bluuebunny/crossref_metadata_2025_split huggingface dataset:
Self-Help and Leveraging Scale by Means of the Wells' Advanced Collaborative Environment's Global Community of Practice
Authors: Sawaryn S.J. J , Deady A , Lennox S , Moore-Cernoch K , Morrison J.M. M , Saunders M 
Published: June 2014

Summary
The Advanced Collaborative Environment Community of Practice (CoP) was formed in March 2009 at the request of BP senior management to share good practice and promote standardization in the area of wells. Its mandate was one of self-help and leveraging scale but working through influence and consensus, with management support rather than by direct authority. The CoP was also required to adhere to company information technology (IT) standards and technology strategy.
At the time of the CoP's formation, collaborative environments had been commissioned in various company locations worldwide, including Aberdeen; Baku, Azerbaijan; Houston; Stavanger; and Tangguh, Indonesia. In the absence of standardized requirements for Wells’ collaborative environments and with an emphasis on innovation, each of these centers had been developed independently, strongly influenced by local ideas, needs, and resources. However, it was evident that connectivity between the different locations and with other disciplines was lacking, and that effort was duplicated.
The CoP currently has more than 30 members, including Wells, subsurface, IT, and well technology from 12 locations worldwide. It meets virtually, involving the widest possible membership in different time zones. It has been instrumental in progressing and communicating standards, supporting the introduction and use of common tools and technology, leveraging members’ knowledge and expertise, and helping startups in new areas. Overall, the CoP has been a great success. The paper describes the CoP's evolution, from its formation to the present, and critically examines its achievements, shortfalls, and future goals.
In a rapidly changing technical environment, achieving and maintaining alignment between the diverse stakeholders in a medium to large organization can be challenging. The CoP has earned its credibility and has proved to be an effective means of sharing experience and making good use of scarce resources, both keys for adoption at scale.
The Design of BHA and the Placement of the Magnetometer Sensors Influence How Magnetic Azimuth is Distorted by the Magnetic Properties of Drilling Fluids
Authors: Waag Tor Inge , Torkildsen Torgeir , Amundsen Per Amund , Nyrnes Erik , Saasen Arild 
Published: June 2014

Abstract
The magnetic property of the drilling fluid is one of the substantial error sources for the determination of magnetic azimuth for wellbores. Both the weight material, cuttings, clay and other formation material plus metal filings from the tubular wear may distort the magnetometer readings. This effect is obviously linked to the amount and kind of magnetic material in the drilling fluid, and the development of corrective means has therefore highlighted the drilling fluid. The problem has been studied by laboratory experiments and analyses of downhole survey data. However, there are several inconsistencies in the results, and the phenomenon is not fully understood. The geometric properties of the BHA and the magnetic directional tool are focused upon in this study.
The influence on directional MWD from drilling fluids has been studied using finite element modeling techniques. The simulations have been performed for several cases with realistic representations of MWD tool geometries and varying location of BHA versus the wellbore. One important result is that for situations with perfect axial symmetry, the magnetometer readings are attenuated proportionally to the square of the magnetic susceptibility. Since the magnetic susceptibility is a small number, this means that the effect on magnetometer readings is generally negligible. However, if the symmetry is broken, the distortion on the magnetometer readings can be increased significantly. This means that segregation of cuttings, metal filings or weight material can strongly influence the strength of the measured magnetic fields.
With a collar based tool, that is non-symmetric by nature, the model shows a complex distortion picture. The influence varies with the tool face angle, and shows both attenuation and amplification. The distortion maxima and minima for the two cross-sectional magnetometers do not coincide. These findings underline how hard it will be to find a straight-forward corrective action.
The results from the simulations give increased knowledge about the influence from the magnetic properties of the drilling fluid. This is essential for accuracy estimation and multistation analysis of magnetic survey data. Furthermore, the results demonstrate the importance of considering the geometry of the BHA and the tool, and of the sensor placement when performing the mechanical design.
A Sonic Method for Analyzing the Quality of Cementation of Borehole Casings
Authors: Grosmangin M. , Kokesh P.P. , Majani P. 
Published: June 2014

Abstract
Determination of the quality of cementation of casing in oil wells in the past has involved inflow and circulation tests to insure that the producing zones were adequately sealed off from the adjacent zones. Existing logging methods, such as temperature and radioactivity surveys, may detect the presence of cement behind the casing. However, the qualities of the cement (i.e., its hardness and particularly its bond to the casing) are not indicated.
The new logging method described in this paper operates on the principle that the attenuation of a sonic pulse transmitted by a casing is greatly increased when that casing is bonded to an outer annulus of hard material (such as set cement) which has an appreciably smaller sonicwave velocity than that of the casing.
The down-hole tool contains a source of recurrent sound pulses which are detected by a receiver spaced a few feet from the source The amplitude of the detected casingborne pulse is measured, and the resulting signal is transmitted to the surface where it is recorded vs depth. Since amplitude is a function of attenuation, the log is readily interpreted.
Laboratory studies have shown straightforward relationship between attenuation and such variables as source-detector spacing and per cent of circumference bonded. It is shown that cement not set or not bonded to the casing has comparatively little attenuating effect. Field examples show not only the cement top, but also the variation in cementation quality below the top. Further, the increase of bonding with time and after squeeze cementation is depicted. The detection of poor cement jobs is confirmed by production tests and by formation-test results.
It is anticipated that the method will have wide application in evaluating cementation quality prior to formation testing in completions and recompletions. The analysis it affords may aid in further improving cementation techniques.
Comprehensive Review of Damages and Repairs on Drill Pipe Connections
Authors: Redlinger Thomas M. , Griggs P. Steven , Odell Albert , Bergo Stein 
Published: June 2014

Abstract
In the last two decades the drilling industry has experienced major changes in both drillpipe connections and related inspection criteria. Many operators and contractors now regularly use premium drill pipe connections to drill all sections of their wells. One result of this is that the drilling community is often surprised by the amount of post-well drillpipe repairs that are required. There is little or no established statistical data available to budget repairs in any given well program. Instead they have been left to guess how much to budget into a given drilling project.
This paper will review data from two inspection databases containing in excess of 200,000 joints of drill pipe. The records were derived from operational data obtained from several years of drill pipe inspection. The databases contain inspection records for premium, double shoulder and API connections. The paper will discuss how different inspection standards, premium connections, etc. can affect the "damages" at the end of the drilling program. The objective of the paper is to provide planning factors to the drilling community in order to provide a basis for budgeting repair costs and to highlight the impact of connection selection and inspection standards on repairs.
Improved Compositions for Cementing Wells with Extreme Temperatures
Authors: Ostroot G. Warren , Walker Wayne A. 
Published: June 2014

Abstract
An increase in the number of deep wells being drilled where extreme bottom-hole temperatures are en countered, and the anticipated drilling of wells where temperatures in the range of 500°F or higher may occur, has brought about a comprehensive investigation of cementing materials and of the techniques involved in their proper usage at these elevated temperatures.
Included are developments in cements, retarders, weighting materials and other cement additives which make it possible to formulate a variety of compositions to help resolve the cementing problems of these extreme well conditions. The problems associated with the selection and testing of cements are discussed, and a resume of field results is included.
Previous studies on strength retrogression indicate that caution should be exercised in the selection of a cementing composition for use in high-temperature wells. It now appears that, by the addition of silica flour as a stabilizing additive to certain cements, compositions covering a wide range of slurry densities can be designed to meet extreme well conditions without strength retrogression.
Improvements in cement retarders make it possible to produce a four-hour thickening time at static temperatures up to 500°F. This temperature is considerably higher than conditions presently being encountered in drilling and completion work. Inert weighting materials, used to produce 20-lb/gal or heavier cement slurries, are reviewed.

Introduction
As the search for oil continues, the number of wells being drilled to depths of 10,000 ft or below has continued to increase over the past decade. During 1959, there were 50,893 wells drilled in the United States for a total of 209 million ft of hole. Of this total, approximately 4.45 per cent were drilled below 10,000 ft and 0.30 per cent below 15,000 ft, with a record depth of 25,340 ft recorded (Table 1).
With the drilling of this record-shattering hole comes the question, "How deep can wells be drilled?" Limitations with respect to equipment (surface and subsurface), cementing materials and techniques would cause some concern; however, a panel of experts have agreed that the U.S. oil industry has the equipment and know-how to drill a 50,000-ft hole. The greatest deterrent would be the 700°F temperature they would anticipate encountering at this depth.
High-Confidence Vertical Positioning for Extended Reach Wells
Authors: Mohammed Nelson , Terpening Michael 
Published: June 2014

Abstract
Establishing confidence in the vertical thickness of the hydrocarbon column (HC) is a critical driver in development project economics. True vertical depth (TVD) uncertainty associated with the HC, in the absence of vertical appraisal well data, may be dominated by the propagation of inclination error in non-vertical or horizontal pilot wells. The challenges associated with establishing reliable hydrocarbon column height can be extreme if high-stepout extended reach (ER) wells are the primary source of appraisal data. Moreover, thin reservoirs targeted by ER wells often have a limited vertical "driller’s target" based on standard TVD error propagation models.
Historically, TVD error improvements over current industry standards have been difficult to document reliably for various reasons: down-hole equipment limitations, bandwidth constraints on measurement-while-drilling (MWD) data, sparse data sets with limited resolution, accounting for variable bottomhole assembly (BHA) geometries, changing borehole environment with time, and little scope for independent validation in a field environment.
This paper outlines the integration of three complementary elements to significantly improve on the TVD uncertainty associated with ER well paths and demonstrates the application in a field setting. The methodology leverages the capabilities of an advanced system incorporating MWD tools and a rotary steerable system (RSS) in combination with a high-quality, dynamically updated borehole sag-correction model to account for axial misalignment of the inclination sensors within the wellbore. Results were corroborated initially with independent third-party surveys and validated with a high-quality formation pressure while drilling (FPWD) data-set from seven ER wells drilled in a hydraulically continuous reservoir prior to production.
The approach was successful in defining the primary HC to an exceptional degree of accuracy from a combination of gas and fluid gradient data in two separate ER pilot holes, enabling proper vertical placement of the production hole in the reservoir. The uncertainty associated with the pressure gradient in a secondary (hydraulically distinct) reservoir was also significantly improved based on the implied vertical offsets from the established reference gradient in the primary reservoir.
The general applicability and real-time capability has been tested under demanding operational conditions on a more recently drilled ER well in the same field, demonstrating the robustness of a TVD assurance methodology that significantly improves the risk-profiles of ER projects for asset management teams.
Drilling Automation: Potential for Human Error
Authors: Iversen Fionn , Gressgård Leif Jarle , Thorogood John L. , Balov Mohsen Karimi , Hepsø Vidar 
Published: June 2014

Summary
Mode confusion is an automated system behaving differently than expected and the operator not being aware of (or not properly understanding) what the system is doing. Mode confusion is well-recognized in the aviation community and has been indicated in a number of high-profile aviation accidents. As an example, a JAS Gripen fighter jet crashed during a test flight in the 1980s because the pilot tried to manually correct instability while the plane's computer was automatically trying to do the same. The potential for the same type of problems, and associated safety hazards, arises in drilling-rig operations as a result of the increasing trend for automation and advisory systems. A simple example could be formation fracturing with an automated downhole pressure-control system when displacing to higher mud weight caused by the driller relying on the automated system to maintain sufficiently low flow rate without having reconfigured the system with the new mud properties. This paper describes how the use of a drilling support system in different modes and levels of automation may influence the system operator's performance and risk of human error. The development of a systematic method for detecting mode-confusion problems by model checking is central in this respect. The test cases have been simulated in a virtual test environment created at IRIS specifically for such purposes. The test environment and test cases are described, and results are reported and discussed.
A New Approach in Permeability and Hydraulic Flow Unit Determination
Authors: Izadi Mohammad , Ghalambor Ali 
Published: June 2014

Abstract
Building an integrated subsurface model is one of the main goals of major oil and gas operators to guide the field development plans. All field data acquisitions from seismic, well logging, production and geomechanical monitoring to enhanced oil recovery operations can be affected by the accurate details incorporated in the subsurface model. Therefore, building a realistic integrated subsurface model in advance of the field development and associated design and operations is essential for a successful implementation of such projects. Furthermore, utilizing a more reliable model can in-turn provide the basis in the decision making process for control and remediation of formation damage.
One of the key identifier of the subsurface model is accurately predicting the hydraulic flow units. There are several models currently used in the prediction of these units based on the type of the data available. The predictions using these models are differing significantly due to the assumptions made in the derivations. Most of these assumptions do not adequately reflect realistic subsurface conditions increasing the need for better models to enhance the predictions.
A new approach has been developed in this study for predicting the petrophysical properties improving the reservoir characterization. Poiseuille flow equation and Darcy equation were coupled taking into consideration the irreducible water saturation in the pore network. The porous media was introduced as a domain containing bundle of tortuous capillary tubes with irreducible water lining the pore wall. A series of routine and special core analysis were performed on 17 Berea sandstone samples and the petrophysical properties were measured and XRD analysis was conducted. In addition, core permeabilities were predicted using a new permeability model and the results were compared to the measured permeability data. In building the petrophysical model, it was initially necessary to assume an ideal reservoir with 17 different layers. Afterwards, by iteration and calibration of the laboratory data, the more realistic number of hydraulic flow units was determined accordingly.
The same model was also implemented to a Cotton Valley tight gas reservoir in Northern Louisiana in order to determine the flow units. A comparative study shows that the new model provides a better distribution of hydraulic flow unitsand prediction of the petrophysical properties. Using the new model provides a better match with the experimental data collected than the models currently used in the prediction of such parameters. The good agreement observed for both the Berea sandstone and Cotton Valley tight gas sand experimental data and the model predictions using the new permeability model show the wider range of applicability for various reservoir conditions.
Taking Advantage of Fines Migration Formation Damage for Enhanced Gas Recovery
Authors: Nguyen P. T. , Zeinijahromi A. , Bedrikovetsky P. 
Published: June 2014

Abstract
The core permeability decline during corefloods with varying water composition, especially with low salinity water, has been widely reported in the literature. It has often been explained by the lifting, migration and subsequent plugging of pore throats by fine particles, which has been observed in numerous coreflood tests with altered water composition. In this work, the concept of using this permeability decline in order to decrease water production during pressuredepletion in gas field is investigated. The small volume injection of fresh water into an abandoned watered-up well in order to slow down the encroaching aquifer water is discussed. Equations for two-phase immiscible compressible flow with fines migration and capture have been derived. In large scale approximation, the equations are transformed to the black-oil polymer flooding model. The performed reservoir simulation shows that injection of fresh water bank significantly decreases water production and improves gas recovery.
Measuring Capillary Pressure Tells More Than Pretty Pictures
Authors: Pagels Markus , Hinkel Jerald J. , Willberg Dean M. 
Published: June 2014

Abstract
Exploitation of shale reserves requires injection of large quantities of water-based fluids during hydraulic fracturing treatments. Damage to the fracture conductivity and to the near-fracture matrix permeability caused by residual water can be avoided by optimizing fracture cleanup. The wide variation in mineralogy, texture and lithology of kerogen rich shales entails a substantial variation in the wetting characteristics of these rocks on all scales, whether one is comparing rock from different reservoirs, formations, or even different zones within a formation. It is therefore critical to evaluate shale/fluid interactions. The contact angle is a quantitative measure of the relative wettability of a substrate with respect to two fluids brought into contact with it. To understand dynamic processes in the reservoir, dynamic contact angles need to be measured. Dynamic contact angles (advancing/imbibing and receding/draining fluids) differ substantially from static contact angles. For fracture cleanup the receding contact angle is most relevant. Obviously, static goniometer measurements that are presently used in the industry to infer fluid behavior within the rock matrix give wrong results that do not reflect the mixed wettability of shales with diverse pore types. The results of a macroscopic goniometer measurement, obtained on a polished surface cannot be projected down to pore scale with rough and diverse surfaces.
In this document, we present a rapid and practical method to measure the saturation dependent capillary pressure in a shale sample pack. A new method has been developed to measure threshold pressures and receding contact angles on freshly prepared shale and mudstone surfaces. We introduce a fluid retention ratio as a meaningful way to directly compare additive performance with regards to fracture cleanup.
This method is used to screen treatment fluid additives on a reasonably small amount of formation material. Rock samples from different shale formations have been tested with various additives. Measurement results show that different additives behave differently when exposed to shales from different reservoirs; different responses are even observed from well to well in the same reservoir and zone to zone in the same well.
Productivity Impairment of Gas Wells Due to Fines Migration
Authors: Zeinijahromi A. , Vaz A. , Bedrikovetsky P. 
Published: June 2014

Abstract
Well productivity decline have been widely observed for gas wells producing the reservoir fines. The phenomenon has been explained by the lifting, migration and subsequent plugging of the pores by the fine particles, finally resulting in permeability decrease. It has been observed in numerous core flood tests and field cases. The new basic equations for the detachment of fine particles, their migration and size exclusion, causing the rock permeability decline during gas production, have been derived. The analytical model, developed for the regime of steady state gas production with a gradual accumulation of strained particles, exhibits the linear skin factor growth vs the amount of produced reservoir fines. The modeling results are in a good agreement with the well production history. The model predicts well productivity decline due to fines production based on the short term production data.