bluuebunny/crossref_metadata_2025_split huggingface dataset:
Case Study: Development and Optimization of Quicksilver
Authors: Rempel D. G. , Somerwil M. 
Published: February 2011

Abstract
Development of CBM in the Horseshoe Canyon (HSC) has exploded since its commerciality was first demonstrated in 2003. To date over 15,000 wells have been drilled and are producing from HSC coals. Quicksilver's development has been steady with approximately 1800 wells drilled and brought on-line between 2003 and 2009, and today operates 17 development pods located throughout the HSC fairway. This case study overviews Quicksilver's learnings and experiences from these activities including various aspects of geological and resource assessment, development tactics and recovery optimization, and presents practical datasets for appropriate management of the resource.
Geological investigation has been an important factor right from the outset of this play's development. Many initial concepts have been challenged and subsequent production data often shows discordant relationships with geological parameters used to calculate net pay, depth, and subsequently the OGIP. Water production trends, gas rate variability, anomalous seam contributions, nonlinear pressure gradients, and variable permeabilities are discussed within this case study and the challenges that they present.
As development unfolds, production data has increasingly become a key factor in understanding these unconventional reservoirs, and is variable between areas and even within the development pods / areas themselves. Despite the variability, trends have been identified using production indicators and forecasts. A statistical approach is used to examine these trends, and in conjunction with the geology / resource characterization is enabling improved management decisions for optimal development. In particular variable density drilling, ranging from 2 wells per section to 8 wells per section, as well as various pilot higher density projects, is examined closely and provides valuable information from a reservoir development and optimization perspective. Impacts of sands completions as an add-on to the primary CBM target are also investigated.
Statistical Approach for PCP Standardizing
Authors: Gamboa Jose 
Published: February 2011

Abstract
The selection of a progressing cavity pump heavily relies on the expertise and experience of field personnel. Therefore, the selection of pumps for a large number of wells becomes an energy consuming and cost-effective task where heuristic prevails over an algorithmic procedure. This paper proposes a new approach that attempt to perform such task by combining multiphase calculations with well known pump selection criteria and statistical clustering method.
The methodology requires massive information about the well completions, fluid properties and operation conditions that are utilized for predicting the pressure rising required, inlet volumetric gas fraction among other variables for every well in the field. Two approaches can be utilized to identify standardized pump models: hit frequency and K-mean algorithm. The standardized models for a particular well are considered equivalent pumps, which means that any of standardized models can be utilized in the same well with equivalent results. The process also allows identifying in how many wells a particular pump model can be utilized.
A case study applying the standardizing methodology is presented. The case is a extra-heavy oil field where standardized pump models for 592 wells are required for future purchase.
The methodology proposed is the first step to establish an analytical procedure for identifying standardized pump in a field. The elastomer selection needs to be added to the methodology for sake of completeness; however, it has been left out due to lack of predicting model for the elastomer swelling, thermal expansion and fluid-material chemical interaction.
Enhancement of PLT Tool Reach in Horizontal Wells Using Advanced Wireline Tractor
Authors: Al-Buali Muhammad H. , Dashash Alaa A. , Al-Shehri Ayedh , Torne Juan , Hussein Walid Kamal 
Published: February 2011

Abstract
The horizontal wells drilled during the last few years are coming to a mature state in different fields and locations. Even the existing vertical wells are being converted to horizontal for better oil sweep and productivity. This has created the requirement to evaluate the production performance of horizontal wells to determine water source for proper monitoring and/or a remedial action.
The conventional conveyance methods for the horizontal production logging tool (PLT) are either coiled tubing (CT) or E-line using a tractor. These methods satisfactorily perform in conventional horizontal wells, however, operational limitations and challenges could be encountered when the horizontal section is more complicated due to extended reach, big and inconsistent washouts and high dogleg severity. These types of challenges can prevent the passage of the logging tools to the desired depth. This has an adverse effect on both data quality and accessibility to the well’s total depth (TD). Accordingly, a lot of effort is being exerted by oil companies, service providers and vendors to improve the conveying performance of logging tools using wireline tractors.
An electro-hydraulic tractor with wheels was introduced and deployed for the first time in the world using mono-cable logging tractor technology into several horizontal open hole wells in a Saudi Arabian field. The wells were drilled in a carbonate formation with long horizontal sections and were producing at high rates. This tool was run as an integral part with the logging tool to help cover the entire horizontal section and reach TD while logging.
The logging jobs using this new technique were completed safely and successfully at flowing and shut-in conditions. At flowing condition, the logging tool was successfully conveyed to TD and measurements were made over the entire horizontal section with the help of the tractor. The well was logged at different choke settings while measurements were taken at down passes (while tractoring) and up passes. The tractor was running at a constant speed and was able to pass a long washout of around 9" in diameter. The data analysis showed very acceptable measurements.
This paper will describe the case histories, challenges, planning, deployment and advantages/disadvantages of this type of tractor.
Heavy Oil (Bitumen) and Alkane Solvent Partitioning (HASP) Process
Authors: Frauenfeld Ted W. , Rajan Raj S. 
Published: February 2011

Abstract
Both gravity-based solvent and cyclic solvent processes for recovery of heavy oil or bitumen may involve relatively high solvent/oil ratios. It has been experimentally observed that at high solvent loadings, the oil/solvent mixture partitions into a solvent-rich oil phase and a heavy-ends-rich oil phase. The partitioning may have significant beneficial impact on the performance of a solvent-based process such as VAPEX, or other gravity based processes if the low-viscosity phase carries the bulk of the oil production, and the asphalt-rich phase is mostly asphaltene and essentially immobile. Data on the physical properties (viscosity and density) and the composition of both the partitioned phases are needed to design and optimize solvent-based processes. The project objective was to analyze the laboratory test data on multiple phases partitioning of a selected oil/solvent system. The experiments, conducted with propane and Athabasca UTF bitumen at different solvent loading, have shown the oil/solvent mixture partitions into a solvent-rich oil phase and a heavy-ends-rich (mostly asphaltenes) oil phase with significantly higher densities and viscosities. CMG-WinProp software was used to model the phase partitioning. It was possible to get a good match between the test data on the liquid phase separations and some properties such as densities, but not viscosities.
Non-Condensable Gas Distribution in SAGD Chamber
Authors: Yuan J-Y. , Chen J. , Pierce G. , Wiwchar B. , Golbeck H. , Wang X. , Beaulieu G. , Cameron S. 
Published: February 2011

Abstract
This paper summarizes a set of SAGD experiments conducted live under an X-ray scanner. These experiments were specifically designed for mapping non-condensable gas distribution and their movement in an active steam chamber during SAGD.
Many researches over the past three decades have shown that non-condensable gases may have critical impacts on SAGD performance. Some may be positive; others may be negative depending on reservoir and operating conditions. For better utilizing the positives, avoiding the negatives and for better SAGD performance predictions, it is crucial to understand how these gases behave in a steam chamber. It is arguable that non-condensable gases tend to accumulate at the steam front where steam condenses. However, this assertion has only been supported by numerical simulations. Field observation data have been too sparse. Meaningful tracking of gas production is not a normal practice in the field.
The first experiment was conducted in an aluminum vessel packed with 4Darcy sands at 1.0MPa. The second experiment was conducted in a scalable system consisting of a titanium pressure vessel and a PEEK cell, allowing the SAGD experiment ran at 2.1MPa. Both experiments used bitumen fully saturated with methane at reservoir conditions and were run live under the X-ray scanner. X-ray images were taken at given time intervals. Temperature profiles were obtained directly from thermocouples. Density profiles were computed from the X-ray images. Methane in free gas phase were calculated and mapped. After each experiment, samples from opened cell were also tested for additional observation and confirmation.
These experiments confirmed the assertion that non-condensable gas tends concentrate along the steam front. It also demonstrated that the steam temperature zone does not coincide with the oil depleted zone, indicating that in a SAGD reservoir with nontrivial presence of non-condensable gases, temperature measurements at observation wells alone would not reflect the boundary of the steam chamber. The more representative measure of a steam chamber should be the mapping of oil depleted zone. 4D seismic plus a more comprehensive monitoring of gas production would be needed for determination of the oil depleted zone in the field operation.
Troubles, Problems and Improvements of ESP
Authors: Shimokata N. , Yamada Y. 
Published: February 2011

Abstract
Since 1975 Abu Dhabi Oil Co., Ltd (ADOC) has been applying artificial lift with ESPs in one of its offshore fields and has aquired experience in the installation and use of more than 300 ESPs, 45 of which are currently in operation. This paper will highlight the problems that have occurred with these ESPs, together with the technical improvements and countermeasures that have been put in place in order to achieve a longer ESP run-life.
The failure of the ESP cables delivered in 2003 caused the ESPs to cease production, after a short period of time, due to cable damage in 2004. Following inspection, we concluded that the problems were related to the quality control of the cables. In order to avoid further cable problems, we reviewed the quality control system, including cable handling during transportation. Furthermore, we investigated the potential for technical improvement of the ESP cable, in order to extend the ESP run-life. As a result, the lead thickness was increased and the pothead coating material was changed. Since improving the quality control system of the cable, no further problems have been observed to date.
The build up of asphaltene and CaCO3 scale is another problem which we face with regard to ESP wells. Once scale is deposited at the down hole, it is difficult to remove and, as a result, oil production will decrease. To avoid asphaltene deposit, Xylene is injected into the annulus periodically. To avoid CaCO3 scale deposition, the brine pH is controlled during stimulation and, if necessary, a scale inhibitor is squeezed after stimulation.
Azimuthal Seismic Pilot for Fault and Fracture Detection - An Abu Dhabi, U.A.E. Case Study
Authors: Mueller Klaus W. , Nahhas Mohamad Samir , Soroka William L. , al Baloushi Mariam , Sinno Rick , Martinez Ruben D. , Hussein Waleed , LeCocq Paul 
Published: February 2011

Abstract
An azimuth dependant processing pilot study was carried out in a large Middle East Field to evaluate if this technology has the potential to successfully identify fracture permeability pathways. The field is heavily faulted and fractured with good well control and therefore is a good candidate to perform this study. The success criteria for the Azimuthal processing are: Improved fault imaging relative to the available conventional processed seismic volume;Obtain information about seismic anisotropy in the reservoir zones.
This anisotropy will be linked in a full evaluation to fault & fracture density and orientation. The anisotropy can be measured via differences in seismic travel times or amplitudes / seismic attributes measured in the different azimuth seismic cubes. Azimuthal anisotropy from a 3D land seismic dataset acquired in the U.A.E. has been analyzed using wide azimuth processing. Two different processing methods and flows were tested to derive optimum processed volumes. In both methods raw CMP gathers, after convolution, residual statics, and inter-bed multiple elimination were used as input data for the azimuth stack processing sequence. The two methods are Azimuth SectoringCommon Cartesian Offset Bins (CCOB)
Both processing methods have their benefits, one big advantage of CCOB is that you can stack very fast different individual azimuths together and get a sharper image, which results in better interpretation.
Azimuth sectors both parallel and perpendicular to the three major fault system orientations, were imaged separately to produce the six final azimuth volumes. Comparisons between the different azimuth sectors were used to detect azimuthal differences in velocities and amplitudes that could be correlated with fault and fracture orientation and magnitude.
The interpretation and validation of the results suggest that value is maximized by integrating multiple attributes that include horizon mapping for time differences, amplitude extractions for reflectivity differences and result validations with available well calibration. The azimuth sector results have aided in the quantification of fault presence, magnitude of throw and suggests that fractured zones can be identified which may indicate higher permeability pathways within the reservoir.
Another important learning from this case study is to use an integrated approach during processing and interpretation and don’t look only at one single part, e.g. velocity cube.
Overall the results of this carbonate Azimuthal Pilot for fault and fracture characterization has produced encouraging results and valuable lessons learned to aid future studies.
Successful Formation Pressure Testing While Drilling Directionally Demanding 17 1/2-in. Hole in Deepwater Angola
Authors: O’Hara Peter , Prieto Olga , Symons Graeme 
Published: February 2011

Abstract
The benefits of formation pressure testing while drilling include improved formation evaluation, drilling hazard mitigation, drilling performance optimization and saving time. In deepwater wells offshore Angola, this is regularly used in 12 ¼-in. and smaller hole sections. The requirement extended to the 17 ½-in. hole sections which are typically directionally drilled with high buildup rates due to the reservoir being located at a relatively shallow depth below the seabed. The plan was to adapt the formation pressure testing equipment already used in 12 ¼-in. hole and establish a technique to use it in 17 ½-in. hole. This was complicated by the high buildup rates in the 17 ½-in. hole, as opposed to the high-angle tangents seen in the 12 ¼-in. hole sections. The unconsolidated nature of the formation further complicated the process as the low compressive strength of the rock can prove challenging for directional steering and the friability of the formation could affect both the seal of the formation pressure tester and its ability to sample pressure.
This paper will discuss development of the techniques over the initial wells, issues that were encountered and solutions developed to simultaneously deliver the formation pressures and the directional profiles using standard equipment. In addition, the paper will discuss how the techniques developed for the 17 ½-in. hole were further adapted to sample formation pressures when these had to be measured in 13 ½-in. hole below 9 ⅝-in. casing in situations where conventional formation pressure testing techniques could not deliver data. As a result, the paper describes the successful deployment of real-time formation pressure testing in large hole sizes whatever the directional challenges.
Optimization of Horizontal Wellbore and Fracture Spacing Using an Interactive Combination of Reservoir and Fracturing Simulation
Authors: Taylor R. S. , Glaser M. A. , Kim J. , Wilson B. , Nikiforuk G. , Noble V. , Rosenthal L. , Aguilera R. , Hoch O. , Storozhenko K. , Soliman M. , Riviere N. , Palidwar T. , Romanson R. 
Published: February 2011

Abstract
The application of horizontal wellbore drilling and multistage fracturing technology has been playing a pivotal role in unlocking shale-gas reserves globally. More recently, the same technology has been applied to both new and mature oil fields.
A key question for economic optimization of these assets is what fracture spacing to use along a horizontal wellbore. Of equal importance is what spacing to use for multilaterals and the wellbores themselves to achieve optimal drainage of the reservoir. In addition, the design of the fracturing treatments must be optimized.
To address these questions, a combination of reservoir and fracturing simulation has been applied. The required input data are provided through a combination of advanced log and core analyses, diagnostic fracture injection testing (DFIT), rate transient analysis (RTA), and characterization of fracture geometry through microseismic monitoring. Fluid rheology is characterized using pressurized rheometers and flow loops.
This paper presents results of this work using examples of current Canadian oil and shale-gas reservoirs and a methodology to improve the economic return of different completion and production scenarios.
Hot Solvent Injection for Heavy Oil/Bitumen Recovery: An Experimental Investigation
Authors: Pathak V. , Babadagli T. , Edmunds N. R 
Published: February 2011

Abstract
Thermal and miscible methods are commonly used for in-situ recovery of heavy oil and bitumen. Both techniques have their own limitations and associated shortcomings, often times yielding an inefficient process. The most common thermal method is steam injection, which is highly energy intensive. Steam generation costs and water production affect the economics of the thermal technique adversely. On the other hand, miscible methods are energy effective but their economics depends on the solvent retrieval. Various combinations of these two techniques such as co-or alternate injection of steam and solvent have been proposed as a solution, but no optimum method has yet been developed.
Thermal and miscible methods can be combined by co-injecting solvent with steam or injecting solvent into a pre-heated reservoir. Current work was undertaken to study the performance of solvents at higher temperatures for heavy oil/bitumen recovery. Glass bead packs and Berea sandstone cores were used in the experiments to represent different types of pore structures, porosity and permeability. After saturating with heavy oil, the samples were exposed to the vapor of paraffinic solvents (propane and butane) at a temperature above the boiling point of the solvent, and a constant pressure of 1500 kPa. A mechanical convection oven was used to maintain constant temperature across the setup. The setup was designed in such a way that a reasonably long sample (up to 30 cm) can be tested to analyze the gravity effect. The oil recovered from each of these experiments was collected using a specifically designed collection system and analyzed for composition, viscosity and asphaltene content.
The amount of oil recovered in each case was also analyzed and the quantity and nature of asphaltene precipitated with each of the tested solvents under the prevailing temperature and pressure of the experiment was reported. Optimal conditions for each solvent type were identified for the highest ultimate recovery. It was observed that recovery decreased with increasing temperature and pressure of the system. It was also noticed that butane diluted the oil more than propane which resulted in lower asphaltene content and viscosity of oil produced with butane as a solvent.
Cement Technology Improves Fracture Initiation and Leads to Successful Treatments in the Eagle Ford Shale
Authors: Stegent N. A. , Leotaud L. M. , Prospere W. , Veillette C. P. 
Published: February 2011

Abstract
Stimulation-design considerations usually include things like formation-fracture gradient, reservoir pressure, stress, casing size, perforation schemes, etc. The type of cement that fills the annular space between the openhole lateral and the casing is not typically considered with regards to its impact on the execution of the frac treatment.
Early horizontal-well completions observed much higher injection pressures than those observed in vertical wellbores in the same formation. Research identified the effects caused by transverse, oblique, or longitudinal fractures from horizontal wellbores, which were usually nonissues in vertical completions. Near-wellbore (NWB) friction (tortuosity) is a component that is common to both vertical and horizontal wellbores but seems to be ignored in horizontal completions. When proppant cannot be placed during a horizontal frac, it is usually blamed on formation-fracture width (or lack of it) and proppant size (mesh size is too large). These are the typical reasons used to explain early screenouts and have become commonplace in the industry. The authors of this paper believe NWB tortuosity issues have a much larger impact than most think and will show how a properly engineered production casing cement, in conjunction with the stimulation design, allows the placement of large-mesh proppant at high concentrations in the Eagle Ford shale. High conductivity is essential for maintaining liquid-rich production.
Fracture initiation in a horizontal well, especially at the toe, can sometimes be very difficult. To minimize injection issues, acid-soluble cement (ASC) was placed in the lateral of several Eagle Ford-shale wells in Karnes County, Texas. Hybrid stimulation treatments were used to place 20/40-mesh proppant at concentrations up to 4 lbm/gal, most without issue. Proper engineering was used to successfully fracture stimulate all the intended intervals (including the first stage at the toe).
Utilization of ASC for horizontal completions can help improve stimulation efficiency and allow alternate onsite frac options that can turn an otherwise-abandoned completion interval into a successfully stimulated section of the reservoir.