bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Computational Study of Packoff Using a Combined Drill Bit Stabilizer Particle Tracking Simulation
Authors: Uddin H. , Choudhury N. R. , Ansari U. 
Published: April 2016

Abstract
The primary cause of packoff in wells is improper hole cleaning resulting from aggregated cuttings and particles from the bottom hole. Drill-bit geometry and rotation plays an important role in dictating returning flow paths of drilling mud and thus transportation of debris particles from the bottom hole. This paper presents an early attempt to investigate the integrated effect of mud flow through drill bit and stabilizer slots on well packoff using computational fluid dynamic (CFD) -based particle simulations.
A commercially available three-dimensional (3D) flow solver was used to simulate turbulent flow for both stationary and rotating drill bits and two competing stabilizer designs with different flow by area. The motion of debris was tracked using a discrete phase model in a Lagrangian framework. A set of parametric studies was performed to investigate the effect of stabilizer location, particle size, rate of penetration (ROP), etc. on the hydraulic performance of the integrated assembly in terms of cuttings-transport ratio [the ratio of average particle velocity to average annulus velocity (Ct)], particle concentration, velocity profiles, etc. for a range of flow rates.
Results from the combined drill-bit stabilizer simulations were reported and design bottlenecks were identified for a legacy stabilizer model. New insights were gained for design modifications to address packoff. Simulation results show that the particles follow the flow path created by the slanted blades of the drill bit initially and then begin a swirling motion before passing through the stabilizer slots. The new design has a larger flow by area, and it straightens the rotating flow and hence offers faster evacuation of cuttings. The flow profile becomes more uniformly distributed and prevents any clustering of particles, thereby significantly reducing non-productive time (NPT) and improving tripability of the bottomhole assembly (BHA) in oil fields.
This study provides insight into stabilizer design concepts and the stabilizer’s location as it is combined with a drill bit. The integrated simulation approach adopted here enables operators to predict the motion of formation cuttings using a simpler particle model in a larger system and helps prevent drillstring packoff.
Simulation of Perforation Cleanup Dynamics and the Effect of the Direction of Gravity
Authors: Craddock G. G. , Haggerty Dennis 
Published: April 2016

Abstract
The understanding of perforation tunnel-flow dynamics in the presence of gravity or orientation is an important consideration. This work examines the flow dynamics after a perforation, both numerically and analytically. It presents CTH simulations of a perforation tunnel created by a shaped charge and the subsequent initial flow into that tunnel. CTH is a shock hydrodynamic code that can simulate the initial dynamics of flow driven by shocks. The longer-term stability of the flow into the perforation tunnel is further analyzed in terms of external influences, including the orientation with respect to the gravitational field. A stability analysis of the various types of instabilities present at interfaces of flow in a tunnel is performed. Simulation results for different charges indicate that the flow enters at different locations in the tunnel. This behavior is also expected to depend on the fluids present, the tunnel they create, and the type of rock. This paper also presents the temporal dynamics from CTH of the flow at different locations along the tunnel, along with a discussion of turning these flow results into predictive models for tunnel formation. The simulation results are then used as inputs into the analytic calculation. Various types of drag are considered, based on laminar and turbulent flow. In the latter case, the geometry of the rough surface and, consequently, the type of rock, plays a critical role in the flow. Results of the stability analysis can be shown to be influenced by the direction of gravity, for example. These instabilities can then influence the drag along the tunnel walls and subsequent cleanup. Consequently, when a cleanup test is performed in a flow facility that can rotate, such as an unconsolidated formation pressure vessel, the perforation tunnel geometry will be influenced by gravity. Suggestions are made to compensate for the gravitational influence on the flow, which can be translated into downhole performance enhancement.
Experimental and Simulation Study of Water Shutoff in Fractured Systems Using Microgels
Authors: Goudarzi Ali , Alhuraishawy Ali , Taksaudom Pongpak , Sepehrnoori Kamy , Bai Baojun , Imqam Abdulmohsin , Delshad Mojdeh 
Published: April 2016

Abstract
Conformance control has long been a compelling subject in improving waterflood oil recovery. By blocking the areas previously swept by water, subsequently injected water is allowed to access the remaining unswept portions of the reservoir and thereby increase the ultimate oil recovery. One technique that has recently received a great deal of attention in achieving the so-called "in-depth water shut-off' is preformed gel injection. However, processing and predicting the performance of these gels in complex petroleum reservoirs is extremely challenging. As target reservoirs for gel treatments are mainly those with fractures or ultra-high permeability streaks, the ability to model the propagation of gels through a fractured reservoir was considered as a new challenge for this research study.
The primary objectives of this work are to conduct laboratory work to understand the transport and propagation of microgel through fractures and develop conformance control schemes using a reservoir simulator to help in screening oil reservoir targets for effective particle gel applications to improve sweep efficiency and reduce the water production. Fractured experiments using transparent apparatus were performed to observe gel transport in matrix and fractures. The same set up was used to observe the effects of gel strength, gel particle size, and fracture size on gel transport. Numerical simulation of fluid-flow in fractured reservoirs can be computationally difficult and time consuming due to the large contrast between matrix and fracture permeabilities and the extremely small fracture apertures and the need for using unstructured gridding. In this work, a model that accurately represents the complex reservoir features, chemical properties, and displacement mechanisms is developed.
The five-spot transparent fracture experiments allowed us to identify the transport mechanisms of microgels through fractures-conduits and also the control variables. With an integration of comprehensive gel transport modules and a novel Embedded Discrete Fracture Modeling (EDFM), gel rheological and transport properties of shear thinning viscosity, adsorption, resistance factors, and residual resistance factor, using multiple sets of fractures with dip angles and orientations were captured. The models were validated against lab measurements and implemented into a reservoir simulator called UTGEL.
The mechanistic models and numerical tool developed will help to select future conformance control candidates for a given field and to optimize the gel chemistry and treatment.
Monitoring Production Well Testing Facilities Using Statistical Analysis
Authors: Brady Jerry L. , Kelley Timothy F. , Mehdizadeh Parviz , Starck Jennifer 
Published: April 2016

Abstract
There are over 50 well test facilities operated by BPXA on the North Slope of Alaska. The test facilities provide production measurement for 100s of producing wells that produce 100,000s of barrels per day. Well tests are a critical surveillance method for production optimization and reservoir performance monitoring of oil and gas fields. The quality of well tests directly impacts production operations, allocation, well workover activities, and capital investment decisions.
A cost efficient method to determine the quality of well testing operations is to use well test repeatability statistics. Observing well test data over periods of time provides the ability to identify anomalies in well operations and metering performance. This paper will discuss the details of an algorithm that was developed to determine the repeatability of well testing for all BP-operated North Slope well test facilities. This algorithm identifies and filters outlier well tests due to operational changes. Remaining well tests are then treated statistically to determine measurement performance.
A web application was developed to allow viewing, sorting, and analysis of well test repeatability statistical data by operational personnel. This application is used to rank well test facilities and wells with high deviations in gross fluid, gas rates, watercut, and oil rates. Examples of the application with actual field data are provided in the paper. Access to this data allows for improved business decision making, identification of problematic well test facilities, and prioritization of repairs and upgrades to equipment.
Drilling Engineering and Formation Evaluation: An Integrated Approach to Improve Real Time Drilling Optimization
Authors: Webb Jerry , Roze Erwan , Jarret Cameron , Le Roux Stephane , Mejia Camilo 
Published: April 2016

Abstract
In the current market climate, the industry is in a time squeeze and it is crucial for future value generation to reduce the well construction time and cost. Drilling Optimization practices have helped to increase drilling efficiency while reducing the likelihood of downhole failures. To see this effort further, an adequate engineering plan to design the operation strategy, along with the understanding of the geological challenges, assists in establishing a more robust real-time optimization program.
Real-time drilling optimization helps to improve drilling performance by providing early warning detection of downhole drilling events, maximum allowable deviation of planned vs. actual hydraulics and torque & drag measurements, and finding the "sweet spot" by use of drilling parameters. These processes can then further be optimized by the integration of pre-job engineering and formation evaluation measurements. Pre-job engineering seeks to ensure the BHA is able to resist vibration- related events, while the drillstring and bit are selectively examined for optimal hydraulics and resistance to torque and drag related issues. The pre-job engineering also considers ways to improve the rig’s overall efficiency, by eliminating invisible lost time while both in and out of hole. New generation of logging while drilling measurements help to provide reliable prediction of pore pressure for early warning of circulation problems, collapse events, lost circulation, blowout, and kicks. This process involves a depth-by-depth correlation between actual borehole lithology and pre-modeled unconfined / confined compressive strength (UCS/CCS). Optimized mechanical specific energy is evaluated using drilling parameters such as torque, RPM and ROP. The resulting two curves are then defined by calculating the value of MSE/CCS-UCS fraction to derive a drilling efficiency indicator. By correlating these curves, the drilling optimization team can identify geological formations that have the optimum correlation then compute the efficiency indicator for the interval, using it as baseline for drilling each hole section. This workflow guides the operations to make necessary real time adjustments to mitigate potential problems.
The workflow demonstrates the integration from the pre-job engineering design to the automation of the real time integrated evaluation, along with the accuracy of the new generation of Logging While Drilling technologies as a cost-effective solution to mitigate non-productive time and optimize drilling rates through the implementation of a solid drilling optimization program during the execution of ERD, offshore and unconventional projects.
Using Data To Create Foresight And Create Value From Volume
Authors: Snøtun Håkon 
Published: April 2016

Abstract
With the recent downturn in oil price, more of the fields in the arctic seem less financially viable and many projects have been postponed, or altogether abandoned. In an industry where companies are unable to change the market price and cost becomes the main differentiator, projects in the arctic have added worries because of an inhospitable climate, lack of infrastructure and severe environmental concerns. This means that companies have to plan better, but also plan differently in the arctic in order to stay competitive.
All planning should be data driven with a focus on learning from past experiences and projects, but how one handles data determines how much value can be extracted from volume, and how much insight and foresight one can expect. We have found that there are four main obstacles to using data effectively. Firstly, it can be hard to find the correct data, but even more importantly, it can be hard to determine what data is missing. By some estimates, geologists use 60% of their time looking for data and less than 20% looking for oil. Secondly, even though a lot of data is sometimes available, the data might not be accessible, and a lot of time is lost in planning from converting esoteric formats, different units of measure and a plethora of curve values. The third obstacle to use data is that the context for the data might be missing, which is even more important in the arctic, because it might be hard to determine if experiences obtained in one area can be transferred to arctic projects. Finally, data is often aggregated before the planning stage it might hard because of time constraints to investigate whether anomalies in the data is caused by error in the data or outliers that can add risk or cost to the project.
We will show how efficient use of Big Data techniques and statistical analysis can mediate the effects mentioned above, and how normalization and standardization of data can allow users to spend their time interpreting data. Although the use of data does not eliminate risk, it can help manage it by identifying which risks should be focused on, but also identify where the project moves into uncharted territory in terms of equipment, location, rig or other factors.
Field Testing and Validation of a Mechanical Alternative to Radial Jet Drilling for Improving Recovery in Mature Oil Wells
Authors: Balch Robert S. , Ruan Tongjun , Savage Mark , Harvard Jeff 
Published: April 2016

Abstract
Short radius laterals, where a drilling tool is able to make a right turn in a cased wellbore and then penetrate some distance out into a formation, is an attractive technology for enhanced oil recovery for both existing and new field developments. Lateral holes with different geometries can penetrate untapped compartments, thin or by-passed pay, less permeable oil zones that cannot be sufficiently drained by conventional processes, and extend the effective radius of a well while reducing skin effects. A commonly referenced technology is radial jet drilling, where a specialized shoe is deployed in the well, a casing cutter cuts a hole through the pipe, and then a nozzle with high-pressure cutting jets is deployed on a hose at the end of coiled tubing. The technology has yet to become common in the United States, despite tens of thousands of candidate wells that could benefit from such a restimulation. Problems with jet drilling systems include: uncertainty in distance and direction of emplaced laterals; low available power to front-facing cutting jets, as most of the power has to be directed to rear-facing jets to keep the nozzle on the formation; and difficulties cutting hard formations and when encountering hard clasts.
The objective of this study was to evaluate a newly developed technology for production enhancement from low-permeability reserves that utilizes a purely mechanical drilling string deployed on coiled tubing that is able to make a right-angle turn in a wellbore and drill a ~1.5 in. diameter lateral 30 ft or more into a reservoir. To study the technology, two wells were selected and stimulated.
A simulation study for one of the field test sites, Millman field, a Grayburg/San Andres field in the Permian Basin, New Mexico, allowed a sensitivity study for optimization of lateral emplacements, optimal number of laterals per level, and allowed prediction of the impact of the recompletions. The prediction of lateral efficiency showed that the four emplaced laterals gave the best overall efficiency for enhancing oil production with 28.5% predicted incremental production in previously stimulated zones, and a 33.3% increase for previously unstimulated zones. Diagnostic techniques for monitoring lateral direction and placement based on small, chip-based gyroscope and accelerometer chips were developed and field-tested, verifying lateral emplacement during the field tests. The first test well saw ~40% increase in oil rate with emplacement of 12 laterals in three intervals. The second test well saw a 47% increase in production after 15 laterals targeted a previously untapped zone.
This paper presents, discusses, and validates the drilling technology, the simulation models and results, the sensor development, and field-testing of those three technologies at two wells, with the emplacement of 27 total laterals with lengths of up to 32 ft.
Effective Extraction of High Viscosity and Low API Gravity Hydrocarbon Resources With Solvent-Steam Processes
Authors: Hascakir Berna 
Published: April 2016

Abstract
Extraction of unconventional resources is vital to meet future hydrocarbon demand. However, the effective extraction of these unconventional resources cannot be accomplished by the application of conventional technologies. This study summarizes different combination of different Enhanced Oil Recovery (EOR) methods to recover effectively the low API gravity and high viscosity crudes to find the main factors affecting the EOR performances most. Several steam flooding, steam assisted gravity drainage, and solvent aided-steam processes (SA-SP) (both with asphaltene solvent and non-solvents) were tested on heavy, extra-heavy, and bitumen resources. Carbon dioxide, propane, n-hexane, and toluene were tested as solvents. While carbon dioxide, propane, and n-hexane are asphaltene non-solvents, toluene is asphaltene solvent. The process performances were discussed in terms of cumulative oil recovery and produced oil quality. Produced oil qualities were compared according to their asphaltene, clay, and water contents. Asphaltene content directly correlates to the water and clay contents of the produced oil samples. As the asphaltene content of produced oil increases while the water content increases, the clay content decreases. The worst produced oil quality was obtained by SAGD and toluene-SAGD. The experiments conducted with the asphaltenes insoluble solvents (carbon dioxide, propane, and n-hexane) produced the highest quality oil with low water content and high deasphalted oil content.
The Effect of Clay and Salinity on Asphaltene Stability
Authors: Demir A. Birkan , Bilgesu H. Ilkin , Hascakir Berna 
Published: April 2016

Abstract
Destabilized asphaltenes cause serious problems by precipitating in the reservoir pores which reduces the oil flow by decreasing the reservoir porosity and permeability significantly. This study investigates the impact of clays and salinity on the stability of asphaltenes for five different crude oil samples. First, both n-pentane and n-heptane insoluble fractions of five crude oils were examined under microscope after the interaction with water, brine, and porous media. The porous media was prepared with clay only, sand only, or sand-clay mixture. A monovalent (NaCl) and a divalent (CaCl2) salts at 0.2% and 4% concentrations were used to prepare brine samples. The systematic microscopic imaging conducted on asphaltenes show that both n-pentane and n-heptane asphaltenes are getting dispersed in water phase. However, this dispersion is hampered with the existence of ions in water and this impact increases with the increase in brine concentration. Nevertheless, the destabilization of asphaltenes is more pronounced with the presence of clays. Because the destabilized asphaltenes are precipitated in porous media, asphaltenes precipitation impacts the wettability of porous media. Hence, the wettability of oil-water-rock and oil-brine-rock systems was determined through water-air contact angle measurements. The pseudo reservoir rock-oil-water/brine systems were prepared by keeping constant the weight of each component in the system for five crude oil samples. Reservoir rocks were prepared by mixing sand and clay. The brine was prepared either with NaCl or with CaCl2. The impact of salt concentration on wettability was tested for both 0.2% and 4% brine solutions. It has been observed that the asphaltenes fraction has an important role on wettability determination, however, the interaction of asphaltenes with deasphalted oil is the main contributor which defines the wettability of the system. Thus, our systematic analyses on asphaltenes should be extended and similar analyses should be conducted on the deasphalted oil fractions.
Polymer-Enhanced Foam PEF Injection Technique to Enhance the Oil Recovery for the Post Polymer-Flooding Reservoir
Authors: Dong Xiaohu , Liu Huiqing , Hou Jirui , Liu Guohua , Chen Zhangxin 
Published: April 2016

Abstract
Polymer flooding process is one of the most commonly-used EOR techniques for the waterflooded light-oil reservoirs. The further development after polymer flooding process is currently challenging the EOR techniques. Using the methods of physical simulation and numerical simulation, the feasibility of polymer-enhanced foam (PEF) injection process in post polymer-flooding reservoir is performed in this paper. Through the introduction of a concept of average foam-composite-index (FCI), an experimentally based screening criteria for PEF is proposed. And, the influence of polymer concentration on the plugging-effect of PEF is also experimentally investigated. After that, the parallel experiments of PEF injection and conventional foam injection are conducted. Then, based on the geostatistics data of an actual oil reservoir, a Lorentz-Monte-Carlo (LMC) algorithm is proposed to establish the heterogeneous geological models with different interlayer and plane permeability-variation-coefficients. Thus, the sensitivity of reservoir heterogeneity on the recovery performance of PEF injection is numerically analyzed, and the implementation plan of PEF injection is also optimized through an orthogonal test.
Experimental results indicate the plugging effect of PEF is significantly superior to the conventional foam. The optimal polymer concentration is 1500mg/L, and the injection of PEF could effectively enhance the oil recovery by about 17.1%. The improving effect of enhanced foam on oil recovery in heterogeneous reservoir is much more significant than that in the homogeneous reservoir. As the reservoir heterogeneity increases, the ultimate recovery factor increases. For the rhythm reservoir, the reverse rhythm reservoir with weak plane-heterogeneity and week interlayer heterogeneity could yield a better recovery performance. The optimal implementation plan of PEF injection process are that the slug size is 0.06PV, injection rate is 50t/d, gas/liquid ratio is 1:1, foamer solution is 0.5wt%, and polymer solution is 0.6wt%. This investigation sheds some important insights for the enhanced oil recovery (EOR) process of post polymer-flooding reservoir. It could be used as a tool for the successful design of PEF injection process during the high water-cut stage of post polymer-flooding reservoir.