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74th EAGE Conference and Exhibition incorporating EUROPEC 2012
- Conference date: 04 Jun 2012 - 07 Jun 2012
- Location: Copenhagen, Denmark
- ISBN: 978-90-73834-27-9
- Published: 04 June 2012
41 - 60 of 948 results
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Considerations on of Drillpipe Dynamics with Actual Drilling Data (SPE 154481)
More LessThe scientific drilling vessel CHIKYU was designed to have the capability to drill down to 10000m total vertical depth and to obtain core samples. To reach such deep drilling and to recover core samples, it is important to know drill pipe dynamics using the actual drilling data. The core recovery rate is affected by the variation of the weight on bit caused by the propagation of the vessel heave motions. Therefore, a heave-compensating system will be used and it is very important to evaluate the performance. Furthermore, the drill bit behavior will also influence on the core recovery. In the extreme case, stick-slip, which will cause cracks or fractures in the core samples, occurs. In addition, to reach such deep drilling, a fine strength evaluation is mandatory because there is little margin. So, the estimation of dynamic tension due to vessel heave motions is necessary. Thus, the authors have acquired the drilling data including the vessel motions, the hook load variations and drilling torque variations. It is observed that the heave compensating system have the capability to mitigate the propagation of the vessel heave to the drill string within 30% if the condition is good. On the other hand, it was also observed that the heave compensator operated at a low level of mitigation if the condition is bad. Also we conduct the drill pipe dynamics analysis such as the vertical dynamic motions and the drill bit rotation, and make considerations on the hook load variations and the drill bit behaviors. Actual drilling data provided the worthy information on the drill pipe dynamics. The considerations will be utilized for future operations such as Tohoku Earthquake Drilling Program and NANKAI Trough drilling programs and also for future technical development.
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In-depth Evaluation of Deep-rock Hydrajet Results Shows Unique Jetted Rock Surface Characteristics (SPE 153333)
Authors H. Stockhausen, D.G.G. Sanchez, R.A. Loghry and J. Basuki SurjaatmadjaThe use of hydrajetting for perforating of wells has been commonplace since the sixties. During those early years, wells were relatively shallow; and jetting success was consistently demonstrated. However, as wells became deeper, and rock formations tend to be harder at those depths, performance of hydrajetting was less dependable; as subsequent stimulation failures more often occur from the lack of fracture initiation. In order to remedy this situation, a series of tests were performed to define new best practices for hydrajet perforating of rock under high ambient pressure. Various rocks were subjected to these tests; which were done using different jetting pressures and different abrasives. The perforation surfaces were then dissected, and then evaluated using photographic and chemical means. Further assessments are then made to determine as to what actually happened during the hydrajetting process. This paper discusses various tests results; and new constraints for jetting are defined and presented.
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Risk Evaluation Technique for Tubing-conveyed Perforating (SPE 152419)
Authors C. Baumann, K.E. Barnard, J.R. Cromb, D.R. McDaniel, R. Suffridge and H.A.R. WilliamsHigh-pressure wells are susceptible to gunshock damage when they are perforated with inappropriate gun systems. This paper presents a simulation tool that predicts Tubing Conveyed Perforating gunshock loads reliably. This tool enables completion engineers to evaluate the sensitivity of gunshock loads to changes in gun type, charge type, shot density, tubing size and length, use of shock absorbers, rathole length, and placement of packers, among others. When planning perforating jobs in high-pressure wells, engineers strive to minimize the risk of equipment damage due to gunshock loads. The software described here helps engineers to identify perforating jobs that have a risk of gunshock related damaged, such as bent tubing and unset packers. When predicted gunshock loads are large, changes to the perforating equipment or job execution parameters are sought to reduce gunshock loads and the associated damage risk. We compare software predictions with high-speed pressure gauge data for each perforation job. Gauge pressure data shows that predicted wellbore pressure transients are accurate both in magnitude and time. Peak sustained pressure amplitudes at the gauges are on average within 10% of software simulated values, both for gun underbalanced and gun overbalanced conditions. For cases where shock absorbers were used, residual deformations of crushable elements correlate well with the peak axial loads predicted by the software. The software is able to simulate perforating job designs in a short time, which allows engineers to optimize perforation jobs by reducing gunshock loads and equipment costs. The ability to predict and reduce gunshock induced damage in perforating operations is very important because of the high cost associated with high-pressure deepwater operations. With the software tool described in this paper engineers can optimize high-pressure well perforation designs by minimizing the risk of gunshock related damage and the associated rig time losses.
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An Engineering Approach to Utilize Fiber Optics Telemetry Enabled Coiled Tubing (ACTive Technology) in Well Testing and Sand Stone Matrix Stimulation - First Time in the World (SPE 154513)
Authors T. Shaheen, S. Abd El Rahman, E. Anwar and V. NoyaThis paper explains the first ever application of using Fiber Optics Telemetry Enabled Coiled Tubing (ACTive Technology) in well testing and the capability of calculating the skin value, live, during Matrix Stimulation. It also explains the efficiency in determining the faults in the reservoir and the time saving in making Build Up test for low pressure reservoirs which are not naturally flowing. For the last years viscous pills and some polymers were used to kill the wells during the workover operation in the tronian formation existing in the eastern desert of Egypt. The polymer being pumped has negatively affected the wells productivity by blocking the pore throats and reducing the permeability. As an example, the well (A) was producing 500 bopd which declined dramatically after a work over operation to produce only 40 bopd. An Engineering Study was done to identify the main reason for the decline in the production. Several experiments were done in the lab in order to simulate the filter cake using formation sample and simulate the effect of the polymer being injected on the permeability. An engineered solution was designed to break the polymer being pumped in the formation and stimulate the Matrix in order to recover and enhance the oil production. Operation was done utilizing Fiber Optics Telemetry Enabled Coiled Tubing (ACTive Technology) in order to achieve the following: 1) Measure and record bottom hole pressure. 2) Measure and record bottom hole temp. 3) CCL depth correlation to achieve max accuracy while placing the fluid. 4) Monitor the change in temp during treatment execution. 5) Monitor how the diversion effect and the reactions in the sand stone formation during stimulations and the timing required for efficient reactions. All the data gathered were very representative and became a reference for the field.
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Simulation of Drilling Fluid Filtrate Invasion Near an Observation Well (SPE 154014)
Authors R. Chassagne and P.S. HammondDescription: We use a commercial reservoir simulator to study first the dissipation of aqueous drilling fluid filtrate invasion around a cased observation well in an oil-saturated formation under the action of capillary pressure, and then the interaction of a waterflood front with the cased well and remaining invaded zone. Hysteretic behaviour of the capillary pressure and relative permeabilities is critically important to these processes and is taken into account using the Killough model, with the various bounding drainage and imbibition curves computed from a pore network model. Application: Filtrate invasion into a hydrocarbon formation influences the readings of well logging tools. Although this phenomenon has been known, and corrected for, for many years, uncertainty remains with regard to the long-time behaviour of invasion around observation wells where no flow in or out of the formation occurs after completion and to the influence of formation wettability. Results: After sufficient time the invaded zone dissipates completely in a water-wet formation, but some invasion always remains in the oil-wet case. Non-wetting-phase trapping, manifested through relative permeability hysteresis, is the cause. Because trapping affects the values and the end points of the relative permeability curves, a waterflood front passing across an observation well is more distorted in the oil-wet case. Significance: The simulation results allow us to understand how logging tool measurements made in cased observation wells are influenced by drilling fluid invasion and will therefore lead to improved interpretation. This study shows strong links between the wettability of the formation and persistence of invaded zone saturation, and between invaded zone saturation and the distortion of subsequent flood fronts.
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Geology and Geohistory Contribute to Flow Assurance (SPE 154585)
Authors H. Yonebayashi, D.R. O‘Brien and S. TosicKashagan is a super giant offshore carbonate field which was discovered in 2000 by a consortium of oil companies (currently, affiliates of): ExxonMobil, ENI, Shell, TOTAL, Conoco-Phillips, INPEX and KazMunaiGaz. The field is a deep, large structural relief, over pressured, isolated, carbonate build-up with a high-permeability, karstified and fractured rim and relatively low-permeability platform interior. The field contains a sour, undersaturated light oil with a large gas content. High pressure miscible gas injection is planned for oil recovery enhancement, as well as sulfur management. No-one doubts the importance of flow assurance in offshore projects. The consortium has undertaken extensive evaluations to ascertain the likelihood of any flow assurance risks from subsurface to surface. During the asphaltene risk evaluation, many bottomhole samples have been collected and analyzed for asphaltene content, asphaltene onset pressure (AOP), and SARA (saturates, aromatics, resins and asphaltenes). These analysis efforts sometimes revealed anomalous results such as AOP being detected from some fluid samples while not being detected from others. The apparently inconsistent AOP results are critical to understand to guide flow assurance measures. Therefore, all available asphaltene data were re-assessed in all their aspects to attempt to clarify asphaltene risk. This paper presents a multidisciplinary approach where a synergy between reservoir engineering and geoscience has been developed to explain AOP results for this difficult fluid. The results should help flow assurance specialists to better define the asphaltene operating envelope, which will be used for reservoir and production operations optimization. In addition, these results should be useful for optimizing data-surveillance and for defining new sample acquisition plans. The paper will show examples of the related flow assurance analyses, and the geological information which were incorporated in the study, resulting in a detailed asphaltene matrix risk profile for this reservoir.
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Optimization of Proactive Control Valves of Producer and Injector Smart Wells under Economic Uncertainty (SPE 154511)
Authors M.A. Pinto, C.E. Barreto and D.J. SchiozerSmart wells can improve oil recovery, mitigate risks and avoid unnecessary well intervention in petroleum fields. However, there is no consolidated methodology to evaluate the applicability of smart wells and to represent smart wells in commercial simulators, which complicates the comparison with conventional well. Moreover, there are two main modes of operation of smart well valves, reactive and proactive; each one can provide different benefits. In general, proactive control seeks maximum oil recovery, but it requires larger computational effort and greater knowledge of the reservoir than the reactive control. This paper presents a comparison between different configurations of smart wells with proactive control and mode operation on/off: (1) five-spot configuration with conventional wells (producer and injectors), (2) one smart producer and four conventional injectors, (3) one conventional producer and four smart injectors and (4) one smart producer and four smart injectors, in order to compare the different behaviors. The objective of this study is evaluate the potential of each type of configuration and the benefits of the smart injectors and producer acting separately or together, considering the effects on production and costs of smart completion. For this, a genetic algorithm was coupled to a commercial simulator to optimize the proactive control and to search the maximum net present value (NPV), determining the optimum operation control for each valve. The case study consists in one heterogeneous reservoir model, light oil and three economic scenarios (pessimistic, probable and optimistic). Results show that the use of smart injector wells, in this case study, can improve control over water production, although it may not be sufficient to justify the investment on a more expensive completion. On the other hand, the configuration using a smart producer well is capable of increasing oil recovery, therefore making the investment in a smart completion feasible.
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New State of the Art Asset-optimization Data Applications for Intelligent Completions in Digital Oilfields (SPE 153702)
More LessInformation provided using intelligent completions in digital oil fields is increasing in importance, because it has the capability to minimize the needs for custom data-gathering solutions as well as simplify industry data interfacing standards for multiple devices and systems. For assets using intelligent completions, solutions offered are attained by a combination of subsurface and surface or subsea sensors provided by several vendors. Challenges arise when attempting to manage the interfaces required for providing real time data from all points of interest; i.e., subsurface choke positions, flow, pressures and temperatures, wellhead positions, subsea facility readings etc. This paper describes the design and implementation of an integrated data-applications system that can integrate data from multiple workflow sources for the purpose of maximizing field performance. The asset optimization applications acquire operating parameters from all points of interest and make them available to software modules designed to estimate key well-performance indicators. The asset-optimization application discussed here is an integrated system that performs the following five services. A data-interfacing methodology acquires data from multiple sources or directly from downhole devices. The integration service converts the subsurface and surface data to engineering units of measured well parameters. The well performance service uses well PVT and device-integration service values to execute complex calculations like virtual flow metering, water-cut estimates, etc. The human/machine/interface service provides visualization, trending and querying. The connectivity service facilitates structured data transfer to field historians. The paper will explain how the system works and its implementation into fields of different scales and types to reduce information technology (IT) customization, simplify interfacing of multiple devices or systems, and accommodate evolutions in IT. Additional system benefits that included more efficient management of real-time data security, quality, redundancy, and mirroring will also be provided.
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A New Approach to Fracturing and Completion Operations in the Eagle Ford Shale (SPE 152874)
More LessDescription: This paper describes a new approach to fracturing and completing shale wells - getting them on production more quickly. Many operators in south Texas use a traditional approach to completions and pipeline hookup. A new process has been introduced which integrates LWD, wireline, coiled tubing, fracturing, micro-seismic, and flow back/testing to bring wells online more safely, efficiently, and repeatably. Application: Wells in the Eagle Ford shale require large high pressure hydraulic fracturing fleets and multiple service providers. Traditionally this entails fifteen - twenty service companies to coordinate the stage fracturing process. 4500 foot laterals in the Eagle Ford shale required ten days to stimulate 14-20 stages using plug and perforating techniques. The new approach described in the paper reduces this time and improves KPIC"s. Results and Observations: The paper documents three south Texas case studies. Eagle Ford well completions are complex. When fifteen or more service companies are contracted this complexity results in inefficiency and safety incidents. The new integrated approach improves process flow, planning, safety and efficiency and has gained favor with south Texas operators. Planning and communicating are key to reducing non-productive time during 24 hour per day operations. New logistics software is described. Other improvements include hybrid and cross-linked fracturing fluids, open-hole completion assemblies, micro-seismic, chemical tracers and geo-chemical use along with azimuthal LWD measurements to ensure laterals remain in-zone. Significance of Subject Matter: This paper documents the efficiencies being experienced by Eagle Ford operators using a holistic approach to completing and fracturing shale wells. Experienced on-site service coordinators are key to effectively bringing wells on line quicker and more safely with fewer lost time problems. Because of the success described in the paper the new approach will become common in shale plays outside of North America.
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Depth of Investigation and Depletion Behavior in Unconventional Reservoirs Using Fast Marching Methods (SPE 154532)
Authors A. Datta-gupta, M.J. King and J. XieThe concept of depth of investigation is fundamental to well test analysis. Much of current well test analysis relies on solutions based on homogeneous or layered reservoirs. Well test analysis in spatially heterogeneous reservoirs is complicated by the fact that GreenC"s function for heterogeneous reservoirs is difficult to obtain analytically. In this paper, we introduce a novel approach for computing the depth of investigation and pressure response in spatially heterogeneous and fractured reservoirs based on a semi-analytic construction of the GreenC"s function. In our approach, we first present an asymptotic solution of the diffusion equation in heterogeneous reservoirs. Considering terms of highest frequencies in the solution, we obtain two equations: the Eikonal equation that governs the propagation of a pressure C"frontC" and the transport equation that describes the pressure amplitude as a function of space and time. The Eikonal equation generalizes the depth of investigation for heterogeneous reservoirs and provides a convenient mechanism to construct the GreenC"s function. A major advantage of our approach is that the Eikonal equation can be solved very efficiently using a class of front tracking method called the Fast Marching Method. Thus, transient pressure response can be obtained in multimillion cell geologic models in seconds without resorting to reservoir simulators. We validate our approach by comparison with analytic solutions for homogeneous and composite reservoirs. We apply the technique using a high resolution full field geologic model of a tight gas reservoir from the Rocky Mountain region to predict the depth of investigation and pressure depletion. The computation is orders of magnitude faster than conventional simulation and provides a foundation for future work in reservoir characterization and field development optimization.
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Analysis of Surface and Downhole Microseismic Monitoring Coupled with Hydraulic Fracture Modeling in the Woodford Shale (SPE 154804)
Authors C. Neuhaus and J.L. MiskiminsThe work presented in this paper analyzes surface and downhole microseismic data for a horizontal well in the Woodford Shale in Oklahoma, comparing those results with calibrated hydraulic fracture modeling. Hydraulic fracture models were created for each of five stages with a three-dimensional modeling software, incorporating available petrophysical data in order to match the recorded treatment pressure and the fracture geometry obtained from the microseismic data. Further analysis investigated the congruency of the downhole and the surface microseismic data, what difference they produced in a match if used exclusively, the influence of the number of events on the fracture geometry obtained from the microseismic data, the error of event location, the degree of complexity of the created fracture network, and the relationship between the magnitude of events and the time and location of their occurrence. The fracture models produced good matches for both pressure and fracture geometry but showed problems matching the fracture height due to cross-stage fracturing into parts of the reservoir that were already stimulated in a previous stage. Surface and downhole microseismic data overlapped in certain regions and picked up on different things in others, giving a more complete picture of microseismic activity and fracture growth if used together. However, they deviated in terms of vertical event location with surface data showing more upward growth and downhole data showing more downward growth. In general, the downhole microseismic data showed that the stimulation treatment was successful in creating a fairly complex hydraulic fracture network for all stages, with microseismic recordings making flow paths visible governed by both paleo and present day stress. Plots showing the speed of event generation, the cumulative seismic moment, and the event magnitude versus the event-to-receiver-distance identified interaction with pre-existing fault structures during Stages III and V.
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Application of New Techniques for Characterization of an Eocene Carbonate Reservoir in the Gulf of Suez, Egypt (SPE 154461)
Authors M. Van Steene, E. Abdul Elaziz Bassim, S. Ghadiry, E. Haddad, S. Shaaban and V. VallegaA variety of recently developed techniques are available to improve carbonate rock characterization. This paper reviews the application of these techniques on an Eocene carbonate reservoir from the Gulf of Suez. Dolomite content was computed from spectroscopy data for direct extraction of the magnesium yield. This allowed computation of the dolomite volume while the photoelectric factor could not be used. Small amounts of dolomite were computed overall, with minimum impact of the dolomitization process over the porosity and permeability. Since rock texture has a strong impact on porosity and permeability in carbonates, it is necessary to include texture-sensitive tools in the evaluation. Based on NMR data, porosity partitioning analysis showed that the porosity is dominated by micro and meso pore sizes. While the default correlations used for NMR in carbonates considerably overestimate permeability, a modified SDR equation was applied to predict permeability more accurately, providing a good match to core data. Hydrocarbon properties have been found to vary vertically. NMR fluid identification stations were used to characterize the variation. Tar was identified based on the comparison of total porosity and NMR porosity. This is an important parameter as tar can affect the reservoir producibility. Fracture analysis was performed on a data set of micro-resistivity image and Stoneley data. The analysis performed on the Oil Based Mud micro-Imager identified the orientation of the fracture system and the sonic Stoneley wave processing determined that the majority of the fractures encountered in the reservoir were healed. This conclusion was supported by the core analysis results. The work presented in this paper demonstrates how it is necessary to integrate the measurements from various tools and sources to gain a good understanding of reservoir producibility in carbonates. The integrated evaluation was validated with core and well test results.
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Improving Well Cementing Quality with an Environmentally Preferred Multifunctional Polymer (SPE 154498)
Authors A. Brandl, W.S. Bray and C. MagelkyIn designing an optimum cementing system for zonal isolation of wellbores, an engineer generally has to combine several different cement additives to adjust the required and complex slurry properties, such as rheology, thickening time, stability, free fluid-, fluid loss-, and gas control. To minimize environmental impacts and incompatibility issues among various chemical admixtures as well as to simplify logistics and operations, it would be ideal to reduce the loadings and number of different additives required to optimize a cement slurry design. One way to accomplish this is to use multifunctional additives that can improve several slurry properties at the same time without significant detrimental effects on other required properties. Towards this end, a modified cellulose-based polymer has been tested according to API recommended practices in various cement slurries and was identified to have multiple benefits in addition to be environmentally friendly: The test results demonstrate that this single additive controls fluid loss better than commonly used fluid loss additives at temperatures up to 80(degree)C while also controlling free fluid and performing as an extender. In addition, it was found to work as a foam stabilizer and gas control agent in cement slurries, which was not observed for any other cellulose-based polymers. Furthermore, the new polymers retarding effect on thickening time is lower than for other cellulose-based polymers. Some forms of this modified cellulose-based polymer also exhibit delayed hydration, which facilitates surface mixing and pumping of the corresponding cement slurries. This paper will describe test procedures and demonstrate that a single modified cellulose-based polymer can replace several additives in a cement system to adjust the required cement slurry performances for optimum placement and properties in the wellbore. The presented multifunctional biopolymer simplifies cement slurry design and operations contributing to higher quality cement jobs.
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Reducing Surfacel Tension to Improve Clean Up Efficiency of Hydraulically Fractured Wells - Does it Really Work? (SPE 154894)
Authors P. Ghahri, M. Jamiolahmady and M.S. RamliThe main purpose of applying surfactants for hydraulically fractured wells is to reduce interfacial tension (IFT) during the leak off process. Much of the research up to now has been concentrated in developing different types of such chemicals. However, in a recent numerical study (SPE-14414), we have shown that for many practical ranges of fracture permeability reducing IFT tends to decrease the cleanup efficiency process. Following our previous study, we have conducted a comprehensive sensitivity study to identify the effect of IFT over a wide range of variation of pertinent parameters, which controls the cleanup efficiency process. We have looked at the impact of matrix permeability (km), fracture permeability (kf) and fracture fluid injection volume. Over 200 runs were performed to evaluate the impact of these pertinent parameters for a single fractured well model. The results indicate that at the early stage of production the cleanup efficiency is almost independent of IFT, km and kf and relatively poor. At late stages of production and when kf is low, reducing IFT decreases the efficiency of cleanup. For high kf values, on the other hand, cleanup efficiency improves with such a reduction. For the cases with km values more than 0.001, the cleanup is more effective if IFT increases. Furthermore as km decreases the damage due to fracture fluid blockage becomes more sever. It is interesting to note that when km is less than 0.0001, cleanup efficiency always decreases with IFT for all different kf values indicating the severity of fracture fluid damage for very tight gas reservoirs. Increasing the fracture fluid injection volume did not significantly change the above trend. The results presented here help the industry in properly evaluating the added value of using surfactant for the hydraulically fractured wells during cleanup process.
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Oilfield Scale Management in the Siri Asset - Paradigm Shift Due to the Use of Mixed PWRI / Seawater Injection (SPE 154534)
Authors E. Mackay, W.R. Ginty and T.J. JonesThere 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 C"top upC" 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 fields offshore Denmark. The available data included analysis of formation and produced water and seawater compositions, and the time evolution of the produced water C"" 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 C"" 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.
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Application of Integrated Production and Asset Modeling for Sour Field Development Planning (SPE 154073)
Authors A. Alkindi and S.J. LinthorstA challenging issue in the EP industry is Integrated Asset Management, which encompasses efforts from various disciplines to build a single integrated model that describes the whole system. This paper presents an integrated production model (IPM), forecasting workflow and decision making philosophy to develop two complex sour fields comprising three reservoirs in South of Oman. The study involves two sour oil reservoirs of different PVT properties, H2S concentrations and drive mechanisms and one sour gas condensate reservoir used to complement associated gas to give a constant gas rate for export. Water injection and water handling are parts of the model. The modeling couples subsurface dynamic 3D models (built using Shell's MoReS reservoir simulator), well models and surface network (built in GAP) and the interactions occuring in the production system. The configuration involves three reservoirs, 19 oil and 3 gas producers, 12 water injectors, one production station, two separators (low and high pressure) and several flow lines of different sizes. The main objective of the study is to optimize the developments of these reservoirs by assessing the best design of surface network (plant capacity). The integration allows to assess the impact of various station capacities; either liquid or/and gas, on the project profitability under different operational scenarios such as injection rate, off-take, artificial lift and well phasing and their impact on CAPEX and OPEX. The model also helps in identifying system bottle-necks, back pressure effects, mixing of fluids and flow assurance. The use of jet pumps as artificial lift mechanism was successfully imbedded and optimized. The paper describes the structure of modeling, surface components, optimization strategy, benefits and challenges of IPM deployment to choose the optimum field design. The results demonstrate the importance and merit of field management in addition to accuracy and rapidness of production forecast.
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Determination of the In-situ Polymer Viscosity from Fall-off Tests (SPE 154832)
Authors T. Clemens, A. Gringarten, A. Laoroongroj and M. ZechnerLaboratory 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 owing to the degradation of the polymers during the injection process. In addition, polymers exhibit Non-Newtonian behaviour resulting in different viscosities of the polymer solutions dependent on the shear rate in the reservoir. For the Austrian reservoir, water injection fall-off tests have been performed. With these tests, a simulation model was calibrated. The calibrated model was used to simulate injection of polymer solutions for some time followed by fall-off tests. The results show that conducting a base-line fall-off test prior to polymer injection and a set of fall-off tests during polymer injection can be used to determine the in-situ viscosity of polymer solutions and the distance of the polymer front from the injection well. Even for Non-Newtonian shear-thinning behaviour, the results show that the average polymer solution viscosity prior to shut-in of the well and location of the front can be determined with reasonable accuracy. Due to the costs of polymers, knowing the in-situ viscosity of polymer solutions is of paramount importance. The injection process can be modified (e.g. changing pumps, modifying perforations) if the degradation of the polymer viscosity is significant. Also, knowing the in-situ viscosity rather than estimating can be applied to tailor the polymer concentration to achieve stability of the displacement process and improve the displacement efficiency.
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Developing a Toolbox for Evaluating of Water Injection Performance on the Norne Field (SPE 154046)
Authors S. Atabay, O.M. Dronen, A.R. Fawke and J.M.F. HvidstenThe Norne Field is a mature oil field located on the Norwegian continental shelf in 380 meters water depth and it has been on production since November 1997. The reservoir drainage strategy in the oil zone has been WAG injection, followed by only water injection from 2007, and the pressure support is successfully achieved; however, the major challenge in this field is to optimize the vertical and areal sweep efficiency. Different methods and techniques have been applied to understand the current water injection strategy in order to optimize the macroscopic (vertical and areal) sweep efficiency: 1) Reviewing the historical well injection data. 2) Hall plot technique for evaluating the vertical sweep efficiency. 3) Tracer data to evaluate the areal sweep efficiency. 4) Spearman's rank correlation to investigate injection-production well relationships. 5) Full field and conceptual fine gridded simulation models. The major conclusions of these evaluations are: 1) The Hall plots can be used to better understand the water injection history and to make recommendations regarding which wells that should be logged (ILT/RST). 2) Spearman's rank correlation has been unsuccessful in finding injection-production well relationships. 3) The coarse full field model gives a reasonable prediction of drainage performance. 4) Conceptual simulation model indicates the vertical injection inflow profiles are of limited importance. Improving the field water injection strategy is important for maximizing the field recovery factor. In order to achieve this goal, several recommendations have been made for improving the current field water injection strategy.
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Optimization of Fluorinated Wettability Modifiers for Gas-condensate Carbonate Reservoirs (SPE 154522)
Authors J. Fahimpour, M. Jamiolahmady and M. SohrabiA significant reduction in well productivity of gas-condensate reservoirs occurs owing to reduced gas mobility due to the presence of liquid condensate/water phases around the wellbore. Fluorinated chemicals as wettability modifiers are capable of delivering a good level of oil and water repellency to the rock surface, make it intermediate gas-wet and alleviate such liquid impairments. The main objective of this experimental work has been to propose an effective chemical treatment process for carbonate rocks, which in comparison to sandstone rocks, suffer from lack of information in this area. Screening tests including contact angle measurements, spontaneous imbibition tests and compatibility tests with brine were performed mainly using anionic and nonionic fluorosurfactants. The anionic chemicals were sufficiently effective on positively charged carbonate surfaces 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 permeable carbonate cores have successfully been treated by chemicals selected through thorough screening tests. Optimization of solvent composition and filtration of solution before injecting chemicals into the core proved very effective to reduce/eliminate 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.
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Experimental and Numerical Investigation on the Performance of Gas-oil Gravity Drainage at Different Miscibility Conditions (SPE 154368)
Authors A. Ghasrodashti, R. Farajzadeh and V.S. SuicmezDescription Fractured reservoirs have been traditionally considered poor candidates for gas injection processes as highly conductive fractures rapidly transport the gas to the wellbore and consequently majority of oil in the matrix is bypassed. In fractured reservoirs, matrix recovery is achieved by interactions between matrix blocks and fractures. A comprehensive study of the controlling mechanisms (e.g. capillarity, gravity, phase behavior) can lead to optimized recovery. We describe a set of gas injection experiments conducted at different enrichment conditions(immiscible, near-miscible, and miscible) using CO2, nitrogen and flue gas. Moreover, we study the effect of block boundary conditions that are aligned with geological artifacts, e.g., horizontally-oriented impermeable shale layers on the recovery efficiency. A compositional numerical model is developed to simulate gas injection processes at different miscibility conditions. Application When the capillary-driven counter-current imbibition is hampered due to non-water-wetting nature of the reservoir, the injection of gas can be considered as an alternative for recovery from fractured reservoirs. Injection of a miscible gas improves the ultimate recovery, because the miscibility adds the advantage of single-phase flow and interfacial tension elimination. Moreover, injection of an immiscible gas before injecting the miscible gas can be considered to optimize the economics of the project. Results Results reveal that although ultimate oil recovery increases considerably once miscibility is reached, increasing the pressure postpones the oil recovery. This can be attributed to the lower density difference between gas in the fracture and oil in the matrix. The impermeable layer impairs the performance of the gas-oil gravity drainage process for immiscible gas injection, however, it improves the recoveries for miscible gas injection. Significance This study addresses important fluid exchange processes (gravity, mass diffusion and capillary diffusion) which occur between fracture and matrix block at various miscibility conditions.
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