bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Use of a Wireline Formation Tester with Dual Intake Inflatable Packers to Optimize Fluid Analysis in an Eastern Siberia Heavy Oil Field
Authors: Tsiklakov A. , Weinheber P. , Wichers W. , Zimin S. , Oshmarin R. 
Published: October 2011

Abstract
The Vankor field development in Russia's Eastern Siberia involves the exploitation of moderately viscous oil from medium to low permeability reservoirs. The field is on production from two different layers, both of which have active aquifers and are supported by water injection. Conventional petrophysics in the field can be difficult and fluid typing is often ambiguous. Downhole fluid analysis with wireline formation testers (WFT) is frequently used to assist in the clarification of petrophysical challenges.
However, formation tester operations are not straightforward. Lower permeability and higher oil viscosity means that the WFT probe does not allow sufficient area for fluid to flow. Inflatable dual packer devices are therefore required. The inflatable packer, however, brings its own challenges. With a larger volume of reservoir being investigated longer pump times are required to evacuate invaded filtrate. Additionally, issues associated with the relative permeability of water and heavier oil frequently mean that hundreds of litres of fluid often must be pumped before the fluid typing questions are resolved. In this paper we discuss the implementation of a modified formation tester tool that uses an inflatable packer arrangement configured with dual intake ports. Each of the intake ports is supported by an independent pump and fluid analysis section. Such a configuration offers two benefits. Firstly, the simultaneous operation of two pumps allows the evacuation of larger amounts of fluid in a given time. Secondly, and more importantly, the positioning of the intake ports within the dual packer module allows the tool to take advantage of the density segregation occurring in the packed off interval and to arrive at a clean oil flow much more quickly than a standard configuration. Field examples and lessons learned are provided.
Estimating Drainage-Area Pressure with Flow-After-Flow Testing
Authors: Kabir C. S. , Elgmati M. , Reza Z. 
Published: October 2011

Abstract
Estimating the individual wells’ average drainage-area pressure or pav is cornerstone to any reservoir-management practice. Yet, conventional methods do not always offer reliable solutions to this vexing problem. This study shows that transient flow-after-flow (FAF) testing offers an excellent opportunity to establish pav in a time-lapse mode, when conducted following operational shut downs. Instrumented wells are natural candidates for FAF testing.
The real-time surveillance offers the opportunity to perform rate-transient analysis that results in drainage volume and, consequently, pav. However, gathering quality rate data commensurate with pressure over a long producing period is fraught with uncertainty, which raises questions about the validity of the pav so obtained. In addition, continuous changes in drainageboundary conditions pose modeling challenges with a given reservoir model. Therefore, the independent estimation of pav cannot be overemphasized. This paper presents a theroretical framework for transient FAF testing and also shows a pragmatic approach to handling pressure/rate data incoherence.
Real-Time Long Distance Teaching: An Extensive Evaluation of the Techniques and Student Response of 6 Years of Non-stop Process
Authors: Teodoriu Catalin , Epps Mary Lu , Barrufet Maria A. , Falcone Gioia 
Published: October 2011

Abstract
This paper presents an extensive evaluation of various Distance Learning (DL) and tele-teaching techniques, based on the experience gained over the past 6 years using free software and commercial web-based solutions, and including live participation of DL students.
This paper discusses the advantages and disadvantages of the various tele-teaching options that have been implemented to deliver highly sophisticated petroleum engineering classes to students worldwide from two universities in College Station, Texas (server location) and Clausthal-Zellerfeld, Germany (teacher's location). Based on the enthusiastic students’ feedback, it is clear that they enjoy tele-teaching and learn from it even more than they do from conventional courses. This paper is a follow-up to the papers SPE 134440 and 124748, which were well received by the audience who suggested further investigation into these techniques.
Backpressure Equation for Layered Gas Reservoirs
Authors: Juell Aleksander , Whitson Curtis Hays 
Published: October 2011

Abstract
This paper presents a backpressure equation (BPE) for wells producing from layered gas reservoirs with or without communication. The proposed BPE handles backflow between the layers through the wellbore for non-communicating layered systems, and accurately describes performance of wells experiencing differential depletion.
The proposed multi-layer BPE has the same form as the familiar backpressure equation for single-layer gas reservoirs, where the correct averages are defined for reservoir pressure and backpressure constants.
The BPE is validated against numerical simulation models, as well as field data which include decades of historical production performance and annual shut-in pressures. All numerical models and field data used to validate the BPE are publicly available. This paper gives guidelines on welltest design to quantify reservoir parameters in layered systems, based on systematic studies with numerical simulation models.
Adequate Cementing Solutions for Deepwater Dual-Casing Running System Improves Operational Efficiency When Drilling Tophole Sections in Deepwater Wells
Authors: Moroni N. , Simeone D. , Parrozza F. , Fazio S. , Therond E. , Belleggia E. , Connell R. , Bogaerts M. 
Published: October 2011

Abstract
To improve drilling operation efficiency in the riserless tophole section, a new casing running system was introduced in offshore Angola. In this new system, the hole sections for the conductor and surface casing are drilled in one run, followed by running both casing strings in one trip, requiring a single cement job. This system uses a minimum of one trip in the hole compared with conventional techniques used for running casing and cementing in the riserless phase. The cementation of the dual casing has similar objectives to normal surface casing cementation: stable wellhead with cement returns to seabed, no shallow flow in case of shallow drilling hazards, and good cement integrity at the casing shoe to continue drilling operations with minimum wait-on-cement time.
The cementation of the dual casing is challenging for several reasons: the cement job has to cover two concentric annuli, the cement returns are passing through the unconsolidated formation with a high risk of losses because there is no conductor casing set below the seabed, possible shallow flow, large formation washouts close to the seabed depth, and the requirement to develop sufficient compressive strength in a short period of time at very low temperatures to bear the weight of both casing strings and the wellhead assembly.
In offshore Angola, the casing running system has been used seven times in water depths from 460 and 1450 m. Initial cement design used conventional lightweight extended lead cement with a neat tail and its drawbacks. The use of this cement system caused losses close to the seabed and resulted in an unstable wellhead requiring top-up jobs. Careful engineering and planning between the service company and the operator resulted in the development and execution of two successful cement techniques. The first technique consisted of Low Temperature Optimized Particle Size Distribution Cement, followed by neat tail slurry. Because shallow drilling hazards were present, shallow water flow slurries were designed for the job. The second technique consisted of a foamed lead cement followed by a neat tail slurry. Both cement designs fulfilled the job objectives.
The dual-string running technique, combined with an efficient cementing technique, enabled a 40% time reduction in the riserless phase of the well operations while safely achieving the well integrity objectives.
Acrolein Provides Benefits and Solutions to Offshore Oilfield Production Problems
Authors: Horaska D. D. , San Juan C. M. , Dickinson A. L. , Lear S. L. , Colquhoun A. 
Published: October 2011

Abstract
Offshore production systems can be negatively impacted by numerous problems attributed to bacterial activity, associated hydrogen sulfide (H2S) and biogenic iron sulfides (FexSy), and mercaptan (R-SH) production. Examples of these problems include microbiologically influenced corrosion (MIC), under-deposit corrosion due to FexSy deposition, equipment fouling due to biomass accumulation, impaired oil-water separation leading to poor water quality and overboard oil-in-water problems, and not achieving pipeline specification due to excess H2S and/or R-SH content.
Acrolein provides a distinctive all-in-one chemical solution to resolving these problems. The key to this solution is fourfold: Acrolein scavenges H2S, it scavenges R-SH, it is a potent microbiocide, and it dissolves FexSy.
This paper details the usage of acrolein in the context of an offshore application with respect to the issues and problems unique to an offshore environment. Acrolein treatment programs can provide effective production odor control and achieve pipeline specifications from both an H2S and R-SH scavenging perspective. The unique dual solubility of acrolein in oil and water enables it to penetrate and remove oil-coated FexSy solids and sessile bacteria from production systems. Due to its low minimum inhibitory concentration, acrolein provides cost-effective biocide treatment not only in batch applications but also in continuous treatment programs. Well-established application protocols using a closed delivery system minimize potential chemical exposure, an important HSE consideration. Acrolein's high order of reactivity and biodegradability lends itself well to usage in a sensitive offshore environment.
A series of case histories are presented that highlight the benefits of using acrolein in offshore systems to mitigate related production problems. Multiple benefits can be realized with the application of one product.
Kinetic Cell and Combustion Tube Results for a Central European Crude Oil
Authors: Glatz G. , Hascakir B. , Castanier L. M. , Clemens T. , Kovscek A. R. 
Published: October 2011

Abstract
This paper increases understanding of in-situ combustion (ISC) mechanisms based on experimental results for a Central European crude oil for which ISC has proven to be economically successful. Ramped temperature oxidation (RTO), or so-called kinetics, studies measure the rate of crude-oil oxidation. Similarly, combustion tubes packed with mixtures of sand, clay, water, and hydrocarbon measure our ability to propagate a combustion front. Through the combination of the isoconversional approach for estimation of reaction kinetics (apparent activation energy Ea, Arrhenius constant or pre-exponential factor A) and implementation of combustion tube runs under different conditions, the mechanisms behind the combustion process are elucidated. The results of seven combustion tube runs are presented and discussed in terms of repeatability, effect of grain surface area, effluent gas concentration oscillations, stoichiometry, minimum air flow rate and recovery efficiency. Based on experimental results, critical parameters for field application as well as for simulation are derived (hydrogen/carbon-ratio, air requirements). Opposed to previous publications, the ISC process is described in terms of stoichiometry for the entire tube run, giving insight into development of hydrogen/carbon-ratio and other important parameters over time. This helps to compare, verify, and tune simulation results obtained from commercial simulators. Results obtained point out the exceptional efficiency of ISC in terms of recovery and fuel consumed. Monitoring combustion stoichiometry over time gives an increased insight into flue-gas composition oscillations.
A Real Time Lift Monitoring and Optimization Solution Applied at Chicontepec Field
Authors: Ramirez Narvaez Antonio , Cetkovic Ivan , Lopez Llopiz Mario , Sandoval Hernandez Gilberto , Acosta Héctor Ruben Tobías , Hernández Utrera Francisco , Cobos V. Héctor , Martínez José R. 
Published: October 2011

Abstract
A Real Time Lift Monitoring and Optimization Solution project has been applied at the Chicontepec Field during 2009, implementing an integrated system of acquisition, monitoring and control of real time data allowing engineers and operators to use the information and needed tools to optimize the operation of the asset.
This solution has provide a comprehensive automation system at 350 wells, most of them under Reciprocated Rod Lift Systems with the objective of increases pumping efficiency, reduces well failures, and minimizes downtime. Monitoring rooms installed at the Operational and Service Company allows access and real time information almost to fifteen engineers to all different workgroups. By integrating engineering analysis and design Production operators now can concentrate on solving problems rather than using valuable time searching for them, improving their efficiency by making effective use of their time and enables all members of a production operations team including automation technicians, well analysts, and production engineers to use the same system enabling them to work as a cohesive team. The system infrastructure is build basically by two servers, serial radio communications and well controllers that allows operating and controlling the Reciprocated Rod Lift Systems like a shut down of the equipment.
This can be accomplish due to the intensive training through courses and on site support that has been delivered to the teams, sharing of data and knowledge leads to better design and implements results, increasing oil production and reducing failures. Some of the results obtained during 2009 were the reduction of premature failures due to smart alarms, reduction on the use of digital echometer, inferred production of each well per day and the capability to determine gas consumption per well.
Micro Seismic Monitoring: First Borehole Micro Seismic Job Done in Colombia, Morpho Well
Authors: Garcia Juan G. , Franco Victor H. , Vasquez Cesar , Wills Alejandro 
Published: October 2011

Abstract
Since the inclusion of Micro Seismic technologies in the Barnett Shale, this technology has become one of the most powerful and used tools to monitor the behavior of reservoirs exposed to hydraulic fracturing with non-permanent arrays and also, to detect changes due to injection/production of fluids during long periods of time using permanent arrays.
This paper focus its efforts in non-permanent arrays, which require the use of high resolution seismic tools deployed in the well and anchored to the casing walls to detect micro seismic events produced by induced movement in un-deformed rock or along pre-existing fractures which is in response to the interaction between natural stress directions and equilibriums and those that are being forced on the deformations through stimulation or injection. This paper will present results from the first micro seismic job done in Colombian history, which was performed in December 2010. The results obtained with the implementation of this technology want to provide an image of the zones affected with the injection of fluids, which will allow the operating company to define drainage areas and optimize the location and development of new wells in the field, optimize perforating spacing and location, analyze the containment of the fracture to the interest zone and avoid the migration or the rupture into undesired zones like aquifers, it will also help define optimal injection rates and proppant concentrations. After having a better knowledge of the fracture behavior, stress distribution and production levels, one can think in re-defining drilling strategies and to think the feasibility of highly deviated to horizontal wells; these kinds of decisions had been taken by companies that used micro seismic and were translated in millions of dollars in savings. One of the most notorious examples is the Barnett - Shale, where they moved from vertical wells to a big majority of horizontal wells, which boost the production rates and transformed this field in one of the biggest gas producers in USA; similar steps are being followed in the Marcellus shale and the Haynesville shale in USA, as well as fields in Canada, and India just to mention some.
This paper center is based on results obtained from the first borehole micro-seismic job done in Colombia and will present the conclusions obtained from combining results from different services ran in the well Morpho – 1. Combining the analysis of pressure curves with micro seismic gives us a great idea of how the different fracture types can be observed and also, will help fracture designing teams to better understand and determine the best way to treat rocks.
Selecting Candidate Wells for Refracturing Using Production Data
Authors: Roussel Nicolas P. , Sharma Mukul M. 
Published: October 2011

Abstract
The selection of candidate wells for refracturing is often very difficult based on the information available at the surface. We propose a systematic methodology to allow a field engineer to evaluate a well's potential for refracturing from an analysis of field production data and other reservoir data that is commonly available. We successfully confronted our method to a case study in the Wattenberg field using data from 300 Codell tight gas wells.
The performance of refracturing treatments has been observed to be highly variable in the Wattenberg field (Colorado) with some wells underperforming while others are restored to initial or even higher production rates. Historically, multiple approaches have been taken to select the best candidate wells, including heuristic guidelines, field correlations, and neural networks.
After identifying the physical phenomena that are thought to impact the performance of refracturing operations, we developed five dimensionless groups to quantify them. By choosing a dimensionless approach, we establish refracturing criteria that may be applied to any oil or gas field. One potential motivation for refracturing is the stress reorientation occurring around a fractured well causing the refracture to propagate orthogonally to the initial fracture in under-depleted sections of the reservoir. Numerical simulations of the areal extent of the stress reversal region as well as tiltmeter measurements confirmed the existence of refracture reorientation in the Codell formation. Guidelines for the selection of refracturing candidates were expressed in terms of the potential for stress reorientation, the quality of the initial completion, the initial production decline and the reservoir depletion around the well of interest. Two groups of wells showed the most promise for refracturing: (a) ineffective initial completions with a small initial production decline and (b) long initial fractures in under-depleted reservoirs. The dimensionless groups help us identify such wells and provide quantitative criteria for selection of wells that may be good candidates for refracturing.
Strategies to Minimize Frac Spacing and Stimulate Natural Fractures in Horizontal Completions
Authors: Roussel Nicolas P. , Sharma Mukul M. 
Published: October 2011

Abstract
The opening of a propped transverse fracture in horizontal wells causes a reorientation of stresses in its neighborhood, which in turn affects the direction of propagation of subsequent fractures. This phenomenon, often referred to as stress shadowing, can negatively impact the efficiency of each frac stage. By mapping the angle of stress reorientation and the horizontal deviatoric stress in multi-fractured horizontal wells, we offer some insight on the completion designs that will (a) minimize induced fracture spacing without compromising the efficiency of each frac stage and (b) effectively stimulate natural fractures in the vicinity of the created fracture.
The rapid development of shale gas in North America can be tied to the combination of horizontal drilling and multi-stage fracturing. The spacing between fractures and perforation clusters as well as the ability to stimulate the fractures naturally present in the rock are thought to be major factors in the success of horizontal completions in shale gas reservoirs. The understanding and quantification of the mechanical stress interference generated during the stimulation of horizontal wells is crucial to improving reservoir drainage in shale gas reservoirs
Transverse fractures initiated from a horizontal well may deviate toward or away from the previous fracture depending on the mechanical properties of the reservoir rock, fracture spacing, and the orientation of the previous fracture. Using a numerical model allowing non-transverse fractures (those that deviate from the orthogonal path), we show that some induced fractures propagate into previously stimulated areas during the consecutive fracturing of a Barnett shale well, thus decreasing the reservoir drainage efficiency of the frac treatment. The observed net pressure trend matches field observations during fracturing and microseismic measurements.
The alternate sequencing of transverse fractures as well as multi-lateral completions were recognized to be effective ways to enhance natural fracture stimulation, by allowing fracture stages to experience a smaller stress contrast during propagation. More importantly, it is shown that net fracturing pressure data measured in the field can be used to detect mechanical interference between multiple transverse fractures and optimize fracture spacing for a specific well.