bluuebunny/crossref_metadata_2025_split huggingface dataset:
Use of Advanced Optimization Techniques To Manage a Complex Drilling Schedule
Authors: Irgens Morten , Lavenue William Lashar 
Published: December 2007

Abstract

Description of the Material
Rig schedules are major components of operating plans and a main connection point between reservoir management and operations. It is therefore of importance that rig scheduling is done well.
As the number of drilling and workover rigs in use at Saudi Aramco has increased, the challenge of scheduling their use and transportation has grown exponentially. Ensuring that the right rig is in the right place at the right time, while minimizing rig movements and costs, is practically unmanageable using a manual approach. Consequently, Saudi Aramco has implemented an automated schedule optimization application. This interactive application supports schedulers in their daily work, and re-optimizes rig schedules as operational changes render previous plans invalid.

Application
Recent advances in optimization technology address complex, dynamic situations, and show the tangible value of operational decision-making in real time. Saudi Aramco has developed a software application where the rig schedule is optimized against multiple objectives, disruptions to the schedule is quick and easily managed, the impact of scheduling decisions on user-defined key performance indicators is immediately displayed, and schedule optimization is supported by a sophisticated user interface enabling direct schedule manipulation in response to changing needs.
Saudi Aramco has used this project to investigate how recent technological advances can turn rig scheduling into a continuous operational task that improves the alignment of daily decisions with long-term strategic objectives. The deployed rig scheduling system is thus designed for both planning and operations and allows for managing the rig fleet while optimizing on both operational and strategic objectives,. It also allows for rapid rescheduling when changes and disruptions occur.

Results, Observations and Conclusions
Early results are convincing and show showed reduced planning time, reduced response time, improved work processes, reduction in scheduling errors, improved "what-if" abilities and decision-making, reduction in transportation cost, and increased expected production. Laboratory experiments indicated an improvement in travel cost of 35% and in production of 25% over common schedule construction methods.

Significant New Contributions
The new application brings near real-time automation to a previously manual process, and applies optimization technology to dynamic, mission-critical operations, offering tangible benefits.
New Analytical Techniques To Help Improve Our Understanding of Hydraulically Induced Microseismicity and Fracture Propagation
Authors: Eisner Leo , Fischer Tomas , Jechumtálová Zuzana , Le Calvez Joel , Hainzl Sebastian , Boušková Alena 
Published: December 2007

Abstract
A multistage hydraulic fracture treatment was performed on a producing well in a mature tight gas field in West Texas and induced microseismic activity was monitored from a nearby observation well. The objective of this microseismic monitoring campaign was to determine the overall geometry of the hydraulically induced fractures in the Canyon sandstone formation. Information and results initially derived from the microseismic interpretation were used to provide the operator with recommendations for reservoir management such as drilling patterns, new well placement, and completion practices.
Microseismic events were located with a newly developed location technique based on S-wave back-azimuth. While originally a couple of hundreds of induced events per stage were mapped, this new processing technique leads to the detection and location of several thousands of events per stage. This increase of mapped microseismic events provides following insights into reservoir management.
First, initial gaps in located seismicity appear to be artifacts owing to the monitoring geometry, not shear shadow as commonly interpreted. The additional located microseismic events show greater fracture system length and height, thus confirming the effectiveness of the treatment. We also show that the upward component of the vertical propagation is more developed than the downward component, resulting in vertical connection of the first three stages of the stimulation.
Second, the high density of located microseismic events allows us to define the velocity of the fracture system propagation along both the horizontal and the vertical directions. On average, the fracture system propagates horizontally at 12–15 ft/min eastward. The observed hydraulic fracture systems propagated slower toward the west, resulting in an asymmetric fracture with twice shorter western wing. Vertical propagation speed of fracture propagation is similar in sandstone layers, however it slowdown in the vicinity of shale barriers as expected.
Analysis of the source mechanisms of induced seismic events reveals that more than 80% of the representative events have a nonshear component of source mechanisms. This observation implies that the induced microseismic events are directly connected with the created fracture and represent movement of the injected fluids.
Inflow Performance Relationship (IPR) For Solution Gas-Drive Reservoirs—Analytical Considerations
Authors: Ilk D. , Camacho-Velázquez R. , Blasingame T. A. 
Published: December 2007

Abstract
This work provides the analytical development of "Vogel"-type Inflow Performance Relation (or IPR) correlations for solution gas-drive reservoir systems using characteristic flow behavior.
Specifically, we provide the following results:
An analytical form of the quadratic (Vogel) IPR correlation: q o q o , max = 1 − v [ p w f p ¯ ] − ( 1 − v ) [ p w f p ¯ ] 2 Where the v-parameter is defined for the solution gas-drive reservoir case using the oil mobility function (i.e., [(ko/(μoBo)]) — this definition is given by: v = 2 [ k o / ( μ o B o ) ] p ¯ = 0 [ k o / ( μ o B o ) ] p ¯ + [ k o / ( μ o B o ) ] p ¯ = 0 The analytical form for a cubic IPR correlation: q o q o , max = 1 − α [ p w f p ¯ ] − β [ p w f p ¯ ] 2 − γ [ p w f p ¯ ] 3 The analytical form for a quartic IPR correlation: q 0 q 0 , max = 1 − ε [ p w f p ¯ ] − σ [ p w f p ¯ ] 2 − η [ p w f p ¯ ] 3 − θ [ p w f p ¯ ] 4
The practical value of this work is that we have proven that an IPR can be written for a given solution gas-drive reservoir system directly from rock-fluid properties and fluid properties.
The "theoretical" value of this work is that we provide a "characteristic" formulation of the oil mobility profile [ko/(μoBo)], which is given as:
[ 1 − [ k o / ( μ o B o ) ] p [ k o / ( μ o B o ) ] p i ] =         1 − ζ [ p ¯ p i ] + ( 1 − ζ ) [ p ¯ p i ] 2 − 2 ( 1 − ζ ) [ p ¯ p i ] 3 ( ζ ≤ 1 )
This proposed "characteristic" mobility model is validated against numerical simulation results from the literature and from work performed as part of this study. Note that the characteristic mobility is only a function of the characteristic parameter (ζ), the initial and average reservoir pressures (pi and p¯), and the oil-phase mobility evaluated at the initial reservoir pressure [ko/(μoBo)]pi.
Fluid Production and Injection Induced Stress Changes Using Reservoir Volume Changes Inverted From Tiltmeter-Based Surface Deformation Measurements
Authors: Du J. , Maxwell S. C. , Warpinski N. R. 
Published: December 2007

Abstract
Production and injection induced stress changes are in some circumstances, an important issue in field development and reservoir management. Previously, induced poroelastic stresses have been calculated by integrating the center of a dilatation source over a certain reservoir region.1,2 However, this approach has difficulty when the observation points lie inside the reservoir blocks. This paper presents the application of an analytical stress solution due to an initial (eigenstrain or transformation) strain in a cuboid3 to calculate the induced stress changes using the volume changes inverted from the tiltmeter-based surface deformation measurements.4,5 Arbitrary strain volumes can then be constructed from an assemblage of discrete cuboids, allowing stresses both within and outside the strain zone. The stress calculation formulation was applied to a field case study where a warm-up phase of steam injection into a steam assisted gravity drainage (SAGD) well pair was monitored with an array of surface tiltmeters and a downhole microseismic array6. Using a Mohr-Coulomb failure criterion, predicted locations of failure are compared with the actual locations from the microseismic monitoring.
A Predictive Pore-Scale Model for Non-Darcy Flow in Anisotropic Porous Media
Authors: Balhoff Matthew T. , Wheeler Mary F. 
Published: December 2007

Abstract
Non-Darcy flow is often observed near wells and in hydraulic fractures where relatively high velocities occur. In these regions an empirical model, Forchheimer's equation, is used in place of Darcy's law. It includes a quadratic correction to the linear model and has been adequately fit to many experimental data sets, while found to be insufficient in others. Furthermore, a number of numerical and theoretical approaches have shown limitations of the Forchheimer model in the laminar flow regime. It is important to understand the applicability of Forchheimer's equation and to be able to obtain good predictions of macroscopic properties so that nonlinear flow may be properly modeled in reservoir simulators.
In this work non-Darcy flow is modeled using a physically-representative1 pore-scale network model. Quantitative and predictive results are obtained using both computer-generated porous media and real sandstones digitized through x-ray computed microtomography (XMT). The permeability and non-Darcy coefficient, β, are determined for these isotropic and anisotropic media where Forchheimer's equation is applicable. The numerical model is compared to existing experimental data and good agreement is found. Furthermore, limitations to Forchheimer's equation at both low and high velocities are determined and discussed.
Detection of Fracture Corridors from Openhole Logs in Horizontal Wells
Authors: Ozkaya Sait. I. 
Published: December 2007

Abstract
Fracture corridors are sub-vertical tabular bodies of fracture swarms which traverse vertically entire reservoir thickness and extend laterally for several tens to hundreds of meters. Fracture corridors are genetically related to faults or incipient faults and are the main building blocks of fracture systems in many reservoirs in the Middle East. Fracture corridors are best identified from horizontal borehole image logs, but the number of wells with image logs is often limited and it is necessary to use indirect means to detect fracture corridors. Fracture corridors manifest themselves as spikes in horizontal well openhole logs. In fields with water injection, fracture corridors can be identified as water saturation spikes with no corresponding change in porosity. Fracture corridors with cemented walls have bulk density spikes. In many cases fracture corridors are associated with caliper enlargement and lost circulation. In some Middle East carbonate reservoirs fracture corridors appear as gamma ray spikes.
Fracture corridors are not the only cause of openhole log spikes. It is necessary to validate and determine fracture corridor signatures in openhole logs by comparing open hole and image logs first. If a diagnostic signature can be recognized, openhole logs, in combination with lost circulation data, can be used to locate fracture corridors in other horizontal wells with no image logs. If there are a sufficient number of image logs from horizontal wells with fracture corridors, it is possible to correlate spikes with actual fracture corridors and determine the probability to correctly identify a fracture corridor.
Identification of Pay Zones Using Compressional Wave Velocity and Shear Wave Velocity Data in Sandstone Reservoirs
Authors: Hamada G. M. 
Published: December 2007

Abstract
Sonic travel time of compressional wave is generally used as porosity tool for given lithology. Introducing shear wave travel time is very helpful in determining mechanical rock properties. It is found that compressional wave is sensitive to the saturating fluid type. The use of the ratio of compressional wave velocity to shear wave velocity "Vp/Vs" is a good tool in identifying fluid type. The fact that compressional wave velocity decreases and shear wave velocity increases with the increase of light hydrocarbon saturation, makes the ratio of Vp/Vs more sensitive to change of fluid type than the use of Vp or Vs separately. Field examples are given to identify fluids type (water, oil and gas) using the Vp/Vs ratio. Field examples have shown that shear travel time decreases while compressional travel time increases when the water saturated points become gas or light oil saturated points in the studied sections. The decrease of shear travel time (increase of shear wave velocity) is due to the decrease of density and the absorption of deformation by free gas in pores. The increase of compressional travel time (decrease of compressional wave velocity) is due to the decrease of bulk modulus of reservoir rocks which compensates the decrease of rock density.
Neural Network Identification of Hydrocarbon Potential of Shaly Sand Reservoirs
Authors: Elshafei Moustafa , Hamada Gharib M. 
Published: December 2007

Abstract
Hydrocarbon potential evaluation of shaly sand layers requires the adoption of certain shaly water model and also the selection of suitable conventional logging suite. The main target is how to get the accurate porosity and how to convert the apparent water saturation to true water saturation for given shaly sand layer. In this paper neural network approach is presented to replace the conventional interpretation of well logging data to better determine formation porosity and water saturation and to identify hydrocarbon potential of clean and shaly sand layers.
Two neural networks were constructed, one for prediction of porosity using six well logging data inputs: GR, LLD, RHOB, NPHI, PEF and t); and water saturation using 5 well logging data inputs: GR, LLD, RHOB, NPHI and PEF. Shale volume was defined from GR data. Four wells were used in this study. The core data from two wells are used to train and validate the neural networks for prediction of the formation porosity and water saturation. Network outputs have shown good matching with core data and the reference calculated petrophysical parameters. A hydrocarbon potential index is then defined based on cutoff values of porosity, water saturation, and shale volume. The trained neural networks together with the hydrocarbon potential index were used to predict possible pay zones in the four wells. The developed network approach has successfully deduced porosity, water saturation and defined pay zones in the four wells
Asphaltene Cleanout Using VibraBlaster Tool
Authors: Al-Ghazi A. S. , Lawson Justin 
Published: December 2007

Abstract
Remediation of heavy organic deposits of asphaltene in the course of oil production has been a costly process and it has hampered the production activities. Well 1 was initially put in production on December 14, 2005, but it failed to flow against the flow line pressure of 260 psig and later against a reduced HPTT pressure of 50 psig. Heavy asphaltene emulsion solids were found to be completely obstructing the tubing, which could not be subsequently displaced or cleaned out by bullheading either water or Xylene.
To break up the asphaltene and restore the productivity of Well 1, the following options were considered: bullheading water, xylene wash, rotating nozzle CT, workover and using the VibraBlaster™ tool. In January 2006, water bullheading was first attempted with no success. In March 2006, xylene wash was attempted, again with no success. In August 2006, the VibraBlaster™ tool was deployed with coil tubing and attempted to remove the emulsions using the tool's vibration and reciprocation, combined with its high velocity jetting. The VibraBlaster™ tool succeeded in breaking up the solid asphaltene accumulations on the Christmas tree and the first 1900‘ of tubing, restoring the well's production with a current oil rate of 10.7 MBOD and 0% water cut at 26/64" choke setting. Close subsequent observation of the well confirms that it is behaving like a normal GOR well, while crude samples also indicated normal levels of asphaltene (2–3%).
Understanding Stress Dependant Permeability of Matrix, Natural Fractures, and Hydraulic Fractures in Carbonate Formations
Authors: Abass H. H. , Ortiz I. , Khan M. R. , Beresky J. K. , Sierra L. 
Published: December 2007

Abstract
Most carbonate reservoirs behave as dual porosity-permeability systems in which the rock matrix and both natural and created hydraulic fractures contribute to the hydrocarbon transport in a very complex manner. Understanding the behavior of the permeability of the matrix frame, natural fractures, and created hydraulic fractures, as a function of reservoir depletion, is vital to designing optimum stimulation treatments and to maximize the carbonate formation's exploitation.
Core samples were selected from a carbonate reservoir and a testing procedure was applied to determine the stress dependant permeability as a function of various combinations of effective stresses. A tensile natural fracture was simulated by splitting a whole core by failing it under tension using a Brazilian test procedure. The stress dependant permeability was evaluated under varied effective stresses simulating a reservoir depletion scenario. A shear fractured core was selected from a given carbonate formation and a stress dependant permeability was established. The tensile fractured core was then propped with a low concentration of small mesh proppants and the permeability of the simulated propped fracture was determined. Using a new reservoir simulator the testing results and selective functions were used to predict the production performance of a carbonate reservoir under the effect of the stress dependant permeability.
The experimental results indicate that the tensile fractures are much less conductive than shear fractures and the shear fractures are less conductive than propped fractures. The concept of effective stress within the rock matrix is totally different than that of natural fractures; therefore, the effective stress function for both matrix and natural fractures should be separately evaluated to obtain representative functions for any simulation study. The tensile fractures lose conductivity at very early stages of reservoir depletion. Recommendations to manage these tensile fractures for optimum hydrocarbon recovery are suggested.
Practical outputs of this work are: 1) Understand how natural fractures are controlled to efficiently contribute to well productivity, 2) Quantify the effective stress concept in the matrix and fracture systems, 3) Provide stress-dependant correlations for simulation studies.
Production –Log base Model for Effective Carbonate Management, Case Study Miocene Carbonate, the Gulf of Suez, Egypt
Authors: Fadel Sayed , Shalaby S. , Khattab H. , Attia A. M. , Desokey S. 
Published: December 2007

Abstract
Carbonate rock are characterized by complicity of pore system. Variety of pore types associate with Variety of flow characteristics. The main characteristics affected by varying rock pore types are; Porosity-permeability relationship, Capillary pressure and relative permeability, and Archie cementation factor (m).
Many pore systems could be existed in heterogeneous carbonate. Discriminate the different pore types in vertical and lateral directions through heterogeneous carbonate are a difficult task but essential for reliable evaluation and effective management of carbonate reservoirs. Conventional log response and traditional log interpretations do not have the ability to discriminate the different pore types. So, discriminating rock pore type and flow units through heterogeneous carbonate, require integration for all available data. There are no universal applicable techniques to integrate the available data for recognizing the different pore type and flow units through heterogeneous rock.
This paper introduces an approach to correlate the conventional log data with the production results of the old wells which were completed on heterogeneous Miocene carbonate reservoirs. A series of cross plots for the perforated intervals of highest and lowest productivity wells were constructed. These cross plot show a relationship between the well productivity and the position of log data on such cross plots. Based on this observation a relation between rock quality or productivity and conventional log data was established. The recently drilled wells data such as mobility from Modular dynamic tester (MDT), pressure transient analyses and core data confirm this relation.
This approach enhances understating the Miocene carbonate behavior and improves reservoir managements by:
Accurate reservoir evaluation and select perforated intervals Effective well completion and stimulation Effective managements the Miocene carbonate gas injection projects.
On other hand, Layering simulation models for the Miocene carbonate reservoirs based on flow characteristic enhance the model reliability and prediction of the reservoirs behavior under different depletion schema.
Using Pressure Gradient Survey as a Cost-Effective Diagnostic and Decision-Making Tool
Authors: Al-Mousa T. S. , Mohammad S. K. , Dashash A. A. , Al-Mubairik A. J. 
Published: December 2007

Abstract
Locating the water entries in an oil producer is critical for the success of remedial work, such as acid stimulation and water shut off, to prolong the life of the well and enhance production. Different logging tools are successfully used to obtain this information such as PLT. Practicality of using these logging tools can be limited. A good example of these limitations is a well that can not flow or sustain flow to surface (dead well).
Therefore, in addition to the historical data, previous PLTs, water drive mechanisms for such wells, along with the well performance history, the pressure gradient survey approach is used to come up with best estimate of static OWC in vertical or slightly deviated wellbores.
This paper will answer the questions of when, and why conduct a pressure gradient survey and the optimum running procedure by discussing the utilization of the pressure gradient survey as a diagnostic and decision-making tool in a few case histories from the Ghawar filed in Saudi Arabia will be discussed.