bluuebunny/crossref_metadata_2025_split huggingface dataset:
Identifying and Addressing Drilling Dysfunctions in Long Horizontal Wells
Authors: Lund H. , Martel K. 
Published: June 2014

Abstract
Horizontal Montney wells in the Albright field of Western Canada drilled by all operators are riddled with motor failures. In 2012, ConocoPhillips drilled two wells in the field that gave us significant insight into the drilling mechanics of slim hole horizontal wells. After 6 consecutive motor failures in the lateral of the first well in 2012, the decision was made to take steps to understand what was happening down hole. The paper will cover the findings as they relate to understanding and mitigating some of the common drilling dysfunctions in the field including vibration, buckling, and loss of WOB while rotating.
This paper will provide some tools and ideas to identify and mitigate some drilling dysfunctions that cause drilling inefficiencies in fields all around the world.
During the planning phase it was determined that the field had a history of drilling dysfunctions. Of these dysfunctions, buckling was identified and addressed in the planning phase. Vibration problems were confirmed while drilling, and steps were taken to mitigate the vibrations. Significant loss of WOB (over 20klbs) while rotating without buckling was observed, and steps were taken to compensate for this loss. Data will be presented to dispute the industry assumption that a well is axially "frictionless" while rotating; significant drag can in some cases exist in a well even while in rotary drilling mode. An alternate theory to relate axial friction to RPM will be presented.
Various drilling dysfunctions are often common in the field, and often viewed as acceptable since the industry is still able to drill the wells. Dealing with the downhole dysfunctions our industry face will likely improve our drilling performance. The current theory on axial friction of rotating drill pipe is proven incorrect, which means a new mathematical model is needed for the torque and drag computer models. A practical method for measuring and dealing with the drag while rotating without the need for expensive BHA components will be presented.
Downhole Steering Automation and New Survey Measurement Method Significantly Improves High-Dogleg Rotary Steerable System Performance
Authors: Sugiura Junichi , Bowler Adam , Hawkins Richard , Jones Steve , Hornblower Peter 
Published: June 2014

Abstract
The first commercial high-dogleg rotary-steerable systems (RSSs) were introduced in 2011. These systems were specially designed to drill vertical, kick off, build at planned 8° to 12°/100 ft (or even higher), and drill the lateral to lengths of up to 6,000 ft in unconventional reservoirs (such as shale gas applications) in North America. Because of the improved economics and other benefits for efficient drilling a high-build-rate curve and lateral in single run, high-dogleg RSS technology has rapidly gained acceptance for drilling shale wells.
The performance of the high-dogleg RSS is greatly enhanced with automated steering mode in vertical and lateral sections by reducing a human–machine interaction and minimizing wellbore tortuosity in these sections. Downhole trajectory-control algorithms make small, but frequent, adjustments to RSS steering parameters, comparing the near-bit continuous survey data against a planned well trajectory. Downhole steering automation is an integral part of the overall drilling system automation that the drilling industry is pushing forward.
A new static and continuous (dynamic) survey method has been used in the near-bit sensors of a specific high-dogleg-severity (DLS) RSS. The new survey method significantly improved the inclination and azimuth measurement in near-vertical angles; thus, it not only enhanced the automated vertical drilling feature but also provided more accurate kickoff from a near-vertical position using the RSS near-bit static and continuous survey. In addition, improved continuous measurements around magnetic north and south allowed the closed-loop trajectory-following algorithm of the RSS to drill lateral sections more precisely in these directions.
The software simulation and field trials were conducted to test a new survey measurement method implemented in a high-dogleg RSS, along with automatic trajectory-following algorithms. In one of the field trials, the RSS drilled more than 10,750 ft (vertical, high-dogleg curve, and lateral) in one run, including 5,000 ft of vertical and 4,500 ft of lateral sections in automated steering mode, saving 4 days (about 30%) compared with the previous non-high-dogleg RSS runs. A unique combination of the new technologies has enabled increased well construction efficiency in shale plays by providing a step change in steering technology, trajectory-following algorithms, and downhole survey method.
Record Success in a Frontline Pilot Deployment of Intelligent Well Completion with Multiple Technology Applications
Authors: Okpokpor Obaro Amos , Azoom Iorkam , Alabi Isaac Babatunde , Nnanna Erasmus John , Oguntimehin Adegbenro B. , Mbanefo Edith Ifeyinwa , Erumwunse Courage Osasuyi 
Published: June 2014

Abstract
Shell Companies in Nigeria have engaged aggressively in searching for means of optimally draining the predominantly stacked reservoirs of the Niger Delta operating region. This quest, in 2002, led to the identification/adoption of intelligent well completion (IWC) technology as an acceptable means of connecting the multiple/stacked productive reservoirs to a single production well conduit (Single String Multiple - SSM).
This paper serves to describe how a dedicated deployment team analyzed various proven intelligent completions architectures and ultimately settled for the ‘direct hydraulic' system as the pilot trial IWC solution for SPDC's Well Victor-2, a 3-Zone intelligent well
The design comprises of interval/zonal isolation packers, Interval Control Valves (ICV), tubing and annulus Permanent Downhole Gauges (PDHG) for each zone and a low powered single well Surface Hydraulic System (SHS) with downhole data acquisition capability. The system is to be remotely monitored and operated by means of a field management supervisory application, named SmartWell Master™ (SWM), with some customization to accommodate the remote power and identified communication infrastructure constraint. The design offers easy operation and integration with the field control operational requirements and communication infrastructure.
In recognition of the regional security challenges, the SHS and associated communication components were designed to be protected by an external enclosure which should allow front access for maintenance purposes - this is in addition to the customized platform design. Within the same protective platform enclosure, a Thermoelectric Generation unit (TEG) is installed to provide the SHS with necessary electrical power.
A major configuration design challenge was that of ensuring efficient deployment of three hydraulic packers intandem noting that several deployment challenges had previously been recorded for single hydraulic packers' installations. Also, there were fears of inability to adequately confirm proper installation/sealing of a combination of external swell packers (integral with lower completion string) and internal hydraulic packers (integral with upper completion string).
This paper further outlines how cementation, dimensional accuracies, proper integration of lower and upper completions compatibility, assurance of proper platform design, surface equipment communication, definition and management of the interfaces between all vendors involved in the pilot deployment project, proper stakeholders engagement, among others were considered and treated as key success factors to the pilot installation.
Thermally Stable Explosive System for Ultra-High-Temperature Perforating
Authors: Barker James M. 
Published: June 2014

Abstract
As oil and gas companies continue to expand drilling and completion operations into increasingly demanding environments, perforating systems must be developed for these extreme conditions. Several upcoming oil and gas frontiers are being developed by operators that will have downhole temperatures exceeding 450°F (230°C); this means perforating operations at these temperatures will push, or even exceed, the limit of traditional explosive systems using HMX and HNS. The thermal deficiency of these explosives will be magnified further whenever the perforating guns are conveyed by tubing rather than wireline because the operational times will be significantly increased.
This paper describes a perforating system based on the thermally-stable explosive PYX, which overcomes the temperature/time limits of traditional explosives. Desirable characteristics of the bulk PYX explosive are discussed, along with design considerations for the major components that comprise the system: percussion detonator, detonating cord, detonation transfer elements, and shaped charges. The role of specialty booster explosives that complement PYX performance, such as NONA and BRX, is also discussed. The testing infrastructure and methodology undertaken to validate thermal performance at both the component and system levels are described, along with results of test programs that demonstrate successful performance to levels up to 480°F (250°C) for 100 hr.
Additionally, steps that promote operational success in the field, such as gun-preparation and loading techniques, are also presented.
Performance and Analysis of a Borehole Gravity Log in an Alaska North Slope Grind-and-Inject Well
Authors: Brady Jerry L. , Bill Michael L. , Nind Chris , Pfutzner Harold , Legendre Fabienne , Doshier Ronald R. , MacQueen Jeffrey D. , Beyer Larry A. 
Published: June 2014

Abstract
A new-generation borehole gravity meter (BHGM) and sonde have been developed and successfully operated under the rigors of a pressurized wireline logging operation in an Alaska North Slope solids injection well. The new BHGM addresses shortcomings of earlier technology, such as sonde diameter, maximum well deviation, depth correlation, reliability, and availability.
Borehole gravity logging provides a large depth-of-investigation alternative to the very shallow formation bulk density measurement obtained with conventional nuclear density logging tools, and the measurement accuracy is close to that of a nuclear density log. Therefore, it is a candidate for density measurements in wells with large near-borehole effects such as invasion, mudcake, rugosity, and completion hardware that are detrimental to nuclear density logs. A BHGM is also well suited for reservoir injection applications, such as the present case study, where changes in the pore fluid, and therefore bulk density, are expected at large distances from the borehole (many tens of feet) and long times (months or years).
We present the results of BHGM measurements made in a disposal well that has been receiving injected slurry of ground-up drilling cuttings and water for 12 years. Descriptions of the well injection history and BHGM log are presented along with performance data from the gravity and depth measurements. The BHGM density log showed agreement above the injection zone with a pre-injection openhole nuclear density log, but showed a large increase in density at the injection region.
Software for 3D gravity forward modelling, constrained by the known total mass of injected material and known porosity, provided a reasonable spatial model of the injected material in the formation consistent with the gravity measurements. This type of analysis, coupled with time-lapse BHGM measurements, can also be used in reservoir monitoring applications to visualize movement of waterflood fronts or gas expansion zones before they reach producing wells.
Radio Frequency Identification (RFID) Leads the Way in the Quest for Intervention Free Upper Completion Installation
Authors: Adan Iain 
Published: June 2014

Abstract
Traditional methods of running the upper completion system in a well typically include several interventions in order to complete the installation. Such activities require skilled resources and consume significant amounts of rig time. In addition, activities such as wireline, electric line and even coiled tubing intervention carry with them the possibility of operational problems leading to non-productive time (NPT). Elimination of such NPT and associated intervention costs has always been an industry goal, but while options exist for such operations as packer setting and tubing isolation, to date no approach has been available which can enable the operator to take full remote control of the installation.
As modern technology evolves so old technologies can be re-evaluated. One such technology is radio frequency identification (RFID) which offers the user flexibility in controlling downhole operations without intervention. RFID uses close proximity sensing to communicate by simply passing a coded tag through an antenna equipped downhole tool to actuate it. These tools also have a secondary means of communication by pressure pulse signature, or timer, if circulation of a coded tag is not feasible. Using this technology an upper completion system comprising packer, circulation sleeve and downhole barrier valve has been developed which is controlled by a single RFID module, thus providing a means to remotely control the installation, reducing running costs and the elimination of NPT.
In this paper the authors will review current upper completion operations and describe in detail the development and operation of an RFID enabled completion. A case study of the industry's first truly remote controlled upper completion, successfully installed in the Middle East will be presented.
The Use of Connection and Total Gases Quantitatively in the Assessment of Shale Pore Pressure
Authors: Alberty Mark , Fink Kristi 
Published: June 2014

Summary
Connection and total gas measurements were used qualitatively for decades in drilling oil and gas wells to identify overbalanced, underbalanced, or near-underbalanced pressure conditions (mud hydrostatic pressure relative to shale pore pressure). Results often conflicted with directly measured sand pore pressures (PP) and the pre-existing perceptions of shale PP. We propose a technique that allows mud gases to be used in a quantitative manner when (1) there is an increased understanding of the relationship between mud gases and shale PP, (2) the development of the logging-while-drilling (LWD) -based annular-pressure measurement allows for the real-time monitoring of downhole hydrostatic pressures, and (3) differences between sand and shale PP may exist as a result of the sand's structural position.
This paper presents time-based equivalent-circulating-density (ECD) behavior relative to block movement, flow rate, and total gas from Gulf of Mexico (GOM) wells, and explains the relationship to shale PP. These examples are quantitatively analyzed for shale PP. The results are compared with direct formation-pressure measurements within the sands.
Six principles guide pore-pressure interpreters on the quantitative use of mud gases. The principles define the pore-pressure values assigned to specific mud-gas observations as a function of recorded annular mud pressure. One can use the pore-pressure estimates in shale as calibration points for traditional shale-pressure indicators such as resistivity, velocity, or corrected drilling-exponent measurements.
This integrated technique yields an improved characterization of shale and sand PPs and can be used as input for well designs to increase reliability, safety, and drilling efficiency.
Estimating Proved Reserves in Tight/Shale Wells Using the Modified SEPD Method
Authors: Yu Shaoyong , Lee W. John , Miocevic Dominic J. , Li Dong , Harris Seth 
Published: June 2014

Abstract
Due to their simplicity, empirical production forecasting methods have been used by the petroleum industry for decades. Since 2008, a number of empirical methods have been introduced to the petroleum industry, specifically for wells located in tight/shale reservoirs. However, most of these new methods are not reliable for forecasting remaining reserves, although they may appear to be very good for forecasting EUR in wells in which a high percentage of the EUR has already been produced.
The Stretched Exponential Production Decline (SEPD) Method was introduced in 2010. Our results from analysis of both synthetic and actual field data by using SEPD have indicated that this method will most likely underestimate EUR in reservoirs with permeability ranging from 0.1mD to 0.0001mD. A modified SEPD (YM-SEPD) Method has therefore been developed to eliminate the SEPD Method's shortcoming by employing a new specialized plot to find all related parameters. This newly developed method is very easy to use and, most importantly, it will yield a much more reliable production and remaining reserve prediction for tight horizontal wells. With longer production histories, remaining reserves can be forecasted even more accurately and with a high confidence level.
Hundreds of horizontal wells including oil wells from various formations (Cadomin, Montney, Notikewin, Cardium, Barnett Shale, Muskwa, etc.), hydraulically fractured in various ways, have been analyzed using the modified SEPD (YM-SEPD) method. Results indicate that reliable EURs and production profiles can be predicted readily for wells having only two to three years of production history. For wells having less than two years of production history, the modified SEPD (YM-SEPD) Method can also yield reasonable production forecasts when coupled with Duong's empirical method.
This paper presents the application of the modified SEPD (YM-SEPD) Method to a number of actual and synthetic oil and gas wells to estimate their proved reserves, including horizontal wells producing dry, wet and retrograde gas as well as tight oil. These examples have had production histories with either observed or non-observed boundary-dominated flow (BDF). The examples also illustrate how the modified SEPD (YM-SEPD) method is capable of estimating proven reserves with high confidence.
Geomechanics Coupled Reservoir Flow Simulation for Diagnostic Fracture Injection Test Design and Interpretation in Shale Reservoirs
Authors: Padmakar A. S. 
Published: June 2014

Abstract
Diagnostic fracture injection testing (DFIT) is an extremely popular technique to generate direct estimates of some of the key characteristics of shale reservoirs. DFIT analysis is generally done using analytical models traditionally developed for high-permeability reservoirs. The use of DFIT to analyze tight shale reservoirs introduces additional issues regarding applicability of these techniques for tight systems as well as operational issues such as long well shut-in times to obtain reasonable reservoir parameters. In this work we conduct geomechanics coupled reservoir flow simulations in order to forward model and analyze DFITs for tight shale gas reservoirs. This capability greatly enhances our ability to efficiently design the DFITs for tight shale reservoirs. In this work we simulate a typical DFIT using a geomechanics coupled reservoir flow simulator and generate the pre-closure and after-closure pressure response from the flow simulation model. This response is then analyzed using a standard Nolte pre-closure and after-closure analysis technique with an objective to evaluate the reservoir properties. We not only we show the validity of the Nolte analysis technique for tight rocks but we also provide guidelines on the amount of shut-in time required to generate a reasonable estimate of the reservoir properties from DFIT pressure response. We also show that the geomechanics coupled flow simulation of DFIT can provide estimates on fracture dimensions which compare reasonably with those given by more traditional fracture design tools. We demonstrate that the geomechanics coupled reservoir flow simulation provides an additional advantage over traditional fracture design tools in that it can numerically model the system response even after fracture closure.
Reduction in Scale Build-up from Sub-surface Safety Valve Using Hydrophobic Material Coating
Authors: Kumar Deepak , Welch John C. , Xu Zhiyue 
Published: June 2014

Abstract
The spring cavities and the inner wall of the sub-surface safety valve can accumulate a thick and hard scale of BaSO4, CaSO4, CaCO3, and asphaltene in certain conditions during production. These scales can impede the smooth operation of the valve and pose potentially serious regulatory and safety risks, e.g. malfunctioning during well blow-out. Currently, exploration and production companies use flow tube exercise remediation tools to remove the scales. However, the approach is not preferable because it requires costly well intervention and is sometimes not feasible.
In the current study, hydrophobic coatings were fabricated to reduce the build-up of scale from downhole tools such as sub-surface safety valves, production tubing, and gas-lift mandrels. The coating is created from low surface energy materials and is combined with a specifically designed micro and micro-nano surface texture. A micro-scratch tester was used to determine the mechanical strength of the coating, and scale growth experiments were conducted in the laboratory to determine the efficacy of the coatings against scale build-up.
History Matching of a Successful Polymer Flood Pilot in the Pelican Lake Heavy Oil Field, Canada
Authors: Delaplace P. , Delamaide E. , Roggero F. , Renard G. 
Published: June 2014

Abstract
A successful polymer flood is being implemented in the Pelican Lake heavy oil field located in Northern Alberta (Canada). With primary recovery around 5-7 % and several billion barrels OOIP, the field offered a big target for EOR but polymer flooding had never been considered in such high viscosity oil (600 to 80,000cp) until the idea of using horizontal wells gave way to a very successful 5 horizontal wells polymer flood pilot in 2005, followed by a progressive extension to the rest of the field. This paper provides a brief description of the polymer flood pilot then focuses on the various steps involved to generate a realistic reservoir model to history match the pilot.
Polymer flooding in heavy oil reservoirs (1500 cp oil in the pilot area) using horizontal wells is really new and the response of the pilot was not totally expected. The oil rate has increased beyond expectations but more surprisingly, the water-cut has increased very slowly and is only in the 50-60 % range after 7 years of operations. History matching the pilot history was important in order to understand what was really taking place in the reservoir; it was performed using up to date Assisted History Matching techniques.
Good results have been obtained in terms of history matching. The model can therefore be used to investigate the influence on oil recovery of many parameters such as well length and spacing, injection rate, polymer concentration, slug size, and to evaluate additional recovery compared to continued primary recovery or waterflood.
History matching the pilot performance opens the door to a better understanding of polymer flooding in heavy oil reservoirs and to increasing the number of potential application cases.