bluuebunny/crossref_metadata_2025_split huggingface dataset:
Underbalanced Coiled Tubing Mechanical De-Scaling Operations: A Case History for an Oil Well in Ghawar Field from Saudi Arabia
Authors: Alabdulmohsin Yousif A. , El-Zefzafy Ibrahim Mohamed , Al-Malki Mohammed H. , Al-Mulhim Abdullah A. , Al-Ramadhan Ali A. , Al Hamawi Kaisar , Arfin Mohammad , Ahmad Danish 
Published: September 2016

Abstract
Accumulation of hard scale in the production tubing will not only affect the well accessibility it will also lead to a dramatic decline in production rate and locking the allocated production. Maintaining wells accessibility to wellbore for well intervention operations in order to run logs, water shut-off jobs, well securement operation,…etc. is part of well integrity and performance assurance program. The traditional operation approaches in other areas and reservoirs include isolating the active reservoir prior to operations are not suitable for all cases especially when formation damage is expected to take place. The implementation of underbalance mechanical de-scaling operations using coiled tubing; will lead to restore wells to production faster, regain well productivity and avoids the formation isolation stage.
The candidate oil producer; located in Southern Area of Ghawar Field; had accumulations of hard Iron Sulfide scale inside the tubing at different depths. Acid de-scaling operation using bullheading technique utilizing 20% HCL went vain to restore well accessibility and productivity. Hence, the underbalanced coiled tubing de-scaling operation was successfully executed for the first time ever in an oil well in Saudi Arabia. The operation consisted of two CT runs executed in underbalanced conditions, where the first CT run was with milling tool and second CT run was with jetting tool. It is worth to mention that the well is equipped with two different tubing sizes (6,500′ of 4 ½″ & 300′ of 3 ½″ TBG). This variation on the tubing size resulted in operation optimization as will be illustrated on the paper.
This paper will illustrate the operation in terms of planning, risk assessment, execution, results and well performance prior and after restoring well accessibility and productivity. Moreover, the paper will highlight the optimization done during the field operation execution after obtaining extra information from the first run using milling tool.
This operation has resulted in cost saving of more than $1 MM, 30% production gain and restoration of the well full accessibility.
Overcoming Challenges, Improving Understanding, and Optimizing Liner Deployment in Long Laterals
Authors: Mathisen Kim Daniel , Sørheim Tore , Koløy Tom Rune , Decker Neil 
Published: September 2016

Abstract
An operator in the North Sea planned an 11-well field development which included installation of long 4-½ in. completion liners in the horizontal reservoir sections of each well. Successful completion liner deployment was identified as a major project risk based on liner deployment challenges experienced in earlier development campaigns in the field. The new drilling campaign had plans to include the longest length laterals drilled and completed in the field to date. Additional challenges included complicated geology, widely varying pore pressure profiles over the length of the laterals, and open hole stability/enlargement concerns. An incomplete understanding of the mechanisms at play in prior drilling campaigns further increased risks of not being able to achieve the planned total depth with the completion liner.
To minimize overall risk, the operator planned to use a managed pressure drilling (MPD) technique to maintain conditions as ‘near balanced’ as possible during both the reservoir drilling and completion phases of the operation. It was hypothesized that MPD would enable the successful drilling of challenging pore pressure profiles and minimize openhole stability issues. This would, in turn, improve the likelihood of successful completion liner deployment. Despite the expected positive impact of MPD techniques, a strong understanding of the downhole dynamics during deployment of the lower completion liner was needed.
To address this challenge, the operator installed a newly developed workstring dynamics logging tool directly above the liner hanger running tools. This tool continuously recorded axial loads, torque, temperature, and pressure data during the lower completion liner deployment operations. The data provided by the tool helped facilitate continuous operational and design improvements by establishing best practices and troubleshooting unexpected results/issues. The data also helped the team understand root causes and develop appropriate mitigations, significantly reducing downtime. These improvements allowed the operator to overcome known challenges from previous campaigns to achieve a robust deployment strategy and add significant project value.
Pricing Unquoted Crudes on Net-Back Basis: Where Are the High Value Markets?
Authors: Gbakon Kaase 
Published: September 2016

Abstract
The objective of this paper is to ascertain the value of a given crude oil stream of known quality in the different refining centres (markets) across the world. The markets have been characterized along the dimensions of regional refinery complexity, price level of regional bench marker crude, regional products pricing and freight to the markets from the crude stream source. This paper posits that a given crude stream can be valued differently in the different refining centres around the world depending on the factors outlined above.
Four refining centres namely – Asia-Pacific, USGC, NW Europe, and Middle East – are delineated across the world. Models to predict the yields of Gasoline, Mid-distillates and Fuel Oil are developed for the different refining hubs. The product yields from the refineries are estimated as a function of refineries' feedstock crude API, sulphur content, and refinery complexity. Furthermore, using the Net back Pricing Methodology, this paper compares the Gross Product Worth (GPW) of a given crude stream with the GPW of the benchmark crude in a given refining centre accounting for freight differences. This procedure results in the value differential (ΔP) between the given crude and the regional bench mark crude, which is then added to the price assessment of the benchmark crude to give the Free On Board (FOB) value of the crude stream.
The analysis shows that crude streams can be valued differently in the different refining centres around the world. The results show broadly, that lower API crudes can be valued higher in refineries with higher complexity than in lower complexity refineries. Whereas, the higher API crudes are valued lower in higher complexity refineries than in lower complexity refineries.
This paper illuminates a basis for performing "alternative-crude" analysis and builds a strong value proposition for unquoted crudes in the global crude oil market around regional refinery capability. Furthermore, the paper points the way in knowledgably negotiating freight contracts to target markets for crude streams matched to those markets. This is done such that Freight costs volatility do not erode the GPW advantage that can be gained by a given crude over the regional bench mark crude.
End of Tubing EOT Placement Effects on the Two-Phase Flow Behavior in Horizontal Wells: Experimental Study
Authors: Dinata Randy , Sarica Cem , Pereyra Eduardo 
Published: September 2016

Abstract
An experimental study investigating the effects of end of tubing (EOT) on the two-phase gas-liquid flow behavior in horizontal wells was performed. The experimental data were used to develop methodologies to determine the optimum EOT location for the observed flow types: stable and cyclic flows. Total pressure drop, liquid inventory and the two-phase flow hydrodynamic behavior were analyzed to determine the optimum EOT location criteria. Tubingless completion and four packerless EOT locations were tested using a transparent laboratory-scale flow loop facility resembling two horizontal well configurations: toe-up and toe-down with 1-in. tubing and 2-in. casing. Water and compressed air were used as test fluids with various constant flow rates under low pressure. Minimum total pressure drop in the well was used to determine the optimum EOT location for stable flow. Various total pressure drop vs. EOT location relationships were observed under different operating conditions. Under low gas flowrates, installing tubing may promote severe slugging (SS) for a toe-up system. EOT located at kick-off point may be preferred as it showed the least test number of points with SS behavior. In addition, this location generated the lowest liquid holdup in the tubing and backpressure to the lateral section in most cases. The observations to explain these findings and the comparison of the tested EOT locations in handling SS were discussed.
Determination of Preferential Flow Direction in a Low Permeability Carbonate Reservoir Through Real-Time Data and Rate Transient Analysis RTA
Authors: Alcantara R. , Vazquez J. L. , Briones M. 
Published: September 2016

Abstract
The determination of the preferential flow direction in a reservoir becomes a very important subject for the development of an oilfield, especially for the selection of the optimum exploitation strategy taking into account that porous media is a very complex environment in which representing the flow behavior of fluids becomes a tough task, mainly in carbonates where the distribution of fractures, lithology changes and diagenesis play a major role in this topic.
Naturally Fractured Reservoirs (NFR) represent a great technical challenge for the petroleum industry because they behave as a heterogeneous medium with a strong influence of diagenesis, a term that encompasses fractures, dissolution, compaction, dolomitization, cementation and recrystallization to conform a reservoir with totally different distribution of properties. The dynamic data must be evaluated in order to match with the static model achieving a good reservoir characterization.
In this paper we present a way to determine the preferential flow direction by the monitoring of the field through permanent real-time downhole gauges that allowed the identification of the interference between wells in a deep naturally fractured reservoir that originally did not show any degree of communication. Suddenly, after some producing time, the field demonstrated a great level of interference among wells and as a consequence, the determination of the preferential flow direction was possible through Pressure Transient Analysis (PTA) and Rate Transient Analysis (RTA). Emphasizing the Palacio-Blasingame1 type curves (PBTC), in which we compare the results obtained using this analysis with its standard form and the one achieved with Material Balance Time (MBT). Additionally, Fetkovich2 decline type curves were also used in the rate analysis.
Finally, a comparison of the geological model with the dynamic data was also applied to further enhance the quality of the data. The results showed conclusive preferential flow direction with the wells tested.
Low-Velocity Non-Linear Numerical Simulation in Tight Sandstone Oil Reservoirs
Authors: Tian Xiaofeng , Cao Renyi , Tian Ji , Cheng Linsong , Zhang Miaoyi 
Published: September 2016

Abstract
Micro and nano throats are widely distributed in tight sandstone oil reservoirs and non-linear flow characteristics are obvious. However, no existing non-linear mathematical models and numerical simulations account for the effect of throat radius heterogeneity and fluid on non-linear flow characteristics. Additionally, they aslso do not account for the mutation of relative permeability curve resulted from non-linear flow characteristics. Therefore, in this paper, based on the method to characterize the non-linear flow characteristics and to calculate the relative permeability with non-linear flow characteristics, non-linear mathematical model is built. Then the numerical simulation module is developed. It is found that because of the effect of non-linear flow characteristics and quasi threshold pressure gradient, the early oil production of conventional model is largest and that of quasi threshold pressure gradient (QTPG) model and non-linear model are the same. Additionaly, QTPG model overestimates the threshold pressure gradient. Therefore, the sweep and cumulative oil production of conventional model is larger than that of non-linear model, larger than that of QTPG model. Becasuse the middle of the production well and injection well has the minimal pressure gradient, it has the minimal effective permeability. Accounting for the effect of non-linear flow characteristics and permeability stress sensitivity on relative permeability, the sweep area of injected water is small. Although the permeability is the same, the non-linear flow characteristics and permeability stress sensitivity are more obvious when throat distribution is narrower. As a result, the effective permeability is lower and sweep area become smaller. Therefore, oil rate and cumulative oil production is lower.
Performance Comparison of Novel Surfactant-scCO2 Systems for Oil Recovery in High Salinity Carbonate Reservoirs
Authors: Jangda Zaid , Sultan Abdullah 
Published: September 2016

Abstract
Recent work on CO2 Enhanced Oil Recovery (CO 2EOR) has focused on the design of fluid systems that have the ability to overcome the deficiencies typically associated with CO2 injection. However, applicability remains a challenge due to the instability of the developed fluid systems at reservoir conditions. The objective of this work was to evaluate and compare novel surfactant-CO2 systems that improve oil recovery.
For this purpose, multiple core-flooding experiments were conducted at high temperature (90°C) and high pressure (1800 psi) and in high saline conditions (TDS&gt;200,000 ppm) to mimic actual reservoir conditions. Three novel surfactant solutions (an amphoteric fluoro-surfactant, a hydrocarbon surfactant and a visco-elastic surfactant) were co-injected with sc-CO2 in foot long carbonate cores to compare their stability and effectiveness in incremental oil recovery. Interfacial Tension (IFT) experiments were also performed with the most performant surfactant at the same conditions and surfactant concentration to further highlight its contribution in increasing oil recovery.
Results from this comparative core-flooding study clearly demonstrate that when combined with sc-CO2, the fluoro-surfactant provided a much higher oil recovery than the hydrocarbon or the visco-elastic surfactant (6-9% increase). The pressure difference between the outlet and inlet of the core (ΔP) during flooding was also much higher for the fluoro-surfactant system indicating possible foam generation. The use of surfactants with CO2 also delayed the breakthrough of CO2 which allowed for longer contact between the oil and CO2. IFT results also showed a significant drop in interfacial tension between reservoir oil and the injected fluid after adding the fluoro-surfactant.
This work provides a novel option for surfactant-scCO2 flooding that overcomes the shortcomings of CO2 gas injection leading to an increase in total oil recovery. The fluoro-surfactant performs exceptionally well even at the very low concentration used in this study which also reduces the overall cost of the design.
Solvent Retrieval During Miscible Flooding in Heterogeneous Reservoirs Using New Generation Nano EOR Materials: Visual Analysis Through Micro Model Experiments
Authors: Cui Jingwen , Babadagli Tayfun 
Published: September 2016

Abstract
Solvent injection has been given attention to enhance oil recovery by sole use or in combination with a thermal method to develop light and heavy-oil fields. To make this process efficient, one needs to retrieve the expensive solvent. This can be achieved by alternative injection of water if the reservoir is homogeneous. In case of heterogeneous reservoirs (fractured carbonates or sands with wormholes), one needs to develop techniques other than viscous displacement to retrieve the solvent diffused into less permeable matrix portion. A method of injecting low temperature steam/water to heat the solvent to vaporize and retrieve it was introduced recently. An alternative is to inject chemical solution to change the wettability and displace the matrix oil/solvent by capillary imbibition. Although it yields lower recoveries, injection of chemical solutions for the same purpose without pre-solvent treatment might be an efficient (more economical) EOR method.
A series of 2-D etched glass micromodel (sandstone replica with a fracture) experiments were designed to investigate the mechanics of chemical injection with and without pre-solvent injection. Conventional surfactants (sulfonate series) as well as new generation chemicals (nanofluids, ionic liquids) were tested for this purpose. After testing and screening effective chemicals without pre-solvent injection, the same chemicals were used to retrieve the solvent and recovery additional oil for pre-solvent injected systems. The micromodel was saturated by dyed processed oils and a selected solvent was injected through the fracture. After the solvent was diffused into matrix completely to recover the oil in it, the model was heated mimicking a thermal method to reach the boiling point of the solvent and retrieve it. Following the heating phase, aqueous phase was injected to retrieve the remaining solvent in the liquid or vapor phase.
Visual observations on chemical flooding process clarified the complex interactions among different phases considering small-scale heterogeneities. This information can help screen promising chemical and determine the efficiency of chemical injection with and without pre-solvent injection for EOR in heterogeneous sands and carbonates.
A Novel Enhanced Oil Recovery Technology Using Dimethyl Ether/Brine: Spontaneous Imbibition in Sandstone and Carbonate Rocks
Authors: Chahardowli M. , Farajzadeh R. , Masalmeh S. K. , Mahani H. , Bruining H. 
Published: September 2016

Abstract
Dimethyl Ether (DME) - augmented brine injection is a novel Shell proprietary enhanced oil recovery (EOR) method. An experimental and numerical study of the enhancement and the acceleration of spontaneous imbibition using DME is carried out, both in sandstone and carbonate limestone cores. The experiments were performed under different boundary conditions using a modified high-pressure Amott cell. The primary recovery with brine from four (weakly water-wet to mixed-wet) sandstone cores, with the top-end, bottom-end, both-ends and all sides open to brine imbibition, was 38-46% of the OIIP. By adding DME, an additional oil recovery of 11-16% of the OIIP was obtained. The primary recovery with brine from the tight limestone cores was only 1-2% of the OIIP. By adding DME to the imbibing brine an additional oil recovery of 43-55% of the OIIP was obtained, which was much higher than the additional recovery from the sandstone cores.
A workflow was considered to model DME-enhanced spontaneous imbibition experiments. The model comprises Darcy's law and the simplified phase behavior of the DME-brine-crude oil system. The model parameters were optimized to match the experimental results. Numerical simulation shows that the oil recovery is more sensitive to the molecular diffusion coefficient and to the partition coefficient, than to the relative permeability and capillary pressure. In the presence of a higher oil saturation in the core, a higher partition coefficient and a higher DME concentration in the aqueous phase, DME/brine imbibition leads to a higher oil recovery.
Development and Rheological Characterization of Suspension of Hollow Glass Beads
Authors: Lumsden Simone , Singh John P. , Morgan Ronnie G. , Hundt Gregory 
Published: September 2016

Abstract
Hollow glass spheres (beads) are widely used as density and rheological modifiers for various oil and gas process fluids, particularly cement. One of the primary uses is to achieve lightweight slurries with good mechanical properties of the set cement. This paper discusses a concentrated yet pumpable suspension of these spheres for offshore cementing applications. Providing the lightweight spheres in a liquid suspension eliminates the risks associated with dry blending these materials. Development of the liquid suspension of hollow beads enables on-the-fly mixing of cement slurries with desired density profiles.
Currently, the beads are premixed in the cement powder before they are shipped to offshore locations, which often results in segregation of the beads during delivery and storage, and limits operations to the predetermined density (concentration of beads) of the slurry. This paper presents the rheological behavior of the concentrated suspension (up to 60% v/v) of hollow glass spheres suspended in a dilute aqueous solution of bentonite and soda-ash. In addition, a patented attachment to the viscometer (called FYSA) was used to characterize the flow behavior. A rheological model was developed to highlight the bead-bead surface interactions as a major component controlling flow behavior.
Four different variants of beads were studied. These were selected to represent a range in surface area per unit volume of beads. Increasing the concentration of beads or the bentonite in solution correlated to increased yield stress and fluid viscosity at operational shear rates. In addition, a Krieger Dougherty-type relation captured well the effect of the bead concentration, with the maximum packing fraction of beads being a function of surface area per unit volume of the beads. Overall, the Herschel-Bulkley (HB) Model best described the suspension rheology with the shear thinning exponent in the range of ~0.8 to 1. Surface area of the beads linearly correlated to the yield stress of the corresponding concentrated bead solution.
Results of this study and the model developed can be used to develop variants of the product with minimal experimentation, thus significantly shortening the development timeline.
Consistent Integration of Drill-Stem Test Data into Reservoir Models on a Giant Field Offshore Norway
Authors: Sætrom Jon , Selseng Harald , MacDonald Alister , Kjølseth Tore , Kolbjørnsen Odd 
Published: September 2016

Abstract
When considering the task of creating reservoir models for fields under development, dynamic data measurements often have limited impact compared with static (geophysical and geological) data. This is not necessarily true for the Johan Sverdrup field offshore Norway, where exceptional reservoir properties make the data from eight drill-stem tests (DSTs) particularly interesting. For this reason, it is important to utilize the information found in the collected static and dynamic data in a consistent manner, to improve the understanding of the reservoir. This is especially true for the Avaldsnes High area, located in the southeastern part of the Johan Sverdrup field, where the observed thickness is below the seismic resolution, and the DST data from four wells indicate permeabilities in the range of 20 to 80 Darcy, with an overlapping radius of investigation.
In this paper, we apply an ensemble-based approach to generate a large set of reservoir models for the Avaldsnes High area of the Johan Sverdrup field, all of which are plausible given the current observed static and dynamic data. We consider multiple modelling scenarios, introducing uncertainty in the sand thickness, facies (rock type) description and the permeability modelling. Unlike conventional pressure transient analysis (PTA), where we analyze the DSTs separately, and the non-uniqueness in the data interpretation is hard to address and quantify, this is not the case with the ensemble-based approach. Since we conduct the static and dynamic data conditioning simultaneously, we can consistently address possible ambiguities in interpreted permeabilities, thicknesses and flow barriers seen in the conventional PTA analysis. The study reveals that by conditioning the generated models to dynamic data we introduce clear spatial trends in both the sand thickness and permeability. In particular, we greatly reduce the potential downside with respect to the sand thickness in the Avaldsnes High area.