bluuebunny/crossref_metadata_2025_split huggingface dataset:
Improved Disproportionate Permeability Reduction of Silicate-Gelant Treatments: A Laboratory Scale Approach
Authors: Askarinezhad Reza , Hatzignatiou Dimitrios G. 
Published: March 2017

Abstract
A new experimental steady-state, two-phase chemical-system placement for Disproportionate Permeability Reduction (DPR) treatment has been recently established using water-soluble sodium silicate gelants. DPR treatment application in oil-wet formations has shown to be effective in reducing the water permeability compared to that of the oil phase. This work focuses on a modified approach of the newly established DPR treatment aimed to improve the treatment effectiveness.
Steady-state, two-phase placement of a DPR-fluid/oil is used not only to better control the formation saturation conditions but also to ensure presence of oil-phase path inside the porous medium. The DPR treatment performance is evaluated based on steady and unsteady-state permeability measurements conducted after treatment. DPR treatments were performed on oil-wet Berea core samples at both the same and lower water cuts (formation water saturation) compared to pre-treatment condition. Water-wet cores were treated chemically to alter their wettability to oil-wet. Measured phase-permeability curves together with recovery curves and spontaneous imbibition results were used to characterize the core wettability.
Results show potential positive DPR effects in all cases resulting in higher water-phase permeability reduction than in oil phase. However, if the DPR fluid placement is carried out at watercut conditions that are lower than the ones existing prior to treatment, the reduction in oil phase permeability is less severe resulting in a more beneficial DPR effect. It is of course worth mentioning that in the latter case, the residual resistance factor of the water phase also experiences a significant reduction compared to the former case but it is still higher compared to the one of the oil phase thus leading to a positive DPR treatment. Experiments conducted at different initial water cuts (high, medium, low) resulted to similar DPR effects when the silicate gelant was placed at the same conditions.
The importance of this approach is that DPR treatments can now be conducted at later production stages (higher water cuts) while achieving similar beneficial treatment effects related to phase permeability reductions. On the other hand, the reductions of the relative permeabilities seen in prolific (high oil saturation) zones of a multilayered system dictates the use of selective placement of the DPR fluid versus the bullhead injection (a) to minimize risks for post-treatment reductions of well oil production rates and (b) to enhance treatment success for post-treatment reduction of water production rates.
Development, Testing and Field Application of a Novel Combination Foamer-Iron Sulfide Scale Inhibitor-Corrosion Inhibitor in East Texas
Authors: Wylde Jonathan J. , Turner Nick , Austill Mark , Okocha Cyril , Obeyesekere Nihal 
Published: March 2017

Abstract
Production in East Texas has a long and rich history in both liquid and gas plays. This paper concerns wet gas production in the Fairfield, TX area and a unique challenge that was overcome by a collaboration between operator and service company. The application in question spans many wells in the Central and East Texas area where a common challenge was production of gas with associated corrosive fluids that led to significant deposition of iron sulfide scale in the production tubing.
This paper details the unique challenge of creating a single chemistry that not only can successfully deliquify the wells when pumped on a continuous basis but also one that can reduce the corrosion and prevent the build-up of carbonate scales and most importantly iron sulfide scale in the production tubing. Development work presented includes laboratory and field foamer testing, iron sulfide scale testing, and autoclave corrosion testing. This was made all the more challenging due to the high downhole temperatures of 300°F with a pressure of 1,000 psi and a mixed sweet / sour gas with a composition of 2.2mol% CO2 and 0.75mol% H2S.
Testing showed that application of these products up to 6,000 ppm was able to stabilize gas production, reduce the corrosion to acceptable levels and prevent the deposition of iron sulfide scale in static and dynamic tests.
Extensive detail is provided on the field trials and the monitoring regimen that was put in place to monitor all functionalities provided by this chemistry. As this was across a whole host of different well types, significant data was generated and a wealth of information and lessons learned for the industry can be extracted from it.
The paper concludes with the overall lessons learned and summary of the validity of this technology and how it could potentially be a game changer for the industry at large in East Texas where gas well deliquification combined with corrosion and scale formation is a shared challenge.
A Re-Evaluation of Reservoir Souring Patterns and Effect of Mitigation in a Mature North Sea Field
Authors: Mitchell Anthony F. , Skjevrak Ingun , Waage Jone 
Published: March 2017

Abstract
Subsurface generation of hydrogen sulphide (H2S), commonly known as reservoir souring, is a clearly identified but, still not fully understood phenomenon associated with water injection for secondary oil recovery. A large number of North Sea fields have been under seawater injection for many years, yet the majority are relatively poorly documented in terms of how and when souring developed and the amount of H2S being generated between injector and producer well pairs.
As part of ongoing work to verify the results of reservoir souring simulations, using empirical data, an exercise was undertaken to collate souring information from a number of older fields, with the objective of attempting to identify trends in, or factors impacting, souring development. A review of available historic data from the Gullfaks field was made; linking measured H2S values, well test data, water analyses and tracer data to identify long term souring patterns, the amount of H2S produced relative to injected water and to determine the effectiveness of the different mitigation strategies used in the field. The Gullfaks field in the Norwegian sector of the North Sea began production in 1985 and has been widely cited in connection with the introduction of nitrate treatment as a mitigation method for reservoir souring.
A number of key observations were made for Gullfaks. Souring development appears to follow a dual pattern of initial production of H2S, coincident with or shortly after breakthrough of injection water, followed by a subsequent decline; thereafter, sometimes several years later, a gradual increase to much higher levels is recorded. This implies that different types of souring patterns are being observed.
On the basis of improved understanding of souring development and data availability, a review of the effectiveness of mitigation techniques used in the field was undertaken. The interpretation indicates that the previously reported effect attributed to use of nitrate could also be explained by the natural progress of souring development in the field.
The work flow and methods of data interpretation opens the way to further full field evaluations as a means of improving the precision of souring simulation and assessment of mitigation methods
Scale and Corrosion Inhibitor Evaluation under High Shear Flow Conditions
Authors: Nichols David A. , Thomson Hunter , Simpson Caroline , Graham Gordon M. 
Published: March 2017

Abstract
Scale and corrosion testing under high surface shear flow conditions, and selection of effective inhibitors, is of increasing importance in oilfield production. Extremely high wall shear stresses, up to 10,000 Pa, can be generated in production systems, for example in inflow control devices, and as such there is a need for high shear corrosion and chemical testing techniques. A jet impingement test technique is presented that enables performance testing of both scale and corrosion inhibitors under these challenging conditions and demonstrates the effect of elevated shear on inhibitor performance.
A test system has been developed that allows routine laboratory evaluation of scale and corrosion processes at moderate to high shear stresses using a jet impingement method. A series of tests has been conducted to determine the extent of scale deposition and corrosion observed with a mild scaling system, both independently and combined, and then to assess the effectiveness of inhibitors under high shear conditions. Static tests and low shear rotating cylinder tests have been carried out with the same brine system to allow comparison of results from the different methods.
The results show that the jet impingement approach is effective in generating scale deposition and corrosion under the high shear, field representative conditions. The effect of the scale and corrosion processes occurring simultaneously in the same system was demonstrated. Both scale inhibitor and corrosion inhibitor performance were found to be affected by the flow conditions with higher concentrations of each being required as surface shear stress was increased although this was also dependent on the chemical nature of the inhibitors. Comparison of the jet impingement results with those obtained from static and rotating cylinder methods showed that the developed technique is more suitable and allows both scale and corrosion processes to be observed in the same system, under the same hydrodynamic conditions.
This test method therefore provides an additional laboratory technique that can be used to evaluate both scale deposition and corrosion under very high shear stresses that cannot be readily achieved by alternative approaches. This work also highlights the importance of testing under field representative conditions and advances the understanding of inhibitor performance in these systems.
Wax and Paraffin Control by Fracturing Fluids: Understanding Mode of Actions and Benefits of Water-Dispersible Wax Inhibitors
Authors: Mahmoudkhani Amir , Feustel Michael , Reimann Werner , Krull Matthias 
Published: March 2017

Abstract
During hydraulic fracturing operations in oil wells, the equilibrium balance of the crude oil is disrupted once high-pressure fluids are injected into the formation. Fluid temperature is often less than reservoir temperature, and if the formation is cooled below the cloud point, paraffin precipitates may deposit in the formation pores and faces as fractures develop. For paraffin-rich reservoirs, such as shale oil, damage caused by wax deposition at the fracture skin can cause decreased production, slow or hard to clean up wellbores, or failure to achieve predicted maximum recovery.
Developments in horizontal drilling and hydraulic fracturing during the past decade provided the industry with a versatile tool that utilized fracturing fluids as a carrier to deliver chemical additives in the form of liquids or solids deep into the reservoir. Chemistries, such as scale, wax and asphaltene inhibitors, are impregnated or infused in porous solids and placed into fractures during the fracturing job, which can provide long-term well protection and production control. Water-soluble additives can be easily formulated within these fluids and/or delivered via slow-release solid products, but the delivery of water-insoluble additives are difficult on an equivalent base. Non-polar additives are not going to be released from solid carriers since the water cut is relatively high within one to four weeks of a hydraulic fracturing job. The risk of organic deposition persists if minimum inhibition concentration of chemical additive is not attained during and after the job.
The scope of discussion in this paper will largely focus on water-dispersible systems, in particular to colloidal microdispersion, since they are the most prevalent type of dispersions found to be viable for hydraulic fracturing applications. A methodology is presented that demonstrates the advantages of water-dispersible wax inhibitors that prevent paraffin deposition from waxy crudes in the Bakken, Permian and Eagle Ford basins while complementing long-term control further provided by solid wax inhibitors.
This study adapted a novel approach by incorporating wax and paraffin control chemistries into a microdispersion system that is fully dispersible in water. In such micron-sized liquid-in-liquid or solid-in-liquid colloidal dispersed systems, active chemistries comprising polymers from poly (EVA), poly (alkylacrylate), poly (EVA-alkylacrylate), poly (α-olefine-MAA) esters/amides/imides, and selected dispersants and surfactants are brought together to deliver immediateand short-term inhibition for paraffin wax control.
The Most Efficient Use of Acoustic Sand Monitors. Lessons Learned from Many Years of Operation
Authors: Haugsdal Torbjoern 
Published: March 2017

Abstract
Sand production has been a critical factor regard the safety and the economics of many oil and gas fields. The first acoustic sand monitor was commissioned in 1995. Since then, a significant amount of time and money have been spent on controlling sand production.
A critical factor has always been accuracy and reliability of the systems, with different approaches used to accommodate the risk and the challenges different fields present.
This presentation will look back at how things were done in the beginning, what we have learned, and how things have changed. It will also cover the technical evolution since then.
We will look at the challenges still to be solved, and the experience gained in the areas of sand production, sand transport and sand monitoring.
The presentation will be supported by field cases.
Leakage Calculator for Plugged and Abandoned Wells
Authors: Ford Eric P. , Moeinikia Fatemeh , Lohne Hans Petter , Arild Øystein , Majoumerd Mohammad Mansouri , Fjelde Kjell Kåre 
Published: March 2017

Abstract
Today's practice on the Norwegian Continental Shelf when designing solutions for permanent plug and abandonment (P&A) complies with NORSOK Standard D-010. This is a prescriptive approach to P&A, as opposed to a "fit for purpose" risk-based approach. A risk-based approach means that any given P&A solution is expressed in terms of the leakage risk, which can be formulated in terms of the following quantities; the probability that the (permanent) barrier system will fail in a given time period and the corresponding consequence in terms of leakage to the environment.
As a part of building a leakage risk model for permanently plugged and abandoned wells, a simple leakage rate calculator has been developed for quick evaluation of the leakage potential from a given (permanent) well barrier solution. The leakage potential from the well can then be quantitatively assessed taking into account different leakage pathways including leakage through bulk cement, through cement cracks and through micro-annuli along cement interfaces.
In the paper, we will provide models to estimate leakage rate for each leakage pathway and show how to integrate them in an overall leakage calculator, to obtain a description of leakage flow from the reservoir through failed barriers to the environment. The information and input parameters needed to achieve this will be discussed, and uncertain parameters will be treated probabilistically, thus allowing for expressing uncertainty in the leakage rate estimate.
Results from the leakage calculator will be demonstrated on a synthetic case, showing variants of a permanently plugged and abandoned well.
ESP-DST Well Testing in a Complex Reservoir in the Barents Sea: Establishing New Methodologies and Lessons Learned
Authors: De Leonardis D. , Shumakov Y. , Morton K. L. , Sarac S. 
Published: March 2017

Abstract
This paper describes a unique combination of equipment and techniques that enabled an ESP-DST well test on a shallow, horizontal well drilled in a faulted and heterogeneous reservoir with complex fluids, in Arctic conditions.
The technical challenges of the performed well test included designing a bespoke ESP-DST string compatible with the shallow reservoir and designing a surface well test spread capable of efficient separation for safe and environmentally friendly disposal, and obtaining accurate flow rate measurements, as well as performing a test with interpretable data given the uncertainty and complexity of the formation, and the complexity of the well itself.
The success of the performed well test was the result of an integrated approach to well test design and real-time support provided throughout. This process included the selection of optimum ESP-DST string design for multizone testing in a high angle well including an innovative arrangement of an ESP encapsulated in a POD and installed in the riser. Integration of ESP with the surface well test package was also important and the design of the surface well test package included a Coriolis type of separator and multiphase flow meter for accurate flow rate measurements.
During drilling, the contingency plan to mitigate against losses was implemented which had a significant effect on the well testing program. To address this, and to understand if the well objectives could still be achieved, an uncertainty-based well test design and interpretation methodology, taking into account reservoir uncertainties and their interaction with each other, which uses numerical models and a global sensitivity analysis method was applied. This method identifies which uncertain reservoir parameters can be interpreted confidently and indicates the test duration. From the hundreds of numerical simulation cases produced during the design stage of the test, matches were obtained during monitoring to give an indication of the future pressure behavior, which allowed the duration of final build-up to be optimized.
The ESP-DST well test was successfully performed on a horizontal well drilled in the Wisting discovery in the Barents Sea. The well was successfully free flow tested giving a maximum achieved flow rate of 5,000 barrels of oil equivalent per day. All the well test objectives were successfully achieved, despite the change to the contingency drilling plan.
Optimizing Bean-Up Procedure after Well Shut-in. Simple Rock Mechanical Aspects and Operational Guidelines
Authors: Andrews Jamie S. , Kittilsen Pål , Låhne Thomas , Antonsen Jan Rune 
Published: March 2017

Abstract
Several theories exist for estimating permissible well drawdowns based on mechanical properties of the formation. These models are well developed and extensively used for the initiation of sand failure. However, models for predicting sand volumes and the sanding behavior post failure are plagued by difficulties in characterizing the mechanical properties of the failed/plastified area, the complicated interplay of erosion and production of sand on stress distribution in the near wellbore and from assumptions of idealized geometries. This work describes a method for determining optimum bean-up strategies that limit mobilization of material such as fines or sand from failed perforations/sand-face. The method nicely circumvents issues that can limit the applicability of theoretical models when optimizing well bean-up by simply ensuring that any transient pressure gradients that develop are lower than the pressure gradients that exist in near wellbore for the normal operating state of the well. The assumption is that the asset is operating the wells at flow rates/drawdown that are acceptable to them in terms of sanding/solids production. Such an approach can be used to minimize sand production during regular bean-ups for wells that are produced at ASR (Acceptable Sand Rates) and for wells where fines mobilization is suspected in causing time dependent skin effects and plugging. Different strategies are given to estimate the maximum step change increases in drawdown, the number of discrete steps and the total bean-up time. Furthermore, a method is presented showing how the pressure profile observed following a shut-in can be used to determine the optimum bean-up rate for any well - without knowing the exact details of the well and flow geometry or the different diffusivity coefficients and properties of the various producing layers. This is a new insight and can be a very powerful tool.
DEMO2000 - Drilling Mud Process Control
Authors: El Boubsi Rachid , Andresen Jan Atle , van Og Geertjan , Bjørkevoll Knut S. , Nybo Roar , Brevik Jan Ove , Nygaard Gerhard , Smith George G. 
Published: March 2017

Abstract
Managed pressure drilling (MPD) is an adaptive and sophisticated drilling process used to control the downhole and annular pressure. Mud management could enhance MPD as the downhole pressure is dependent on mud parameters such as mud density and rheology. Therefore, a step-change is needed in drilling process control, to enable consistently high performance, accurate pressure control and reduced risk of unwanted effects. Advances in process control have been made, but risk reduction and optimization of the drilling process is still a major challenge in the drilling industry.
A missing piece in considering the process-control puzzle is the in-situ determined drilling mud characteristics. Without accurate knowledge of mud properties and cuttings contents or without an ability to adjust the mud in real-time, a control system cannot reliably maintain bottom hole pressure or ensure a smooth flow of cuttings. The use of real-time density and rheology measurements in combination with a model that optimize the drilling operation by adjusting the mud will be a radically new innovation on the drilling market.
To complete the puzzle, a demonstration of a pilot unit will be carried out. The unit combines monitoring of mud and cuttings with wellbore hydraulic modelling and a control system that adjusts mud properties in real-time. The control setup will strive to keep the drilling operation within its operating envelope with respect to cuttings transport and bottomhole pressure. The demo project will construct such a system from existing components. Its focus will be on demonstrating the potential of a fully integrated drilling system. In particular to demonstrate that mud properties can be adjusted automatically based on real-time mud measurements. This demonstration project will be carried out in collaboration between Huisman, Statoil, SINTEF, Intelligent Mud Solutions (IMS) and Cybernetic Drilling Technology (CDT), with financial support from the Norwegian Research Council.
The demonstration project will take place at Huisman Innovative Tower in the Netherlands, where a full scale facility with drilling rig and a 400 m deep test well goes operational in Q1 2017. Available technology from the project partners covers many of the process control components. Such as a commercial hydraulic flow model for downhole pressure predictions provided by SINTEF, a mud density and rheology sensors provided by IMS with software by CDT and a mud treatment system of Huisman's design, allowing for real-time adjustment of mud.
HONOR Y DUELO EN LA ARGENTINA MODERNA, de Sandra Gayol
Authors: Hirsch Leonardo D. 
Published: March 2017

RESEÑASHONOR Y DUELO EN LA ARGENTINA MODERNAGAYOL, Sandra (2008). Honor y duelo en la Argentinamoderna. Buenos Aires: Siglo XXI. 284 pp. ISBN: 978-987-629-042-5.