bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Next Generation Inflow Control, the Next Step to Increase Oil Recovery on the Norwegian Continental Shelf
Authors: Mathiesen Vidar , Werswick Bjørnar , Aakre Haavard 
Published: June 2014

Abstract
One of the challenges on the Norwegian shelf is declining oil production and relatively low recovery rate. At current estimate, less than half of the oil will be remaining in the reservoir after shut down. A major challenge is to improve recovery from existing fields by developing and implementing new technologies that make mature and marginal fields more profitable. It's vital to develop technologies that can increase recovery before fields shut down. In most fields on the Norwegian continental shelf is the draining mechanism of pressure support from gas and / or water. This means that after a period of production, all wells will have gas and/or water breakthrough. As the breakthrough expands the production have to be limited due to excessive gas and/or water production. This means that production from the well have to be choked or stopped, even there is oil left along the wellbore. Inflow Control Device (ICD) and Autonomous Inflow Control Device (AICD) developed and installed by Hydro and Statoil have shown that the oil production and recovery can be increased significantly with better inflow control along the well. However, neither ICD nor AICD is able to shut off the unwanted gas and water production completely. The newly developed and patented Autonomous Inflow Control Valve (AICV) can shut off the unwanted fluid completely. This technology will probably be the next major step for increased oil recovery on the Norwegian Continental Shelf, in new and old wells. The new completion technology is presented and experimental test results with gas, oil and water are presented together with reservoir simulations that confirm that the AICV will give significantly increased recovery in field suffering from gas or water breakthrough.
Successful Use of Multilateral Technology to Improve Oil Recovery in the Brazilian Amazon
Authors: Mendes S. , Albuquerque M. , Vento M. , Batista N. 
Published: June 2014

Abstract
Petróleo Brasileiro S.A. (Petrobras) assessed many technologies to increase production and reduce costs while protecting the environment in the Brazilian Amazon. For this project, where access to likely wellsites is restricted both by limited infrastructure and Brazilian regulations, minimizing environmental impact was the primary factor in the operator's decision process.
To address both environmental and production issues, the operator selected multilateral technology, which minimizes the wellsite footprint, yet allows for drainage of a much larger volume of the reservoir from a single surface location. This is a significant advantage when compared to the cost and environmental impact of drilling multiple wells or using large drilling pads.
Petrobras implemented this technology in the Urucu field, located 650 km southwest of Manaus, in the heart of the Brazilian Amazon. The Urucu has three reservoirs and more than 95 wells. The target formation is Jurua in the Paleozoic Solimões basin—a basin that includes an important petroliferous system (Jandiatuba-Jurua). The reservoir rock consists of eolian and marginal, marine carboniferous sandstones.
This paper presents the results of a successful multilateral technology project in the Urucu field in which three TAML Level-4 dual-lateral wells were installed by Petrobras. These wells had an average production rate of 1.75 times more than a typical horizontal well while spending only 1.42 times the average cost of the same.
Characterization of Semipermeable Stratigraphic Layer of the Upper Cretaceous based on the Sedimentary Model of the Ku-Maloob-Zaap Production Asset
Authors: Carmona J. Garcia , Lopez M. Correa , Figueroa R. Rojas , Franco N. Aguilera , Pena M. Prado , Ibarra R. Martinez 
Published: June 2014

Abstract
The detailed study of the Cretaceous stratigraphic column and diagenetic studies in the Ku, Maloob and Zaap fields, have identified a low porosity, low permeability rock unit, which acts as a vertical barrier across the Cretaceous reservoir. This semi-permeable rock unit which reduces vertical transmissibility between adjacent strata has been called KSA. This calcareous-clayey and sometimes dolomitized layer has been associated with oil generating rocks and potential seal rocks. The aim of this work is to establish the sedimentological conditions, age and areal distribution of the KSA unit to understand its influence on the dynamic behavior on the Cretaceous reservoir for the Ku, Maloob and Zaap fields.
The interpreted sedimentary model is based on microfacies interpretation. All sedimentological and paleontological data is obtained allowing a reconstruction of depositional environment and origin of the sediments. Subsequently, paleoenvironments are interpreted by correlating stratigraphic sections to establish the lateral and vertical facies changes as well as the construction of the sedimentary model.
To understand the presence of the KSA unit it was necessary to know the Cretaceous sedimentary evolution. Eighteen (18) microfacies were defined. There is an open and shallow platform development. On top of the Cenomanian and Middle Turonian, we found a deepened area due to rising sea level (Oceanic Anoxic Global Event).
Based on sedimentological analysis and the correlation of electrofacies and gamma ray log, we can conclude that the KSA corresponds to a maximum flooding surface with clay peak values in the gamma-ray log averaging 15 to 40 ° API. The relative lack of planktonic and other organic matter suggests that this level is associated with an oceanic event caused by a deficiency of oxygen and possibly an increment in nutrients. Stratigraphic correlations of this interval yield an average thickness of about 35 m in Ku, Maloob and Zaap fields.
The new geological understanding of the semi-permeable KSA unit has been incorporated into a 3D model thus helping to optimize the position of new wells.
Selection and Optimization of Artificial Lift System in Heavy Oil Fields
Authors: Kaplan Vedat , Duygu Ersan 
Published: June 2014

Abstract
Emulsion which occurs in all phases of oil production and processing in heavy oil fields causes several operational problems. Especially, it can preclude performance of artificial lift system and induce malfunctions due to high pressure drop in production string and high shear stress around rod.
Existence of rod string in tubing heavily reveals production limitations in artificial lift systems used in deep wells which produce emulsifying heavy oil. Artificial lift systems do not only require power for lifting heavy oil up to the surface, but also they require power for coping with resistance of high viscous fluid during movement of rod string in tubing.
Movement of rod string originates shear stress that is very sensitive to viscosity of fluid. In case of using progressing cavity pump, radial shear stress occurs during clockwise rotation of rod string. In contrast, as sucker rod pump is used, axial shear stress takes place on the up and down stroke of rod string.
As far as negative effect is concerned, radial shear stress on the progressing cavity pump system is less detrimental than axial shear stress on the plunger pumping system in theoretical and practical aspects. It is also evident that it is possible to decrease negative effect of radial shear stress by selecting large displacement pump and reducing rotation speed of rod string by means of variable speed drive system provided that the same amount of production is received. Moreover, tubing back-off, twist-off caused by reversed movement of rod string and rod being screwed off when being shut down can be avoided owing to decrease in radial shear stress or torque created by high viscous fluid.
This paper aims to expatiate that progressing cavity pump is viable choice for particularly deep wells producing emulsifying heavy oil in terms of operation and energy consumption.
Changing the Way To Drill in Ecuador: Experience Using Point-the-Bit and Hybrid RSS in Horizontal and 3D Complex Wells
Authors: Carrizo Hector R. , Sanchez Jose L. , Perdomo Luis , Bertarelli Mario 
Published: June 2014

Abstract
To face up the drilling of complex oil wells, the point-the-bit rotary steerable technology was introduced in Ecuador in 2010. The excellent drilling performance results and savings (both in time and money) have pushed the rest of oil fields in Ecuador to introduce and apply point-the-bit rotary steerable system (RSS), which was the key technology implemented in the drilling campaign for this paper. Twelve horizontal wells with complex 3D configurations were drilled.
The point-the-bit RSS for 8-½-in and 12-¼-in hole sections was promoted, accepted and used based on desing and operational advantages. The drilling campaign developed in 2011, 2012 and 2013 showed very good results: 107, 061 ft were drilled in 2, 821 operational hours with a significant average rate of penetration improvement of 20% in comparison with conventional technology in the same field for the same oil operators.
The point-the-bit RSS provided the way to solve common catastrophic events observed before (i.e., stuck-pipe and lost-in-hole situations). Aditionally it allowed to reach geological objectives for very complex wells offering several advantages like: Drill through all the proposed targets with a minimum separation from the planned trajectory.Reach higher dog leg severities in rotary mode with a minimum well tortuosity.Minimize reactive formation exposure by a faster drilling speed.Improve hole cleaning.Minimize stuck-pipe events while drilling and while tripping.Run 7-in liner and completions without any issues.Improve landing development and horizontal navigation process.Allow to drill longer horizontal sections.Possibility to run a reamer to enlarge the hole while drilling.
The successful drilling campaing with this point-the-bit RSS in Ecuador leaves the door open to the next generation of RSS which is a combination of push-the-bit and poin-the-bit RSS technologies that improves the capability to generate dog leg severity without compromising the rate of penetration and will allow to redefine the planning and execution phases of drilling process considering that the new wells to be drilled are every time more complex. Those RSS are part of the integrated drilling solutions to adapt in the directional drilling process in Ecuador for extremely challenging drilling environments.
Advanced Technique for Enhancing Fracture Conductivity in Tight-Gas Condensate Reservoirs through Applying Liquid Resins: Case Histories from Burgos Basin, Mexico
Authors: Lopez-Bonetti E. , Cuessy A. , Coronel H. , Suarez-Fromm J. D. 
Published: June 2014

Abstract
The purpose of this research was to identify challenges related to optimizing hydraulic fracturing in tight-gas condensate reservoirs using liquid resins to coat fracturing proppants. The selected case histories illustrate specific documented solutions of recent, successful approaches using this technology in the Burgos basin by analyzing production behavior before and after treatment in an exploratory well.
When discussing post-treatment production evaluation, the immediate pressure response and water flowback are commonly the very first parameters to observe during the cleanup stage. This surging process may indicate whether the objective was reached or not. However, additional uncertainty can arise when undesired monthly decline rates are observed, suggesting a loss of conductivity that can be caused by several factors—fracture embedment, early diagenesis, proppant crushing, fines migration caused by high producing rates, and stress cycling, among others—compromising the propped fracture effectiveness.
Real fracture growth during stimulation treatments, which can be monitored by microseismics, determines production longevity and is the actual criteria for determining fracturing success. This ultimate goal has been achieved in Burgos basin by applying the appropriate fracture design and considering a wide range of permeabilities present in the reservoir, as well as using proper geomechanical models along identified gas-condensate pay zones. Based on these findings, the recommended and applied treatment design used a liquid resin coating on 40 to 100% of the ceramic proppant, which was applied on-the-fly during pumping of the high-concentration proppant stages. This new technique led to obtaining an important production increase, maximizing reserves, and creating new opportunities for the operator to drill several wells in the area.
Applications of Computational Fluid Dynamics To Study: Slurry Flow in Pipeline for Heavy and Extraheavy oil
Authors: Zambrano Meza H. J. , Brito A. , Márquez J. G. 
Published: June 2014

Abstract
The Faja Petrolifera del Orinoco (FPO), located in the southern part of the Eastern Basin of Venezuela, has the largest reserves of heavy and extra heavy oil in the world. These oils are highly viscous and their API gravities values are between 7 and 15, these properties together with the existence of multiphase flow make the production and transportation of these oil is highly complex. Therefore, it is necessary to use heavy oil transportation methods focused on reducing the viscosity of oil, this is achieved be removing or modifying the oil compounds that have been pointed out as the main cause of the high viscosity of these oils, such as: partial or total upgrading or slurry transportation.
This study presents a flow modeling of a solid-liquid dispersion through horizontal pipes, which represents a slurry transportation, using a software of computational fluid dynamics (CFD) called FLUENT 6.3. For the simulation methodology was selected Euler-mixture in a three dimensional pipe model, with different concentrations of solids. The simulations were validated with experimental data development by PDVSA Intevep that contains pressure drops, temperature, solid characterizations and reological behavior of the slurry.
The performance evaluation by the CFD model showed an acceptable fit when it is compared against experimental data, this results allow to understand the hydraulic behavior of heavy oil slurry transport through pipeline.
LWD Formation Tester Applications in Colombian Basins
Authors: Galindo J. A. , Rincon C. C. , Hemsing J. J. 
Published: June 2014

Abstract
Because of the complexities of the Colombian geological basins, logging-while-drilling (LWD) is recognized as a preferred method of acquiring data for formation evaluation. This paper will present experiences with a new formation tester tool, which has the potential to evaluate reservoirs in wells that are mechanically complex or pose a high risk to the operator.
Current challenges for new oil and gas discoveries in remote locations, added to the geological and structural complexity of the Colombian basins has made LWD technologies the best method of reservoir evaluation. With complex stress regimes and common wellbore stability issues, formation evaluation programs frequently run over budget or fail to acquire the desired information. As a direct consequence of the difficulties encountered, a wide array of LWD sensors has been developed, based around the three principles of investigation, innovation and technology. A new technology has recently been deployed to several basins within Colombia providing a method of acquiring formation pore pressure measurements in real time.
Data from two projects, one in the Putumayo basin and the other in the Upper Magdalena Valley basin, will be presented. The addition of an LWD formation tester provides increased data assurance because it was run as part of the drilling bottomhole assembly (BHA). Overall, the LWD formation tester succesfully obtained valid formation pressure measurements in over 90% of the attempts to date. This data has allowed the operators to identify several compartments inside their reservoirs.
This paper will demonstrate how the addition of a formation tester into the LWD suite has enabled reliable reservoir evaluation, providing both technical and economic benefits. With the integration of a formation tester as a part of the drilling BHA, the operators were able to acquire a complete real-time profile of their reservoir and to allow long-term behavior to be predicted.
Engineered Fiber-Based Loss Circulation Control Pills To Successfully Combat Severe Loss Circulation Challenges During Drilling and Casing Cementing in Northern Pakistan
Authors: Arshad U. , Jain B. , Pardawalla H. , Gupta N. , Meyer A. 
Published: June 2014

Abstract
Loss circulation is the biggest challenge after drilling and weather-related problems during the process of constructing new wellbores. As per industry figures, more than USD 2 billion per year are spent in combating losses. In the Kohat-Potwar plateau of the Upper Indus basin of northern Pakistan, a harsh and complex environment, a well usually takes anywhere from 180 to 270 days to drill. The overall time taken to drill depends on the formation thicknesses, severity of the losses, and the concession location within northern Pakistan.
High-pressure water zones are located close to salt and shale formations, above the potential reservoirs. While drilling through the high-pressure formations, high mud weights greater than 1980 kg/m3 (16.5 lbm/gal) are required to maintain a well under control, which often leads to induced losses during drilling and also while running casing. The mud weight is typically lowered to 1500 kg/m3 (12.5 lbm/gal) or lighter to combat massive losses in naturally fractured limestone formations in the production hole.
Engineered fiber-based loss circulation (EFBLC) control pills, based on a specially engineered fiber system and the particle size distribution principle, were developed to control the losses. The pills were effective in curing losses during drilling and while cementing; prior to the introduction of the EFBLC pills, operators spent days in combating losses with numerous traditional methods. Also, the pills were robust enough to work in water-base mud (WBM), oil-base mud (OBM), or synthetic-base mud (SBM) environments with weights up to 2040 kg/m3 (17.0 lbm/gal).
In applications in northern Pakistan, the EFBLC pills were successful in combating the losses while drilling and cementing, thus reducing the threat of nonproductive time (NPT);minimizing the quality, health, safety and environmental (QHSE) concerns of well control; and preventing costly remedial jobs due to poor zonal isolation.
Integrated Conceptual Probabilistic Model Forecast to Optimize and Prioritize the Development Plans of Exploration Prospects, Early Visualization: Sur Lago Trujillo Field Case
Authors: Pérez F. , Albarracin R. , Jazzan W. , Valera A. , Llavaneras A. , Arguello V. , Griborio G. , Novaes K. , Acosta I. , Luján L. 
Published: June 2014

Abstract
Generating an integrated conceptual probabilistic model forecast for exploration of hydrocarbon fields is essential to the decision-making process when developing a strong portfolio of exploration prospects. It is important not only when considering the potential volume that could be discovered within each prospect, but also when considering drilling plans for extracting these reserves. It is important to both define the best strategies for achieving strong growth and sustainable profit over time and to consider possible risks and uncertainties that could impact such results.
Southeast of Lake Maracaibo, the most important axis of production growth is located within the western part of Venezuela, formed by the Ceiba, Tomoporo and Franquera fields, where a set of exploratory prospects comprise 36 potential reservoirs. Exploratory wells are planned to validate the estimated reserves of the development to help increase oil production. The optimization and prioritization of exploration prospects provides the foundation for creating an interactive workflow that is automated, versatile, and innovative to help optimize the portfolio of the defined prospects.
This workflow provides a strategy based on the generation and use of a probabilistic conceptual reservoir model based on information from neighboring fields and exploratory studies. Using this approach, the initial potential for each well and each of the prospects' different production profiles can be probabilistically calculated based on the development strategy. This allows visualization of how many wells should be drilled, the capabilities of the surface facilities, the number of personnel required to operate the field, and other additional important aspects.
This conceptual probabilistic model forecast (prospects—wells—surface) is connected to an economic-risk-uncertainty model, creating fully integrated modeling. When new information is gained, automated adjustments can be made, thus achieving quick optimal viewing of opportunities within the portfolio of prospects and improving decision making.
Reservoir Characterization and Estimating EOR Potential with a Sector Model Simulation of Señal Picada, a Large Mature Field in Argentina
Authors: Manestar Gastón , Thompson Anthony , Rivarola Laura Gómez , Mykietiuk Karina 
Published: June 2014

Abstract
A number of fields in the Neuquén Basin are currently mature waterfloods. To obtain significant incremental volumes of additional oil, EOR technologies need to be screened and then implemented.
Señal Picada is one of Argentina's largest fields with nearly 500 wells in 2013. These wells have exploited all the oil bearing areas of the field and have identified all of the oil water contacts in the various reservoir that make up this field. In 2013 the field was producing with a 96% water cut. Therefore for this field to have a long term future, post waterflood opportunities need to be identified.
To accelerate the characterization of such a large field, it was decided to study a sector of the field which was thought to be suitable for an EOR pilot and where an excellent quality core has been acquired.
By focusing on a sector, the construction and data QC of both the static and dynamic models was faster than if an attempt was made to construct a full field model. Additionally more iterations between static and dynamic models were possible in less time to identify which variables had the greatest impact on the history matching process and forecasts. With the main reservoir layers characterized, it was possible to both extrapolate the learning to the whole field and to evaluate EOR processes in more detail.
The sector modeling demonstrated that 3–4 stratigraphic cycles had the highest potential for EOR. However within these cycles two very different facies were identified by the study, a high permeability sandstone suitable for EOR and a low permeability carbonate which would negatively impact any chemical injection program.
The dynamic modeling of the field combined with analysis of the logs of infill wells surprisingly demonstrated that there was significant attic oil potential. This was interpreted as being due to the high vertical permeability in the field resulting in a waterflood which was more affected by gravity forces than viscous forces.
In conclusion the sector modeling study characterized the reservoir, identified the key sands with potential for exploitation by EOR and that there was remaining oil to be recovered both by the reduction of the residual oil saturation to water or by improving the vertical sweep efficiency.