bluuebunny/crossref_metadata_2025_split huggingface dataset:
Cyclic Noise in Open-hole and Cased-hole Logging Measurements: Its Impact and Remediation
Authors: Fitz Dale E. , Mills Andrew A. 
Published: December 2007

Abstract
Cyclic noise can complicate interpretation of open-hole log data, cased-hole log data, and pressure transient data, especially when its amplitude becomes large relative to the primary measurement of interest. Sources of cyclic noise include the following: winch magnetism that affects the spontaneous potential measurement; cyclic (spiral or threaded) bore holes that cause variable standoff on bulk density, neutron porosity, and pad-type resistivity measurements; drill ship and floating platform vertical movement from wave action that can affect the absolute velocity of flow meter tools, reciprocating tool movement from logging-while-tractoring that affects the absolute velocity of flow meter tools; and tidal effects on long time pressure transient tests.
Depth (time) domain filtering of log data affected by cyclic noise is not suitable in most cases because the filter length required to treat the problem causes severe reduction in the vertical resolution of the filtered log measurement. Frequency domain filtering using fast Fourier transforms has been used in the past to eliminate random noise using low pass filters and to determine the vertical resolution of logging measurements. Frequency domain filtering using fast Fourier transforms is readily amenable to treating cycle noise using notch filter(s) centered around the frequency (or frequencies) of the cycle noise. This approach has been used in the electronics industry for decades. Although these techniques are simple to implement, they seldom are used for logging data because stable filter application usually requires interactive filter design.
This paper will review the methodology of applying fast Fourier transforms, designing frequency-domain filters, and applying them. Examples applying this approach to several of the types of cyclic noise listed above will be presented. Issues associated with non-zero mean cyclic noise such as is the case for log measurements made in spiral bore holes and its impact will be addressed.
Production Logging In Horizontal Gravel-Packed Highly Viscous Oil Producers in the North Sea
Authors: Riley Steve , Clark Jim , Guivarch Benoit , Chace David , Trcka Daryl 
Published: December 2007

Abstract
Horizontal wells in ChevronTexaco's Captain Field in the North Sea typically exhibit low temperature and pressure in the produced intervals with highly viscous heavy oil production in 2 and 3-phase flow. The highly viscous oil (88 to 135 cp) has historically presented difficult conditions for most horizontal production logging instrumentation due to the tendency for plugging and coating of sensors. The wells are also screened completions which makes logging and interpretation more complex.
Production profiles in three of the Captain Field screened horizontal wells were recently determined utilising an advanced horizontal production logging system. The system combines 2-dimensional parallel-plate capacitance array measurements of 3-phase holdup and velocity profiles, pulsed neutron measurements of 3-phase holdup and water velocity, and conventional production logging measurements to determine the production profile.
This paper presents the results of the logging campaign, including several interesting observations relating to production and measurement in the profiles under flowing conditions (and shut-in, with cross-flow). Atypical velocity profiles due to the presence of heavy, highly-viscous oil. Observation of annular flow regime, or "core flow", where oil flow is surrounded by an annular layer of water. Effects due to flow through the gravel pack and the need for both capacitance and pulsed neutron measurements. The importance of simultaneous measurement of holdups and velocities across-the-wellbore for accurate flow rate determination.
Better Flow Profiling Against Producing Zones Using a New Production Log Interpretation Technique
Authors: Mishra V. K. , Kenawy A. F. , Rutt T. , Ezzat A. 
Published: December 2007

Abstract
All software that is designed to interpret production logs uses the same technique when it comes to dealing with flow across a perforation. This technique involves creating "stable" zones above and below the designated interval, and the flow calculations are done at these "stable" zones, and thus implying that the flow from the interval is equally distributed along its length.
In some cases, it becomes of extreme importance to determine which parts of the perforated interval is actually producing, and producing what. This case arises when some perforating intervals are covering more than one type of rock, or different textures of the same formation.
In this paper, we will show two methods that will define the location and type of flow from every foot of a perforated interval.
A real case is introduced in this paper; the production logs involved are interpreted in the conventional manner, and also with the new techniques. The results show that with the new technique, a clear definition of the contribution of each foot of the perforated interval is shown, and an accurate assessment of the stimulation job performed in the well was achieved.
The Definitive Identification of Candidate Wells for Refracturing
Authors: Oberwinkler Christian , Economides Michael J. 
Published: December 2007

Abstract
While hydraulic fracturing is perhaps the most widely used well completion technique for production or injection enhancement, often treatments are badly or inadequately designed and/or executed. Because fracture treatments are performed in fields which contain hundreds of wells, large databases are generated de facto. These databases contain considerable and valuable information, but they are rarely used by engineers for the purpose of improving or optimizing future treatments or to select the most promising refracturing candidates. There are two main reasons, which prevent such obvious use: lack of time and, especially, lack of appropriate tools.
There are, however, emerging methodologies, which can be applied for this exercise and they fall under the general category of Data Mining and Knowledge Discovery. Although these terms are already established, the specific tool used in the method and case study presented in this paper is new and innovative.
The method uses Self-Organizing Maps (SOMs) which are used to group (cluster) high-dimensional data. Clustering data can be done with multidimensional cross plots to a certain extent, but when a large amount of parameters (dimensions) is necessary, the cross plot loses its effectiveness and coherence.
The technique, as shown also in the case study of this paper, first identifies underperforming wells in relation to others in a given field. SOMs have been employed in this work to cluster different fracture input parameters (proppant volume, fluid volume, net pay thickness, etc.) of about 200 fracture treatments into different groups. To differentiate between these groups, the incremental post-fracture treatment production has been used as an output. The comparison of the different clusters with the corresponding output reveals a better practice for future treatments and possible refracture candidates. It is important to note that the output has not been included in the clustering process itself.
Once the wells are identified, a Neural Network is trained to rank the most promising wells for a refracture treatment and new optimum fracture designs are prepared which compare ideal performance with the one observed. These are then the criterion for deciding refracturing candidates as well as a significant aid in the design of treatments in new wells in the neighborhood.
This work and the methodology that it implies provide for a faster and more efficient way to analyze well performance data and, thus, to reach a verdict on the success or failure of past treatments. The technique leads to the definitive selection of refracturing candidates and to the improvement of future designs.
(Note: for better understanding this paper should be viewed and copied in color)
Case Study: Analyzing Bottomhole Temperature Gauge Data in Gulf of Mexico Frac Packs to Optimize Fracture Fluid Crosslink, Stability and Break Times
Authors: Malochee S. , Comeaux B. 
Published: December 2007

Abstract
The crosslinkers, buffers and breakers that are used in fracture fluid designs have typically been tested with emphasis placed on break time. Fracture fluids for high permeability formations need to be designed for multiple purposes: wellbore crosslink time, stability, and break time. Crosslink time in the wellbore is critical for fracture propagation. Stability is critical for proppant transport. Break time is critical for proper cleanup of the fracture fluid so that proppant-pack conductivity is maximized. It is important that these times are based on the correct temperatures.
Fracture fluid additives have primarily been based on bottomhole static temperature (BHST) or some portion of BHST. The wellbore temperature while pumping is typically cooler than BHST. Crosslink and stability time should be based on the cooler wellbore temperature. Test temperature for break time, on the other hand, should be based on temperature in the fracture once the treatment has been completed. Therefore, a fluid design needs to effectively satisfy: 1) crosslink time at a cooler wellbore temperature while pumping, 2) stability time at a cooler wellbore and in-situ fracture temperature while pumping, and 3) break time at a temperature closer to bottomhole static temperature once pumping has ceased.
This paper analyzes the bottomhole gauge data from over 50 frac packs in the Gulf of Mexico. The data was evaluated by identifying the maximum cool down while pumping and identifying the percentage of temperature increase after treatment. The BHST's ranged from 122°F to 262°F. The objective is to evaluate the design temperature so that the recommended fracture fluid will have an effective crosslink in the cooled-down workstring, stability for proppant transport, and an effective break time upon completion of the fracture treatment.
Coupling of a Surface Network With Reservoir Simulation
Authors: Kosmala Alexandre , Aanonsen Sigurd Ivar , Gajraj Allyson , Biran Valerie , Brusdal Kari , Stokkenes Arild , Torrens Richard 
Published: December 2007

Abstract
A controller providing a link between reservoir and network simulators has been developed to facilitate reservoir and production management. An optimizer included in the network simulator ensures that optimal management of the coupled system is achieved. The utility of the tool is first tested using a very simple reservoir model with one injector and a single smart producer, and subsequently demonstrated for water-alternating-gas (WAG) injection in two North Sea field cases. For the synthetic test case, various optimization scenarios are explored with the coupled system and compared to standalone flow simulation results. In the North Sea Field 1, optimum oil production is achieved by adjusting the settings of the surface valves as well as the downhole intelligent completion valves (ICVs); in Field 2, gas lift is optimized over time. The coupled system has given more accurate and realistic results in all cases. For the synthetic test case, the coupling gives a significantly higher production than the standalone reservoir simulator run whatever the optimization scenario. For the Field 1 smart well case, the coupled results match historic performance more closely because the pressure drop across the flow lines and surface facilities, the interaction among the wells in the production network, and the boundary conditions are all accounted for. For the gas lift optimization case, the coupled system gives more realistic results with respect to the potential for increased oil production and recovery than the standalone reservoir and network models.
Intelligent Distributed Management System for Automated Wells (SGPA): Experience and Results
Authors: Correa Jose F. , Lepkison Herman , Bittencourt Antonio C. 
Published: December 2007

Abstract
SGPA is an Intelligent Distributed Management System for Automated Wells developed back in 2001/2002 for sucker-rod pumped wells analysis and management. The SGPA concepts and ideas were presented in the 2002 SPE ATC&E, in San Antonio, Tx.
SGPA operates under three main subsystems, Data consistency module for acquisition and consistency of the information from different sources, Knowledge module for well analysis based on Artificial Lift experts coded experience and dynamometer card apprenticeship module for dynamometer card patterns development.
The sucker rod pumping experts knowledge were coded, used and improved in several well analysis creating a Sucker rod pumping knowledge base used now to do more precise analysis and also to teach and train new engineers. Well automation brought a big change to the field personnel routine, in a few months a huge amount of well information became available and the field personnel urged to use it to implement well analysis.
The dynamometer card patterns to be used by the PLC at the well site for optimization and control was also an issue. The use of patterns for normal operation, pump-off, gas lock, etc… is a key feature of the well automation system and a fundamental necessity in any well analysis. The SGPA dynamometer card apprenticeship subsystem was used to develop dynamometer patterns based in the acquired real dynamometric cards stored in the well automation system databases.
This paper presents an in depth description of the SGPA knowledge base after one year use and the set of dynamometric card patterns developed.
Options for Exploiting Stranded Gas – An Overview of Issues, Opportunities & Solutions
Authors: Verghese Joe T 
Published: December 2007

Abstract
A significant proportion of the growth gas reserves seen in recent years is stranded gas, that is gas which is remote from markets and often in hostile environments.
Simultaneously, there is a decisive trend in the utilization of gas relative to other fossil fuels. Natural gas has been steadily winning market share from coal, and is currently overtaking coal in usage worldwide.
The above trends have spawned the development and commercialization of a range of technologies that are directed at monetizing stranded gas reserves. These technologies offer the promise of economically linking these remote gas assets to profitable markets.
This paper will overview optional routes available for stranded gas utilization and its transportation to viable markets, and comment on the maturity and commercialization status of the underlying technologies.
It is hoped that this analysis will provide some insight into the potential these available/emerging technologies (for example, niche LNG, GTL, CNG) can offer in providing robust solutions to the economic exploitation of stranded gas.
Hydrates for Transport of Stranded Natural Gas
Authors: Berner Dale 
Published: December 2007

Abstract
This paper addresses the feasibility of using a Natural Gas Hydrate, NGH, transport-system to economically convey remote, stranded, and/or associated natural gas to market. Such a transport system could convey NGH either on retrofitted crude oil carriers, carrying both NGH and oil, or on new custom-built carrier designed specifically for NGH.
Design Considerations for an LNG Receiving Terminal
Authors: Kaplan Al , Yang C. C. 
Published: December 2007

Abstract
LNG receiving or import terminals are not a new phenomenon, with over 40 in existence worldwide, the oldest being more than 30 years old. At present, there is renewed interest in LNG receiving terminals outside Japan, due to the increased demand for clean burning energy and an abundance of natural gas worldwide. Currently, there are at least 50 proposed new receiving terminals in various stages worldwide; more than 35 potential projects have been identified for the North American market alone. This paper will address the key drivers governing LNG receiving facility design and will then examine key design issues for each of the main elements os such terminals. This paper primarily addresses the issues surrounding onshore terminals, but also in specific areas highlights the differences between an onshore and offshore facility.
The Role of Geomechanical Earth Modeling in the Unconsolidated Pre-Khuff Field Completion Design for Saudi Arabian Gas Wells
Authors: Zillur Rahim , Al-Qahtani Mohammed Y. , Bartko Kirk M. , Goodman Harvey , Hilarides W. K. , Norman W. D. 
Published: December 2007

Abstract
Geomechanical modeling is playing an increasingly important role at Saudi Aramco during the earliest phases of field development planning. Field development decisions are aided by an accurate assessment of well design options that are closely tied to the existing geological and engineering data set using geomechanics technology.
Beginning at the reservoir, completion design in highly productive mechanically weak sandstone formations, and stronger – less productive formation intervals that must be fracture stimulated to produce, depend heavily on the accuracy of the Pre-Khuff geomechanical model that recognizes the complexity of this geological environment.1
The Pre-Khuff model finds formation layer stress and rock strength to be to extremely anisotropic, with stress magnitude and horizontal stress differences linked closely to formation layer stiffness, namely, static Young's modulus. The impact of interval stress and strength complexities to sanding potential, frac-pack design in sand-prone intervals, and hydraulic fracture stimulation design in stronger sanding-free intervals, is modeled using commercially available petrophysics and fracture stimulation design software. Perforation stability is modeled by customized and calibrated numerical modules developed by Saudi Aramco specialists and ChevronTexaco's Rock Mechanics Analysis group.
An overview of the Pre-Khuff geomechanical earth model is presented in the paper. Perforation stability forecasts, including the impact on perforation design and completion type selection is also presented with field performance results. Calibration to the geomechanical model for various fields and reservoir conditions are also illustrated.
Streamlining the WorkFlow from Structure Model to Reservoir Grid
Authors: Hoffman K. S. , Neave J. W. , Klein R. T. 
Published: December 2007

Abstract
Reservoir grid models and geologic structure models are often two distinct and unrelated entities. Ideally, these two models would be identical; realistically, however, geologic modeling systems often do not produce high quality reservoir grids, and gridding systems fall short of producing good geologic models. The problem is often one of resolution and the approach taken for fault modeling. When the reservoir grid is designed first, the fault framework and geologic layering is often approximated, and the model is not optimally compartmentalized. Antithetic faults are often a problem in this case. Moreover, geologic models created in one application often need to be transferred to another application for reservoir gridding, resulting in loss of resolution.
We have developed a new method for creating a 3D reservoir grid from a high-quality geologic structure model. Here, the geologic model is a fault block-oriented, compartmentalized model which has been created using a unique algorithm for producing internally consistent stratigraphic layers. The fault reconstruction process used in this algorithm conserves volume and produces a water-tight, compartmentalized geologic model, which may include normal faults, antithetic faults (also known as "y" or lambda faults), growth faults, reverse or thrust faults, and multi-valued surfaces such as overturned folds or salt domes.
When the reservoir grid is based on this type of internally consistent geologic model, the geologic structure defines the reservoir grid, rather than the grid defining the structure. All types of faults are easily transferred from the geologic model to the reservoir model. Individual faults may be selected for the alignment of the reservoir grid in the I, J or IJ direction; the grid may even conform to a multi-valued surface.
The process of transferring the geologic model to a reservoir grid is extremely fast – usually requiring just minutes to grid models even with large numbers of faults. The speed, simplicity of transfer (without loss of geologic definition), and quality of the final product allows the asset team to work together to refine the reservoir grid while maintaining detailed geologic input.
Is Ottawa Still Evolving? API Specifications and Conductivity in 2003
Authors: Stephenson Chris J. , Rickards Allan R. , Brannon Harold D. 
Published: December 2007

Abstract
Proppant mesh size is arguably the most important characteristic for controlling and describing the quality of a particular propping material. More importantly the mesh size relates to the permeability performance of the proppant. For many years now, a series of American Petroleum Institute Recommended Practices have existed for testing the quality of the numerous proppants available. Along with testing procedures, these documents contain suggested typical proppant sizes, such as 20/40 mesh, and the size specifications they should meet both at the source and at the point of application. In addition to other size criteria, it has long been accepted that if a batch of proppant has at least 90% of its mass between the designating mesh sizes, it passes an acceptable quality control target. However, it is possible to have two samples of 20/40 proppant that are both 90% in-size but could, for example, have a two-fold difference in permeability due to differences in distribution. In this case would the median diameter be a more informative description of the proppant size?
With conductivity as the final goal, does the mesh size have much relevance other than as a guide to performance? In many reservoirs, the success of a fracturing treatment often depends upon a sufficient permeability contrast between the fractured formation(s) and the proppant placed. However, other factors that influence the fracture conductivity, such as polymer damage, multiphase flow and non-Darcy effects, can greatly reduce the significance of the baseline permeability. For some reservoirs, operators consider proppant size to be extremely important to the overall success of a fracturing treatment and demand tight quality control at the wellsite. In contrast, there are reservoirs where operators can pump non-typical proppant sizes or even those that do not meet API specifications. Also, in recent years the industry has seen the introduction and acceptance of several products that are not typically sized, such as 14/30 mesh deformable proppants for flowback control and, most recently, a broad-mesh, intermediate-strength proppant. So are industry attitudes changing and becoming more open to new ways of achieving fracturing success?