bluuebunny/crossref_metadata_2025_split huggingface dataset:
Effective "Just In Time" Data Integration: The Cased-Hole/Openhole Composite Log
Authors: Davidson John P. , Rourke Marvin , Bootdee Sasithorn 
Published: December 2007

Abstract
More data, fewer people, and less time are universal problems in our industry today. There is a continuous search for ways to streamline processes and to improve efficiency. A wealth of data must be rapidly validated and interpreted so that value-based decisions can be made in a timely manner.
In a typical development environment, wells are drilled, formation evaluation data acquired, completions run, cement evaluated, perforations made, and later in the life of the well, additional perforating added. The workflow includes geologists, petrophysicists, reservoir and completion engineers, and well operations personnel. Well log data contains critical information used by various asset team members at different times throughout the workflow. Traditionally, open-hole and cased-hole logs, while representing the same well have been maintained separately, most often because of the differing data-users. In this paper, we demonstrate improvements in workflow efficiency and database quality control by bringing together most of the depth-based well data into a single user-friendly format that can be used by all disciplines.
The primary purpose of the cased-hole/open-hole (CH-OH) composite log is the correlation between open-hole logs, either LWD or wireline, cased-hole logs, and other depth-specific data. Users of this log select the perforation intervals, write well work orders, complete perforating operations, and expedite hydrocarbon delivery. This composite log saves time, promotes cross-functional understanding, and provides the first step toward an all-electronic interface between reservoir engineering and completions engineering operations.
This paper provides a detailed explanation of the process of building the CH-OH composite log and of the benefits realized by engineers, as well as the additional benefit of database quality control feedback for earth scientists in the asset team. We foresee a completely digital workflow in the future in which engineers select perforating intervals from a graphical composite log environment and work requested to the well site.
Identifying the Optimum Development Plan for the Western Area of Elgin/Franklin in the North Sea
Authors: Naylor P. , Cutler J. , Denham M. K. , Ribeiro P. C. D. 
Published: December 2007

Abstract
The Western Area Development (WAD) involves the Glenelg and West Franklin undeveloped discoveries which are located in the UKCS Central Graben, to the west of the Elgin/Franklin (E/F) asset. E/F is one of the largest high pressure, high temperature producing asset in the world and involves gas condensate reservoirs at 1,100bara and 190degC. The WAD is at similar conditions and two drilling strategies involving up to five new wells were proposed: Strategy-A: Drilling from the existing E/F platformsStrategy-B: Drilling from a new wellhead platform (WHP) which would be constructed over West Franklin
Strategy-A involved high step-outs of more than 4,000m, which have not previously been attempted under the extreme WAD conditions. The drilling risk associated with Strategy-A was greater than with Strategy-B but, to compensate, Strategy-A offered the prospect of lower capex and earlier production.
This development decision involved complex interactions between conflicting issues and the best way forward was not obvious. Decision Risk Management (DRM) provided a structured and auditable analysis of the optimum development strategy, taking risks and uncertainties into account. A decision risk model was constructed which involved fifteen uncertainties and calculated the drilling, completion and hook-up schedules, production profiles and corresponding cash-flow profiles. The model identified the set of decision options that generated the best net present value (NPV).
Drilling from the existing E/F platforms (Strategy-A) gave the highest expected NPV. The decision to pursue Strategy-A was robust and Strategy-B only became the favoured option when the high step-out drilling durations became more than double the expected value, or the WHP capex was reduced by about 45%.
This structured and open approach enabled the Partners to move forward and sanction Strategy-A.
Field-of-the-Future Program: Planning for Success
Authors: Reddick Chris 
Published: December 2007

Abstract
BP is in the process of implementing a programme called FIELD OF THE FUTURE covering the development and deployment of technology and business process solutions to most aspects of oil and gas field operations – from reservoir to export, in both mature and new fields, onshore as well as offshore.
This program is focussed on leveraging real-time or near realtime data to improve both short-term operational performance and long term recovery. There are a number of challenges associated with this program, not least being that it has to be demonstrably focussed on the highest value opportunities in BP's portfolio, and that the content of the program needs to be seen to be value adding by the business. Both of these challenges require deep engagement with the business around the question of value – how it is defined, accessed and measured.
Further, since BP's program is impacting a number of its Business Units simultaneously, it is important that all lessons learned from the implementation of this program are shared as rapidly as possible. In many cases these lessons are not simple extensions of current practice but rather a very significant shift in the way of working which will have a profound and lasting impact on BP's operations.
This paper describes the approach that BP has taken to assessing the value opportunity from its FIELD OF THE FUTURE program, how it has been refined to address specific challenges in BP's businesses, how these are being measured and how they are being used to shape the content of the program for maximum impact.
The paper also describes the approach taken by BP in sharing lessons learned from the implementation of the program.
Control of Multiple Zone Intelligent Well to Meet Production-Optimization Requirements
Authors: Konopczynski Michael , Ajayi Arashi 
Published: December 2007

Abstract
The application of intelligent well has greatly increased, however, integrating real-time data into a reservoir management work flow, and accurately predicting the hydrocarbon delivery to meet optimization requirement is still an elusive task. This paper presents a single intelligent well optimization strategy and attenuated IPR technology to fill this gap. By referencing individual zone production to one nodal reference point, a general flowl model was developed to combine the fluid flow from individual zones. The model integrates each individual zone's IPR with the production constraint equipment's flow performance to generate attenuated IPR's corresponding to the relative ICV choke setting. By integrating this attenuated-IPR with tubing flow performance, the hydrocarbon deliverability of the intelligent well and production fluid allocation of each zone can be reasonably predicted. Furthermore, to convert the real-time monitoring data into tangible value, this paper has proposed a two intelligent well optimization strategies. By combining the gauge data with a real-time flow distribution model, the production allocations of individual zones can be predicted. The attenuated IPRs provide operators reliable data to accurately predict the hydrocarbon delivery of the well and enable them to make decisions to meet optimization requirements.
Assuming a hypothetical two-zone intelligent well case, a computer model was developed to demonstrate this attenuated IPR method. This work provides engineers with a reliable tool for designing, analyzing and optimizing the production and downhole ICV operations of the multiple zone intelligent production well.
Field Operations Strategy Under Uncertainty in El Carito Field, North of Monagas, Venezuela
Authors: Khan K. , Arcia L. , Quijada Q. , Rodríguez J. , Monterola L. , Otaiza O. , Noriega R. , Vásquez Y. , Machin J. , González A. , Figuera L. , García A. , Chacón J. , López L. , Guarique J. , Quiroz F. , Chacon A. , Alvarado M. , Saputelli L. 
Published: December 2007

Abstract
El Carito field is a giant, deep onshore reservoir in East Venezuela; and it is the second largest field in the north of Monagas basin. Field exploitation started in 1986, and it has been subject to a huge gas injection project to maintain 100% fluid replacement as the optimal exploitation strategy.
Market thrust, gas utilization guidelines, and production increase expectations were the drivers calling for implementaation of an in-depth analysis of the reservoir's history and forecast performance. The proposed analysis would require the application of novel methodologies for modeling uncertainty and for analyzing optimium scenarios.
A multi-disciplinary team for El Carito field business unit implemented an integrated asset modeling (MIAS) methodology for selecting the optimal field exploitation strategy. The objective was to assure optimal short-term field operating strategies in agreement with long-term reservoir management objectives with social and environmental responsibility.
This paper describes the methodology used for developing a field operating strategy and a long term field exploitation plan based on the analysis of historic production profiles, drilling and workover success statistics, production enhancement practices, and world–class best practices available for modeling uncertainty and for optimizating scenario.
The applied methodology established fast and consistent, integrated support for decisions and identified quick, constructive actions for immediate implementation in the field. These actions were consistent with optimal long-term reservoir management strategy that best utilizes the subsurface resources and the surface facilities.
Effect of Surfactant on Volume and Pressure of Generated CO2 Gas
Authors: Bakhtiyarov S. I. , Shakhverdiyev A. K. , Panakhov G. M. , Abbasov E. M. 
Published: December 2007

Abstract
The experimental studies were conducted to estimate the effect of surfactant additives on the volume and the pressure of the CO2 gas generated according to the new proposed technology. An experimental device was designed and built specifically for these purposes. The designed setup allowed initiating and controlling the reaction between the "gas-yielding" (GY) and "gas-forming" (GF) agents proposed by this technology. The temperature was controlled, and the generated gas pressure and volume were recorded during the reaction process. Three types of surfactants were tested to estimate the effect on volume and pressure of generated CO2 gas. The preliminary experimental results on CO2 gas pressure measurements demonstrated that the gas pressure increases with (i) surfactant addition, (ii) decreasing the temperature, and (iii) increasing salinity of the system.
Using PDA Technology for Health, Environmental, and Safety Process Improvement
Authors: Dudics D. D. , O'Toole W. P. , Schmillen M. 
Published: December 2007

Abstract

Introduction
In 2003, Occidental of Elk Hills, Inc. (OEHI) developed several tools to help manage safety proactively. These tools included the "Contractor Scorecard" and the PDA-based "Self-assessment" Program. In 2005, Thums Long Beach Company (THUMS) a subsidiary of Occidental of Long Beach, Inc., reviewed these innovative technologies and collaborated with OEHI to transfer them to the THUMS Unit. The PDA-based program in particular has been instrumental in improving safety compliance and overall performance.

Background
The "Self-assessment Program" (the Program) developed is dependent on PDA technology to provide a simple means and method to capture data, analyze the information and confirm HES compliance. The Program developed is highly automated allowing for quick, easy data gathering while still providing report capability that is simple, direct and informative. The crux of the Program is the PDA which provides the convenience, flexibility and speed unlike most paper-based systems.
The PDA originally selected was the Palm Zire-71 because it was user friendly, MS-Access compatible, easily programmable and durable. This PDA included camera capability which was helpful for facility audits, incident investigations and similar activities where photos could be stored in e-file format; transmitted and/or incorporated into reports. Data gathered in the field could be easily downloaded daily into an MS-Access dB using the standard PDA cradle and "thinkDB" software. Once the data was downloaded trending, analysis and reporting was easily performed.
Safety or compliance "checklists" provided the foundation for the "field data" gathered and analyzed. These were initially written in "Pendragon – Forms 4.0" because it was flexible software and provided easy programming capability. The compliance or "self-assessment" checklists developed and programmed into the PDA's covered some 70 subject. These were derived from OSHA regulations, company policies, procedures and similar requirements. Checklists subjects included, by example, hot work, lock-out/tag-out, confined space and spill prevention. These checklists or inspection sheets provided a uniform means and method for any interviewer to ask a series of questions or observe a number of activities and record objective answers systematically.
The PDA checklist also provided a list of causal factors that the interviewer could input for those answers to questions that were non-compliant. This was intended for later analysis of the data to determine underlying causes of non-compliance where improvement efforts could be focused. (See Figure 1.0, Lock Out / Tag Out Checklist)
Realizing the benefits of such technology and the proactive means of managing contractor safety compliance, the THUMS' organization decided to adopt the process for their Unit.
Road Map to Establishing Effective Shared Environmental Governance
Authors: Haider S. A. , Al-Khamees K. M. , Zaher A. , Al-Yakoob S. 
Published: December 2007

Abstract
The state of Kuwait is moving forward to engage international oil companies (IOCs) in the development of some of its oil fields for a limited period under a contract with the recently established Oil Development Company (ODC). The aim of IOC involvement is to improve performance in a number of areas in the upstream sector including those related to environmental activities.
Implementation strategies for environmental regulations, being the responsibility of the Kuwait Environmental Public Authority (KEPA), are still evolving. Nevertheless, compliance with Kuwait Environmental regulations must be timely fulfilled. This situation could be of a concern especially if delegation of authority by KEPA to ODC for implementing the environmental regulations is not acceptable.
This paper describes an innovative approach involving cooperation between KEPA and ODC through a partnership framework. The framework is designed to enhance KEPA capabilities and ensure proper enforcement of Kuwait environmental laws and regulations in a manner that parallels the effectiveness of compliance strategies included in the IOC's Environmental Management Systems (EMS).
The cooperation framework is activated through an implementation mechanism that involves a pre-operation compliance assessment and regulatory governance. During the pre-operation compliance assessment, the compliance status of facilities to be operated by IOCs will be determined, while regulatory governance during IOC operation will consist of an implementation framework for Kuwait environmental laws and regulations through cooperation between KEPA and ODC. Environmental compliance audits are part of the implementation mechanism that the ODC would adopt in dealing with the IOC's, which are important management tools to ensure that the facilities operated by IOCs that discharge, emit, prepare, manage, store, or dispose of pollutants or contaminants are in compliance with Kuwait environmental laws and regulations.
Integrated Project and Data Tracking Saves Expertise and Time
Authors: Xue Yan , Yang Anping 
Published: December 2007

Abstract
Many companies are faced with project and data tracking issues. How to make information related to a project readily available to the people doing the project? When people move to different projects or even to different companies, how to keep the expertise in past work on the projects and make such experiences available to new people coming to the projects?
This paper describes how a web-based database management system is used to address such issues. Each day, users input project notes, questions, and files to be shared into the web-based system. Users in different office locations and different time zones can share the information easily, either in office, at home, or during travel. Managers can review project progress anytime anywhere, such as during an offsite meeting. Questions about the project can be answered by people in different offices or different time zone. Besides project notes and files, data available to the users may include completion information, workover activities, markers, well logs, petrophysical analysis, seismic locations and views, production data, and accounting data. To keep the system simple to use, different level of complexity can be selected, and different levels of security can be assigned to different users.
Management leadership is needed to take full advantage of such system, since not everyone is used to writing notes when they work. Once implemented, such system can save lots of time in tracking a project and getting new people familiar with the project.
A web-based integrated tracking system can significantly reduce the time needed for a project team to retrieve information. Information is also saved even when people move, making it easy for new people coming to the project to continue the work, or for people in other projects to reference the experiences.
A Rigorous Analytical Model for Fluid Flow in Drainholes of Finite Conductivity Applied to Horizontal and Multilateral Wells
Authors: Guo Boyun , Zhou Jinkui , Liu Ying , Ghalambor Ali 
Published: December 2007

Abstract
Use of horizontal and multilateral wells for oil and gas recovery has become a common practice in the petroleum industry. It is generally recognized that most horizontal wells do not produce oil and gas at the expected production rate. The discrepancy is mainly due to the fact that it is unclear as what constitutes the "expected production rate." The expected production rate is usually the production rate predicted by the mathematical models that were derived on the basis of the assumption of infinite-conductivity drain hole. Although a number of mathematical models are available for predicting the productivity of horizontal wells, they are not easy to use due to their common nature of mathematical complication and numerical treatments. This paper presents a simple and rigorous mathematical model for estimating the productivity of horizontal wells.
By rigorously coupling reservoir inflow and drain hole hydraulics we derived an equation for pressure distribution in the horizontal drain hole in this study. A simple function for fluid flow rate distribution in the drain hole was then developed. An equation for deliverability of the horizontal drain hole was obtained by evaluating the flow rate function at heel. This new model was compared with three existing mathematical models and field data. The comparison shows that the new model has two advantages over other models: 1) it is more accurate than other models, and 2) it is very easy to use. This paper provides petroleum engineers a simple tool for accurately predicting productivity of horizontal drain holes.
Case Study Development of Low-Permeability and Low-Pressure Reservoir Block Bao14 by Fracturing and Water Injection
Authors: Liu Wei 
Published: December 2007

Abstract
Block Bao14 has a burial depth of −850~-1420m, porosity of 17.0%, permeability of 27.0×10−3μm2 and orginial formation pressure of 12.3MPa. However, the pressure in the reservoir declines very quickly, so it is a typical low permeability and low pressure sandstone reservoir. The paper will present the developmemt situation of the reservoir with both fracturing and water injection. Due to the existence of the induced fractures, this kind of development mode poses great risks, i.e. premature water-flooding or water channeling may happen to the oil wells if the azimuths and lengths of the fractures are not compatible with the injection- production patterns and parameters. The following methods are adopted to solve the problem. The azimuths and lengths of the fractures are measured by the electric resistivity tomography and microearthquake method to be the bases for adjusting the injection-production patterns and designing the injection-production parameters. The relationships between the injection-production parameters, fracture parameters of the oil or water wells at different locations in the well pattern and the sweep efficiency, production and watercut under the conditions of induced fractures are simulated and calculated and the fracture lengths and flow conductivity of the oil and water wells are optimized. With the application of low temperature gel break activator, the activity of APS is activated at low temperatures and the process of peroxy release by APS is controlled to control the chemical reaction rate so that the gel breaking time of the fracturing fluid can be controlled to ensure quick gel breaking of the fracturing fluids at low temperatures. An integral pipestring for fracturing and flowback is used. With multistage gas lift valves installed at different locations on the fracturing pipestring, continuous flowback of the fracturing fluid can be realized, improving the flowback rate and efficiency. Resin coated sands are tailed in to effectively contol the the flowback of proppants after fracturing without any effects on fracturing stimulation results. Based on fracture azimuth and length, alternate water injection is applied horizontally and cyclic water injection is applied vertically and intermittent water injection is applied in some heavily flooded areas, greatly improving water injection sweep efficiency and effectively controlling the premature occurrence of water-flooding and water channeling. 20 wells have been put (converted) into water injection in Block BAO14 under this mode with water injection of 184m3/d and cumulated water injection of 36.7761×104m3. Altogether 78 oil wells have been put into production with fluid production of 605t/d, oil production of 289t/d, overall watercut of 52.17%, oil recovery rate of 2.61%, oil recovery rate for the residual recoverable reserves of 38.4%, cumulated oil production of 29.1728×104t and degree of reserve recovery of 7.76%, achieving favourable overall development results of the block.