bluuebunny/crossref_metadata_2025_split huggingface dataset:
The First Visualization of Acid Treatments on Carbonates With 3D Nuclear Magnetic Resonance Imaging (NMRI)
Authors: Krebs M. , Lungwitz B. , Souza A. , Pépin A. , Montoya S. , Schlicht P. , Boyd A. , Vidoto E. , Polli R. , Bonagamba T. 
Published: June 2014

Abstract
Carbonate reservoirs with their high hydrocarbon potential show often a great heterogeneity in their inner rock structure, wherefore stimulation treatments are often necessary to maintain or establish fluid production. Therefore, core flow tests are usually conducted to test and model stimulation treatments within a laboratory scale in order to predict their performance. The visualization of wormholes that were created within core flow tests requires novel technologies for evaluation and pathway prediction purposes. Unfortunately, past visualization techniques were always associated with the destruction of the core sample and in that way, an increased demand raised in non-destructive methods.
Nuclear Magnetic Resonance Imaging (NMRI) is such a method that fulfills the approach of being non-destructive. The technology is widely known by medical applications, but has never been used before in correlation with 3D rock imaging. Hence, this study developed a procedure on how to use the NMRI technology to visualize wormholes with NMRI in 3D.
Therefore, a comprehensive study was started by initially choosing and obtaining various core samples that have different contents of calcite and dolomite. These core samples were imaged with the NMRI and μCT technology in their unchanged state as well as basic petrophysical experiments were conducted for initial experiments. The μCT technology was utilized as reference visualization technique, since it provides a very high resolution with a corresponding high level of detail. Afterwards, core flow tests were conducted on the core samples with various acid systems and wormholes generated. Finally, the core samples with wormholes were imaged again with the NMRI and μCT technology, whereby the NMRI acquisition technique was improved towards imaging of rock samples and the results were compared to the μCT results. The NMRI results showed moderate imaging achievements for the unchanged rock samples and high quality imaging achievements for the extracted wormholes.
Multizone Openhole Stand Alone Screen: Innovative Sand Control Solution to Develop Shallow Gas Reservoirs in the Mahakam Delta
Authors: Laidlaw D. , Muryanto B. , Isdianto-Maharanoe M. , Alberson-Panjaitan R. 
Published: June 2014

Abstract
Developing shallow reservoirs in the Mahakam Delta requires cost effective completion solutions to produce gas from multi-layered, unconsolidated sands. Typically, multi zone gravel pack systems have been utilised as the sand control completion methodology. Technical limitations of these techniques in terms of zone spacing, number of zones and well deviations drove the need to develop an alternative completion technique. Using modified existing screen and open-hole isolation technology, a unique open hole stand alone screen (SAS) system was developed.
Several challenges must be overcome in the Mahakam Delta reservoirs. Highly unstable and inter-bedded coals seams that swell and slough create challenges in terms of both running the completion equipment and its effective performance once installed. Water bearing sands underlay the productive sands making water breakthrough a risk.
To date, four wells have been completed with the SAS system. Overall productivity has exceeded expectations and most importantly, the sand screens have provided excellent sand control with no sand production occurring. Cost savings have been achieved through reduced completion times, eliminating pumping operations and reducing surface locations. Successful pilot wells will lead to further development of shallow reservoirs previously deemed uneconomic due to the marginal nature of the Tunu Shallow reserves.
Critical Sand Deposition Velocity in Horizontal Stratified Flow
Authors: Ibarra Roberto , Mohan Ram S. , Shoham Ovadia 
Published: June 2014

Abstract
Transport of sand in multiphase pipelines occurs in the petroleum industry as sand is produced co-mingled with crude oil. Stationary sand beds are formed at the pipe bottom when the flow velocity is lower than the critical sand deposition velocity. These sand beds reduce reservoir production and affect the integrity of the pipe system due to pipeline plugging and erosion/corrosion produced by sand particles. Therefore, the production system must be designed to operate at a velocity high enough to enable transport of sand particles along the pipe. For that reason, it is crucial to predict the critical sand deposition velocity in order to maximize reservoir production.
Gas-liquid-sand flow hydrodynamics, which is commonly encountered in most reservoirs and also in oil and gas transportation pipelines, is more complex than liquid-sand flow, making the modeling extremely difficult. At present, gas-liquid-sand flow is still not well understood, with limited data available in the literature. In addition, the effect of sand concentration has not been thoroughly studied for two-phase flows transporting sand.
Experimental and theoretical investigations have been conducted in this study on gas-liquid-sand stratified flow in horizontal pipes at low sand concentrations. A 4-in experimental facility was designed and constructed and data were acquired utilizing air-water-glass beads flow. The data include measurements of critical sand deposition velocities, namely, the transition between moving and stationary beds. The data reveal that for a constant superficial liquid velocity, the critical mixture and liquid sand deposition velocities increase with increasing sand concentrations. Also, for a given sand concentration, the critical liquid velocity is almost the same for different superficial liquid velocities.
The sand deposition correlations of Oroskar and Turian (1980) for single-phase flow and Salama (2000) for two-phase flow are modified and extended in order to develop a new correlation. The developed correlation enables the prediction of critical sand deposition mixture velocity for horizontal stratified flow, as a function of sand concentration along with other parameters. Comparison between the predictions of the developed correlation and the experimental data reveal a very good agreement, whereby the relative errors of mixture and liquid critical sand deposition velocities are ±2.5% and &lt; 5%, respectively.
Design and Successful Field Execution of Sand Control Completions in Naturally Fractured Reservoirs
Authors: Tahirov Tahir , Allam Robbie , Mason John , Twynam Allan , Tanilir Beran , Sweeney Kieran , Bissoon Anderson 
Published: June 2014

Abstract
The Clair Ridge field development is located in the UK Continental Shelf, 142 miles north of mainland Scotland. This is the second phase of the Clair Field Development involving a subsea pre-drilling campaign and programmed long term well suspensions prior to new platform arrival. Two pre-drilled horizontal wells have been successfully completed with downhole sand screens in a geologically challenging environment, and suspended with cleaned-up hydrocarbons across the reservoir until the wells can be tied back to the platform in 2016.
The reservoir drilling and completion design strategy was complicated due to the reservoir section being a naturally fractured sandstone alongside high permeability and weak matrix intervals susceptible to sand production. This presented several challenges to the team: the high risk of losses whilst drilling the reservoir with the probable use of large volumes of lost circulation materials (LCM), the risk of damage to the natural fractures or high permeability zones impacting subsequent well productivity, the need for down hole sand control completions, the ability to run these across a reservoir section containing large amounts of sized calcium carbonate LCM materials and also the mitigation of screen plugging from filter cake and LCM during well start-up. The downhole completion hardware was specifically designed to allow efficient placement of chemical breaker to dissolve LCM and filter cake to reduce the risk of sand screen plugging. The importance of minimising screen plugging and formation damage was also dictated by long term suspension of the pre-drilled wells required for start-up of a new offshore platform.
This paper details the reservoir sand control completion design philosophy, the drilling and completion fluid system design and assurance testing in readiness for the technical challenges to be faced and the overall operational practices used in the field execution. The well flow-back and test results exceeded expectations, indicating good flowing length, greater than predicted Productivity Index (PI) and absence of skin damage, which creates significant benefit for the Clair Ridge project.
Interconnected Fiber Network Prevents Gravel Washout in Water Injector Wells
Authors: Vidma Konstantin , Glaznev Ivan , Green Sarah , Panga Mohan 
Published: June 2014

Abstract
In water injector wells, continuous injection can wash gravel from the annulus around the screen, especially if the rate of injection generates a pressure above the fracture threshold. The voids created after the washout are sometimes filled by an influx of formation sand during shut-in operations. This sand accumulation consequently reduces the injectivity when the injection operations resume. A solution to prevent such washouts is needed to maintain sand control and injectivity throughout the life of water injector wells.
As a solution to this common problem, we propose a new fiber based product that reinforces the gravel and/or proppant pack. The fibers have an outside layer that is activated by temperature to form a bonded fiber network that locks the gravel in place. The fibers can be used with any type and size of proppant. The key benefit is that the fibers can withstand the cyclic loading of stress inherent to the shut-in and restart of injection operations, which are typically performed several hundred times during the life of an injector well.
Our experimental study showed that the drag force of injected water easily displaced the gravel in the annulus into the fracture, whereas when gravel is reinforced with the fibers it withstood the drag force even at high injection rates (e.g., at 100 B/D per 0.5-in.-diameter perforation). We performed several experiments to evaluate the strength of the pack under cyclic stress conditions. After 30 cycles, the pack strength remained unaffected. The fiber chemistry was tailored for compatibility with commonly used fracturing fluids and brines. We found that the fibers remained connected in an interconnected network even after long-term interaction with seawater. We also studied the interaction of fibers with screens and other downhole equipment that comes in contact with the fibers during gravel placement. The laboratory results of that study showed the fibers do not create any issues with proppant placement or tool functionality during the sand control operation.
Our experimental study also showed the fibers provided an effective solution for preventing gravel washout in water injector wells, thereby supporting the sand control and injectivity for the life of the well.
Data Analysis and Updated Screening Criteria for Polymer Flooding Based on Oilfield Data
Authors: Saleh Laila Dao , Wei Mingzhen , Bai Baojun 
Published: June 2014

SummaryEnhanced-oil-recovery (EOR) screening is considered the first step in evaluating potential EOR techniques for candidate reservoirs. Therefore, as new technologies are developed, it is important to update the screening criteria. Many of the screening criteria regarding polymer flooding that have been described in the literature were based on data collected from EOR surveys of the Oil and Gas Journal. However, the data quality has not been addressed in previous research. The data set originally contained 481 polymer-flooding projects from around the world, and it contained some problems, including outliers and duplicate, inconsistent, and missing data. To ensure the quality of the data set before running analyses, boxplots and crossplots were used to detect and identify data problems. After detecting outliers and deleting duplicate and severely inconsistent data records, only 250 projects remained. Both graphical and statistical methods were used to analyze and describe the results of the data set. Two major sets of information were given after data cleaning: The first was that the majority distribution of each parameter was shown by use of a histogram distribution, and the second was that the range of each parameter and some of its statistical values were presented by use of a boxplot. Finally, the screening criteria are presented on the basis of these statistics and the defined data parameters. The developed criteria were compared with previously published criteria, and their differences were explained. The developed criteria show that a polymer-flooding project can be successfully applied in a reservoir with a temperature of less than 210°F, an oil viscosity up to 5,000 cp, and gravity lower to 12°API.
Impact Map for Assessment of New Delineation-Well Locations
Authors: Zagayevskiy Yevgeniy , Deutsch Clayton V. 
Published: June 2014

Summary
This paper describes a new technique for effective placement of delineationwells on the basis of the change of the uncertainty in the key global-reservesvariable. Uncertainty is summarized through the geostatistical framework. Theauthors develop a numerical and analytical methodology that is tested onsynthetic and real petroleum case studies. The implementation isstraightforward, and the results are promising. A methodology is developed toassist in delineation-well placement. Decisions for new-well locations areassisted with a quantitative measure of the expected reduction in globaluncertainty in the volume of original oil in place (OOIP). The availablerealizations are analyzed and processed to quantify the impact of wellplacement. Variograms and other required statistics are inferred from therealizations. As a result, a gridded map of impact values is produced, fromwhich locations with the highest impact are suggested for new-well locations.Numerical and analytical approaches for the impact-map calculation are proposedand compared. Pros and cons of each approach are summarized. The numericalapproach requires a large number of realizations for effective implementationof the impact map, which might not be practically achievable. On the otherhand, the analytical approach does not require many realizations and producesstable results. In most cases, only variogram models and current well locationsare needed for the analytical impact-map computation. Although computationaltime of this approach largely depends on the model size, some options aresuggested to reduce the cost. The analytical impact calculation is developedfor the OOIP model response, in which the petroleum reservoir is defined as acomplex geological architecture with multiple structural surface constraints.Several case studies, including a real-petroleum-reservoir example, demonstratethe use of the impact map for the assessment of new delineation-well locations.The developed tool is of significant help for well placement.
Rescaled Exponential and Density-Based Decline Models: Extension toVariable Rate/Pressure-Drawdown Conditions
Authors: Ayala Luis , Zhang Miao 
Published: June 2014

Summary
Constant-bottomhole-pressure (BHP) solutions to the diffusivity equation areused routinely for the analysis of well-decline performance inboundary-dominated flow (BDF). Gas-well-performance equations for constant-BHPconditions may be written in a number of ways, including rate vs.pseudopressure, rate vs. pseudotime, rate vs. material-balance pseudotimeexpressions, and, more recently, in terms of density-based rescaled exponentialmodels (Ayala and Ye 2013a, b; Ye and Ayala 2013). A significant constraint forsome of these models, especially for the rescaled exponential model, is theassumption that BHP conditions remain constant throughout the declining life ofthe well. However, the most realistic well-specification scenario is that inwhich both BHP and flow rate decline in time (i.e., avariable-pressure-drawdown/-rate condition. In this study, we explore and provethe validity of rescaled exponential and density-based gas decline models forthe analysis of variable-rate/pressure-drop gas systems in BDF. We alsodemonstrate that the constant-rate and constant-BHP solutions given by theproposed density-based decline models for gas wells under BDF areinterchangeable.
Second-Order Gas-Permeability Correlation of Shale During Slip Flow
Authors: Niu Cong , Hao You-zhi , Li Dao-lun , Lu De-tang 
Published: June 2014

Summary
Recent molecular-dynamics (MD) simulation of methane flow through nanoscale kaolinite channels shows that the gas molecules accumulate near the kaolinite wall, which will reduce the flowpath of the gas through tight porous media. Considering this gas-accumulation effect, and on the basis of the corrected second-order slip boundary condition (BC) proposed by Zhang et al. (2010), a permeability-correlation model is proposed for nanoscale flow in highly compacted shale reservoirs. Full-derivation detail of this model is presented along with a comparison with several existing correlations. Results show that, with the increase of the Knudsen number (Kn), the molecular-accumulation effect has an obvious negative effect on the shale permeability, which should not be neglected in further investigation. The parametric investigation of the model proposed shows that the permeability is mostly decided by the pore-wall structure of shale matrix and only slightly influenced by the gas property.
Extending the Reach of Coiled Tubing in Directional Wells with Downhole Motors
Authors: Oyedokun O. , Schubert J 
Published: June 2014

Abstract
A rigorous study has dispelled a longtime myth about coiled-tubing technology. The inability to rotate the tubing limits its reach in the lateral section of the wellbore. Past and current extended-reach techniques for coiled-tubing drilling (CTD) have not been sufficient (individually) in significantly increasing the reach of the tubing in the wellbore; often four or five extended-reach methods are combined to have significant tubing displacement in the wellbore, which is quite expensive to do.
After much rigorous investigations and computer simulation tests, the study has demonstrated that a downhole motor (second motor) can be employed in extending significantly the reach of coiled tubing in the wellbore. This technique is expected to also improve hole cleaning process (during CTD), since the configuration allows for the rotation of the coiled tubing string.
With the proposed technology having two tubing segments (rotating and nonrotating segments), the investigations show that the two segments will not buckle under applied torsional loads in the course of using a hydraulic downhole motor. But the nonrotating segment of the tubing string will be subjected to severe twisting.
Downhole electric motors and a dynamic torque anchor (or full-gaged stabilizer) coupled to a hydraulic motor can be employed to achieve the primary aim of the technology and prevent twisting of the nonrotating segment (the twisting of the segment destabilizes the drilling process).
Although the use of a dynamic torque anchor or full-gaged stabilizer can be employed in arresting the twisting moment, it induces high frictional forces, which reduce the lateral displacement of the tubing (relative to an electrodrill). To solve this problem, a new "dynamic torque arrestor" has been proposed in this project. The simulation tests show that the lateral displacements of the tubing in the wellbore (when the newly proposed dynamic torque arrestor is coupled to a hydraulic motor) are greater than the displacements achieved with the use of dynamic torque anchor or full-gaged stabilizer.
Since the proposed technology does not require the intense modification of the current configuration of the coiled tubing unit, its application will be inexpensive.
Defying Conventional Wisdom; Reversing Tapered Coiled Tubing Strings for Extended Life
Authors: Grant Ryan , Canada Sanjel , Burgess Lara 
Published: June 2014

Abstract
It is common practice in the coiled tubing industry to manage the fatigue of straight wall coiled tubing (CT) strings by reversing the string on a work reel. The benefit is to shift the fatigue profile along the string by moving high fatigue sections away from high cycle depths in the well. This often helps extend the working life of the coiled tubing. For tapered CT strings, however, this is not a common practice. Tapered strings are traditionally not considered reversible as the effectiveness of the taper would be lost, and in some cases, pulling out of hole would exceed the yield strength of the tapered section of the string. In a large unconventional gas play, a tapered string was designed to be utilized for a number of completion activities on extended reach wells. String costs had a significant impact on the economics of the project. The strings were utilized until a given section exceeded 80% of the predicted fatigue life of the coil, and then in a conventional fashion, the strings were taken out of service. By evaluating the upcoming work on the project and the location of the fatigue spikes in the string the coiled tubing service company was able to develop a procedure to remove the fatigue spikes and manipulate sections of the string to gain additional useful life out of the string. Forward planning, special operating procedures and engineering analysis were used to gain over 60% longer working life of coiled tubing strings on this campaign.
Coiled Tubing Drilling: Increasing Horizontal Reach in the Kuparuk Field
Authors: Burke J. , Eller G. , Venhaus D. , Gantt L. 
Published: June 2014

Abstract
Coiled Tubing Drilling (CTD), is a cornerstone of the brownfield redevelopment that is taking place on the North Slope of Alaska. Through-tubing horizontal multilateral completions are now being drilled with CTD to further develop the thin, highly faulted reservoirs in the Kuparuk field. Five years ago, the average horizontal lateral length was 2150 ft, with a maximum horizontal length of 3126 ft. As of June 2013, a horizontal lateral length of 4293 ft was drilled to a measured depth of 13,375 ft, currently a CTD record for the area.
As redevelopment of the Kuparuk field continues, the horizontal extension limits are being pushed to even greater lengths, and as development continues there will be many factors that pose challenges to continue drilling extended reach CTD laterals out of the existing well bores. These challenges include: down hole mechanical limitations, fluid systems (hole cleaning ability and pressure considerations), and equipment limitations. This paper highlights these challenges, and presents some possible solutions as well as discusses how these techniques were applied on the most recent record CTD horizontal lateral, and how these lessons will be applied for future extended reach candidates.