bluuebunny/crossref_metadata_2025_split huggingface dataset:
Cement-Bond Evaluation: A Step Change in Capabilities
Authors: Kessler Calvin , Bonavides Clovis , Quintero Alberto , Hill Jim 
Published: October 2011

Abstract
A new, small-diameter ultrasonic scanning logging tool has been field tested and commercially deployed for simultaneous cement-sheath and casing evaluation. The tool is designed for use in 9-5/8-in„ heavy-weight casing down to 4-1/2-in. casing.
Enhancements in downhole electronics, computing capabilities, and telemetry transmission allow the new circumferential acoustic scanning tool to operate on 7/32-in., 5/16-in., and 9/32-in. mono-conductor e-line cables, which allow for the data acquisition to be performed off a small foot print cased-hole unit with a smaller, lighter tool at the same logging speed as previous generation tools run off a seven-conductor e-line cable on an open-hole unit. The enhanced portability and evaluation capability in casings as small as 4-1/2 in. make the system ideally suited for land operations.
Analysis of the cement data is accomplished with the same statistical variance process that has been widely used over the years to analyze data provided by all ultrasonic logging tools available in the industry, resulting in a robust and easy-to-interpret computed product in traditional, light-weight, and foam cement.
The cement-evaluation process uses the measured acoustic impedance of the material in the casing-formation annulus. The casing's internal diameter is obtained from the twoway travel time and the measured borehole-fluid travel time. The casing-wall thickness is determined from the frequency content of the reflected waveform data. Both internal diameter and wall thickness are used to determine internal and external casing wear. Legacy ultrasonic scanning tools could not provide quality data in small-diameter casing because of tool size and tool-fishing constraints and near-field transducer ring-down effects.
A new, interactive job-planner program has been developed to optimize data acquisition for casing size, weight, and borehole fluids. The planner determines the number of shots per scan and maximum logging speed required for the tool to provide 100% circumferential coverage without sector gaps or interpolated data.
Examples comparing the multi-conductor circumferential acoustic scanning tool and the mono-conductor circumferential acoustic scanning tool in conventional and nonconventional cement slurries are presented.
A Novel Methodology to Develop Relative Permeability Inputs for Field Simulation Models for the Solution Gas Drive Process in the Tengiz Reservoir
Authors: Padmakar A. S. , Schembre Josephina , Kamath Jairam 
Published: October 2011

Abstract
Predicting primary depletion recovery below the bubble point is a very difficult challenge, especially for carbonate reservoirs. Accurate predictions require sufficient laboratory data to cover the variability in response from the different rock types and laboratory procedures, and proper upscaling of laboratory data to simulation grid scales.
Many recent studies have shown that laboratory derived gas oil relative permeability curves often depend on whether the tests were conducted using depletion drive or steady state methods. Though it may seem preferable to use depletion drive derived laboratory data for modeling solution gas drive recovery, these tests are complex, quite expensive and it is not practical to conduct many depletion tests. In a previous study we recommended conducting few specialized experiments to gauze the effect of solution gas drive process on the relative permeability data sets and make the requisite corrections to the steady state plug data accordingly. In this work we build further on this methodology and we have analyzed all the available gas-oil relative permeability data to date for the Tengiz reservoir after applying the requisite corrections for the solution gas drive process. We show that the P10, P50 and P90 classification of the relative permeability data set varies considerably depending on the response variable of interest such as recovery or productivity. Finally, we demonstrate a simple and robust workflow to generate a single set of low-mid-high gas oil relative permeability curves for use in full-field simulation models which incorporates all the different measurements on the plugs, the requisite corrections for the depletion process as well as the various effects on the response variables.
Modelling of Cable Forces as a Decision Support Tool for RLWI Operations
Authors: Kjærsgaard-Rasmussen J. , Rask N. , Iversen M. , Arnskov M. M. 
Published: October 2011

Abstract
Subsea well intervention has been performed extensively over at least two decades to service wells and to increase recovery from these wells.
It is a well known fact that subsea wells normally underperform platform wells in recovery between 15–20%. To a large extent, the gap in recovery is related to the high cost in access to the subsea well compared with surface or platform wells. Efficient and low cost well intervention techniques are of the outmost importance for increased field recovery. Riserless Light Well Intervention (RLWI) is one of the tools helping to close the recovery gap.
RLWI operations are now common in shallow water depth up to 600 meter although at least one operation has been performed on 906 meter water depth.
Considerable efforts have been made to improve the RLWI system with respect to efficiency, weather sensitivity and at last – but not least – deep water compatibility.
During RLWI in deeper water, the environmental loading on the wireline from the vessel to the subsea equipment becomes the limiting factor as the wire is subjected to considerable loading from sea current.
Welltec, one of the pioneers in RLWI operation have started an R\&D program to fully understand the limitations and to provide the operator with a tool to assess if RLWI is possible based on simulated behavior and empirical data instead of merely stating that RLWI is not possible beyond a certain water depth.
Accelerating Petro-Technical Learning in the E&P Industry
Authors: Edmundson Henry , Pickering Stephen 
Published: October 2011

Abstract
Accelerating Petro-Technical learning is a key requirement for all players in the upstream industry. It is the only solution for resolving the industry's demographic crisis of skilled professionals, and it is also key for ensuring that our skill-base is equipped to exploit the hard to extract oil and gas now that the easy resources are exploited. This paper describes the the key factors in implementing an accelerated learning program.
The key to acceleration is maximizing the efficiency of learning, achieved by using a competency management approach that ensures that learning fits defined paths of personal development. It is also essential to balance different learning modes in a blended approach. These include learning from instruction-led classes, integrated workflow classes that combine technical and software components, learning from coaches and mentors, self-study, and learning on the job.
The paper review the key factors in accelerated learning and reviews the challenges in implementation.
In-Situ Viscosity from Acoustic Logging
Authors: Dyshlyuk E. , Parshin A. , Charara M. , Nikitin A. , Plyushchenkov B. 
Published: October 2011

Abstract
This work contributes to a concept proposal for obtaining pore fluid viscosity and formation permeability from thermoacoustic measurements (i.e., conducting acoustic logging of pore fluid mobility at different temperature conditions in the wellbore).
The acoustic method for mobility estimation from Stoneley wave attenuation and dispersion is widely used in the industry. Currently, nearly all wireline measurements are performed at static thermodynamic conditions in the wellbore. But what happens if thermodynamic conditions are changed and logs are run at different temperature conditions at a given depth? In this case, the measurements of the pore fluid mobility at different temperatures allow obtaining additional information on the pore fluid viscosity and improve the accuracy of permeability estimation by the acoustic method.
This work includes experimental and modeling verification of the suggested thermoacoustic method. The experiments were on laboratory core samples; finite-difference poro-visco-elastic code was used for the modeling. The applicability of the method is shown to be dependent on the temperature difference of the formation, accuracy of the Stoneley wave dispersion and attenuation measurements, and the in-situ wellbore pore fluid viscosity, temperature, and pore pressure.
Case History of the World's First Installation of Continuous Chemical Treatment in a Horizontal Openhole Gravel Pack to Inhibit Scaling While Maintaining Production Levels
Authors: Surveyor Nilufer , Amaral Anderson , Pinto Marcela 
Published: October 2011

Abstract
Offshore deepwater fields usually require a semisubmersible rig to drill and complete their wells. Additionally, if any intervention is required in the well, a costly workover rig will need to be moved to the site. Hence, solving problems remotely using a method requiring less intervention can provide substantial savings in the overall cost of the well.
Such an opportunity emerged when working on a project in the offshore oilfields of Brazil, where use of water injection as a reservoir energy maintenance method is common. However, the mixture of water injection wells and oil producing wells can lead to the formation of barium sulfate on downhole equipment, which can precipitate under pressure change during production.
Barium sulfate's insolubility makes its removal difficult; usually requiring the use of special tools for mechanically cleaning the gravel pack screens’ interior. This type of intervention method requires an offshore rig. It demands a considerable amount of time and resources to complete the cleanup procedure, especially in the case of long openhole horizontal gravel packs. However, by pumping inhibitors directly to the gravel pack screens’ interior, production suspension is avoided, along with any intervention-related time and cost.
This paper will describe the world's first installation of a horizontal openhole gravel pack system specifically designed to allow continuous pumping of scale inhibitors. The chemicals were injected through a single flowline down to the interior of the sand-control screens at two distinct parts of the well pay zone, without interrupting oil production in offshore Brazil. This pay zone management system incorporates a hydraulic wet connector, an openhole zonal isolation packer, and two chemical injection mandrels with flow regulator valves. The mandrel valves evenly distribute the barium sulfate inhibitor, preventing its deposit inside the screen.
Potential applications of this system in offshore Brazil are being considered on the basis of this successful first installation. Results of this project, as well as other compelling data, suggest that operators may benefit from its incorporation in their field development plan, maximizing their return on investment.
RFID Provides Multiple On-Demand Activation/Deactivation Reliability to Underreaming
Authors: Gonzalez Luis A. , Valverde Eddie , Laird Tommy 
Published: October 2011

Abstract
There is a need in the industry to advance the technology in underreaming, specifically in operations where simultaneous drilling and underreaming take place. Underreaming hurdles have existed for several years that could not be overcome by a simple reliable mechanical apparatus to activate or deactivate the tools. Activating a tool on demand offers options and underreaming techniques that can enhance the way wells are drilled.
Traditional underreamers are activated or deactivated by dropping a steel ball to the tool via the drillstring. The dropped ball creates a bore restriction in the underreamer, which only allows drilling fluid to pass. RFID (Radio Frequency Identification) activation offers several key advantages; it creates an option to increase the performance of the underreamer by allowing multiple activation or deactivation without restricting the ID of the tool. The operator may elect to underream only specific sections of the well where swelling formations cause stuck drillstrings, or allow full circulation in deactivated mode to clean out sections of the wellbore. RFID tools have a full bore which enables wireline to be run through the reamer. RFID allows for multiple tools to be run in the drill string and activated or deactivated on demand.
Activation is controlled by pumping small tags through the bore of the tool. RFID tags transmit commands to the underreamer as they pass through the tool; an electronic reader embedded in the tool reads the command. All commands and other RFID controller events are stored into memory and may be downloaded after the job is complete.
This paper discusses the benefits and value of RFID activated underreamers. The lab and field test results of the RFID controlled underreamer will be presented.
Reservoir Simulation of Detailed Object-based Models of a Complex Fluvial System
Authors: Gilman James R. , Wang Huabing 
Published: October 2011

Abstract
This paper addresses insights obtained from dynamic simulation of detailed models of low permeability fluvial sandstones in the Williams Fork Formation, Piceance Basin, Colorado. The detailed static models and an overview of the dynamic modeling aspects were decribed previously (Pranter et. al., in press). The static models represent the complex stratigraphic architecture and connectivity of these fluvial sandstones as developed through outcrop analysis while the flow simulation provide a means to understand the dynamic connectivity. The Williams Fork Formation consists of fluvial channel sandstones, crevasse splays, floodplain mudstones, and coals that were deposited by meandering- and braided-river systems. Static connectivity analyses of 3-D outcrop-based architectural-element models have shown how relatively wide sandstone bodies enhance connectivity. The dynamic simulations illustrated in this paper shows that historical performance can be mimicked by considering only point bars, channel bars and marine sandstones (reservoir-quality sandstones) as pay. The reservoir simulations used an integrated approach to create 3D dynamic simulation models by combining detailed static geological, geophysical and petrophysical characterizations. We incorporated and calibrated hydraulic fracture properties at each well to approximate initial productivity, used the characterization process to match hyperbolic decline behavior and then investigated the volume influence of wells and the impact of geologic characterization on performance by predicting longterm gas recovery. These realistic and detailed reservoir models can honor the historical gas rate without applying the assumption of open natural fractures. This work demonstrates that an integrated approach can lead to realistic 3D geologic and dynamic models which are consistent with static data and historical performance. Such models are useful for estimating the impact of complex sandstone connectivity on early and long-time performance including well interference and optimal spacing. The paper also briefly discusses how seismic constraints can lead to more unique descriptions with regard to distributions of multi-story sandstone channels. Such methods combined with detailed geologic models as described here could be used for designing more optimal well locations and optimal spacing in less developed areas in tight gas reservoirs.
Automatic Early Fault Detection for Rod Pump Systems
Authors: Liu S. , Raghavendra C. S. , Liu Y. , Yao K. , Balogun O. , Olabinjo L. , Soma R. , Ivanhoe J. , Smith B. , Seren B. , Lenz T. L. , Dinesh Babu C. G. , Ershaghi I. 
Published: October 2011

Abstract
Typically, rod pump system failures are determined using the dynamometer card which may miss some early warnings. This paper presents a novel approach for early failure detection in rod pump wells using more than 14 parameters that indicate the daily functions of rod pump wells and employs advanced machine learning techniques. Our system recognizes failing, failed as well as normal situations by learning their patterns/signature from historical pump data, that include card area, peak-surface load, minimum-surface load, daily run-time, and production data. These data are automatically pre-processed using expert domain knowledge to reduce noise and to fill-in missing data. Our approach is novel in two ways. First, our machine learning algorithm AdaBNet uses boosting to learn several Bayesian Network models and then combines these models with different weights to form a stronger boosted model. Second, our approach generates this single boosted model that is applicable across all the wells in a field, as opposed to well-specific approaches that generate one model per well. This model detects anomalies, prefailure and failure signals and generates corresponding alerts. Early fault detection in rod pump wells is useful for automatic monitoring of large number of assets remotely, and could be extended to other artificial lift systems. We used a training data set of 12 wells to construct the learning model for the AdaBNet algorithm and tested the algorithm on 426 wells from the same field. The results show that our algorithm detects failures with accuracy higher than 90%. This framework can help field operators not only to remotely recognize and predict failures in advance, but also to help prioritize the available manpower, save significant time, reduce operating expense (OPEX), downtime and lost production. Early fault detection in rod pump systems can allow for proactive maintenance that can delay and even prevent future well failures. The proposed algorithm can enable production engineers remotely detect failures and anomalies before they occur, and assess the situation at control centers before taking any remedial or corrective actions. This approach to using a single model for an entire field is superior to other approaches with individual model for each well.
Innovative CT Abrasive Hydrajetting Perforating Approach in A Complex Saudi Arabian Gas Well Overcomes Initial Inability to Perform A Proppant Fracturing Treatment and Achieves Better Than Expected Results: A Case History
Authors: Nunez Garcia Walter , Solares J. Ricardo , Malik Ataur , Vielma Jose , Chacon Alejandro , Wolfe Craig 
Published: October 2011

Abstract
One of the key components for a successful hydraulic proppant fracturing treatment is an efficient perforating strategy capable of ensuring good communication with the formation while reducing near wellbore pressure losses. It is not unusual to encounter unexpected high fracturing fluid injection pressures and low injectivity conditions in wells requiring stimulation to increase their productivity, due to a variety of reasons including inadequate perforation tunnels. The problem gets compounded further in wells drilled in high pressure and temperature formations, in which performing proppant stimulation treatments poses a considerable challenge.
The general approach used in wells selected for proppant fracturing treatments is to use conventional perforating techniques that create relatively short tunnels with entry holes with a diameter several-fold larger than mean proppant diameter. However, due to formation damage related effects caused by drilling practices or other operational steps long tunnels are frequently required to bypass the near-wellbore damage and connect with the reservoir.
Saudi Aramco has been successfully using hydrajetting technology while stimulating open-hole horizontal wells. However, application of the technique in vertical wells drilled in sandstone reservoirs had been successfully tried only once before its application in Well A.
This paper describes how the inability to perform a proppant fracture treatment in a well drilled in a sandstone reservoir, which had originally been perforated using conventional methodology, was overcome by applying an innovative approach involving the use of hydrajetting technology. The proppant fracture stimulation treatment had to be aborted after very low initial injectivity and abnormally high stress at maximum allowable treating pressure were encountered during the DataFrac diagnostic test. However, after implementing the innovative approach a large size proppant fracturing treatment was successfully performed, and it improved well performance from a gas rate of 0 to 25 MMSCFD at high FWHP. The successful approach provided a viable cost-effective alternative to the conventional methodology, and it has since been applied with equally excellent results in several additional cases.
The Integration of Petrophysical and Formation Tester Data in the Creation of a Petrophysical Model for an Eastern Siberia Oilfield
Authors: Karpekin Y. , Weinheber P. , Abdrakhmanova L. , Tsiklakov A. , Gordeev Y. I. , Maslov S. O. 
Published: October 2011

Abstract
The Verkhnechonskoye oil and gas field in Eastern Siberia produces from a highly complex Precambrian, lower Vendian sandstone. In this reservoir there has been significant post-depositional alteration due to diagenesis, secondary porosity is common and salt, anhydrite and carbonate cementation of the porosity frequently occurs. In short, the reservoir provides substantial petrophysical challenges. In the development of a petrophysical model three specific concerns were noted. Firstly, the effects of the salt-filled pore spaces complicate the determination of porosity and therefore permeability. Secondly, it is difficult to resolve permeability predictions from logs, core and formation testers. Finally, using conventional petrophysics, even with a comprehensive suite of logs and extensive core data, it is difficult to clearly delineate gas-filled porosity from oil-filled porosity and the determination of the gas-oil contact was therefore uncertain.
This paper will discuss how petrophysical data from traditional triple-combo measurements was integrated with NMR measurements, core analysis data and formation tester data including permeabilities from pressure transient analysis (PTA) to produce a coherent and robust petrophysical model for permeability prediction.