bluuebunny/crossref_metadata_2025_split huggingface dataset:
Field Performance of Automated High-Speed Mud Pulse Telemetry System
Authors: Emmerich Wojciech , Akimov Oleg , Brahim Imed Ben , Greten Alexander 
Published: January 2016

Abstract
Present logging-while-drilling (LWD) technologies have substantially increased the amount of information collected downhole. Mud pulse telemetry (MPT) is the core real-time data transmission technology in the oil industry, and it must deliver answers while drilling with equal log densities despite the increased number of services. Ultimately, faster real-time data rates are required when a compromise between rate of penetration (ROP) and log density is not an option. In particular, when using high-density and high-plastic viscosity oil-based muds in deep wells, transmitting data at high rates presents challenges due to the harsh transmission channel conditions.
We describe improvements to the MPT system, enabling reliable data transmission with physical data rates of 10bits/s and higher. Special signal sequences are used to automatically adjust adaptive filters. The pulser sends out the sequences regularly, enabling the surface system to tune the adaptive filters for changing channel conditions. The filter performance is tested and saved into a data base with quality indicators, empowering field personnel to optimize decoding quality through better decision making. Enhanced signal processing algorithms on the surface significantly increase the success rate of this automated system, as well as improve the decoding quality and reliability.
This improved MPT system has been effectively run in challenging fields in different regions. The system has achieved improved operational performance and higher system reliability compared to offset runs. Complex bottomhole assemblies (BHA) with many LWD services can be deployed with outstanding data density and no ROP reduction. Its ease of use enables the increase of real-time data rates and timely decisions when decoding quality indicators start to decrease. Furthermore, the new system introduces higher automation level, which allows the field service engineer to concentrate on delivering more answers to the operator.
By enabling high-speed data rates in a wider variety of environments as well as higher data rates in standard settings, the improvements in MPT increase the safety while drilling and lower the overall cost of drilling wells.
Team Approach to Horizontal Drilling Optimization in the Marcellus Delivers Record Setting Performance
Authors: Livingston Denise Azuaga , Andes Drew , Czerneski McKenna , Bauer Scott , Castro Boris , Gorr Kevin , Coffman Ryan , Beebe Luke 
Published: January 2016

Abstract
The Marcellus tight gas shale formation in the northeast Appalachian region of the USA represented 40% of total domestic production in 2014 and 2015, and is strategically positioned close to its gas demand. To increase production and improve well economics, operators are drilling from multi-well pads, requiring complex well profiles. This is driven by local logistics and environmental requirements. This paper will discuss the main drilling challenges faced by one operator and their directional drilling provider, while drilling more than 1 million feet in this area, and the evolution of effective drilling practices including bit and bottom hole assembly (BHA) design, drilling parameter optimization and reservoir navigation techniques. This resulted in the achievement of a drilling record of a mile a day on the most recent pad.
Typically steerable motor assemblies require multiple runs to drill the curve and lateral sections of a directional well. Different formations in the curve may yield different build-up rates (BUR) requiring close attention to well planning and execution to land in the target zone. Longer laterals for optimal lease development may cause undesirable torque management issues. A drilling system with near bit inclination capability and near bit gamma is ideal for TVD control to stay in the producing target zone. Recent advancements in rotary steerable systems (RSS) have resulted in high build-up rate designs that meet these requirements. To address these challenges, the operator, engineering and service companies created a drilling program for eight wells with the objective of drilling the 8¾-in hole section in one run, including 3D well profiles, matched bit and BHA designs, optimized drilling parameters for each curve and lateral portions of the well, and reservoir navigation techniques. The 8¾-in hole section length ranged from 4,400 to 14,700 ft including curves varying from 8°/100ft to 10°/100ft and an average lateral section length of 9,700 ft.
The results of this team approach and optimized drilling program delivered improved rates of penetration (ROP) by 10% compared to previous pads and an average of 1.12 runs per well. The two most recent wells set drilling records of a mile in a 24 hour period resulting in 31% and 30% reduction in drilling time while staying 100% in the target zone compared to 97% average from previous pads. This successful collaboration between all parties involved resulted in optimized drilling time, reduced operational costs and financial predictability and consistency. The authors will explain the process used and show examples of this outstanding drilling performance using case histories from the program in the Marcellus shale play.
Swab and Surge Pressures with Reservoir Fluid Influx Condition during MPD
Authors: Samuel Robello , Lovorn Randy 
Published: January 2016

Abstract
With managed-pressure drilling (MPD), there is a need to have precise control on the profile of annular pressure while drilling and cementing. However, current methods using conventional calculations for controlling bottomhole pressures in MPD wells do not properly take into consideration the elasticity of drillpipes under reservoir fluid influx and, therefore, do not control the proper pressures. For these reasons, a method for more precisely controlling the annular pressure profile throughout the wellbore is required. The purpose of this study is to investigate the dynamic motion of the drillstring when there is an influx of formation fluid, with particular interest focused on the effect of bottomhole pressure. Increased underbalanced and managed-pressure drilling operations have necessitated predicting wellbore pressures more accurately, as they allow for reduced fluid loss and reservoir influx. While drilling through or reciprocating in a potential reservoir zone where the borehole and formation fluid pressures are in a narrow margin under a managed-pressure condition, the swab pressures may cause the wellbore to be underbalanced for a small period of time.
At certain times, an incremental influx for a short duration may be potentially detrimental. Neither the steady-state model nor the transient model is comprehensive enough to predict the wellbore pressures correctly, as both models neglect the reservoir fluid influx or fluid loss under this condition. This paper presents a coupled swab/surge model, whereby the wellbore bottomhole pressure can be predicted more accurately with a reservoir fluid influx. A full balance of mass and momentum for pipe and annulus flow is solved. The model also includes the effects of fluid inertia and compressibility, wellbore elasticity, axial elasticity of the pipe, and temperature-dependent fluid properties. The transient-gas reservoir model allows for investigating the effect of produced gas when the formation pressure exceeds the bottomhole pressures. This model allows for measuring the influx as a function of pipe movement and predicting the amount of influx as a function of time.
The practical usefulness of the theory, backed by the fundamental analysis, is demonstrated with numerical cases. The effects during underbalanced conditions have been analyzed, and several non-intuitive transient effects, such as the observation of reduction in surge effects while swabbing and vice versa, are highlighted.
Deepwater Tieback Cementing Design Challenges and Engineering Approach - Gulf of Mexico Case Study
Authors: Elhancha Anouar , Dooply Mohammed , Koons Brian , Saleh Muhammad 
Published: January 2016

Abstract
The Gulf of Mexico post-moratorium well design requirements became more stringent after the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) imposed the worst-case discharge (WCD) criteria. The conventional design configuration of nested liners does not always allow meeting the WCD criteria and the long string configuration presents operational limitations.
Tieback casings and liners, on the other hand, enable reaching the well objective while meeting the WCD criteria. However, tieback casings and liners present several operational challenges during the well construction phase, such as casing design, hardware selection, running in the hole and cementing.
Cementing design challenges, include defining the optimum top of cement (TOC) to mitigate annular pressure build-up (APB), managing high placement pressures resulting from tight annular clearances to prevent damages to casing hardware, optimizing centralization and fluid properties for safe cement placement and effective mud removal, and estimating hook load variations during cement placement to prevent premature release of the running tool.
This paper will mainly focus on the above cementing design challenges and discuss the engineering techniques used to approach them. The first part of the paper will review the limitations of current cementing design tools in tieback configurations. The second part presents the applications of and key learnings from engineering techniques to overcome the limitations in cementing design to achieve better cement placement and effective mud removal. Two case studies from Deepwater Gulf of Mexico will be presented.
New Wireline Extreme Pull Systems Reduce Gulf of Mexico Deepwater Fishing Incidents Saving Operators 12 Days of Deepwater Rig Time and USD 9 Million
Authors: Fisher Bill , Daugherty William T. , Sarian Serko , Tucker Jim , McManus Dacey , Babin Chris , Varkey Joseph , Dalhami Issa Al 
Published: January 2016

Abstract
The combination of a newly developed extreme-tensile-strength steel wireline cable armor and polymer encapsulation technologies has recently created a second generation of low-torque, extreme-strength wireline cables. The high-pull system is complemented with high-capacity winch units for surface data acquisition, tension-relief capstans, and downhole well accessories. The resulting surface pull capacity of wireline conveyance reaches 26,000 lbf, a 25% increase over the strongest system available previously.
When the 21,000-lbf system was introduced in 2010, deepwater fishing incidents dropped to less than 1% of total descents. However, with 3 days per fishing operation, associated deepwater fishing time remains high. The new high-pull system has been deployed in the Gulf of Mexico since October 2014. Pulls exceeding 21,000 lbf made it possible to prevent four instances of otherwise unavoidable fishing incidents, saving more than 12 deepwater fishing days and USD 9 million of rig time. In 2015 Gulf of Mexico fishing incidents have dropped to a record low 0.4% of total descents.
Efficiently Transferring and Sharing Drilling Data from Downhole Sensors
Authors: Baumgartner Theresa , Zhou Yang , Oort Eric van 
Published: January 2016

Abstract
The drilling industry has begun to cherish the value of data collected from downhole sensors, often gathered at high frequencies. Moreover, it has started to capitalize on the availability, analyses and credibility of this data through step-changing knowledge gains that have enabled meaningful drilling performance improvements. As a result, topics like data quality, data ownership, and data integration are now routinely being discussed among stakeholders as data from downhole memory tools slowly starts to integrate into routine well planning and optimization workflows.
The collectors of data usually are not the sole owners and main beneficiaries of such data. Large amounts of data have to be transferred from service providers to various collaborators within and across companies. The process of agreeing on a data format, relevant accessory information and means of transfer, is currently laboriously repeated on a project-by-project basis. This practice not only consumes unnecessarily resources on both ends, but also carries the risk of losing crucial contextual information. WITSML standards are often unsuitable for large high frequency data files and do not provide enough flexibility for certain contextual information.
This work proposes a file format suitable for securely storing downhole data and sharing it across all stakeholders, providing both flexibility and simplicity. The proposed file format implements a set of specialized horizontal and vertical dividers to structure contextual information on the well, the run, and the sensors, and to store them in the same file as the measurements. Among other things, well and section information, responsible personnel, equipment and sensor properties, time calibration, and operational parameters may be specified. The inclusion of both required and optional inputs ensures both flexibility and essential context, and allows the coverage of a variety of applications. It is comparable to the Log ACSII Standard (LAS) file that quickly found wide acceptance in the well logging community and beyond after its introduction in 1990.
The implemented dividers enable the data files to be easily accessed by variety of programs and comfortably viewed by the human eye using any standard spreadsheet or text file application. Importing and exporting applications can be provided to the users, who can then easily produce these files from raw data for transfer, or integrate them into existing data management systems.
Stakeholders, such as operators, service companies, and tool manufacturers are involved with the creation of this standard file format to ensure consent amongst all users. The standardization of downhole sensor data files proposed in this work marks an important step towards automated analysis of downhole data, reduction of data loads, and data integration. Our approach is illustrated using various examples of how the new standard can be applied on actual field data.
A Deepwater Openhole Gravel Pack Completion with Prolonged Well Suspension without Initial Cleanup: An Angola Block 15/06 Case History
Authors: Staltari D. , Urdaneta J. , Barradas O. , Pellicano’ D. , Ripa G. , Fernandes P. , Cauende C. , Sonangol E. P. , Nasrallah M. M. , Aye Y. A. , Djouli L. B. , Adeolu A. I. , Magloire B. A. , Kumar A. , Gadiyar B. R. , Parlar M. 
Published: January 2016

Abstract
Most of the deep water reservoirs in Angola are weakly consolidated sands, requiring sand control, and openhole gravel packing is one of the most widely used sand control techniques in the area, Block 15/06 being no exception. High inclination wells targeting multiple reservoir sections interlayered with reactive shales, relatively low frac window, and prolonged well suspension without well cleanup were some of the challenges that needed to be addressed to ensure completion integrity and well productivity.
This paper presents the measures taken during the design and execution phases to address the project challenges, along with an evaluation of completion integrity and well performance. Analysis of the downhole gauge data is detailed for one of the wells as an example, illustrating the importance of including downhole gauges in the completion.
Selectively Stimulating Oil Production in Mature Naturally Fractured Carbonate Reservoirs
Authors: Guillot Guillermo , De Antuñano Yuri , Cuadras Romel , Milne A. , Miquilena E. , Losada M. , Molero Nestor , Mujica L. , Vazquez J. , Santini J. 
Published: January 2016

Abstract
Carbonate reservoirs in the southern region of Mexico are deep, hot, and naturally fractured. The intensity of natural fractures varies greatly. Wells in these formations are typically completed with multiple perforated intervals, with different producibility and pressure. The oil production is dependent on the presence of natural fractures, which, with time, are invaded by the aquifer, leaving the remaining reserves in the low-permeability formation matrix. The challenge when stimulating these wells is not only to selectively divert the treating fluid away from the natural fractures, but also to reduce water production from the natural fractures and fissures after the treatment.
To divert treating fluid from the lower-pressured natural fractures requires a viscous fluid with fibers or solid particles, whereas to limit water production after the treatment requires a disproportionate permeability modifier (DPM). However, the adsorption of conventional cationic low-viscosity DPM polymers is often limited in carbonates. This led to the development of a viscous zwitterionic DPM (ZDPM) fluid to both divert stimulation fluids from the natural fractures and reduce water production after the treatment. The ZDPM fluid comprises two polymers and a viscoelastic surfactant at a concentration below the critical micelle concentration. The adsorption and DPM properties of the polymers are further enhanced by adjusting the pH and salinity of the fluid.
More than 150 treatments have been performed in mixed carbonate formations with natural fractures and fissures using the ZDPM fluid. The oil production increased by as much as 220% while at the same time the water cut was reduced by up to 23%. This is supported by core flow testing in which the ZDPM fluid reduces the effective permeability to water by up to 80%, whereas in oil-wet cores, the fluid water-wets the core and effectively stimulates oil production, in some cases by more than 25%. The use of the ZDPM fluid has greatly improved the economics and feasibility of treating wet producers in naturally fractured dolomitic limestone reservoirs.
This paper summarizes the laboratory evaluation conducted to validate the use of viscous ZDPM fluid and the successful application in the field to divert stimulation fluids from the natural fractures and reduce water production after the treatment.
Developing a Marginal Field Combining Stimulation and Water Control to Limit Scaling
Authors: Martinez A. , Melo O. , Resendiz T. , Aguilar J. , Vazquez J. , Molero Nestor 
Published: January 2016

Abstract
Many oilfields in southern Mexico produce from naturally fractured carbonate reservoirs with a high water cut. The majority of the remaining reserves are in the formation matrix. The objective when stimulating these wells is to connect the formation matrix with existing fractures. However, in some cases, the water-oil contact is close to the producing interval and the salinity of the water is more than 350,000 ppm. This results in rapid scaling and loss of production. The time for the scale to plug the well is a function of the volume of water produced.
The challenge in these wells is not only to selectively divert the treating fluid away from the natural fissures/fractures—thief zones—invaded with water, but also to reduce water production from the natural fractures and fissures after the treatment. To treat the formation matrix, the diverter fluid must reduce the high permeability of the water-saturated intervals without impairing the permeability of the oil-producing intervals.
Historically, in southern Mexico, viscoelastic surfactants have been used as main diverter for acidizing treatments. However, these systems have been successfully implemented in other applications. The surfactant also acts as a disproportionate permeability modifier (DPM) as the water cut is reduced after the treatments. The water cut of wells stimulated with treatments including the surfactant-based diverter remains below 10%, and the wells typically produce over 1,000 BOPD for more than 200 days before the scale has to be removed. The water cut of wells treated conventionally in the same field is typically above 60%, and the wells produce for fewer than 50 days after being treated before plugging with scale. The ability of the solids-free surfactant-based diverter to limit water production has made possible developing a field that previously was considered uneconomic due to the saline precipitation into the formation.
Study of Condensate Blockage and Its Remedy in Eagle Ford Gas- Condensate Zone
Authors: Pu Hui , Li Yinghui 
Published: January 2016

Abstract
Tight gas condensate reservoirs are an important source of reserves and exhibit unique flow and thermodynamic behaviors. Owing to the overwhelming effects from nano-pores, formation damage mechanisms are uncertain. Significant phase and compositional change occurs in the circumstances where nano-pores dominate. Productivity reduces faster than most existing models could explain owing to a lack of understanding how the condensate affects deliverability, and how the flow and phase behavior would have been altered in unconventional reservoirs caused by those nano-pores. This paper presents a novel formulation that consistently evaluates capillary force using pore size distribution (PSD) directly from core measurements. This study develops a better understanding of production- induced formation damage in important liquid-rich formations for an optimal production strategy, to mitigate productivity risks associated with condensate blockage at reservoir conditions.
Effects of High Pore Pressure on Perforation Tunnels in Both High and Moderate Compressive Strength Rocks
Authors: Haggerty D. , Craddock G. , McGregor J. 
Published: January 2016

Abstract
Knowing the productivity to expect from a well is highly dependent on how deep the perforation penetrates. Besides the quality and explosive load of the shaped charge, the type of rock and the stress it is subjected to help determine penetration depth.
Using the equipment capable of stresses and pore pressures at extremes found in deep, outer-shelf wells, a made-for-purpose perforation laboratory offers insights regarding perforation behavior. Care was taken in the tests to ensure the configuration used matched a typical downhole setup including the applied stress on the rock target. Using Sandia National Laboratories' CTH shock wave physics software, computer simulations were run to compare with the results to offer further insight.
The results from the tests did not necessarily follow trends from extrapolating data from similar tests conducted at lower pressures, historically using matching net stress as a substitute prior to obtaining higher pressure-capable equipment. It was observed that a large increase in pore pressure resulted in only a small decrease in perforation penetration. Formations with various rock properties behaved differently, and with the new higher capacity equipment the ability to quantify these differences was improved. Other attributes beside penetration were observed such as perforation tunnel geometry differences between the high and moderate unconfined compressive strength (UCS) rocks.
This paper discusses the effects on the magnitude of penetration and quality of perforation tunnel in both the high and moderate strength rocks, and possible implications on flow. Simulation runs were conducted on the effects to a perforation at elevated pressure and compared to the test results showing the value of conducting such simulations and insights gained.