bluuebunny/crossref_metadata_2025_split huggingface dataset:
Expandable Liner Hangers in Off-Bottom Cementing Applications Reduce Cost and Increase Reliability: Regional Case History
Authors: Hayward Daniel , McCormick John , Matice Marilyn , Dickinson James 
Published: June 2014

Abstract
The oilfield continues to experience increasing material costs for land wells as well as hydrocarbon depletion in common shallow reservoirs. To offset the resulting impact on profitability, reducing rig time and cost with new technologies has been critical for maintaining project profitability.
This paper is intended to inform operators of the advancements made with off bottom cementing (OBC) system technology, including a diverter (DV) tool, which is the crux of this system. This paper will also consider new well design opportunities that will not only improve reliability, reduce installation time and increase versatility in new drills but also can be implemented in pre-existing land wells.
This paper incorporates case histories in which four original OBC applications in South Texas provided consistent material cost savings and improved reliability while providing the capacity to strategically isolate adverse zones above the target formation. The paper will demonstrate consistent reduction in overall well cost by enabling the elimination of a five inch casing string that was designed in the original well plan. The new OBC plan provided a larger openhole ID section with more surface area to the target formation.
Running 7" liner to TD using turbine technology in Gullfaks Satellites and Oseberg Fields
Authors: Corriveau Jean-Philippe , Nafikov Rustem , Bryce Toby , Prescott John 
Published: June 2014

Abstract
In the Norwegian sector of the North Sea west of Bergen, unstable shales, coals and paleosols in the reservoir have regularly resulted in problems when running liner. Conventional mitigations learnt from previous wells or taken from similar fields have been adapted, but running 7″ liners successfully to TD at the first attempt has continued to be a challenge and it is desired to drill longer horizontal wells through these unstable formations in order to improve the recovery factor. New mitigations are therefore considered, including a turbine power shoe that had been used successfully in other countries.
The turbine power shoe provides the ability to rotate a reamer shoe without rotating the whole string from surface, while it requires limited changes to the liner string and running parameters. It is an additional tool to cross ledges and unstable intervals. The tool has been used in four wells in Gullfaks Satellites and Oseberg fields. In all these cases, the turbine shoe was activated and the liner was run to TD. Therefore the turbine power shoe will continue to be considered as an additional mitigation for running liner at high inclination through unstable formations.
Avoid Pilot Holes, Land Wells, and Optimize Well Placement and Production with Deep Directional Resistivity Logging-While-Drilling
Authors: Dupuis C. , Mendoza-Barrón V. 
Published: June 2014

Abstract
Landing horizontal wells in a reservoir is a critical task, and the accuracy of the result drives the economics of a well. Except when the geological environment is largely predictable, relying on well to well correlation techniques or on pilot holes fails to mitigate important risks in landing most wells. This paper details how a different solution more effectively manages the risks of a landing operation. The deep directional resistivity (DDR) logging while drilling (LWD) tool has been in use on dozens of fields around the world. The key features of the technology that play a role in de-risking landing wells range from the tool hardware, which enables a deep depth of investigation, sensitivity to direction, and a wide frequency range, to the surface interpretation software, which provides real-time automatic multilayer inversion. Applied to a landing in a North Sea field, the DDR LWD tool was part of the solution for meeting ambitious field development targets.
Innovative ERD Well Construction for Severe Losses and Wellbore Instability Environment
Authors: Yadav Anurag , Verma Jaywant , Qureshi Ahmad Shakeel 
Published: June 2014

Abstract
While designing a development plan for a field that was underneath a city, major engineering and design stumbling blocks were encountered for the extended-reach drilling (ERD) prototype. There was also the risk of encountering shallow gas and high concentrations of hydrogen sulphide gas across different formations in the field. Hence, the biggest challenge for the field development plan was to develop a well construction design that would provide well integrity and at the same time allow running casings and completions to the desired depth. In addition, different hole sections were experiencing well control, loss circulation, and wellbore stability issues all at once, resulting in a loss of well integrity or total lost circulation. This was making torque and drag unmanageable, which meant inability to drill, run conventional or drillpipe conveyed wireline logs, or run casing and completion. Also, there was a high incidence of stuck pipe events due to wellbore stability issues and hole cleaning problems in a lost circulation scenario. Due to the torque and drag limitation, performing a sidetrack was not an option in the field. In this operation, an extensive offset well analysis and comprehensive risk assessment was done to put together an innovative well construction design and a customized drilling procedure that would lead to successful drilling and completion of a world-class ERD well under high-to-total loss circulation scenario. The selection criterions for technologies for the BHA and the drilling procedures were based on the specifics of designs and highlighted how a predrill geomechanics modeling, a drilling liner application, fit-for-purpose equipment selection, optimized well placement, judicious casing flotation, advanced logging-while-drilling technology application, and tailored drilling practices that not only made an undrillable well drillable but also set a new industry limit to run smart-completions.
First Sand Clean Out of a HPHT Well on the Norwegian Continental Shelf Using Rig Assisted Snubbing and Sand Cyclones
Authors: Brähler Johannes , Helland Anders Groth 
Published: June 2014

Abstract
The Kvitebjørn field is located in the Norwegian North Sea – production is based on gas/condensate bearing reservoir formations. The reservoir/field is classified as high pressure high temperature (HPHT). The main field development is centered on a steel jacket platform with combined production, drilling and quarters facilities (pictured).
This paper will describe the background, planning, execution and results of a rig assisted snubbing (RAS) operation conducted to clean out the production liner in Kvitebjørn well A-9 T2.
Intial production from well A-9 was significantly below expectations. At first this was attributed to complications related to a closed/stuck valve in the bottom of the completion string. A successful coiled tubing milling operation eventually removed the blockage caused by the valve but the poor production performance continued. It was concluded that wellbore fill in the production liner was blocking production and mechanical access to the reservoir section.
Planning was initiated for a wellbore fill cleanout operation and rig assisted snubbing was selected for the task. To ensure a successful operation a number of significant challenges were overcome including limitations on available experience with the type of operation, availability of qualified equipment and logistics issues related to other on-going activities on the platform. Fluid management was also a major consideration for the planning/operations team.
After an intensive planning period the operation was executed successfully in 2013 and the production liner in the well was cleaned out down to the reservoir section. Additional wireline conveyed perforating could then be performed. Despite these successful actions production from the well continues to fall below expecations and further remediation activites are being evaluated.
Experimental and Visual Simulation of Gravel Packing in Horizontal and Highly Deviated Wells
Authors: Changyin D. , Jiajia L. , Yanlong L. , Huaiwen L. , Lifei S. 
Published: June 2014

Abstract
The gravel packing process in horizontal or highly deviated wells involves the solid-liquid two-phase flow and the sand-bed migration under complicated conditions, in which the sand carrier fluid filtrates into the formation and the mass exchange occurs between the fluid in screen-washpipe annulus and the fluid in casing-screen annulus. One of the key problems in gravel packing is to predict the α wave sand-bed equilibrium height to simulate the gravel packing process and optimize operation parameters. In this paper, a full-scale simulation equipment for internal circulation gravel packing in horizontal wells is utilized for the study of the effects of screen offset, flow rate, and sand concentration on the α wave sand-bed equilibrium height. The comparison is made among the results using three empirical equations to calculate the equilibrium flow rate. Based on Gruesbeck model, a more accurate calculation method of the equilibrium sand-bed height is developed. Then, the mass and momentum conservation equations of the gravel and sand carrier fluid of two-phase flow in casing-screen annulus and single-phase flow in screen-washpipe annulus and the flow coupled equations of these two flow systems are established. A mathematic gravel-packing model for horizontal and highly deviated wells is thus obtained. The solution of the model can lead to the development of gravel-packing simulator software package, which can be used to visually simulate the gravel packing process. The characterization of the gravel packing process and the variation of each dynamic parameter are also analyzed.
An Innovative Workflow for Appropriate Selection of Subsurface-Surface Model Integration Scheme Based on Petroleum Production System Nature, User Needs, and Integrated Simulation Performance
Authors: Tillero E. , Rincón J. , Nuñez H. 
Published: June 2014

Abstract
The generation of portfolio of opportunities from hydrocarbon reservoirs requires, because of its nature defined by process, more reliable production scenarios based on better decisions making from the whole petroleum production system (reservoir-wells-surface facilities). Therefore, a truly production forecasting would be obtained if boundary conditions imposed by reservoir, well completion and surface network are considered through integration schemes that allow to emulate, as accurate as possible, operating conditions expected (flow and pressure behavior) from network–well to reservoir.
This paper introduces an innovative workflow, developed for explicit simulation of subsurface-surface models, to assist assessment of IAM schemes (Integrated Asset Modeling). This assessment was based on a qualitative algorithm focused on defining the most appropriate subsurface-to-surface integrated modeling, considering the petroleum production system nature and users needs. In addition, a comparative analysis of performance variables from integrated simulation output (computing time, material balance error, among other) was implemented by combining both reservoir-network coupling and balancing methods available in the modeler used (AVOCET™). A test model was considered for the assessment of the proposed workflow.
Results showed that better decision making is reached out for integrated petroleum production system simulation when the proposed workflow is implemented, depending on the nature of flow and pressure behavior through the system, simulation performance, and users needs (reservoir, production, or processing engineer). In addition, it is suggested that a comparative assessment can be considered to evaluate reservoir-network simulation performance if both convergence and stability of the integrated model and user expertise is on demand.
For the test model, better performance was obtained from coupling scheme at wellhead, with both the lowest computing time and material balance error percentage of fluids, followed by those from bottomhole coupling scheme. As far as reservoir-network balancing methods concern, results showed that balancing controlled by reservoir simulator presented shorter computing time as much as lower oil, water, and gas material balance error percentage, compared with the others reservoir-network balancing methods tested.
Overcoming Ultradeepwater Cementing Challenges in the Caribbean
Authors: Gupta N. , Bogaerts M. , Bellabarba M. , Mendiola A. , Salehpour A. 
Published: June 2014

Abstract
Ever increasing energy needs have encouraged the operators to explore newer areas in deepwater. One of the high potential areas under exploration is the Caribbean basin, which includes Trinidad and Tobago, Suriname, Guyana and French Guiana. Due to the extreme environmental impact that can result from incidents occurring offshore, well integrity is a critical element in offshore development.. Cementing plays a major role in ensuring well integrity and this paper will cover various cementing challenges that were faced in Caribbean deepwater zones. The water depth of wells in Caribbean can be as much as 2300m with seabed temperature of about 4 ºC causing complex heat transfer and requiring fluid modeling software to accurately predict the bottom hole circulating temperature (BHCT) profile. Deepwater wells in the Caribbean can also be affected by the formation of gas hydrates. Cementing in hydrates requires cement slurries with low heat of hydration (HOH). The results from several field studies were used to select an optimum slurry design to successfully cement in hydrates. The wells in this area are also characterized by low fracture gradients with a narrow window between fracture and pore pressures. The cement jobs are designed with advanced computer aided design (CAD) to accurately simulate equivalent circulating density and assist in designing fluid placement within this narrow window. Engineered lost circulation material (LCM) can be used in fluids to achieve successful cement placement. Fluid modeling software also helps in optimizing mud removal by simulating the impact of centralizer distribution, optimizing spacer properties and more. To evaluate cement placement a combination of advanced acoustic logging-while-drilling (LWD) tools and pressure analysis can be used for deeper sections while for riserless sections, visual feedback from remote operating vehicle (ROV) can be used. A case study from Trinidad and Tobago and Southern Caribbean highlights some specific solutions and lessons learned.
Natural Gas Reinjection in a Heavy Oil Field Increases Foamy Oil Recovery
Authors: Fei Sun X. , Zhang Y. , Duan X. , Li X. 
Published: June 2014

Abstract
Foamy oil behavior contributes significantly to the anomalously high primary recovery of heavy oils observed in the Orinoco Belt, Venezuela. Nowadays, disappearance of this phenomenon results in a rapid increase in the produced GOR and a fast decline in oil production when the reservoir pressure is below the pseudo-bubble pressure. This paper presents the results of a laboratory investigation, including pressure-volume-temperature (PVT) studies of foamy oil-natural gas mixtures and coreflood tests, for evaluating the feasibility of the natural gas injection process for enhanced heavy oil recovery with foamy oil characteristics. The study characterized the natural gas dissolution process in the foamy oil, and examined the effects on viscosity reduction and foamy oil swelling of the presence of natural gas. Coreflood tests were carried out to investigate the effects on oil recovery of injection mode (huff-n-puff, continous gas injection, and intermittent gas injection) and their different process parameters, such as reservoir pressure, injection timing, permeability and the size of the gas slug. The results indicate that significant amounts of natural gas could dissolve in the oil, which would cause oil swelling, viscosity reduction and artificial foamy oil formation. Core-flooding tests show that the natural gas huff-n-puff process could increase oil recovery 7.8% compared to the primary pressure depletion process, indicating a greater potential for recovering heavy oil. The continous and intermittent gas flood processes were not viable methods to enhance oil recovery from the heavy oil reservoirs in the Orinoco Belt, Venezuela.
A Review at the Problem of Sanding in Colombia: Evolution and Cases of Evaluation for Sand Exclusion and Management Alternatives
Authors: Jaimes M. G. , Quintero Y. A. , Martin D. P. 
Published: June 2014

Abstract
Sand production in oil and gas wells is a complex problem that requires an integral analysis of rock mechanics, mineralogy, granulometry, etc. that allows a risk management in order to make the best technical and economic decision.
In this study the background, strategy used in the past and in the present to tackle the problem of sanding, and Cases of evaluation of alternatives SEM (sand exclusion and management) in the recent history of the fields Casabe, Lisama, Galán, Llanito and Bonanza, located in the basin of the Middle Magdalena Valley in Colombia, are shown.
The effects of water injection and the gravel packing, in the low drainage and repression of the reservoir in the Casabe field are shown. These effects are: injected water distribution, behavior of pressure and sand cleaning jobs in packaged and unpackaged wells, production, effective injectivity and bsw before and after the gravel packings, number of wells packaged, abandoned producer wells, injectors collapsed, etc. Also mentioned are other factors that affected the low drainage and the repression of the reservoir, such as: reservoir heterogeneity, granulometry (% fines), mineralogy (migratory and swelling clays, etc.).
After Casabe field experience, the problem was approached very conservatively, limited at the drawdown control and the use of special metallurgy and sand cleaning jobs, etc. Today the problem is focusing differently, considering new technologies and an integral analysis of the reservoir. To carry out the above, the methodology SEM (Sand Exclusion and Management) was developed for the selection and technical-economic evaluation of alternatives of exclusion and/or management of sand during drilling; completion and production, which including probabilistic risk analysis.
The following case studies are presented in this article: Application of the methodology SEMEvaluation and implementation of sand exclusion and management technologies Chemical Consolidation (Laboratory)Chemical Treatment (Laboratory – Oil field)Screen Less Frac (Oil field)Artificial Lift Experiences With Sand ProductionAcoustic MonitoringGeomechanics applied to reduce risk of sanding during drilling, completion and productionDesign and Implementation of Software Tool
Finally, conclusions and recommendations obtained in this study are shown.
Challenges and Successes in Horizontal Drilling Shallow 3D Unconventional Turbidite Reservoir, Mexico
Authors: Murillo G. Gutierrez , Zapata G. Villanueva , Medina E. , Centeno J. Salguero 
Published: June 2014

Abstract
Aggressive plans for exploiting vast oil resources within the Chicontepec basin (Mexico-Poza Rica) are currently underway. One of the most complex deposits in the world, this basin is qualified as an unconventional turbidite reservoir, and one of its characteristics is the existence of hydrocarbon resources in shallow regions. Horizontal wells within this basin are extended three-dimensional (3D) wells in parallel arrangement, suitable for termination techniques, such as simultaneous multi-fracturing.
Commercially developing these resources requires the construction of wells that present major challenges. These challenges can be attributed to low depth, required dog leg severities close to 8°/30 m, 3D geometry necessary for construction and horizontal navigation uphill "boomerang" within the target unconsolidated sand formations (which are thin and unstable with mechanical hydraulic limitations), superficial limitation of space, the use of conventional drilling equipment, and required exhausting analysis.
The successful exploitation of these wells was achieved with thorough planning simulation, detailed engineering analysis, and the selection of appropriate tools for each operational stage. Monitoring key factors during drilling was essential to helping prevent problems with uncompacted sands and gas migration.
The use of advanced technology helped reduce deviation from the plan designed for the well and helped achieve a successful completion using a rotary steerable system (RSS), in some cases from the first casing, to prevent collapse and initiate the construction of the kickoff point (KOP).
Capturing Regional Geomechanical Knowledge for Heavy Oil Carbonate Offshore Fields in Campeche Oriente-Mexico
Authors: Gavito D. García , Carrillio Galícia L. A. , García J. C. , Cabrera A. C. , Duarte A. P. 
Published: June 2014

Abstract
As part of the strategic projects for reserves incorporation in the south-east Mexican Gulf, Heavy Oil-Carbonate fields have been explored in an area of about 900 km2 called "Campeche Oriente". As of today, a total of 13 extra heavy oil offshore fields have been discovered and delimited. In order to characterize this area in an early stage of its development, a conceptual model for Wellbore Stability Analysis of the new fields, in coherence with a nearby developed fields Geomechanical knowledge has been built. As a first approach to evaluate the regional coherence on the geomechanical modeling parameters, an existing and calibrated model previously built in an offset development field was applied to the exploratory fields in Campeche Oriente basin, focusing in design and drilling optimization purposes. As a result of this analysis, nearby field modeling parameters showed good correlation in an area of 900 km2, covering the exploration fields. It has been possible to identify two main sectors (East and West) with differences in shallow sediments velocities leading to slight variation of the normal compaction trend. Based on these regional results, it has been possible to identify the fields that fall on each sector allowing, on a first stage of well design, the application of a fit for purpose geomechanical model, adjusted for each sector in order to reproduce geological conditions and operative events of the area. This analysis focusing on the operational experience, well logs/reservoir characterization information and lessons learned from an offset field has been an excellent starting point for the Front End Loading of the development wells to be drilled in the area, allowing to better understand, from a conceptual perspective, the expected behavior of the planned wells and design cost effectively according to it on a critical environment involving overpressure zones, depleted carbonate reservoirs and heavy oil.