bluuebunny/crossref_metadata_2025_split huggingface dataset:
Innovative Horizontal Water Injector Completion Improved Wellbore Accessibility and Enhanced Well Control
Authors: Al-Amer A. A. , Al-Sowayigh M. I. , Al-Mumen A. A. , Al-Zain A. K. 
Published: December 2007

Abstract
Drilling of horizontal oil and water injection wells in Saudi Aramco is rapidly increasing. Ensuring the optimum completion for all types of wells, and in particular water injectors, is essential for rigless intervention work such as stimulation, logging using Coiled Tubing (CT) and installation of mechanical downhole isolation barriers for rigless wellhead repair. A typical horizontal water injection well is usually completed with 3000' to 7000' open hole horizontal section and a tubing string that extends below the last casing. The tubing string is packerless and is installed as a CT guide for intervention work to bypass washouts below the casing shoe. This completion introduces well control challenges in case of rigless wellhead repairs especially in high reservoir pressure areas, where the minimum requirement for well control is two isolation barriers. The standard completion can not accommodate this requirement. The only alternative for the rigless wellhead repair is mobilizing a rig to perform the required work. This option is very expensive. An innovative completion for horizontal water injection wells has been recommended and implemented to achieve two main objectives: first to alleviate well control issues by allowing at least two shutoffs to execute rigless wellhead repair or replacement and second to facilitate accessing the wellbore, in case of formation washouts below the last casing shoe, with CT for intervention work. This paper covers completion background for horizontal injectors and challenges to optimize downhole completions to overcome limitations. Also, discussion of the collaborative work among various Saudi Aramco organizations and Service Companies in deploying this innovative completion will be presented. This success story of using this modified completion will illustrate Saudi Aramco's determination to overcome challenges and introduce best completion practices.
Mercury Monitoring and Removal at Gas Processing Facilities
Authors: Abu El Ela M. , Mahgoub I. S. , Nabawi M. H. , Azim M. Abdel 
Published: December 2007

Abstract
Khalda Petroleum Company (an international joint venture company in Egypt) has recently found Mercury as a naturally occurring component of geological derived hydrocarbons in the Western Egyptian desert. Since then, Khalda Petroleum Company has concentrated on measuring and removing of the mercury from its produced gas. A mercury removal unit was installed at Salam gas processing plant. The mercury contents of the gas at the inlet and outlet of Salam mercury removal unit have been continuously monitored. This paper covers the process design, the field analysis procedures, and the performance of the Salam mercury removal unit. Such study is an original contribution to the knowledge of mercury problems in the gas industry and the technologies used for mercury removal.
From Sensors to Models to Visualization—Handling the Complex Data Flow
Authors: Kolnes Ø. , Kluge R. , Halsey G. W. , Bjørkevoll K. S. , Rommetveit R. 
Published: December 2007

Abstract
The paper describes the underlying infrastructure of an advanced real time integrated drilling simulator that is under development. Focus will be on handling the complex data flow and meeting the requirements regarding simultaneity when designing such a compound system.
A synthesis of multiple transient and steady state models for drilling sub-processes with links to 3D visualization software and measured data is being built on the technology described in this paper. Possible applications include: personnel trainingtesting and comparing drilling plansreal-time diagnosis: warnings, optimization and forward lookingprocess controlpost analysis
This paper describes several challenges when developing a compound system for data processing in networks. For example the system must: be designed to function with a degree of sensor failuremake both measured and predicted values availablemake historical data available for the entire wellmake auxiliary data (rig, formation) availableallow for synchronization of measurements and predictions in timemanage task co-ordination between modulesmanage storage and retrieval of user communication
The paper discusses different approaches to the challenges presented and recommends solution strategies.
The underlying infrastructure is a crucial part of an integrated drilling simulator. It is the core of a technology that allows better utilization of drilling data through easier data access, visualization and advanced modeling. Such a system is an important element in integrating operations and enabling better communication between distributed experts.
Natural-Disaster Preparedness: Best Practices
Authors: Perdue J. M. , Divakaruni S. M. , Russell C. , Johnson C. , Dowden C. , Kaleda P. , Haran E. 
Published: December 2007

Abstract
Following the 2006 Digital Energy Conference with its stimulating Lunch & Learn session on "Hurricane Preparedness," the SPE Gulf Coast Section's Digital Energy Study Group formed a Working Group to collect lessons learned during Hurricanes Katrina and Rita, which had a disastrous impact on the oil and gas industry along the U.S. Gulf Coast. Composed of crisis team leaders and business continuity professionals from major oil companies, independents, oilfield service companies and communications providers, the Working Group sought to identify a number of better practices to share with the global oil and gas industry in the form of a White Paper. This SPE paper is a synopsis of the better practices captured during three Working Group meetings, at which companies shared their Hurricane Katrina and Rita experiences and subsequent improvements they made to their natural disaster preparedness programs. These recommendations are consistent with the professional practices of both the Disaster Recovery Institute (www.drii.org) and the Business Continuity Institute (www.thebci.org). In most cases they provide an additional level of industry-specific detail to established practices.
New Flow Regimes for Well Near Constant Pressure Boundary
Authors: Sui W. , Mou J. , Bi L. , Deng J. , Ehlig-Economides C. 
Published: December 2007

Abstract
Recent studies have shown field data exhibiting a negative half slope trend in the pressure derivative that cannot be explained as spherical flow. In one case the well was located in an elongated fluvial reservoir bounded on one end by an aquifer acting as a constant pressure boundary. In another case the well was also in an elongated reservoir, this time crossed by a highly conductive fault. None has shown a rigorous derivation for the analytical equations for this flow regime.
This study derives flow regime equations for two new flow regimes encountered by a well near a constant pressure boundary. When there is no evidence of another nearby boundary, the pressure derivative trends are radial flow until the constant pressure boundary is encountered, and after that a straight trend with negative unit slope is observed. This flow regime is named here as dipolar flow. When the well is in an elongated reservoir near a constant pressure boundary perpendicular to the elongated direction, possible flow regimes include radial, dipolar flow, linear flow, and a flow regime with negative half slope, which is named here as dipole linear flow.
Normally falling derivative behavior due to a constant pressure boundary is assumed to signal the end of any useful parameter estimation, but the new dipole flow regimes are sensitive to permeability and to the distances to the constant pressure boundary and to boundaries defining the elongated reservoir. This study shows how to use the flow regimes to determine distances to closed and constant pressure boundaries, and to identify bedding plane permeability anisotropy (kx from well to constant pressure boundary, ky parallel to constant pressure boundary plane). The new flow regimes are present in standard single fault and rectangle models for pressure transient behavior, but they have never been rigorously derived or described.
Effects of Friction in Drain Hole on Productivity of Horizontal and Multilateral Wells
Authors: Guo Boyun , Zhou Jinkui , Ghalambor Ali 
Published: December 2007

Abstract
It is generally recognized that most horizontal wells do not produce oil and gas at the expected production rate. The discrepancy can be attributed to several factors including reservoir heterogeneity and non-perfectly horizontal wellbores. This study reveals that the frictional pressure loss in the horizontal drain hole is a key factor affecting inflow performance of highly productive and small-diameter and/or long horizontal wells.
By rigorously coupling reservoir inflow and drain hole hydraulics, equations for pressure distribution in the horizontal oil and gas drain holes were first derived in this study. Simple functions for oil and gas flow rate profiles in the drain holes were then developed. Equations for deliverability of horizontal oil and gas drain holes were obtained by evaluating the flow rate functions at the heels. Sensitivity analyses with the equations indicate that neglecting the frictional pressure losses in the horizontal drain holes can cause over-estimate of well productivity by 30 % in highly productive reservoirs and by 50% in small and/or long horizontal wellbores. This paper provides petroleum engineers a simple tool for accurately predicting productivity of horizontal and multilateral wells.
Simultaneous Acid Diversion and Water Control in Carbonate Reservoirs: A Case History From Saudi Arabia
Authors: Al-Taq Ali A. , Nasr-El-Din Hisham A. , Beresky Jimmy K. , Naimi Khalid M. , Sierra Leopoldo , Eoff Larry 
Published: December 2007

Abstract
Acid diversion and water control are usually addressed as two separate issues. Associative polymers can be used to simultaneously achieve effective diversion and water control during a single treatment. A polymer-based treatment was applied in an offshore, perforated vertical well with two sets of perforations in a carbonate reservoir in Saudi Arabia. The acid treatment was needed to restore the productivity of the upper set of perforations and reduce water production from the lower set of perforations.
Experimental studies were carried out to investigate the potential use of associative polymers to control water mobility and act as an acid diverter. Coreflood experiments were conducted on reservoir cores at downhole conditions (temperature of 200°F and pressure of 3,500 psi). Extensive lab testing showed that associative polymers had no significant effect on the relative permeability to oil. However, the relative permeability to water was significantly reduced.
This paper presents a case history where an associative polymer was applied during matrix acid treatment of a damaged well. The treatment included stages of associative polymer solutions and 20 wt% HCl with additives. Post stimulation treatment production data showed that oil rate increased by 11-fold; whereas water rate decreased by 3-fold; resulting in a reduction in the water-cut from 75 to 14 vol%. The PLT test confirms that the associative polymer was very effective in diverting the acid to the oil zone. The PLT showed that the upper set of perforations was producing most of the fluid, which further confirmed that the associative polymer was effective in reducing the relative permeability to water.
Successful Application of Integrated Digital Automation System for Production Optimization in the North San Juan Basin
Authors: Oyewole Peter O. , Scull Michael D. , Downey Mark S. , Herring John B. 
Published: December 2007

Abstract
An integrated digital automation system has been used successfully to efficiently optimize tubing flow control and plunger lift installations in North San Juan basin. This paper presents description, application, and significant results achieved by using an intelligent closed looped digital integrated automation system. Results included increased gas production, equipment reliability, also, efficient and inexpensive deliquification method through almost exclusively remote-controlled operations.
The smart digitally enhanced system consists of two parts; the Remote Terminal Unit (RTU) and the SCADA-host. The common RTU application is deployed across all well sites and utilizes a common application load. Where and when needed, new feature selections have been added however complete backwards compatibility has been maintained. This is made possible mainly by abstracted I/O and a modular programming technique. The SCADA-host which is also a common unifying system provides interface to all wells for surveillance, monitoring and control capability. The system displays the current system layout graphically. Historical trends are also easily retrievable.
Gas production increment of over 4MMcfd has been achieved and sustained in less than 40 plunger lift installations mainly due to availability of high quality digital automatic control system coupled with effective utilization of plunger lift data. By itself, the system adjusts plunger arrival time, after flow and shut-in time based on pre-set operating range to maximize gas production. Thirty tubing flow control installations have resulted in an average gas production uplift of 130Mcfd per well. In tubing flow control application, the casing valve is automatically controlled based on well conditions. This allows a well to flow gas through tubing above critical gas rate while releasing friction and backpressure on the formation by producing additional gas through the tubing-casing annulus. It is a simple process that includes a combination of surface equipment and control logic that could not perform faultlessly without intelligent automation system.
This is a significant departure from the traditional means of operating gas wells where highly expensive full rig intervention is required to continuously optimize tubing size and artificial lift installation. As expected, improved business performance has been achieved through an intelligent integrated digital automation system.
Environmental Management System Developments by the E&P Industry
Authors: Rost Susan T. , Hinds Aston A. 
Published: December 2007

Executive Summary
Over the past 20 years the way in which the Exploration and Production (E&P) industry manages environmental affairs has changed dramatically. In the beginning, environmental was thought of something that would be taken care of concurrently as safety moved from program management to a management system approach. Currently, while a variety of methodologies exist for controlling the environmental impacts of E&P companies and support companies.
Implementation of HSE Management Systems is ranked as greatest area of progress over the past five years by the oil and gas industry according to the SPE 2006 HSE committee.1 Many of the majors and larger European Union (EU) E&P based corporations have Environmental Management Systems EMS combined with Health, Safety & Sustainability. There is a distinct difference in these disciplines where as safety is impact of safety hazard tend to be immediate and acute; where as Environmental impacts are sometime acute, if the event is large (a major oil spill), but usually develop over time; Health and Sustainability issues are more gradual to discover but very significant once they occur. Training and measuring environmental, health and sustainability programs and management systems is harder to do. Disparities in consistencies also exist between how integrated environmental programs are between upstream and downstream operations for of many Oil and Gas Producers.
Vibration and Rotation Considerations in Extending Coiled-Tubing Reach
Authors: Newman Kenneth R. 
Published: December 2007

Abstract
In recent years there has been increased usage of coiled tubing (CT) to drill1 shallow wells or to drill laterals from an existing wellbore. Often the weight on bit (WOB) which can be applied with CT is limited due to friction between the CT and the wellbore, preventing some drilling operations and methods from being possible. Two methods proposed to reduce this friction are vibration of the CT and rotation of the CT. This paper presents research that was performed to determine the effectiveness and practicality of these two methods.
Deployment of Advanced Collaborative Environments at Scale In The North Sea Operations
Authors: Phillips I. C. , Critchley C. , Shaw P. , Thomas J. 
Published: December 2007

Abstract
As part of its global FIELD OF THE FUTURE initiative, BP in the North Sea has embarked on a programme to significantly change how onshore and offshore staff interact and collaborate, with the objective of improving the efficiency of drilling and operations. This paper reports on the first phase of this project, in which five Advanced Collaborative Environments (ACEs) have been designed and deployed in the BP Aberdeen office in support of production operations. These environments take advantage of a range of digital technologies to deliver operational data to a wider team who are focused on further improving operational excellence.
The second phase of this programme involves the deployment of ACEs into all remaining North Sea assets as BP moves into its new offices in Aberdeen in late 2007 / early 2008.
The paper describes the following; The extensive consultation with the operational staff involved onshore and offshore to ensure that the new systems delivered meaningful support to the offshore operationsThe steps taken to ensure complete "ownership" of the new way of working, for both onshore and offshore teamsA review of the business benefits anticipated and/or achieved by this deploymentThe integrated hardware and software technologies deployed to deliver offshore data to an onshore support environment in real timeThe thinking behind the physical configuration of the onshore and offshore working environmentThe plans for the second phase of the project, in which further ACEs will be deployed across all BP's North Sea producing assets. This deployment will be the subject of a subsequent paper
Permeability and Relative Permeability Measurements at Reservoir Conditions for CO2-Water Systems in Ultralow-Permeability Confining Caprocks
Authors: Bennion D. Brant , Bachu Stefan 
Published: December 2007

Abstract
Carbon dioxide has been successfully used in more than 80 enhanced oil recovery (EOR) operations in North America, and the number of such operations may increase significantly around the world if CO2 becomes available at reasonable costs. On the other hand, geological storage in deep saline aquifers and hydrocarbon reservoirs of large amounts of CO2, captured from large stationary sources is one method that is under consideration for reducing greenhouse gas emissions into the atmosphere on a worldwide basis. In both cases of CO2-EOR and CO2 capture and geological storage (CCGS), the containment of CO2 within the injection unit and leakage avoidance are essential. Effective CO2 containment is achieved by the overlying tight caprock that is initially highly saturated with formation brine, which prevents CO2 migration into uphole intervals and potentially into shallow freshwater aquifers and ultimately to the atmosphere. The confining properties of the caprock are due to its very low permeability and to relative permeability and capillary pressure effects that prevent the penetration of CO2 into, and significant flow through the caprock. Essential to the assessment of CO2-EOR and CCGS operations, including numerical simulation, is knowledge about the caprock permeability to brine and CO2. This paper presents results of detailed measurements at full reservoir conditions for permeability to water, primary drainage and secondary imbibition permeability, relative permeability and trapped saturation of supercritical, dense-phase CO2 and brine for three different, regionally-extensive low permeability formations in the Alberta basin, Canada. These formations include Devonian and Cretaceous shales and a Devonian anhydrite whose measured relative permeabilities were found to be in the nano to pico Darcy range.
The methodology used in the test program and the results can be extended to the evaluation of other sealing caprocks for other prospective CO2-EOR or CCGS operations around the world.
An Integrated Modeling Approach for Characterizing Multiphase Flow, Chemical Transport, and Heat Transfer in Fractured Reservoirs
Authors: Wu Yu-Shu , Lu Guoping , Zhang Keni , Bodvarsson G. S. 
Published: December 2007

Abstract
Even with the significant progress made in modeling flow and transport in fractured rock in the last few decades, characterizing fractured reservoirs remains a great challenge. This is because of the inherent complexity within actual fractured reservoirs, from multiphase flow and transport to the spatial variability of the fracture network. To investigate coupled processes of fluid and heat flow and chemical isotopic transport in the highly heterogeneous, unsaturated fractured tuff of Yucca Mountain (a proposed underground repository site for storing U.S. high-level radioactive waste), we present an integrated modeling methodology. The proposed modeling approach integrates a wide variety of moisture, pneumatic, thermal, and geochemical isotopic field data into a comprehensive three-dimensional numerical model for modeling analyses. In particular, the results of this evaluation indicate that moisture data, such as water potential and liquid saturation in the rock matrix, are not sufficient to determine in situ percolation flux, whereas temperature and geochemical isotopic data provide better constraints to net infiltration rates and flow patterns. In addition, pneumatic data are found to be extremely valuable in estimating large-scale fracture permeability. The integration of hydrologic, pneumatic, temperature, and geochemical data into modeling analyses is thereby demonstrated to provide a practical modeling approach for characterizing flow and transport processes in complex fractured reservoirs.
Calculating Seismic Attributes Within a Reservoir Flow Simulator
Authors: Emerick Alexandre Anozé , de Moraes Rafael Jesus , Rodrigues José Roberto Pereira 
Published: December 2007

Abstract
This paper describes the implementation of a petroelastic model (PEM) based on Gassmann's equation to calculate seismic attributes into a commercial reservoir flow simulator. This implementation is the first step of a project to integrate time-lapse (4D) seismic attributes into an assisted history matching tool developed in a previous project.
The paper includes the description of the PEM and some implementation issues, such as the coupling of the model with the flow simulator with the purpose of using its basic calculated properties, discuss some user options (such as properties input through correlation or geoestatisticaly obtained maps) and the model variants and extensions (such as lithology influence and pressure effects). Three applications of this petroelastic model are shown: the first is a synthetic model based on outcrop data; the second is a 4D feasibility study for water injection monitoring in an offshore field; and the last one is a comparison between observed and calculated pressure impedances for an offshore field.
The resulting tool is applicable, for example, in 4D seismic feasibility studies, in seismic modeling for comparison with observed surveys and makes possible further implementations for incorporating the seismic data in assisted history matching.