bluuebunny/crossref_metadata_2025_split huggingface dataset:
Development of Reduced-order Oil Reservoir Models using Localized DEIM
Authors: Yoon Seonkyoo , Alghareeb Zeid M. , Williams John R. 
Published: October 2014

Abstract
For applications of numerical reservoir simulators such as production optimization or uncertainty assessment, hundreds or thousands of reservoir simulation runs must be performed. Such huge computational cost is a major problem in petroleum engineering, and reduced-order model (ROM) based on proper orthogonal decomposition (POD) has been intensively studied in recent decade to overcome it. While POD-based methods have been shown to be efficient compared to full order model (FOM), it is not as efficient when it is applied to a typical large dimensional nonlinear reservoir system. One of the reasons for the inefficiency is that in a typical nonlinear reservoir system ROM based only on POD is still dependent on the dimension of FOM. This is due to the fact that to compute the reduced nonlinear term in mass balance equation of a reservoir system, one must first reconstruct the full-order state solution such as pressure and saturation, evaluate the full-order nonlinear term before projecting it onto a reduced subspace. Therefore, we developed a reduced-order reservoir model based on a discrete empirical interpolation method (DEIM) to approximate nonlinear phase potential terms so that the repeated online evaluations of the ROM in Newton iteration are independent of full-order dimension. The independence comes from the fact that DEIM just needs to evaluate the nonlinear term only at interpolation indices that represent grid blocks that are important in terms of preserving the continuity properties of the mass balance equation. A case study was carried out to investigate the performance of DEIM compared POD. Although the testing schedule of well controls is far apart from the training schedule of well controls, close matches are obtained. Thus, the ROM using DEIM is expected to enable the practical application of reservoir simulator, such as production optimization in which many simulation runs must be performed, in a reasonable time frame by significantly relieving the required numerical effort.
Detecting Fracture Growth Out of Zone Using Temperature Analysis
Authors: Ribeiro Priscila M. , Horne Roland N. 
Published: October 2014

Abstract
Hydraulic fracturing is a widely applied well stimulation technique. Recently the application of multiple hydraulic fractures along horizontal wells has made possible the exploitation of unconventional reservoirs, such as shale gas and shale oil. However, the process of horizontal well fracturing is uncertain and it is not fully understood yet. There exist many questions about the number and position of created fractures and whether or not the fracture stays contained within the main reservoir thickness.
This work presents the modeling and analysis of temperature data during and after the creation of multiple fractures along a horizontal well. Our model accounts for fracture growth and closure, the well effects and interaction between multiple fractures.
The interference between multiple fractures growing simultaneously and the presence of reservoir permeability heterogeneity were investigated. Capabilities and limitations of information carried by temperature data are presented through different geometry analyses.
A special consideration of fracture growth out of zone was addressed. For this case it was considered that one of the hydraulic fractures activates a preexisting fault and interconnects the reservoir with other zones hundreds of feet away.
Our work shows the advantage of using continuous distributed temperature data in comparison with the traditional single-point pressure analysis. The local characteristic of temperature allows us to identify not only which of the created hydraulic fractures has interconnected the main reservoir with a different zone, but also the location of this zone. We also account for the effect of the interconnection on the growth of the other hydraulic fractures along the horizontal wellbore.
The simultaneous multiple fracture growth shows that falloff distributed temperature data can predict the number of created fractures. More than that, in presence of heterogeneity the interaction between the contained fractures can be captured by the temperature analysis. Different from the pressure analysis, distributed temperature data can differentiate between different heterogeneity locations along the wellbore.
Throughout this paper we present a series of examples where the temperature can provide information that would not be obtained from the traditional pressure analysis.
Autonomous Inflow Control Valves - their Modelling and "Added Value"
Authors: Eltaher Eltazy , Muradov Khafiz , Davies David , Grebenkin Ivan 
Published: October 2014

Abstract
Wells equipped with inflow control devices (ICDs) are a proven method of improving sweep efficiency by passively controlling the influx of fluids into the well by the addition of a restriction to each completion joint. The application of ICDs is also essential to development of some oil fields previously found to be uneconomic. The ICD-completion design is a complex process requiring selection of the ICD restriction size, ICD type, and annular flow isolation (AFI). Several commercial ICD designs are now available, each of which react differently to the flowing fluid properties. This complicates the completion design process, which often requires the ICD completion to be specified against a poorly known reservoir and well performance prior to drilling the well. This adds a requirement for the ICD completion to improve oil recovery in a range of potential production scenarios.
Unfortunately ICDs do not provide an optimal well design after breakthrough of the unwanted phases, despite their ability to balance the well inflow profile and achieve a uniform sweep towards a horizontal well in early years. Field experience has taught that ICD completions balance the well influx initially, but may not offer the optimal solution throughout the well's life due to the changes in the inflow conditions as the well matures. The recently introduced Autonomous Inflow Control Device (AICD) aims to restrict unwanted phases (gas and water), (partially) overcoming the results of reservoir uncertainty at the well completion design stage.
Autonomous Inflow Control Valves (AICVs) are the next generation of flow control technology, being designed to virtually shut-off unwanted fluid inflows at completion joints. This paper describes the first AICV modelling workflow for integrated well/reservoir simulators. Its application allows reservoir and well engineers to quantify the value added by the optimal use of this new, down-hole completion technology.
The workflow has been used to compare the performance of advanced well completion options (AICVs and ICDs) in a synthetic, oil-rim reservoir model mimicking a larger North Sea field where production is dominated by gas-coning problems. Down-hole flow control with AICVs significantly increased oil recovery compared to ICDs and conventional wells employing wellhead choke control. Unwanted fluid production was also reduced by up to 80%; a result that combines higher oil recovery with more efficient use of reservoir energy by the AICV completion.
Profile Formulation of the Future Petro Technical Professional in Argentina
Authors: Abalos R. , Erdmann E. , Gallardo F. , Sidoruk B. , Osses J. 
Published: October 2014

Abstract
The objective of this paper is to formulate a Petro Technical Professional profile in Argentina to propose a new academic curriculum.
Argentinean university's curricula analysis is performed trying to elaborate the actual profile of the Petroleum Engineering Professional.
An analysis of the energetic situation and the petroleum industry needs in Argentina is also carried out attempting to know the work situation in which the future graduate will be immersed.
Unconventional oil and gas resources in Argentina and their potential exploration and improvement were decisive to initiate this work. New opportunities in this direction will be presented for future professionals so academic curricula should be adapted to follow them. The environment is also taken in consideration as an important topic to be included.
It is remarkable to mention the participation of two Petroleum Engineering's students in this work.
A Comparison of Proppant Erosion during Slurry Injection
Authors: Frosell Thomas , McGregor Molly , Ross Colby 
Published: October 2014

Abstract
During frac-pack treatments, proppant erosion is often a limiting factor for the allowable flow rate and total volume of proppant pumped during the job. Each completion assembly has a rating based on limited amounts of full scale erosion testing which is typically provided for one or two types of proppant. Previous testing results have shown that different types of proppant, such as lightweight ceramic (LWC), intermediate strength proppant (ISP), and high-strength proppant (HSP) have different erosion rates.
A jet impingement test facility was used to compare different sources of proppant for each of the commonly used proppant types. The test facility was designed to replicate the downhole conditions, while providing the capability to control the test parameters. A nozzle diameter was selected to represent the typical flow-structure size within the completion equipment and a linear gel with proppant loadings between 2 and 10 PPA was selected for the test slurry. The test coupons were low-alloy steel with a representative heat treatment of the material used for downhole equipment. The results were analyzed by measuring mass removal and the 3D erosion profile to compare the overall erosion rate in each test, as well as the erosion profile produced by the various proppants. Furthermore, the proppant was inspected using a laser confocal microscope to provide comparisons between proppant types and sources.
The test results, presented in this paper, show that different sources of proppant within a single type of proppant can lead to significantly different erosion rates. Comparison between two sources of HSP showed that there can be a variation in erosion rate of over 60% and that the variation in erosion rate can double when comparing two sources of ISP. These results have verified that proposed changes, such as changing the proppant from what was tested originally for the frac-job operation, can affect the erosion within the completion equipment. Therefore, it is of critical importance to evaluate the possible effects of any change to ensure that the rating of the tool will not be exceeded.
Relative Permeability Normalization – Effects of Permeability, Wettability and Interfacial Tension
Authors: Jahanbakhsh Amir , Shahverdi Hamidreza , Sohrabi Mehran 
Published: October 2014

Abstract
The relative permeabilities (kr) are crucial flow functions governing the fluid distribution within and production from the petroleum reservoirs under various oil recovery methods. To obtain these important reservoir parameters, conventionally, it is required to take rock samples from the reservoir and perform appropriate laboratory measurements. Although, kr is expressed as a function of fluid saturation, it is now well-known that kr values are affected by; pore structure and distribution, absolute permeability, wettability, IFT, and saturation history. These rock/fluid properties often change from one region of the reservoir to another but it would be impossible to perform kr measurements for all regions of a reservoir. Generally, performing experiment on a core with higher permeability is faster and easier than a low permeability rock. Therefore, assuming all other parameters such as wettability, IFT, and displacement direction are the same for two rocks with different permeability, the question is, how do we estimate the kr of a rock with lower permeability from available (measured) kr of a higher permeability rock? How do we account for wettability and IFT differences? Normalization techniques have been proposed to remove the effect of irreducible water and trapped saturations, which would be different under different conditions. The relative permeabilities can then be de-normalized and assigned to different regions (rock types) of the reservoir based on their own irreducible water and trapped saturations.
The objective of this study is to predict the kr for a new rock/fluid conditions (i.e., permeability, wettability, IFT) using existing kr data measured at different conditions. Using measured data from coreflood experiments, we show that by applying an appropriate normalization technique one can adequately predict kr of rocks with different permeability and wettability conditions in two-phase flow. However, the results show that the effect of IFT change cannot be captured by normalization techniques. To improve the methodology, a new hypothesis is introduced and proposed here based on Dynamic Trap Saturation. Finally, using our experimental data, we evaluate the validity of Coats IFT scaling method. We demonstrate the shortcomings of the method and offer an improvement to its prediction.
Long-Time Diversion in SAG Foam Enhanced Oil Recovery From Field Data
Authors: Rossen W. R. , Ocampo-Florez A. A. , Restrepo A. , Cifuentes H. D. , Marin J. 
Published: October 2014

Abstract
The ability of foam to divert gas flow over a long period of gas injection in a Surfactant Alternating Gas (SAG) foam process is important for the economics of foam-diversion processes for enhanced oil recovery. Here we interpret field data from the foam test in the Cusiana field in Colombia, South America (Ocampo et al., 2013). In this test surfactant was injected into a single layer that had been taking about half the injected gas before the test; then gas injection resumed into all layers. Based on the size of the surfactant slug injected and estimates of adsorption and of water saturation in the foam in situ, we estimate that the treated region extended about 5.3 m from the injection well: fortunately the results to follow are not sensitive to this estimate. Based on the change in injection logs before the test and at day 5 of the test, when approximately 30 pore volumes of gas has been injected, foam still reduced gas mobility in the treated layer by about a factor of 9. We base this estimate on the decrease of injection into the treated layer and the increase into the other layers; the results are consistent among the layers. After 35 and 152 days of injection (220 and 1250 pore volumes gas injected), foam reduced gas mobility in the treated zone by about a factor of 4 and 2, respectively.
This result suggests that foam continued to reduce mobility by a modest amount even after long injection of gas. In this test, the large volume of gas had quickly penetrated far beyond the edge of the surfactant bank. In a design where a larger bank of surfactant were injected, a much greater and longer diversion of gas would be expected. On the other hand, foam did weaken progressively as it dried out. Foam models where foam remains strong at irreducible water saturation would greatly overestimate foam effectiveness at long times in this test.
Oil Relative Permeability During Enhanced Oil Recovery by Foam Flooding
Authors: Heins R. , Simjoo M. , Zitha P. L. , Rossen W. R. 
Published: October 2014

Abstract
A previous study (Simjoo and Zitha, 2013) reports enhanced oil recovery by foam injection in corefloods: that is, reduction in oil saturation in the core below waterflood residual. This reduction is achieved by foam in a process with reduced oil-water interfacial tension and increased pressure gradient. Those results, combined with bubble-column experiments, suggest that a new mechanism of oil recovery is involved in these floods: emulsification of oil into the Plateau borders between the bubbles of the foam and transport of oil along with the foam bubbles.
Using these data we compute the oil relative permeability during this process of enhanced oil recovery. There is an initial oil bank with oil relative permeability of order 0.1. Thereafter, during the period of highest capillary number and oil production attributed to emulsified oil droplets, oil relative permeability is between 0.001 and 0.0001: far less than with surfactant flooding, for instance, at similar capillary number. Over time in these experiments, the final oil saturation is greater than, but is slowly approaching, that expected at the large capillary number of the experiment. Since in the proposed mechanism emulsified oil must travel with the foam, which has extremely large effective viscosity, but oil relative permeability is computed based on the much-smaller oil viscosity, the low oil relative permeability can be seen to be result of strongly adverse viscous coupling between the phases. Efficient oil recovery by the mechanism of emulsified oil droplets would require a large volume fraction of oil within the foam, a less-viscous foam, and/or a more-viscous oil. Other studies of foam displacing oil briefly examined here reflect a larger oil relative permeability during foam displacement, in large part because of a smaller contrast between foam and oil viscosity, or even a foam effective viscosity less than that of the oil it displaces.
Ensuring The Safety Of Onsite Personnel And Neighboring Community During Workover And Well-testing Activities With A High H2S Risk Potential – A Case Study
Authors: Ferrante Andrea , Daher Elie , Warwick Hugh 
Published: October 2014

Abstract
OMV Petrom had a planned workover and well-testing activity on a well with high potential concentration of hydrogen sulfide (H2S) located 200 meters from a neighboring community. To ensure safety during the workover and well-testing activity, a leading oil and gas group in Central Europe undertook a careful preparation of processes, systems and its personnel. Considering the proximity of the wellsite to the community, they also needed to inform and educate the surrounding community.
Servizi Integrati di Sicurezza (S.I.S. S.r.l.), part of United Safety International Group was given the task to ensure the safety of personnel and neighboring community through effective preventive actions including extensive H2S training and prevailing wind monitoring. A site-specific Emergency Response Plan (ERP) was developed that defined the coverage of the Emergency Planning Zone (EPZ). Wind speed and direction was monitored for a period of four months prior to the drilling activity which allowed the identification of high risks areas in the event of a gas release.
A dedicated wireless H2S and sulfur dioxide (SO2) gas detection system was installed including a general alarm system for public awareness in case of a public evacuation. Rovers were dispatched continuously to monitor remote areas of the EPZ. The safety solutions company conducted H2S drills, man down simulations, and public evacuations in coordination with the operator and the local community. Prior to commencement of drilling activities, nearly 400 training certificates were released to personnel, contractors and sub-contractors.
This paper discusses lessons learned and best practices of emergency planning and management of the EPZ as critical elements of drilling operations. It highlights the continuous improvement of EPZ management methods and discusses the importance of engaging affected communities and residents to build confidence, partnerships and ultimately boost a company's public image. The paper also demonstrates the impact of corporate citizenship and responsible care practices beyond the immediate community.
How Intelligent Coiled Tubing Technology Combined with Realtime Downhole Camera Visuals Created a Formula for Success During a Challenging Thru-Tubing Recompletion Operation in the North Sea
Authors: de Jonge R. M. , Tousis U. , Nijenhuis J. 
Published: October 2014

Abstract
A North Sea gas well was drilled and completed in 2000. Soon after the well was put in production, sand was also produced and became a major problem. Since the process system on the satellite platform was not capable of handling the sand, sand screens were installed in the well to prevent any further sand production. During the following years the sand screens became completely blocked and production ceased. The well was shut in for the next 10 years until a thru-tubing recompletion program was executed: milling out the permanent packer, fishing and retrieving the existing sand-screens and installing 130 m of new screens in a live well, all with 2 3/8–in. intelligent coiled tubing (CT).
Intelligent CT interventions are operations in which rea-time downhole data is used to improve operational efficiencies. The realtime downhole data that can be obtained during CT operations include accurate depth correlation, pressures, differential pressures and temperatures. In combination with a realtime downhole camera, the high quality of data proved to be very valuable during the decision-making process, since the actual downhole situation can be assessed while many uncertainties are being eliminated. The visuals obtained by the camera played an important role in the choice of fishing tools and in discovering the exact position of fish and packer elements.
This paper describes the challenges, the operational execution and the lessons learned from the recompletion project. It also explains in detail the operational aspects of the intelligent CT and how it was beneficial to the successful execution of the intervention program.
Following the successful operation, the well was produced through the well test package on board the support jack-up, and production figures exceeded expectations. After this initial well, interventions in several more wells followed, whereby thru-tubing sand screens were installed with use of intelligent CT.
Accelerated Oil Droplet Separation from Produced Water Using Magnetic Nanoparticles
Authors: Ko Saebom , Prigiobbe Valentina , Huh Chun , Bryant Steven , Bennetzen Martin V. , Mogensen Kristian 
Published: October 2014

Abstract
The treatment of highly stable small oil droplets in produced water is challenging for offshore production, where platform space is constrained, because their long residence time requires large equipment volumes. The use of magnetic nanoparticles (MNPs) to remove dispersed droplets is a promising alternative due to their quick response to external magnetic field, allowing easy separation of oil droplets on which MNPs were attached from water. The goal of this study is to prove the concept of magnetically separating oil droplets from produced water using surface-coated MNPs. Batch-scale experiments were performed and they showed that droplets in 5 wt. % of decane-in-water emulsions, which have negative surface charges, were successfully separated from water using cationic surfactant-coated MNPs, with decane removal efficiency of 85 to 99.99%, depending on the experiment conditions. Anionic surfactant-coated MNPs did not remove oil droplets, indicating that the electrostatic attraction between emulsions and MNPs control the attachment of the MNPs to the droplet surface. The settling velocity of a droplet coated with MNPs was derived by extending classical theory to account for the magnetic force as well as buoyancy and drag forces. Under the applied experimental conditions and considering the geometry of the oil-water-MNP system, velocity calculations show that the droplet settles spontaneously when a magnetic field is applied. Otherwise the MNP-coated oil droplets (MNP-droplets) would naturally migrate upwards due to buoyancy. The velocity of a single MNP-droplet is strongly dependent on the intensity of the magnetic field and it changes up to three orders of magnitude within the height of tested sample of approximately 3 cm.