bluuebunny/crossref_metadata_2025_split huggingface dataset:
Probabilistic Well-Time Estimation Revisited
Authors: Adams A.J.. J. , Gibson C.. , Smith R.. 
Published: June 2010

Summary
Probabilistic estimation of well duration has been common practice for more than a decade; many papers have been written on the subject, and commercial software is available for the purpose. Is the subject, therefore, mature? The authors suggest that this is not the case and show that several essential aspects of both data characterization and probabilistic analysis have been overlooked in previous contributions.
In 2007, Nexen began a study with the objective of improving our process for well-time estimation. Its workscope was to Assemble a statistically significant historical well database.Develop a consistent definition of nonproductive time (NPT) as it relates to the original approved-for-expenditure (AFE) timings.Reanalyze the historical well database for NPT from the original daily drilling reports (DDRs), on the basis of the definition above.Decide how NPT is best characterized (that is, determine the correct choice of input variables).Determine the associated occurrence frequencies and probability-density-function (PDF) parameters from the historical database.Validate the probabilistic model, by comparison of program predictions against the historical data set.Work with a software provider to implement any necessary changes in a commercially available product.
A database of 118 central North Sea wells was reanalyzed independently for NPT from the original DDRs. These considerably underestimated the true NPT, by 19.7% on average. Train wrecks (mechanical NPT events of more than 2.5 days) were only 4% by number but contributed 50% of NPT by duration. It was found that "ordinary" mechanical NPT, train wrecks, waiting on weather (WOW) in open water, and WOW with riser connected are all statistically distinct, with very different occurrence frequencies and PDFs. Earlier workers did not observe this distinction or properly validate their models against the well database.
Therefore, it is impossible to obtain historically accurate probabilistic well-time predictions (i.e., that are consistent with the historical database) using the previous state of the art. Moreover, such predictions will generally be underestimates. This paper describes an accurate method that overcomes previous limitations. While central North Sea data are used, the analysis techniques are not area specific, and the method may be applied easily to other areas in the oil field.
Quantifying Transient Effects in Altered-Stress Refracturing of Vertical Wells
Authors: Roussel Nicolas P. , Sharma Mukul M. 
Published: June 2010

Summary
The production or injection of fluids in reservoirs results in a redistribution of stresses. In this paper, the extent of stress reorientation has been calculated for fractured production and injection wells and the results have been analyzed for their effect on refracturing operations. Rules of thumb and charts have been provided to help with candidate-well selection for refracturing on the basis of the study.
For previously fractured wells, it is possible to create a secondary fracture that is perpendicular to the first. The secondary orthogonal fracture can be created only within a certain time window that, in turn, depends on the reservoir properties. Conditions leading to orthogonal secondary fractures in different kinds of reservoirs (oil, gas, and tight gas reservoirs) have been analyzed to establish some rules of thumb. The effects of the layers bounding the pay zone and of permeability heterogeneity and anisotropy on stress reorientation are also discussed.
Our results allow us to quantify the phenomenon of orthogonal secondary fracturing around fractured production wells by calculating the extent of the stress-reversal region as a function of time. The results of our model are shown to agree qualitatively with field observations obtained from microseismic measurements. The model presented in the study helps to clarify the concept of refracturing and provides a quantitative estimate of the time window for refracturing as a function of dimensionless parameters. The final result demonstrates the potential of the model to increase the reservoir sweep in unconventional reservoirs for which the optimum time window for refracturing is on the order of months to years. The conclusions of this study are useful for the design of refracturing operations and for candidate-well selection.
Maintaining Steerability While Extending Gauge Length To Manage Whirl
Authors: Dupriest Fred E. , Sowers Steven F. 
Published: June 2010

Summary
This paper discusses the results of a global campaign to increase the length of the gauge area of bits used on rotary-steerable systems (RSSs) to mitigate bit whirl and its undesirable effects. The desired steerability was achieved with lengths in excess of 4 in. with all RSS tools used. The modifications have resulted in reduced vibrations, significant improvement in drill rate, improved borehole quality, and reduced tool damage.
When the operator's performance-management process was implemented, real-time and post-drill analysis of mechanical specific energy (MSE) suggested 40% of footage drilled worldwide was affected by bit whirl or lateral instability. One element in the programmatic response was an initiative beginning in 2006 to extend bit-gauge lengths to constrain side cutting and reduce the amplitude of whirl-induced patterns. The value of extended gauge lengths has been demonstrated in numerous papers. However, field implementation by the industry has not been uniform, and a significant issue has been concern that steerability would be reduced. The purpose of the initiative was to demonstrate that common build rates could be achieved with all RSS tools used by the operator with bits having a minimum gauge length of 4 in. In the subject wells over a 2-year period, normal build rates (2-4°/100 ft) were not affected with 4-in. gauges if the profile and aggressiveness were designed properly. The gauge profiles used to maintain steerability included full taper, full undercut, and partial undercut. While the desired steerability was achieved with both point-the-bit and push-the-bit RSS tools, specific modification required in the gauge profile varied with the RSS used, desired build rate, and drilling environment. Drill-rate performance and bit life also improved, but this was attributed partly to implementation of the performance-management process and specific rig-crew training. Extension of the gauge length is also known to benefit bent-motor operations (Norris et al. 1998); however, the effects of various gauge profiles are less certain, and motor operations are not discussed in this paper.
The objective was not to determine the maximum build rates achievable but to simply confirm that gauge lengths of 4 in. or greater could be used as standard practice in normal operations. This paper discusses the rationale for the use of extended gauges, the modified profiles used to maintain steerability with various RSS tools, and the field performance achieved.
Evaluation of Renewable Energy as a Source of Power for Desalination of Remote-Oilfield Brines
Authors: Barrufet Maria A. , Mareth Brett C. 
Published: June 2010

Summary
A hybrid system of wind, solar, and diesel generators could provide an efficient alternative for powering water-desalination projects in remote-oilfield locations in Texas, USA. Disposal of produced water from oil and gas wells is a costly procedure for production companies, but water-to-oil production ratios exceed 10:1 (by volume) at many wellsites. Much of the petroleum produced in the United States and elsewhere is found in arid regions that could benefit greatly if the produced water could be purified sufficiently for agricultural, industrial, or potable use. Our previous research identified and validated treatment options capable of recovering a high proportion of fresh water from oilfield brine. In this paper, we extend the earlier research further by examining the possibility of using renewable energy to power the units in "off-the-power-grid" situations. A macro-driven spreadsheet was created to allow for quick and easy cost comparisons of renewable energy sources for a variety of scenarios. Using this tool, wind and solar costs were compared for cities in regions throughout Texas. The renewable energy resource showing the greatest potential was wind power, with the analysis showing that in windy regions such as the Texas Panhandle, wind-generated-power costs are lower than those associated with diesel-fuel generation.
Stability of Partially Hydrolyzed Polyacrylamides at Elevated Temperatures in the Absence of Divalent Cations
Authors: Seright R. S. , Campbell A. R. , Mozley P. S. , Han Peihui 
Published: June 2010

Summary
At elevated temperatures in aqueous solution, partially hydrolyzed polyacrylamides (HPAMs) experience hydrolysis of amide side groups. However, in the absence of dissolved oxygen and divalent cations, the polymer backbone can remain stable so that HPAM solutions were projected to maintain at least half their original viscosity for more than 8 years at 100°C and for approximately 2 years at 120°C. Within our experimental error, HPAM stability was the same with and without oil (decane). An acrylamide-AMPS copolymer [with 25% 2-acrylamido-2-methylpropane sulphonic acid (AMPS)] showed similar stability to that for HPAM. Stability results were similar in brines with 0.3% NaCl, 3% NaCl, or 0.2% NaCl plus 0.1% NaHCO3. At temperatures of 160°C and greater, the polymers were more stable in brine with 2% NaCl plus 1% NaHCO3 than in the other brines. Even though no chemical oxygen scavengers or antioxidants were used in our study, we observed the highest level of thermal stability reported to date for these polymers. Our results provide considerable hope for the use of HPAM polymers in enhanced oil recovery (EOR) at temperatures up to 120°C if contact with dissolved oxygen and divalent cations can be minimized.
Calculations performed considering oxygen reaction with oil and pyrite revealed that dissolved oxygen will be removed quickly from injected waters and will not propagate very far into porous reservoir rock. These findings have two positive implications with respect to polymer floods in high-temperature reservoirs. First, dissolved oxygen that entered the reservoir before polymer injection will have been consumed and will not aggravate polymer degradation. Second, if an oxygen leak (in the surface facilities or piping) develops during the course of polymer injection, that oxygen will not compromise the stability of the polymer that was injected before the leak developed or the polymer that is injected after the leak is fixed. Of course, the polymer that is injected while the leak is active will be susceptible to oxidative degradation. Maintaining dissolved oxygen at undetectable levels is necessary to maximize polymer stability. This can be accomplished readily without the use of chemical oxygen scavengers or antioxidants.
Incremental-Oil Success From Waterflood Sweep Improvement in Alaska
Authors: Ohms Danielle , McLeod Jennifer , Graff Craig J. , Frampton Harry , Morgan Jim C. , Cheung Stephen , Chang K.T.. T. 
Published: June 2010

Summary
Waterflood thief zones in communication with the rest of the reservoir are a severe and previously challenging problem. This paper gives an introduction to the nature of a novel, heat-activated polymer particulate. Details are presented of a trial of this in-depth diversion system, resulting in commercially significant incremental oil from a BP Alaskan field. The system of one injector and two producers was selected because of a high water/oil ratio and low recovery factor, which was recognized as an indicator of the presence of an injection-water thief zone and was confirmed by study of a previous injection survey. The area around the wells is bounded by faults, so the system can be considered to be isolated from surrounding wells and operations. The position of the thermal front in the reservoir, tracer transit times, injection rates, and interwell separations indicated that the slowest reacting of the three commercial grades available was most appropriate for the trial.
The treatment was designed using laboratory tests and numerical simulation informed by pressure and chemical-tracer tests. Long- sandpack tests indicated permeability-reduction factors of 11 to 350 for concentrations of 1,500 to 3,500 ppm active particles in sand of 560- to 670-md permeability at 149°F. 15,587 gal of particulate product was dispersed using 8,060 gallons of dispersing surfactant, into 38,000 bbl of injected water, and was pumped over a period of 3 weeks at a concentration of 3,300 ppm active particles.
Placement deep in the reservoir between injector and producer was confirmed by pressure-falloff analysis and injectivity tests. The incremental oil predicted from the simulation was 50,000 to 250,000 bbl over 10 years. In fact, more than 60,000 bbl of oil was recovered in the first 4 years at a cost comparable with that of traditional well work and less than that of sidetracking.
Formation-Damage and Well-Productivity Simulation
Authors: Lohne Arild , Han Liqun , Zwaag Claas van , van Velzen Hans , Mathisen Anne-Mette , Twynam Allan , Hendriks Wim , Bulgachev Roman , Hatzignatiou Dimitrios G. 
Published: June 2010

SummaryIn this paper, we describe a simulation model for computing the damage imposed on the formation during overbalanced drilling. The main parts modeled are filter-cake buildup under both static and dynamic conditions; fluid loss to the formation; transport of solids and polymers inside the formation, including effects of porelining retention and pore-throat plugging; and salinity effects on fines stability and clay swelling. The developed model can handle multicomponent water-based-mud systems at both the core scale (linear model) and the field scale (2D radial model). Among the computed results are fluid loss vs. time, internal damage distribution, and productivity calculations for both the entire well and individual sections.The simulation model works, in part, independently of fluid-loss experiments (e.g., the model does not use fluid-leakoff coefficients but instead computes the filter-cake buildup and its flow resistance from properties ascribed to the individual components in the mud). Some of these properties can be measured directly, such as particle-size distribution of solids, effect of polymers on fluid viscosity, and formation permeability and porosity. Other properties, which must be determined by tuning the results of the numerical model against fluid-loss experiments, are still assumed to be rather case independent, and, once determined, they can be used in simulations at altered conditions as well as with different mud formulations. A detailed description of the filter-cake model is given in this paper.We present simulations of several static and dynamic fluid-loss experiments. The particle-transport model is used to simulate a dilute particle-injection experiment taken from the literature. Finally, we demonstrate the model's applicability at the field scale and present computational results from an actual well drilled in the North Sea. These results are analyzed, and it is concluded that the potential effects of the mechanistic modeling approach used are (a) increased understanding of damage mechanisms, (b) improved design of experiments used in the selection process, and (c) better predictions at the well scale. This allows for a more-efficient and more-realistic prescreening of drilling fluids than traditional core-plug testing.
Gas-Well Liquid-Loading-Field-Data Analysis and Multiphase-Flow Modeling
Authors: Veeken Kees , Hu Bin , Schiferli Wouter 
Published: June 2010

Summary
Gas-well liquid loading occurs when gas production becomes insufficient to lift the associated liquids to surface. When that happens, gas production becomes intermittent and eventually stops. In depleting gas reservoirs, the technical abandonment pressure and ultimate recovery are typically governed by liquid loading. To date, most methods for predicting liquid loading have followed Turner et al. (1969), who describe liquid loading as the point where the liquid droplets suspended in the gas flow start moving downward rather than upward. This paper presents (offshore) liquid-loading field data that exceed the Turner predicted values by an average of 40%, and analyzes the sensitivity of the liquid-loading gas rate for different well parameters. It subsequently presents the results of steady-state and transient multiphase-flow modeling, carried out to identify the influence of the same well parameters. A modified Turner expression is proposed that best fits the liquid-loading field data and broadly agrees with the results of a multiphase-flow model that uses a modified version of the Gray outflow correlation. The results of transient-flow modeling support the flow-loop observation that liquid loading occurs because of liquid-film-flow reversal rather than droplet-flow reversal. The impact of these findings on gas-well deliquefication is explored.
IO Design Gives High Efficiency
Authors: Moltu Berit , Nærheim Jakob 
Published: June 2010

Summary
Integrated operations (IO) is about employing real-time data and new technology to remove barriers between disciplines, expert groups, locations, and companies. In this paper, we investigate the effect on efficiency from design and work practice in operations support (OPS) rooms. A study taken within a Norwegian oil and gas company shows an evident correlation between IO design and high efficiency.
This study shows the difference in design and practice between four different OPS rooms. The OPS unit is supposed to support interaction between different locations (e.g., onshore and offshore) in the upstream oil industry. Recent practice has established special OPS rooms to make operations and maintenance work more feasible between the onshore-based operation unit and the offshore operations.
In this study, newer academic perspectives from science and technology studies (STSs) are taken into the field of health, safety, and environment (HSE). Inspired by actor network theory (Latour 1987, 1999), the OPS rooms are seen as a chain of networks between different physical locations, different information and communication technology (ICT) solutions, different organizational and managerial models, and new working practices, all intended to support the current operations. The IO solution is intended to support and create new ways of working based on real-time data and online communication, and across geographic space. This improves transparency in solutions (e.g., to open up frozen borders between different departments, different disciplines, different geographical locations, and between management and employers, and to foster new perspectives on ICT and on what a room is).
The variety of solutions and practices was studied by participative observation in all five rooms. More than 40 employees working with OPS onshore and offshore were interviewed. A survey was conducted on efficiency of operations and maintenance work, optimization of production, and management of asset integrity and technical disciplines. Analyses of the results on efficiency concluded that the highest-IO-maturity assets perform well when it comes to efficiency. We attribute this to a more-online and -proactive work practice. The asset with the highest IO maturity reports a good work environment where it is enjoyable to work. We also attribute this to the transparency in solutions.
Creating Efficient Portfolios That Match Competing Corporate Strategies
Authors: Willigers B.J.A.. J.A. , Majou F.. 
Published: June 2010

Summary
The process of portfolio optimization provides guidance to decision makers on how to manage an asset base given corporate objectives, market conditions, and organizational capability. Many applications in the oil and gas industry are based upon Markowitz's (1952) efficient-portfolio theory. In the standard implementation of this framework, an efficient portfolio is defined as one that yields the highest value given a specific degree of risk.
A corporate decision maker will aim, however, to select a portfolio that meets several often-competing objectives (i.e., maximize portfolio value while minimizing capital expenditure). The optimal portfolio choice given one constraint is typically not optimal given one of the competing constraints. This requires the portfolio manager to identify and select those portfolios that best meet all corporate constraints. Deciding which portfolio to develop is often compounded by there being several portfolios having similar economic characteristics. However, these portfolios can generally be differentiated by strategy, which may depend on nonfinancial attributes such as the geographic location of the assets or on geological settings that might require different engineering expertise.
In this study, a large set of exploration portfolios and their attributes have been simulated. Through applying a series of simple and transparent filters, a few portfolios can be identified that meet all the corporate constraints. After a shortlist has been created, the portfolios can easily be characterized by strategy, and the tradeoffs between them can be assessed.
Partitioning of Bitumen-Solvent Systems Into Multiple Liquid Phases
Authors: Jossy C. , Frauenfeld T. , Rajan V. 
Published: June 2010

Abstract
Both gravity-based and cyclic processes for heavy oil/bitumen recovery may involve the use of hydrocarbon (n-alkane) solvent at relatively high solvent/oil ratios. Previous work at ARC has shown that at high solvent loadings, the oil/solvent mixture partitions into a solvent-rich oil phase and a heavy-ends-rich (mostly asphaltene) oil phase. The liquid phases have significantly different densities and viscosities. The partitioning phenomenon could have a significant impact on the performance of gravity-based processes such as Vapex involving solvents, where the low-viscosity liquid phase carries the bulk of the oil production, and the heavier liquid phase consisting of mostly asphaltene is essentially immobile. The solvent-rich phase will consist of the upgraded (de-asphalted) oil. Production of upgraded oil thus would not only enhance the production rate, but also have both economic and pipelining advantages. 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 in reservoir engineering calculations.
Phase partitioning experiments conducted at the Alberta Research Council Laboratories along with the experimental data are presented in this paper.

Introduction
Both gravity-based and cyclic processes for heavy oil recovery may involve the use of solvent which dissolves in heavy oil or bitumen at relatively high solvent/oil ratios. Earlier works at ARC, and recent work in the Thermal Gravity Strategic area, have shown that at high loadings the oil/solvent mixture partitions into a solvent- rich oil phase and a heavy-ends-rich oil phase. The two liquid oleic phases have significantly different densities and viscosities. The phase partitioning may have significant impact on the performance of a solvent-based heavy oil recovery process. In particular, VAPEX and other gravity-based processes involving solvents may have their performance enhanced if the low-viscosity phase carries the bulk of the oil production, and the heavy-ends-rich phase contains most of the asphaltene and is essentially immobile.