells drilled from cluster locations. All this was done using a novel drilling mud system developed for the use in oil bearing formations but never used for gas storage applications before. Exploratory Meetings In advance of the jobs multiple meetings within the company as well as with specialists from service companies were held in order to get an overview of new technologies available. The outcome was that the mud system for recompleting, workover as well as for drilling purposes had to be evaluated in detail. After intensive discussions with the mud system provider a novel drilling fluid (Tab.1 & Tab.2) was chosen, assuming that it complies with most of the requirements. During the planning phase of the completion design of the two horizontals with ESS respectively with OHGP, controversy arose about the suitability of the mud system especially regarding the well cleaning after the installation of the completion. The first production phase for both completion designs is critical, especially in case of the ESS completion. Expandable Sand Screens in general have a low permissible pressure differential. In case of an outside plugging of the screen they could collapse. The maximum allowed ?p is 20 bar in case of 5 ½" Screens in a ~8 ½" openhole. It is contended that the combination of classic fluid loss control material like carbonate and starch with their hydrophobic derivates act as selective barriers for water into the formation, while providing very low adhesion forces for the filter cake when flow is reversed during production. The vendor had examples showing that oil was easily able to penetrate the oleophilic channels in the cake, thereby lifting the cake off. However, it was not clear whether this would also hold for dry gas coming out of a storage well and whether the gravel and screen might not restrict the clean up process.
Schizophrenia (SZ) is a serious psychiatric disorder, causing substantial socioeconomic burden. Since an SZ patients' brain may have structural changes including reduced hippocampal and thalamic volume [1], brain MRI is becoming a popular imaging method studying SZ. In addition, as a genetic disorder, genetic information such as single nucleotide polymorphisms (SNP) plays an important role in distinguishing SZ. However, the structural and genetic changes in SZ patients are too subtle to be identified by human vision, so it is necessary to develop an automated method to find the nonlinear patterns associated with disease progression. Toward this, we propose a novel multi-modal deep learning approach where we combine both features from structural MRI (sMRI) and single-nucleotide polymorphisms (SNPs) for SZ classification. For sMRI, we extract convolutional features from a pre-trained deep neural network to capture morphological characteristics. For SNPs, we apply a layer-wise relevance propagation (LRP) method on a pre-trained 1-D convolutional network to identify SZ-linked SNPs. We then feed the combined features to a tree-based classifier for SZ diagnosis. Experimental results on clinical dataset showed classification accuracy was increased by 5.3% compared to the state of the art DenseNet using only sMRI data.
The Pirawarth Field, located in Austria, has been considered for polymer flooding. The reasons were the good permeabilities, medium viscosity of the oil (50 cP), low reservoir temperature (30 °C) and injection of low salinity water, resulting in low polymer concentration requirements. Production from this field started in 1964. Until 2008, the recovery factor of the field reached 26 %. The reason for the low recovery factor is the unfavourable mobility ratio between the viscous oil and water. In addition to conventional history matching, produced water chloride concentration data was implemented as matching parameter. The chloride concentration match revealed that the geological structure of the field was not well represented, although the water cut increase could be matched. This lead to delayed simulated breakthrough of the low salinity injected water. Improving the geological model enabled an improved match of the injected water breakthrough. Laboratory experiments confirmed high efficiency of polymers in increasing water viscosity for the Pirawarth conditions. A core flood experiment was conducted and showed that adsorption is limited, the water relative permeability will be reduced by polymer injection and that the displacement with polymer after water flooding results in incremental recovery of more than 20 % of oil in place. The core flood experiment was simulated and the parameters derived from the core flood experiment were used in the dynamic model of the field. The results of the simulation are very promising, indicating an increase in oil recovery in the pilot area of 5 %. It is planned to perform the pilot in 2010. Introduction The Pirawarth Field is located about 20 km northeast of Vienna in the Vienna Basin. First oil was produced in 1964. In 1977, water flooding was implemented. The recovery factor today reached 26 %. The Ultimate Recovery factor at abandonment of the field is expected to be 32 % applying the current production strategy. In 2007, an integrated study was performed to identify opportunities to improve oil recovery from this field. Screening parameters for various enhanced oil recovery methods concluded that polymer injection is the most promising method to increase oil recovery after waterflooding at reasonable costs. Geological setting/reservoir parameter The dominant structural features in the Pirawarth area are the NE trending left lateral Steinberg and Vorstaffel Fault systems that controlled, as synsedimentary faults, the sediment input from the Upper Badenian on. The fault system is part of a large left lateral fault zone that forms the western termination of the Vienna Basin.
The 16. Tortonian Horizon is one of the largest producing oil reservoirs in continental Europe. The field has been on production since 1949 and has already gone through a long decline period. The average water cut currently exceeds 96%. The western region of this reservoir, called Bockfliess area, was the focus of the latest field re-development effort, aiming to increase oil production by doubling the liquid rate. Although the project comprised various activities – including facility upgrades and the construction of additional surface infrastructure –, this paper focuses mainly on subsurface measures. The majority of modifications were conducted on existing production wells. Quick wins included additional perforations and sucker rod pump (SRP) unit changes. The artificial lift systems of more than one third of the producers were converted to electrical submersible pumps (ESPs). Three new high-rate horizontal producers were also drilled. To maintain reservoir pressure, nearly all the produced water had to be re-injected. Several of the existing producers were converted to injectors and two new horizontal injector wells were drilled. The overall goal of doubling the gross production rate was accomplished by an integrated multidisciplinary team in a short time period. 13 additional perforations, four SRP unit exchanges and 32 conversions of producers to ESPs proved to be successful in increasing oil production. In order to target the remaining attic oil, three high rate horizontal infill producers were effectively placed within specific zones of the reservoir by applying state of the art geosteering technology. The planned voidage replacement ratio was achieved by converting nine producers to injectors and two successfully placed horizontal high rate injector wells. These measures increased oil production by 62% (43% was gained from existing wells and 19% from new wells). The concept of doubling the gross rate on a reservoir scale was unprecedented in Austria, especially for a reservoir that was already producing at maximum surface capacity. For single wells, gross rates were increased up to seven-fold as compared to the rates produced before the project. To control such high volumes with an optimized operation, real-time monitoring of the sensor-equipped ESPs was implemented. Horizontal infill drilling had not been implemented before in the targeted reservoir area due to the close well spacing. Real time geosteering methods using advanced logging while drilling (LWD) technology proved to be beneficial in this onshore mature brown field. Different sand control and bottom hole flowing pressure control methods were applied in each of the new horizontal producers, including autonomous inflow control devices (AICD) which are currently mainly utilized in offshore environments.
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