bluuebunny/crossref_metadata_2025_split huggingface dataset:
Preparing for the Crew Change - Gearing Up Women to Spud In
Authors: Williams John M. , Lau Laura J. , Lau Richard A. 
Published: February 2011

Abstract
The late president of the United Arab Emirates, Sheikh Zayed Al Nahyan, insisted that women participate fully and equally in its growth and prosperity. In 2006, the Abu Dhabi National Oil Company (ADNOC) invited women to join their petroleum engineering educational program and study on a par with their male counterparts. ADNOC is already planning to incorporate the first female graduates into their operating companies in 2011, but are women receiving the same level of instruction as men? To help find out, the researchers initiated a study collecting data from more than 600 students over five semesters, ranging from educational background, gender, grade point average, and choice of engineering major. In addition, student and faculty surveys were conducted attempting to assess opinions about the courses, the instructors and the students.
The study highlights that female employment issues are an increasingly important subject in the U.A.E. and two reasons are proposed why more women are opting to study for professional positions in the oil and gas industry.
Data for student performance at the Petroleum Institute show that females are achieving almost identical academic results to males. Analysis of the wide-ranging survey data draws conclusions as to whether women will be able to compete effectively with men. The variety of attitudes to female engineers in the oil industry is presented. A significant proportion of male students reported major reservations about hiring and working with female engineers.
This study demonstrates the benefits of cooperation between language and engineering faculty and concludes that fast track changes in gender diversity require commitment and changes in attitude from political leaders, oil companies and young engineers. The study will be of great interest to national oil companies, and other petroleum organizations aiming to increase use of nationals, and to all companies considering expanding opportunities for female engineers as part of a response to the changing demographics in the oil industry, commonly known as the crew change.
Reservoir Modeling: From RESCUE To RESQML
Authors: King Michael J. , Ballin Paulo , Bennis Chakib , Heath David , Hiebert Allan , McKenzie William , Rainaud Jean-Francois , Schey Jana 
Published: February 2011

Abstract
The RESCUE consortium formed in 1995 in response to the requirement to transfer the structural framework, 3D gridded models, and associated well data from "geomodels to upscalers". RESCUE developed a data standard and libraries which allowed multiple vendors to support subsurface projects across the geoscience and engineering domains. To date, over 20 of the sponsoring petroleum companies and application vendors have integrated RESCUE into their applications.
In late 2008 the consortium began a transition to a much more flexible standard: RESQML™. RESQML joins with WITSML™ and PRODML™ as the latest XML-based data transfer standards managed by Energistics. Simple prototype models have already been transferred using RESQML; we expect commercial application in the next 12-24 months.
RESQML has been designed to support:
Interaction with the real-time production and drilling domains; Transfer of giga-cell reservoir simulation models, as are currently in use in some areas of the world, with static reservoir models which may be several orders of magnitude larger; Loss-less data transfer for complex grids, especially for non-standard connectivity; Retention of the geologic and geophysical meta-data associated with 3D grids; Data standards for flexible and iterative multi-vendor subsurface workflows across geology, geophysics and engineering.
As an example of the latter, workflows that support fault seal analysis or 4D seismic interpretation benefit greatly from the integration of data, meta-data and interpretations from multiple geophysical, geologic and engineering applications into a coherent subsurface model. Such integration is not possible for a single application or vendor.
In this paper, we will present our objectives, challenges and work plan for 3D/4D reservoir model exchange. Details of the technical design defined by participating oil companies and software vendors will be shared to demonstrate the efficiency of the RESQML standard.
Experimental Research of Work of Different ESP Stages on Viscous Fluids
Authors: Mokhov Mikhail , Tsunevskiy Andrey 
Published: February 2011

Abstract
Recent years there is trend of oil production increase from the wells with abnormal operating conditions. One of the complicated factors is elevated viscosity of the oil well production. Selection of the high-performance equipment for the work in such conditions is nowadays very relevant. The purpose of this research is a comparison of work of different construction ESP stages on the viscous fluids.
Tests of work of Different ESP Stages were hold on the experimental bedstead of Oil Field Development and Exploitation Department of Gubkin University. Tested ESP Sections are shown in Figure 1.
The following ESP stages were used as a subject for comparison: production stage VNN5-125, production stage VNN5-125 with bored impeller blades, and new construction stage with open-type impeller, which was developed at the Oil Field Development and Exploitation Department of Gubkin University.
Industrial glycerin was used as a viscous working fluid. Viscosity of glycerin has been changed in accordance with different concentration of water in the solution, and variation of temperature of the flow in different production conditions as well.
Using Maps of Microseismic Events to Define Reservoir Discontinuities
Authors: Craig David P. , Burkhart Roger 
Published: February 2011

Abstract
Multidirectional linear trends are commonly observed in maps of microseismic events recorded during fracture stimulation. Since Fisher drew lines through an animated map of microseismic events (Fisher et al. 2002), the industry has recognized that complex-fracture patterns can develop during hydraulic fracturing. Consequently, several new complex-fracture propagation models have been introduced to "match" the stimulated reservoir volume observed in maps of microseismic events recorded during hydraulic fracturing.
Every complex-fracture propagation model requires geometric input, including a pattern of discontinuities in the rock that can dilate or propagate during hydraulic fracturing; however, defining a pattern of discontinuities is a challenging task in a subsurface rock formation that cannot be observed directly.
We present a new method for defining a geometric model for input into a complex-fracture model using microseismic events recorded during fracturing. Events are animated and planar trends are identified to define natural fracture orientation, trace length, dip angle, and natural fracture density within the stimulated reservoir volume. Statistical analysis of the natural fracture properties allows probability distributions to be defined for each fracture property, which are then used to generate stochastic natural fracture patterns for input into a complex-fracture model.
Joint Inversion of Cross-Well Electromagnetic and Seismic Data for Reservoir Petrophysical Parameters
Authors: Gao Guozhong , Abubakar Aria , Habashy Tarek 
Published: February 2011

Abstract
Accurate determination of reservoir petrophysical parameters is important for formation evaluation and reservoir management. In this paper, we present a joint inversion approach for the estimation of reservoir petrophysical parameters, such as porosity and fluid saturations, from electromagnetic and seismic measurements. Electromagnetic data are linked to porosity and fluid saturations through Archie's equations, while seismic data are linked to porosity and fluid saturations through a rock physics fluid substitution model. The approach provides substantial advantage for an improved estimation of porosity and fluid saturation distribution over the one obtained from the separate inversion of electromagnetic and seismic data. Sensitivity studies combined with inversion tests show that seismic data are mainly sensitive to the porosity distribution, while electromagnetic data are sensitive to the fluid saturation distribution. The inversion of either electromagnetic or seismic data is not unique, and thus leading to ambiguity in the determination of porosity and fluid saturations. We show that the joint inversion approach reduces the ambiguity on the determination of porosity and fluid saturations, thus leading to improved reservoir characterization. The concept and the implemented inversion method are demonstrated using various cross-well survey examples.
Application of Air Percussion Drilling Improves Drilling Efficiency in Horizontal Sandstone Wells
Authors: Pletcher Joe , Scarr Adam , Smith Jeremy , Swadi Shantanu , Rogers Clint 
Published: February 2011

Abstract
EQT Production has implemented a new technique for drilling horizontal wells in the hard formations of the Appalachian Basin. Air percussion drilling has been adopted for use horizontally in the Berea sandstone, a hard and abrasive sandstone reservoir that had been traditionally drilled with roller cone bits. The evolution of the technology started with a packed-hole assembly that was trialed on three wells using stabilizer placement to provide directional control in the horizontal. The results were promising as penetration rates increased, but many trips were required to keep the wellbore in the desired target zone. To improve directional control, a percussion BHA with a bent housing positive displacement motor (PDM) was implemented. The introduction of the positive displacement motor with the air hammer produced the same penetration rates seen in the packed-hole assembly while providing the directional control needed. Since mid 2009, the PDM percussion assembly has become the standard practice for drilling Berea horizontal wells, replacing the roller cone BHA. Through June 2010, over 40 wells have been drilled using the assembly. The lateral portion for a majority of the wells is now drilled in one run, reducing total drilling time from 22 to 13 days, dry hole costs by over one half and total well costs by about one third.
Lessons Learned Implementing Step-Change Technology on the Latest Generation Deepwater Drillship
Authors: Ruths Mark 
Published: February 2011

Abstract
Two of the greatest opportunities to increase value in drilling today are improving drilling efficiency and reducing Non Productive Time (NPT). A new sensor technology was developed to make step-change progress on both these opportunities. A new sensor and data integration and analysis system was implemented on one of the world's most advanced drillships. This paper presents the challenges and lessons learned that were experienced during deployment and first use of this technology, many of which can point the way to implementing other new technologies on advanced drillships.
This technology is specifically designed to give the driller, DSM and office personnel the most integrated view of all the data needed to fine-tune drilling efficiencies, warn of impending events and take evasive action to prevent and minimize them, thereby reducing NPT. To accomplish this, the data is presented in easy-to-digest displays on a web browser securely accessible from anywhere.
This technology, which is the subject of several pending patent applications, includes new technology which includes new ways to measure real time flow rate, volume and other mud properties. With continuous refinement, this technology offers the industry a step-change in drilling efficiency and NPT reduction and provides a platform upon which other sensors can be easily tested and evaluated.
This paper focuses on the challenges and lessons learned in piloting this new technology on an advanced generation drillship in an accelerated manner to reap value soonest.
Biogenic Gas Generation From Shallow Organic-Matter-Rich Shales
Authors: Cokar M. , Kallos M. S. , Huang H. , Larter S. R. , Gates I. D. 
Published: February 2011

ABSTRACT
Understanding both physical and biological processes of gas generation and movement in immature organic matter rich shales is essential to optimize gas production from this resource. As yet, there is no complete description that accounts for the many gas transport modes in these systems. Field production data reveals that gas production from these reservoirs declines initially and then stabilizes after a specified time. The stabilized rate is controlled by the contributions of biogenic gas generation, desorption of gas from kerogen, diffusion and transport of gas through nanometer to potentially even micron scale pore systems in coarser grained intervals where physics of transport differ in mechanism. One factor that is ignored is the biogenic gas generation rate and whether this is significant in recharging the resource during a resource well lifetime. This paper presents a modified gas material balance to account for biogenic gas generation. The results of the theory are then compared to gas production data obtained from a shallow shale reservoir in Western Canada. Production from biogenic shale gas reservoirs tends to be at low rate but is stable over extended periods of time. However, it is not yet well understood what the dominant gas transport mechanisms are so that production from these reservoirs can be improved and optimized. Although the gas material balance approach is well established, it has not been used to constrain biogenic gas generation rates. The analysis conducted in this research can be used to optimize productivity from these fields. The new theory helps reveal the key physical controls on gas production from organic shales and means to enhance it. The theory developed in this study is novel and significant because it further develops the underlying theory for biogenic gas transport and production from organic shales, a potentially massive gas source in Western Canada and worldwide.
Changing the Shape of Fracturing: New Proppant Improves Fracture Conductivity
Authors: McDaniel Greg , Abbott Jonathan , Mueller Fred , Mokhtar Ahmed , Pavlova Svetlana , Nevvonen Olga , Parias Thomas , Alary Jean André 
Published: February 2011

Abstract
Hydraulic fracturing is used extensively to increase hydrocarbon production from oil and gas formations. Hydraulic fracture conductivity is a key parameter in optimizing the productivity of a well after the fracture treatment. The American Petroleum Institute (API) proppant permeability / fracture conductivity testing results are frequently used in industry fracturing models when selecting the proppant that provides the optimum fracture conductivity for a well's particular reservoir properties. This design methodology invariably results in a lower than expected fracture conductivity and in many cases, lower than optimum well performance. The industry has recognized that actual fracture conductivity is often a small fraction of what would be expected by using API test results. Non-Darcy flow, multiphase flow, gel damage, stress cycling, fines migration, proppant embedment, proppant flowback, and fracture cleanup are some of the parameters that result in fracture conductivities significantly lower than those measured in an API conductivity test.
A new proppant was developed to improve the final fracture conductivity achievable with high-strength spherical proppants currently available in the market place. This new product is an elongated rod-shaped, high-strength particle with integrated proppant flow back control.
Initial field testing of the product was conducted in moderate permeability formations where production from prior fracture treatments indicated lower than optimum fracture conductivity. Production results from these field tests confirmed that substantial increases in fracture conductivity can be achieved. The large improvement seen in fracture conductivity can be attributed to increased porosity of the proppant pack and reduced fracture conductivity losses due to non-Darcy and multiphase flow effects.
Completely changing the typical geometry of proppants used in hydraulic fracturing is a viable option for improving the conductivity of hydraulic fractures to a point not currently obtainable with spherical proppants.
Dynamic Network Modeling of Resistivity Index in a Steady-State Procedure
Authors: Tørå Glenn , Hansen Alex , Øren Pål-Eric 
Published: February 2011

Abstract
We present numerical results of electrical resistivity of two-phase flow in reservoir rocks using a dynamic network model. The model accounts for viscous and capillary forces, as well as wetting layers in the crevices of the pore space. It can be used as a unified model for drainage, imbibition and steady-state displacement.
We use the model to study viscous effects on electrical resistivity for two-phase flow under strongly water-wet conditions. The pore network is extracted from a realistic pore space of a sandstone. For unsteady drainage and imbibition, our numerical results display capillary number dependent non-Archie behavior and hysteresis of the resistivity index. For steady-state displacement the resistivity index exhibits no significant hysteresis. For increasing capillary number we observe a higher degree of non-Archie (negative curvature) behavior. The simulated data are compared with relevant experimental data, and are in good agreement.
Our conclusion is that the dynamic network model successfully reproduces viscous effects on the resistivity index in drainage, imbibition and steady-state displacement processes.
Comparative Study of Cemented Versus Uncemented Multi-Stage Fractured Wells in the Barnett Shale
Authors: Lohoefer Darrell , Snyder Daniel J. , Seale Rocky , Themig Daniel 
Published: February 2011

Abstract
The industry has made a very quick turn toward both unconventional reservoirs and horizontal, multi-stage fracturing. Some industry experts have begun to question the effectiveness of recoveries in these massive reserve assets. A notable formation in these discussions has been the Barnett Shale, where a variety of methods and technologies have been used to fracture stimulate horizontal wells. In fact, much of the learning curve for completion practices has come from experimental work in this unconventional play.
From 2004 through 2006, a new, open hole, multi-stage system (OHMS) completion technology was run in Denton County, Texas. Using publically available data from the past five years, this study contrasts long-term production results from OHMS completed wells and wells completed with cemented casing.
The data set for OHMS fractured wells compared to the data set for cemented fractured wells indicates that open hole wells, on average, performed better. Significantly, no failures or shut-in periods were observed for the OHMS wells. This establishes the viability, reliability and effectiveness of this technology for the long-term life of wells not only in the Barnett, but for performance enhancement in other shale plays.
Substantial amounts of money are currently being spent to rapidly develop resource plays similar to the Barnett worldwide. Based on short-term results using current completion methods, predictions for ultimate recoveries may be overestimated. This paper evaluates the effectiveness of current completion practices by contrasting two methods in terms of production, economics, operational efficiency, and best fracturing practices to determine whether the completion method can affect overall well performance and long-term recovery.
A Technical and Economic Study of Completion Techniques in Five Emerging US Gas Shales
Authors: Agrawal A. , Wei Y. , Cheng K. , Holditch S. A. 
Published: February 2011

Abstract
With the increased demand for energy and the declining conventional hydrocarbons worldwide, energy companies are turning to unconventional resources, such as shale gas. With over 2, 000 TCF gas in place indentified in just 5 shale gas plays in the United States, shale gas formations are now the number one targets for exploration drilling. Furthermore, there are still many more major shale gas plays and basins waiting to be explored, evaluated and developed. Because of the extremely low permeability of most shale formations, it is essential to select the appropriate completion techniques for shale gas reservoirs. There are very few papers in the petroleum literature that provide a logical method to select completion techniques for given shale gas reservoir conditions. There are papers discussing successful completion techniques that seem to work for a specific shale. We have used many of these SPE papers to help define "best-practices" in completing shale gas reservoirs. We then developed logic to determine the best practice on completing shale gas reservoirs as a function of reservoir conditions. In this paper, we will specifically cover the logic we have developed for choosing completion techniques on shale gas reservoirs.
First, we performed a literature review on the five basins as well as on all shale gas plays in the U.S. to determine the best practices in shale gas completion techniques in fluctuating price environments and identify key geologic parameters that affect overall well performance. From our literature review, we identified seven pertinent geologic parameters that influence shale gas completion practices. Next, we identified different completion trends in the industry for different geologic settings. Subsequently, we generated an economic model and performed sensitivity analysis to determine optimal completions for each gas shale basin. Based on these economic models, we developed the decision flowcharts to select completion techniques. Finally, we programmed the flowchart and we call this program as Shale Gas Advisor. This program can be used to determine optimum completion best practices for not only the five gas shale basins discussed, but also, for gas shale plays that have similar geologic attributes. We validated the program with published case histories in the SPE literature.