bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experimental and Theoretical Investigation of Clogging Processes near Production Wells using X-ray Tomography
Authors: de Zwart A. H. , Currie P. K. , de Boer J. , Naeini Alireza Vafaie , Schotting R. J. 
Published: September 2008

Abstract
Formation damage in production wells has been less studied than in injection wells. In injection wells, decline in well injectivity can occur, due to fine particles suspended in the water. These particles are deposited in the reservoir, blocking the pores, causing reduction in the permeability of reservoir rock near the well. Thus, the decline is due to injected water quality and reservoir properties.
In production wells, particles can be transported through the reservoir and cause formation damage. The damage is caused by deposition near the wellbore as a result of the converging flow geometry. As is briefly discussed, it is a common problem in the water industry, where water production wells suffer from productivity decline due clogging of the aquifer near the wellbore. The accumulation of particles causes plugging of pores and decreases the permeability creating a damaged zone near the well. This results in extra, expensive cleaning operations and early shut-in of producers.
This paper reports on an investigation on particle deposition in converging flow geometry, modeling oil and water production wells. Parameters are varied to study the effect on particle deposition of flow rate, particle concentration and particle/grain aspect ratio. The experiments use a converging-flow unconsolidated sand-pack. A hematite particle suspension is injected into the sand pack to observe clogging effects. With the aid of a CT-scanner (X-ray tomography), deposition profiles in time are obtained. Effluent particle concentrations and pressure profiles are also measured in real time. The results of the experiments are interpreted using deep bed filtration theory in converging flow geometry. The experiments show a clear effect of converging flow geometry on particle deposition.
Field Testing of an Automated Well Tester in Extra-Heavy and Diluted Oil Application
Authors: Bastardo Rafael , Imam Asher , Scoglio José 
Published: September 2008

Abstract
In the past, gas-liquid cylindrical cyclone (GLCC) technology was chosen mainly for low viscosity applications, where liquid and gas phases could be completely separated from the mixture and measured independently. Due to its reduced footprint, investment cost, and simplicity, this turned out to be an attractive solution for oil industry applications. However, the practice of not using GLCC technology when handling heavy oils became a model. This model shift happened because of GLCC's short residence time, poor separation efficiency, high gas carry-under (GCU), and limitations of single-phase flow-metering instruments.
The main improvement made to this technology, was finding an efficient way to separate a majority of gas from heavy-oil mixture and finding a combination of metering technologies able to handle certain amounts of GCU without affecting liquid-rate accuracy.
The evaluation program was conceived to test the behavior of a partial separation system (PSS) when handling extra-heavy and diluted oil. A total of 42 tests were performed on 16 wells from 3 well pads.
The diluent injection rate was determined to be one of the main parameters impacting the PSS performance and liquid metering accuracy. It was observed that the variation in the diluent percentage impacted the liquid metering by over- or under-estimating the total liquid measurement. High viscosities and foamy mixture effects were countered by making minor adjustments to the GLCC level control and instrument configurations.
Based on the success criteria, the PSS evaluation was qualified as successful. The system proved to be ±10% accurate on total liquid-volume measurement with a confidence interval of 90%. Regarding repeatability, a maximum deviation of 1 to 2% was shown under normal well operating conditions.
For water-cut measurements, the objective was to measure within ±5% of the actual value without performing individual well calibrations. Testing of fluctuations in extra-heavy oil properties and concentration of diluent, as well as field conditions, proved that a ±5% accuracy for the water-cut measurements could be achieved if individual well calibrations were performed.
Throughout the entire duration of the project, the PSS, with its flexibility and ease of operation, maintenance and diagnostics, proved to be a solution for extra-heavy and diluted oil applications in the Orinoco Belt of Venezuela.
Drilling Hard and Abrasive Rock Efficiently, or Generating Quality Cuttings? You No Longer Have to Choose…
Authors: Desmette Sébastian , Deschamps Benoit , Birch Ron , Naegel Matthieu , Essel Philippe 
Published: September 2008

Abstract
The drilling of hard formations usually requires specific drilling systems to achieve an efficient rate of penetration. Due to the limited depth of cut, the solution often involves the use of high RPM drive systems such as turbines or high speed motors and a fixed cutter product is usually the drill bit of choice.
With increasing well depth the roller cone option is normally avoided due to the low penetration rates and limited rotating hours obtainable with these drill bits. Roller cone use invariably leads to multiple trips and a significant increase in the time and cost of the drilling operation, especially for deeply buried reservoirs where hard rocks are generally encountered and bit diameter is reduced at TD.
Unavoidably, in some applications roller cone bits continue to be used in order to obtain the quality cuttings necessary for the geologist to correctly assess the formation. This is typically the case when the reservoir interval is encountered and exact formation knowledge is critical.
A new drilling solution has been developed to address this situation and is presented in this paper.
The idea consists of a fixed cutter bit which leaves the center of the hole uncut. The lack of bit center leads to the creation of a core. This core is broken by the bit itself and ejected at the side through a specifically designed junk slot. The core is then carried to the surface along with the other cuttings. This process leads to very high quality cuttings for surface examination.
The improvement is especially important where normal cuttings quality is poor due to the use of turbines or high speed motors together with impregnated diamond bits.
Importantly, as the center part of the bit is uncut this new technology also provides a significant increase in the rate of penetration. In a fixed cutter bit the center is one of the most inefficient cutting areas as the rotational speed of the cutter is low to null. By removing the center, an increased ROP efficiency in the range of 15 to 25 percent can be obtained depending upon the bit diameter.
The field tests that are presented in the paper show quantifiable improvements in terms of geological sample quality, cutting efficiency and drilling cost reduction.
A Guide to Successful Backreaming Real-Time Case Histories
Authors: Yarim Gokhan , Ritchie Graham Martin , May Richard B. 
Published: September 2008

Abstract
Backreaming is the practice of pumping and rotating the drillstring while simultaneously pulling out of the hole. When reliable top drive drilling systems (TDS) on conventional drilling rigs were introduced over 25 years ago, the practice of backreaming became a popular technique in the driller's toolbox for tripping out of hole initially in deviated wells.
In general, backreaming operations have become a popular solution to poor hole conditions while pulling out of hole, but they are also notorious for causing the very same problems they are supposed to prevent, such as stuck pipe. If backreaming is not done properly, it may complicate the operations, cause wellbore stability issues, higher ECDs, and it may also cause stuck pipe incidents due to packoffs.
As part of Integrated Project Management's (IPM's) stuck pipe prevention initiative, it became clear that when backreaming is carried out in a wellbore that has a large amount of cuttings and/or cavings, it can cause problems rather than solve them if it is not done with sufficient care. Also backreaming and tripping operations were usually occasions when the rig based team went to a "low vigilance" level. Based on historical cases, it was concluded that in the majority of instances there were no clear guidelines on when to start, how to do it, when to slow down, and when to stop backreaming operations. A review of industry literature also indicated a lack of procedures generally for backreaming.
As a result of the analysis of the real-time data from several case histories, a plan was put in place to improve backreaming operations, define the situations that require backreaming, and focus on tripping practices to prevent stuck pipe incidents and tool failures.
This paper focuses on one of the industry's most controversial subjects, reviews the implications of backreaming by using real-time data and case histories, and suggests proven procedures to trouble-free backreaming. It recommends the conditions that require backreaming and also suggests wellbore conditions that are not recommended for backreaming. More importantly, it proposes key drilling parameters that need to be monitored when backreaming. These include pump pressure, torque, hookload, cuttings rate and downhole measurements (if available) to detect and prevent backreaming induced operational problems. In addition, this paper provides guidelines for successful backreaming operations and defines conditions that may be resolved without needing to backream. Backreaming guidelines have been developed based on IPM company's world wide operations, supported by real-time case histories and extensive stuck pipe prevention program.

Introduction
Backreaming can be thought of as "drilling backwards" in order to trip out of the hole when there is a problem pulling the pipe out of the hole without rotation and circulation.
Advances in World Oil Shale Production Technologies
Authors: Crawford Peter M. , Biglarbigi Khosrow , Dammer Anton R. , Knaus Emily 
Published: September 2008

Abstract
The development of domestic oil shale resources has regained significant attention in the past few years. Several factors have contributed to this, including high oil prices, emerging recovery technologies, increasing world demand for liquid hydrocarbons, and the continued decline in U.S. conventional oil production. In recent years, several initiatives have been taken by government and the private sector to encourage the development of a domestic oil shale industry.
The United States has the largest and most concentrated deposits of oil shale in the world, including nearly 2.0 trillion barrels across the eastern and western states. However, until recently, U.S. oil shale development efforts have largely been in hiatus. Several other nations also have significant oil shale resources, including China, Estonia, Israel, and Turkey. Since 2006, more than 25 U.S. companies have made public information about new oil shale technologies. Other non-U.S. companies have also achieved significant advances.
An analysis has been conducted to identify and profile advanced oil shale technologies that improve performance and help mitigate barriers to commercialization. Advances include reduced water use, improved energy efficiency and net energy balance, better carbon and emissions management, reduced surface impact, spent shale use and disposal, and effective groundwater protection. The analysis addresses both surface and in-situ processes and includes technologies intended to produce liquid fuels or to fire electric power generation.
Notable examples include the Kiviter and Galoter retorts in use in Estonia, the Alberta Taciuk Processor considered for use by OSEC in Utah, Shell's In-Situ Conversion process under consideration in Colorado and in Jordan, Petrobras’ Petrosix Gas Combustion Retort (and variations) in use in Brazil, the Raytheon/CF radio-frequency with critical fluids technology just licensed by Schlumberger, and the EcoShale process under development in Utah.
The results of the analysis suggest significant promise that production of oil from oil shale can be technically and economically feasible while meeting rigorous industry and public standards for technical performance, resource conservation, and environmental protection. It also identifies areas where further research, development, and demonstration are needed.
The Determination of Minimum Tested Volume from the Deconvolution of Well Test Pressure Transients
Authors: Whittle Tim , Gringarten Alain 
Published: September 2008

Abstract
Radius of investigation and tested volume are important results of well test analysis which can make or break future field development. Currently, their evaluation is either approximate or relies on a complete analysis of the transient pressure response using an appropriate model. A new method is proposed that uses the deconvolved derivative response to determine a minimum tested volume. It is accurate and does not rely on further transient analysis.
The method can be applied to any oil or gas well test. It is simple and only requires input of data that is known at the time of testing. Furthermore, if the uncertainty in the deconvolution is quantified, then the uncertainty in tested volume is also defined.
Field examples of both oil and gas well tests are presented which demonstrate how tested volume is easily calculated. Radius of investigation is calculated from the tested volume by making assumptions about the reservoir geometry. The method relies on a good deconvolution algorithm which can also compute the error bars in the derivative response.
Recent advances in deconvolution algorithms have enabled the use of this simple but powerful new method to accurately calculate tested volume without the need for complex transient analysis.
A Comprehensive Study on the Effect of Compliance on Productivity
Authors: Hembling Drew , Lauritzen Eric , Phillips James , Rabba Ali , Jones Colin , Beare Steve , Morgan Quentin , Cameron John 
Published: September 2008

Abstract
Expandable sand screens are a globally accepted sand control system with more than 600 installations worldwide across all vendors. A growing body of data suggests that when compliantly expanded in openhole they perform very well, with consistently low skins and high PIs. Where comparisons have been done, the expandable screens perform at least as well as other sand exclusion systems such as standalone screens and openhole gravel packs. There are a number of possible reasons for the high performance:
The ESS presents a large open area to the formation. This gives a low pressure drop across the screen and minimizes the possibility of plugging to a minimum. The compliant expansion into contact with the wellbore limits the zone of deformation around the hole. Compliance also improves filter cake clean up by reducing mixing with failed sand.
The effect of compliance has been investigated in two sets of experiments. The first was full scale test with a compliant expandable screen and a stand alone screen with an annulus. The expandable showed 60% higher productivity than the screen with an annulus. The second set of experiments was in a specially designed Perspex cell. This cell allowed the effect of an annulus to be investigated for a variety of different sands from well sorted to poorly sorted. The results show that the compliant screen has advantages in sand retention and 100% greater productivity.
Taken as a whole, the field results and the two types of experiment show in a very clear way the benefits on productivity of compliant sand screens.
Modeling Permeability in Tight Gas Sands Using Intelligent and Innovative Data Mining Techniques
Authors: Ali Liaqat , Bordoloi Sandip , Wardinsky Serene H. 
Published: September 2008

Abstract
Evaluation of gas potential in low permeability reservoirs (&lt; 0.1 md) generally referred to as Tight Gas reservoirs is not very straight forward as in conventional reservoirs. This study is focused on modeling permeability in the Travis Peak Formation where there are many challenges. One may encounter low resistivity pay due to clay coated grains and alternating thin laminae of finer and coarser sandstones with distinctly different pore geometries, natural fractures, bituminous zones and multilateral fluvial channel sandstones in broad lenses. Core data is sparsely available. Most importantly, there are no structural features that may construe trapping mechanisms. In view of these challenges, a permeability model was developed primarily for the Travis Peak Formation of Robertson and Leon counties where it has produced 96 BCF of gas and 0.54 MMbbl of oil.
A permeability model was developed by integrating core and log data using the Adaptive Neuro Fuzzy Logic Inference System (ANFIS) that combines the functionality of neural network and fuzzy logic techniques. A combination of conventional logs such as lithology (GR, SP), porosity (RHOB, NPHI), deep and shallow resistivity logs were integrated with core data (porosity, permeability).
The results showed excellent agreement with measured core permeability values. The results of the conventional porosity-permeability transform are also presented for comparison purposes. Since the data has been used from the Travis Peak Formation of East Texas Basin comprising several counties, it is expected that the permeability model should be applicable anywhere in the basin.
Use of Combined Material Balance and Volumetric Analysis to Improve Performance Predictions In a Large Coproduction Field Project
Authors: Smith James E. , Payne Dalian V. , Desantis Cory L. , Broyles Owen L. 
Published: September 2008

Abstract
This paper describes the combined use of volumetric and material balance analysis to understand and predict performance of a large West Texas oil and gas field currently under coproduction.
The Keystone Ellenburger Field, located in Winkler County in the Permian Basin of West Texas, is a large field originally containing both an oil column and a gas cap, along with a moderate to strong water drive. The reservoir is a fractured carbonate with associated vugs and low matrix porosity but high effective permeability due to the natural fracturing. It has undergone a complex development history: primary oil production, gas reinjection and water injection, but since 1992 has been produced by coproduction of large volumes of water to increase gas and oil recovery. As the field matures and the operators confront lower pressures and productivities, along with higher operating and capital costs, we saw the need to develop a reliable predictive model of future performance. Prior efforts with conventional material balances and reservoir simulation have failed to meet expectations.
Because the field has high effective permeability, fluids in the reservoir appear to be in vertical equilibrium. Since 1992 we have acquired pressure and gas-liquid contact information through observation wells. This data, coupled with reservoir maps and production history, have allowed us to build and calibrate a spreadsheet which tracks fluids in place and estimates other parameters such as net water influx.
Reservoir maps were used to generate horizontal slices through the reservoir in order to estimate reservoir pore volume for a given slice through the reservoir. As reservoir pressure declines and the gas-liquid contact moves up or down, we can calculate water influx as well as refine such parameters as effective porosity, original oil and gas in place, and trapped gas saturation.
Based on the historical pressure decline and gas-liquid contact changes we have seen, and using the combined volumetric/material balance approach, we can predict much more accurately how the reservoir will behave under different future production schemes.
The method has shown us that significant gas remains to be recovered, but most of it exists as trapped gas in the water/oil leg of the reservoir. Continued coproduction will lower the reservoir pressure and the gas-liquid contact, both of which will allow additional gas to be produced.
Microseismic Deformation Rate Monitoring
Authors: Maxwell S. C. , Shemeta J. , Campbell E. , Quirk D. 
Published: September 2008

Abstract
Microseismic monitoring of hydraulic fractures is an important tool for imaging fracture networks and optimizing the reservoir engineering of the stimulation. The range of magnitudes of the recorded microseisms depends at the lower limit on the array sensitivity; while the upper limit varies significantly from site to site. In this paper the variation in the microseismic magnitude range is examined and compared with the injection and site characteristics. Although there are numerous potential factors effecting the seismic deformation, the energy of the pumping and state of stress appear to be the two dominant factors. However, interaction with pre-existing faults also results in increased deformation. Ultimately, this can potentially be used to design the stimulation to maximize the deformation. Characterization of the seismogenic potential is also important for seismic hazard assessment, as well as the design of passive monitoring.
Environmental Considerations Related to Oil Shale Development
Authors: Knaus Emily J. , Dammer Anton R. 
Published: September 2008

Abstract
Recently, public attention has been directed at global warming, greenhouse gases and overall environmental quality in the United States and around the world. Fuels production inherently produces carbon dioxide as a byproduct and the public and the legislature have deemed it necessary to consider these impacts. Development of the vast oil shale resource within the United States must be accomplished with consideration to the impacts such development will have on the environment. Those factors include oil shale developments impact on air quality, land disturbance, water use and quality, wildlife, and others.
A great deal of environmental analysis on oil shale development has taken place including the Oil Shale Prototype Leasing Program (1970's) and most recently, the DOI BLM's Programmatic EIS on the oil shale region of the western United States. This paper will synthesize these and other analyses to provide a comprehensive description of environmental considerations related to the development of oil shale.
Air quality considerations include the release of oxides, carbon dioxide, particulate matter, and water vapor. Commercially available stack gas clean-up technologies currently in use elsewhere should be effective in controlling oxides and particulates emissions. Carbon dioxide (CO2) will be produced in large quantities and may need to be captured, used in other commercial applications, or otherwise sequestered.
America's best oil shale resources are highly concentrated in several major deposits in Colorado, Wyoming and Utah. The footprint that an oil shale industry would have in this region would be ~31 square miles per MMBbl/d of shale oil. This paper will consider the land disturbance of surface mining, underground mining, in-situ production, other surface impacts, and spent shale. Surface and groundwater impacts will also be assessed.
Environmental control technologies have advanced to improve efficiency, and reduce or better control effluents and emissions. Companies have implemented sophisticated environmental management systems that are incorporated into project development and plant management and operations. This paper will consider all of the potential impacts on the environment posed by oil shale development as well as how existing and emerging technologies are addressing these concerns.