bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Method for Modeling Bypassed Oil Recovery in EOS Compositional Simulation
Authors: Zhang B. , Okuno R. 
Published: September 2013

Abstract
The conventional reservoir simulation uses the local equilibrium assumption, where fluids are completely mixed and at equilibrium within individual gridblocks. This assumption allows for no bypassing of oil at the sub-grid scale in gas injection simulation. Oil bypassing by gas, however, always occurs due to micro and macroscopic heterogeneities, gravity, and front instability.
There are a few methods proposed in the literature that attempt to model the effects of sub-grid heterogeneity in gas injection simulation. The concept of miscible residual oil saturation (i.e., the Sorm method) excludes the immobile oil from flash calculations and explicitly models bypassed oil. However, the Sorm method cannot model bypassed oil recovery because it allows for no mass flux between the bypassed and flowing fractions. The alpha-factor method uses transport coefficients to adjust components’ flux in compositional simulation. It has been used to retain a desired amount of residual oil in history matching for predominantly single-phase flow. However, its applicability to partial miscibility conditions is not fully understood. This is likely because the presence of more phases with partial miscibility yields more non-linearity and severer non-uniqueness in the history matching process.
In this research, we develop an efficient method to model bypassed oil recovery in multiphase compositional simulation. Oil bypassing in gas injection simulation is first explained using dual-porosity-flow (DPF) models. We show that DPF can capture the characteristics of the dispersion-capacitance model, where oil held up in the bypassed fraction gradually migrates to the flowing fraction through intra-block mass flux. Fluid flow in the presence of capacitance is characterized using the DPF parameters; the bypassed fraction, throughput ratio (RT), and Peclet number.
A new fluid characterization method is then used to efficiently reproduce DPF characteristics using a single-porosity-flow (SPF) model. An EOS fluid model is corrected for capacitance by adding heavier oil components that are characterized depending on RT. A case study demonstrates successful application of the new method to reflect capacitance effects observed in corefloods in field-scale gas injection simulation. Prediction of residual oil distribution within a reservoir depends significantly on how bypassed oil is modeled in the simulation. Unlike the alpha-factor method, our method requires no changes in the governing equations and in relative permeabilities.
Experimental Study of Liquid Viscosity Effect on Two-Phase Stage Performance of Electrical Submersible Pumps
Authors: Banjar H. M. , Gamboa J. , Zhang H.-Q. 
Published: September 2013

Abstract
Experiments with a seven-stage Electrical Submersible Pump (ESP) have been carried out to study the effect of liquid viscosity on the gas-liquid two-phase stage performance. The experimental tests provided data about the stage pressure increment as a function of the liquid flow rate at constant rotational speed, inlet pressure, and volumetric gas flow rate. Two different mineral oils were used so that the ESP two-phase stage performance was measured for 1 cP, 1.2 cP and 8.5 cP liquid viscosities, and for 8 different gas flow rates.
The experimental results demonstrate that the increase of liquid viscosity causes gas surging in the stage to initiate at lower normalized gas flow rates, reducing the gas handling capability of the stage. Increasing the liquid viscosity also causes the stage to reach a zero pressure increment at a higher normalized liquid flow rate. The pressure increment deterioration caused by the gas worsens with increased liquid viscosity. The performance map is analyzed and compared with that of another pump (GC-6100) with a higher inlet stage pressure.
Density-Based Rate-Time Production Analysis of Unconventional Gas Reservoirs Under Gas Slippage and Desorption
Authors: Vardcharragosad Pichit , Ayala H. , Luis F. 
Published: September 2013

Abstract
Accounting for gas-slippage and desorption effects is a critical step towards the reliable analysis of production performance in unconventional gas systems. This study demonstrates how to account for gas slippage and gas desorption effects in gas reservoirs using a density-based approach of analysis—an approach recently proposed for analyzing unsteady state flow of natural gas reservoirs. Gas-slippage and gas desorption models are incorporated into the original density-based approach by modifying the definitions of depletion-driven variables which are the basis of the density-based type of analysis. The proposed modification of the original approach successfully enables associated analysis techniques to be applicable to natural gas reservoirs with gas slippage and absorbed gas. Results indicate that by modifying the definitions of the depletion-driven variables, the density approach can effectively and successfully capture the effects from gas slippage and desorption. It is shown that gas flow rate can be successfully predicted by rescaling liquid solution with the modified density-based variables. This work illustrates the methodology required to do so and its application to production data prediction analysis for unconventional assets.
Smart Alarms Tool Development Approach for Oil Production Monitoring System
Authors: Pchelnikov R. L. , Mironov D. V. , Salikhov R. , Gladkov A. V. , Kogan G. A. , Gareev R. R. , Khabibullin R. A. 
Published: September 2013

Abstract
Data analysis and event alarms are essential part of any production monitoring system. Most often standard event alarms in production monitoring are based on selected measurements. Oil rate, pump intake pressure and temperature, water cut are some of them. Less often alarms are based on calculated values, for example production increase potential. However, they always indicate something goes wrong but never indicate why. Alarms can indicate there are deviations from planned values but do not give any clue about deviation reasons. Production engineer should investigate deviation reasons himself.
From author's point of view, smart alarms are the tool to overcome these challenges. Smart alarms in production monitoring system should be able to determine reasons of parameters deviation and to predict deviations before they become critical.
Smart alarms should use all the information available in order to increase estimation and prediction accuracy. They should classify and rank problems and problem reasons identified from potential future problems to problems required immediate reactions. Smart alarms should give reasonable results based on partial data, and should be able to analyze thousands wells per day.
Primary goal for smart alarm tool is to automate business process for 80% of well stock working in a standard way and to allow engineers to concentrate on 20% of complicated wells.
Smart alarm tool based on Bayesian network framework is under development and pilot implementation in TNK BP of Samotlorskoe oil field. Smart alarm tool is a part of corporate production monitoring system. This paper discusses Bayesian network application for engineering tool development and results of pilot implementation including algorithm accuracy, lessons learned and development plans.
A State-of-the-Art Completion Technological Innovation: The First 25,000- psi 500°F Permanent Bridge Plug
Authors: Ruffo Tony , Deng Guijun , Doane James , Anderson Gary , Lehr Douglas , Collins Scott 
Published: September 2013

Abstract
Global growth in demand for hydrocarbons is the key driver for the development of high-pressure/high-temperature (HP/HT) completion and isolation technologies. However, completion of ultra-HP/HT wells (T ≥ 450°F, P ≥ 20ksi) presents tremendous technological challenges to the operator and service companies. Conventional HP/HT packer and bridge plug technology is generally limited to long-term operation at 15,000 psi and 450°F, and the same can be stated for conveyance technology for these devices. A great deal of research and development effort has been put into extending performance beyond these limits for completion and isolation applications in the last 10 years. Recently, an innovative approach was applied to the solution of this problem, with the objectives of increasing these pressure and temperature limits and enabling long-term isolation in ultra-HP/HT wells. This approach resulted in the development of the world's first Ultra HP/HT Permanent Bridge Plug for long-term exposure at 25,000 psi and 500°F.
The Ultra HP/HT Bridge Plug was developed to satisfy a number of operational requirements that are unique to HP/HT wells:
Bridge plug longevity equal to that of the liner in which it is set. Bridge plug design which is capable of isolating reservoir pressures in standalone mode, without the aid of a column of cement on top of it. Bridge Plug operational reliability when conveyed into the well on electric line.
All these "mission critical" requirements were met. This paper discusses the development of this new Ultra HP/HT Bridge Plug. This discussion will cover elements of materials, design, prototype testing methodologies and conveyance. The validation testing processes in ISO14310/API11D1 Grade V0 requirements, as applied to this bridge plug, will also be described in detail. The application of state-of-the-art metallic and polymer material and design processes will also be discussed. Finally, the paper will conclude with the status of field installations.
Field Production Optimization Using Closed-Loop Direct Feedback Control of Intelligent Wells: Application to the Brugge Model
Authors: Dilib F. A. , Jackson M. D. , Khairullin A. Y. 
Published: September 2013

Abstract
Optimized production strategies using intelligent wells have been shown in numerous studies to improve economic performance. However, most optimization methods are model-based, effective only if the reservoir model captures the range of all possible reservoir behaviors at the individual well and completion level. This is seldom the case. Furthermore, reservoir models are rarely predictive at the spatial and temporal scales required to identify control actions. Motivated by this, recent studies have shown that direct feedback control, triggered by monitoring at the surface or downhole, can increase net-present-value (NPV) and mitigate reservoir uncertainty. This approach does not neglect model predictions entirely; rather, a model-based approach is used to optimize adjustable parameters in a generic feedback control algorithm. We evaluate the benefits of using direct feedback control for multi-well production optimization using the synthetic Brugge field case study. We test three inflow control strategies. Two are based on direct feedback control, but differ in the level of monitoring and control. In the first feedback control strategy, all monitoring and control is taken at surface, using surface multiphase flow meters and on/off well-head control valves. In the second, monitoring and control can take place either at surface or downhole, using on/off well-head and variable completion inflow control valves, in response to measurements from surface and downhole multiphase flow meters. These control strategies are optimized on a subset of the published model realizations; the other realizations are then used to simulate unexpected reservoir behavior. For benchmarking purposes, we implement a third, reactive rule based approach, heuristically developed with prior reservoir knowledge of the truth model. We also compare our results to previously published, model-based inflow control strategies developed by optimizing NPV with perfect knowledge of the Brugge truth case. Our results suggest that closed-loop direct feedback control, implemented at surface and downhole, can yield significantly higher NPV compared to surface feedback control alone. Moreover, despite the simplicity of the direct feedback control approach, the NPV returned is higher than a heuristic reactive approach, particularly when reservoir behavior is unexpected. In contrast to model-based optimization techniques, direct feedback control is straightforward to implement and can be easily applied in real field cases.
Experiences with an Efficient Rate Management Approach for the 8th Tortonian Reservoir in the Vienna Basin
Authors: Kornberger Martin , Thiele Marco R. 
Published: September 2013

Abstract
Active well rate management is a simple way to increase recovery in brown fields while minimizing costs and preserving existing field/well fluid handling constraints. In this work, we present the application of an efficient flow-based surveillance technique to drive rate management decisions for the 8th Tortonian reservoir in the Vienna Basin, Austria. The 8th Tortonian is a typical example of a decade-long peripheral water flood on a long, steady decline for which it is difficult to justify expensive drilling/workover programs. Active rate management to improve sweep patterns presents a cheap solution to increase recovery. In case of the 8th Tortonian, Euro 10,000 (US$13,000) were spent to modify well rates resulting in ∼5700 m³ (∼35000 STB) incremental oil recovered over a 30-month period. The current oil rate remains above the oil rate before the start of the project.
Our approach takes advantage of streamline-derived well allocation factors (WAF's) that quantify injector-producer connections. It is simple and efficient to estimate WAF's using total historical well fluid rates, well locations, and a geological model. The geological model can vary in complexity from being a single homogenous layer to a sophisticated, 3D geo-model. With the WAF's known, the efficiency of each injector/producer pair can be estimated by using the historical observed phase rates times the well allocation factors. Well pair efficiencies are the starting point for the rate management approach described in this work.
A simple, single homogenous layer system was used in conjunction with historical rates and well locations to estimate the WAF's for the 8th Tortonian reservoir. Connections were compared to available tracer data, and an area of interest was subsequently selected based on streamlines and tracer data both indicating recovery by injected water. A key constraint was to maintain the total gross rate of the area selected at current capacity. New target rates we determined and implemented resulting in a 30% increase of oil rate over a 30 month period. Considering the simplicity and efficiency of the approach, this is a notable result. The production response of the selected wells showed an increased recovery in conjunction with a decreasing watercut suggesting contact with previously unswept oil. All operations and modifications were done at minimum cost. There were no perforation changes or acidizing jobs involved and rate changes were obtained simply by changing pump sizes or increasing the number of strokes by changing the V-belt pulley.
Novel Measurement of Asphaltene Content in Oil Using Microfluidic Technology
Authors: Sieben Vincent , Kharrat Abdel , Mostowfi Farshid 
Published: September 2013

Abstract
We present a state-of-the-art microfluidic technique for measuring the asphaltene content in crude oil samples. The automated microfluidic system improves data quality, reduces turnaround time, and minimizes solvent-volume consumption compared with conventional wet-chemistry measurements. The method is based on conventional precipitation techniques, such as the ASTM D6560, in which n-heptane is used for precipitation. However, instead of using gravimetric techniques commonly utilized in conventional methods, we use a novel spectrophotometry method for quantifying the asphaltenes. The optical technique is based on the spectral difference of crude oil before and after precipitation of asphaltenes using the titrant. We show a strong linear correlation between the optical method and the wet-chemistry technique for a broad selection of samples. The sample set included more than 50 crude oils with asphaltene contents as high as 15 wt.-%.
The unique microfluidic platform developed for this study uses a 200 µL sample loop to deliver the crude sample into a microfluidic chaotic mixer, where the sample is mixed with toluene. After dilution, we injected the sample into a 2.5-mm path-length flow cell, where a visible spectrum of the oil is recorded. To measure the spectrum of the maltenes, the sample is mixed with n-heptane in the microfluidic mixer at a predefined volume ratio. The mixture then flows into a reactor channel, where the aggregation process takes place and asphaltene molecules grow into large aggregates. After precipitation, the mixture is passed through a 200-nm-pore membrane, where asphaltenes are trapped and maltenes permeate through the membrane. The spectrum of maltenes is then measured using the 2.5-mm path-length flow cell and a UV-VIS spectrometer.
Using the microfluidic technique, a complete measurement takes only 40 minutes, a considerable improvement over conventional wet-chemistry techniques that require a minimum of 2 days. Furthermore, conventional wet-chemistry measurements are highly operator dependent. We show that, for our optical technique, the repeatability of measurement is better than ±0.1 wt.-%. The microfluidic measurements require only 200 µL of sample and 40 mL of solvent, which reduces the environmental impact of measurement. Finally, the small footprint of the apparatus makes it highly desirable for wellsite and offshore applications.
Industry Trends Utilizing Larger Diameter Coiled Tubing for Extended Reach Operations in Northwestern Canada
Authors: Edillon Lemuel 
Published: September 2013

Abstract
Coiled tubing (CT) operations in Canada have evolved significantly due to advancements in horizontal, multi-stage fracturing. This evolution has caused a shift from using smaller diameter tubing (31.75 mm to 50.8 mm) less than 3,000 m in length to using larger diameter tubing (60.3 mm to 73.0 mm) with lengths over 6,000 m. The preference for larger diameter CT is a result of operators drilling longer lateral lengths to stimulate as many zones as economically possible. To illustrate recent trends in Canadian CT operations, statistics from the past 10 years of horizontal drilling are briefly analyzed followed by an examination of operational data from a leading CT service provider. The surface equipment and CT string design required to perform these operations is also reviewed. Three recent case studies of CT milling operations in Northwestern Canada are discussed to highlight the importance of purpose-built equipment and accurate string selection in today's horizontal market. The industry trend to larger CT is significant because CT capability has become a key component in the overall feasibility and economic evaluation of extended reach, multi-stage horizontal wells.
Asphaltene Deposition in Metal Pipes: Efficient Inhibition and Removal by Different Surfactants
Authors: Hashmi Sara M. , Firoozabadi Abbas 
Published: September 2013

Abstract
We describe asphaltene deposition and removal processes in metal pipelines. We induce asphaltene precipitation by adding an asphaltene precipitant, heptane, to a petroleum fluid. The mixture is then injected through a lab-scale pipeline and allowed to deposit. We assess the inhibition or reversal of the deposition via the use of three separate chemical treatments: 1) a non-ionic dispersant, 2) a strong organic acid dispersant, and 3) an aromatic solvent. We find that the non-ionic dispersant under consideration (BA), has the ability to reduce the amount of precipitated asphaltenes when co-injected with the petroleum fluid-heptane mixture. Our previous studies show that, even at 10 ppm, BA can stabilize dilute colloidal suspensions of asphaltenes, but even high concentrations cannot dissolve asphaltenes. For this reason we investigate BA as a potential asphaltene deposition inhibitor. The strong organic acid surfactant, dodecyl benzene sulfonic acid (DBSA), has been shown to completely dissolve asphaltenes via acid-base chemistry reactions at heteroatomic sites on the asphaltene molecules. We investigate the use of DBSA as an efficient removal agent, injecting it in a mixture of petroleum fluid after the deposit has already been formed. An aromatic solvent, toluene, is also investigated in such a fashion, to assess its ability in removing deposited asphaltenes. We find that DBSA can effectively remove asphaltene deposits quickly and at concentrations roughly ten times less than that required by toluene. To the best of our knowledge, our current study is the first lab-scale investigation using dispersant or surfactant chemicals to either inhibit or reverse asphaltene deposition in pipes.
Aspects of Oilfield related Accidents
Authors: Qi Qianru , Ershaghi Iraj 
Published: September 2013

Abstract
Petroleum engineering literature contains limited reviews or documentations of oilfield accidents. We considered a number of cases which in the past have resulted in human fatalities, injuries and environmental disasters. Our study included a number of oilfield accidents ranging from drilling operation to pipeline transportation. Publicly available analysis of these case studies indicates accidental causes ranging from mechanical malfunctioning, electric shocks, falling objects, human errors and management flaws. For the studies included in our analysis, however, we observe that unless we resort to innovating and install advanced techniques for early failure prediction and monitoring for protecting workers, other similar events can re-happen with unfortunate impact on safety of human and the environment. As such, steps must be taken to not just enacting system integrity monitoring but also developing tools for empowering and enhancing human senses or system sensors for predicting failures and thus saving lives. This becomes particularly more critical in work processes where either overwhelming volume of incoming signals or, on the opposite, lack of critical sensor data become matters of concerns. Our review also show that critical situations develop when human response time is out of sync with unexpected systems responses and, more importantly, when human attitude about risk and safety, contributes to the disasters.
Lessons learned show that, while it is important to equip oilfield workers with the appropriate attire, safety tools and decision making systems, it is more important to support workers with remote monitoring and early warning systems. This will help for real time sensing and failure prediction of systems integrity for safeguarding oilfield workers when they deal with complex systems and/or when they may need to make decisions under duress. These remote monitoring systems must be able to rapidly process information from multitudes of sensors and sensor nets and provide real time feedback to the workers for protecting them against their shortcomings in their sensing limitations and for potential human related attitudes that can cause accidents.