bluuebunny/crossref_metadata_2025_split huggingface dataset:
Spatio-Temporal Stress Path Prediction using A Fluid Flow-Geomechanical Model
Authors: Shahri Mojtaba P. , Miska Stefan Z. 
Published: June 2014

Abstract
In-situ reservoir stresses change during the production period due to the reduction in pore pressure. Consequently, the upper limit of the drilling mud window; i.e., formation fracture pressure, reduces corresponding to the pore pressure depletion. Since drilling operations in critical situations such as deep water and depleted reservoirs require precise prediction of the mud window, it's of vital importance to accurately assess the reservoir stress path; i.e., the change of in-situ stresses with pore pressure. Currently used models for reservoir stress path prediction can be divided into two main categories: space- and time-independent and spatio-temporal models. Space- and time-independent models have been used for several decades. According to industry demand of precise stress path prediction, spatio-temporal models have recently been developed for stress distribution determination within reservoirs. However, the developed stress path models are based on the transient flow regime and can not be utilized in depleted reservoirs wherein the pressure response usually reaches the reservoir boundary.
The aim of this study is to provide an analytical model for predicting reservoir stress changes at different times and locations within reservoirs during the pseudo-steady-state flow regime. Constitutive equations from the theory of poroelasticity are combined with a force-balance equation to find the relationship between reservoir stresses and pore pressure. The application of the proposed model for reservoir stress path prediction is illustrated using a numerical example.
The Dynamics of Fluids In Reservoirs
Authors: Mullins Oliver C. , Zuo Julian Y. , Dong Chengli , Elshahawi Hani , Seifert Douglas J. , Cribbs Myrt E. 
Published: June 2014

Abstract
Measurement of reservoir fluid gradients vertically and laterally in a reservoir captures a ‘snapshot’ of the evolution of fluid processes that take place over geologic time. Downhole fluid analysis (DFA) has enabled this reservoir fluid profiling to be performed in an efficient manner. Dramatically different fluid distributions are obtained in different reservoirs and can be categorized in terms of the extent of thermodynamic equilibrium attained. Factors that influence the equilibration process include the geologic timing of reservoir charging, possible secondary fluid processes, the extent of convection versus diffusion, the size of the equilibrating fluid component, and the size of the reservoir. Here, we show reservoirs that span a very large range, from very young reservoirs (Pliocene) that evidently exhibit stochastic distributions of solution methane over relatively small distances to old reservoirs (Lower Cretaceous) with equilibrated asphaltene clusters over immense distances. For each class of reservoir evolution, very different yet very important production concerns are identified. Characterization of the fluid columns in terms of (dissolved) solids, liquids and (dissolved) gases is found to be most informative for several reasons including 1) the large gradients associated with the different (dissolved) phases and 2) the important production concerns associated with the different phases. In particular, understanding the disposition of the asphaltenes in the reservoir is key for many purposes. This is accomplished using the industry's first equation for asphaltene gradients, the Flory-Huggins-Zuo Equation of State for asphaltenes, with its reliance on the Yen-Mullins model of asphaltene nanoscience. The ability to model all three crude oil phases within a proper thermodynamic framework enables the ability to track the evolution of these phases in the reservoir, bringing into view simplifying systematics that significantly improve risk management in production of these reservoirs.
How Does Innovation Happen in the Upstream Oil & Gas Industry? Insights from a Global Survey
Authors: Perrons Robert K. 
Published: June 2014

Abstract
Few would argue that the upstream oil & gas industry has become more technology-intensive over the years. But how does innovation happen in the industry? Specifically, what ideas and inputs flow from which parts of the sector's value network, and where do these inputs go? And how do firms and organizations from different countries contribute differently to this process? This paper puts forward the results of a survey designed to shed light on these issues. A joint research initiative between the Society of Petroleum Engineers and the Queensland University of Technology, the survey was sent to 469 executives and senior managers who played a significant role with regards to R&D and/or technology deployment in their respective business units. A total of 199 responses were received from a broad range of organizations and countries around the world. Several interesting themes and trends emerge from the results, including: (1) service companies tend to file considerably more patents per innovation than other types of organization; (2) over 63% of the deployed innovations reported in the survey originated in service companies; (3) neither universities nor government-led research organizations are considered to be valuable sources of new information and knowledge in the industry's R&D initiatives; and (4) despite the increasing degree of globalization in the marketplace, the USA still plays an extremely dominant role in the industry's overall R&D and technology deployment activities. By providing a detailed snapshot of how innovation happens in the upstream oil & gas sector, this paper provides a valuable foundation for future investigations and discussions aimed at improving how R&D and technology deployment are managed within the industry.
Application of New Fingerprinting Bacteria DNA in Crude Oil for Reservoir Charaterization-Part II
Authors: Hayatdavoudi A. , Chegenizadeh N. , Chistoserdov A. , Boukadi F. , Bajpai R. 
Published: June 2014

Abstract
In early 80's, while reassessing some old gravel pack sands from a well, we noticed some sludge in the samples. The sludge had plugged formation and the gravel pack pores. The permeability was so low that the owner of the oil property thought of abandoning the well and consequently stopped all workover measures. The owner stated that there was no more oil left in the reservoir. This observation and the previous ones in early 70's, in addition to the laboratory studies conducted at a later date, suggested the existence of bacteria in the oil. In the current study we implemented a novel, sensitive technique for bacterial DNA fingerprinting; that is, denaturing gradient gel electrophoresis of PCR amplified 16S rRNA genes. This approach allowed us to identify and classify bacteria found in the oil. The research enabled us to evaluate the application of our technique to evaluate the origin of oil in the reservoirs.
To prove the hypothesis that bacteria were present in oil, we requested an operating company to provide us with 6 samples taken from 2 separate wells, but drilled in the same reservoir or at least the operator believed both wells were drilled in the same reservoir. To characterize the oil and subsequently the reservoir, we implemented our procedure of fingerprinting bacteria DNA as follows: (1) DNA extraction from oil, (2) DNA concentration, (3) Making 0.7% and 1% Agarose gel, (4) Electrophoresis of total DNA isolated from oil, (5) PCR amplification of 16S rRNA gene fragment from DNA isolated from oil, (6) Running gel on the PCR product, (7) Running Denaturing Gradient Gel Electrophoresis (DGGE), and (8) Cycle Sequencing DNA.
The result from DNA concentration using our technique proved the existence of the bacteria DNA in all crude oil samples, which was not possible to find previously. Using the governmental open source data from offshore Louisiana and the results of researchers work available in the literature, we conducted a detailed geological and petroleum engineering study of the field in our study area. Furthermore, in order to find petroleum engineering applications for our discovery of DNA in crude oil we classified the bacteria and found the origin of the crude oil produced from each well in the reservoir. Based on our results, we found that Well B drained oil from a grassland, lacustrine, fresh water environment, whereas Well A drained oil from a very shallow marine environment. From the results, we concluded that, these two wells are not drilled in the same reservoir, implying that there may be enough oil left in both reservoirs to be drained by one or more wells.
Transport and Distribution of Proppant in Multistage Fractured Horizontal Wells: A CFD Simulation Approach
Authors: Bokane Atul , Jain Siddharth , Deshpande Yogesh , Crespo Freddy 
Published: June 2014

Abstract
Multistage hydraulic fracturing has become the key technology for completion of horizontal and vertical wells. The perf and plug method is the most commonly used staging method. In each stage, multiple perforation clusters are used, attempting to create a separate transverse fracture at each cluster. How these clusters are placed can significantly affect both short- and long-term production performance. Simultaneous creation of multiple fractures is a cost-effective and time saving method for stimulating both vertical and horizontal wells. Multistage fracturing is an effective method in terms of completion efficiency; however, achieving even proppant distribution to each cluster is an intricate task that proves to be challenging within the industry.
Numerical simulations predict uneven proppant distribution of the fluid streams entering different perforation clusters. Field data indicates, in many cases, that some of the clusters do not contribute to production. This led to hypothesizing that actual proppant and fluid distribution along the stimulated clusters can differ from the assumed uniform distribution. However, with respect to limited-entry frac design, the proppant distribution among the different perforations is assumed to be the same as the fluid distribution. Until recently, this assumption remained unchallenged.
This paper presents extensive study and investigation of proppant transport in different perforation clusters within a single stage by using computational fluid dynamics (CFD) techniques. Effects of varied fluid and proppant specific gravity, viscosities, proppant sizes, and slurry flow rates were analyzed while maintaining outside-casing parameters constant. Validation of empirical proppant transport CFD simulation results are compared to experimental test data. This is helpful to gaining a better understanding of fluid and proppant behaviors in multi cluster fracturing processes to achieve maximum efficiency.
The results of the study indicate that proppant transport can be accurately modeled when the effects of single particle settling, density driven flow, particle velocity profiles, and slurry rheology are all considered. The investigation demonstrates that CFD is an effective tool for optimizing proppant distribution among perforation clusters and enhancing production.
An Innovative Survey Method Using Rotating Sensors Significantly Improves the Continuous Azimuth and Inclination Measurement Near Vertical and Offers Improved Kickoff Capabilities
Authors: Bowler Adam , Sugiura Junichi , Lowdon Ross , Hawkins Richard , Jones Steve 
Published: June 2014

Abstract
When kicking off at low inclination, static measurement-while-drilling (MWD) surveys are used to confirm the kickoff direction, when free of magnetic interference from offset wells. However, as MWD continuous azimuth and inclination measurements have limited accuracy when near vertical, the directional driller does not have confidence in the kickoff direction with continuous (dynamic) survey while drilling. This requires additional static surveys to be made, taking up precious rig time.
In a novel continuous survey method used in a particular rotary steerable system (RSS), a six-axis survey was taken continuously, both while drilling and when static, with the surveys sensors being housed in a rotation-speed-controlled platform in the RSS. This algorithm was first verified in a software simulator, and it was subsequently implemented in hardware and tested in a hardware-in-the-loop-simulator environment. The effectiveness of the new measurement method was field tested and compared against MWD static survey points. The field test result shows that the new near-bit continuous azimuth and inclination from the RSS is considerably more accurate than that of the MWD continuous measurements at very low inclinations of between 1° and 5°.
This unique measurement method has valuable applications, such as low-angle kickoff without using multiple static surveys as the directional driller can use the continuous azimuth and/or toolface to accurately steer the well. Equally important is that if gyro surveys are required, their number will reduce as the survey measurement point is so close to the bit, reducing the amount of time of exposure to magnetic interference from an offset casing. When drilling out of the shoe, this survey method will allow an accurate kickoff approximately 50 ft earlier than would normally be expected as magnetic interference is cleared. Additionally, the use of a continuous gravity toolface is possible without the need for static surveys, allowing accurate low-side sidetracks to be performed even in areas of high magnetic interference. This surveying method reduces the rig time needed to kick off and provides a more reliable real-time measurement for the directional driller to ensure the desired well trajectory is drilled through crowded platform environments.
Performance of Multiphase Flowmeter and Continuous Water-Cut Monitoring Devices in North Slope, Alaska
Authors: Brady Jerry , Igbokwe Chidiebere , Montague Stuart , Warren Mike , Stadnicky Nick , Linder Mathew , Hall Andrew , Mehdizadeh Parviz , Roberts Bart , Lievois John , Rodriguez Daniel J. 
Published: June 2014

Abstract
Alaska's North Slope oil fields offer several different types of production environments that can prove challenging for effective production well testing with conventional gravity type test separators. The Prudhoe Bay field has mature production: high water cuts exceeding 90%, crudes with low 20s API gravity and gas-lifted wells with high gas volume fractions (GVF) &gt;99.9%. The Milne Point field has viscous crude and light oil production and employs electrical submersible pumps (ESP), jet pumps and gas lift. This wide range of production methods and challenging fluid properties create challenges when analysing potential equipment and procedures to provide the critical production data needed to optimize overall production.
Over the last several years, BP Exploration (Alaska) Inc. (BPXA), installed over 24 infrared water-cut sensors. Nineteen water-cut devices have been installed in three-phase flow regimes at the wellheads. Five water-cut units have been installed on the liquid legs of two phase test separators. During this period BPXA also installed seven in-line multiphase meters—five in use at production pads for testing wells and two on individual wellheads.
This paper will discuss BPXA's experience with these metering devices over two years of operation, and present the verification process used to qualify the devices and their performance data. Additionally, successes, challenges and lessons learned are discussed.
Evaluation of Annular Pressure Losses while Casing Drilling
Authors: Dokhani Vahid , Shahri Mojtaba P. , Karimi Moji , Salehi Saeed 
Published: June 2014

Abstract
Casing Drilling is an innovative drilling method wherein the well is drilled and cased simultaneously. The small annulus of Casing Drilling can create a controllable dynamic ECD (Equivalent Circulating Density). Casing Drilling technology permits the same desired ECD as conventional drilling to be achieved using a lower, but optimized, flow rate, rheological properties, and mud weight. In this paper, the frictional pressure loss during Casing Drilling operation is evaluated using Computational Fluid Dynamics.
Annular pressure losses have received substantial attention in theoretical analyses, laboratory assessment and actual well measurements. Combinations of casing motion, annular eccentricities, wall roughness and fluid temperatures along the length of the annulus affect fluid flow regimes that control annular pressure losses. Current analytical solutions have limited applicability for complex conditions with pipe rotation and eccentricity.
In this study, the pressure losses during Casing Drilling operation are investigated using computational fluid dynamics. The results are compared against the available analytical solution and field data. The effect of pipe rotation and eccentricity on the frictional pressure loss is investigated as well. According to the simulation results, the pipe rotation reduces the frictional pressure loss for Yield-Power-law fluid which would be beneficiary during the casing drilling operation. It is found that the pipe eccentricity has a significant effect on the ECD calculation.
The industry is moving towards more challenging jobs in narrow pressure window scenarios such as deep-water and HPHT applications. Drilling with casing/liner is among the primary options to complete these sections due to strengthening effects associated with plastering the wellbore wall and also eliminating conventional drill pipe trip. Having accurate models for ECD including the effects of pipe rotation and eccentricity in the narrow annulus is essential to the success of these challenging jobs.
Resistivity-Based Pore-Pressure Prediction—Pitfalls and Solutions
Authors: Saleh S. , Williams K. E. , Rizvi A. 
Published: June 2014

Abstract
An investigation of resistivity-based pore-pressure estimation in sediments near salt bodies was conducted as part of a joint-industry project (JIP) that acquired, analyzed, and documented more than 100 wells in the Gulf of Mexico from shelf to deepwater (2005–2009). The result of this unique study culminated in the compilation of a comprehensive database that includes geophysical, petrophysical, and drilling data. This database was used to develop best practices for pore-pressure estimation below and around salt bodies.
Resistivity-based pore-pressure prediction is dependent on many variables including: porosity, salinity, temperature, fluid type, saturation, shale content, type of clay, and texture. Resistivity changes resulting from changes of pore water salinity near salt masses may give a false indication of pore-pressure changes. Approximately 50% of the subsalt wells show some signs of salinity variations near the salt (within ∼1,000 to 1,500 ft) that impact pore-pressure estimates for sediments adjacent to salt. Resistivity commonly responds to changes in pore water chemistry near salt; thus, there is a compelling need to recognize the salinity variation near salt bodies and find ways to account for these variations in resistivity-based pore-pressure analysis. This report presents exploratory efforts into possible approaches to achieve this goal.
Resistivity variations owing to salinity and temperature have been addressed using a dual water-modeling procedure, as published by Revil et al. (1998). This was used to generate a normalized resistivity. Normalized resistivity is then used as a primary input to conventional (Eaton 1975) pore-pressure analysis. The analysis of pore pressure from normalized resistivity remains an academic interest and has yet to be proven practical.
This paper shows good evidence for a potential improvement to be gained from normalized resistivity analysis. It is hoped that accumulated experience from applying this approach (resistivity normalization) will pave the way to an improved resistivity-based pore-pressure prediction analysis in sediments affected by salinity variations.
Static and Dynamic CFD Modeling of Viscoelastic Polymer: Trapped Oil Displacement and Deformation at the Pore-Level
Authors: Afsharpoor Ali , Balhoff Matthew T. 
Published: June 2014

Abstract
Understanding the flow behavior of viscoelastic fluids in porous media is critical for optimizing enhanced oil recovery (EOR). Polymers such as hydroxypolyacrylamide (HPAM) are used to improve sweep efficiency in reservoirs and these polymers often exhibit elasticity. Surprisingly, recent experimental and field observations indicate that these viscoelastic polymers improve oil recovery up to an additional 20%, contrary to the conventional wisdom that polymers should have no impact on residual oil saturation. Here, we attaempt to understand effects of viscoelasticity on residual saturation in water-wet and mixed-wet porous media. Static and dynamic computational fluid dynamics (CFD) simulations of oil droplets in the presence of viscoelastic polymer are conducted in geometries representative of pore throats. Results show that additional forces on the oil droplet are present for fluids that exhibit elasticity over those that do not (e.g. water) and those forces become larger as the oil droplet approaches a constriction. It is also shown using dynamic simulations that the amount of deformation of the oil droplet is greatly affected by the elasticity of the displacing fluid. These results are promising and provide a theoretical foundation for the laboratory and field observations of reduced residual oil.
Workflow to Image Unconformities with Deep Electromagnetic LWD Measurements Enables Well Placement in Complex Scenarios
Authors: Dupuis C. , Omeragic D. , Chen Y-H. , Habashy T. 
Published: June 2014

Abstract
The advent of deep-reading directional electromagnetic logging-while-drilling measurements brings opportunities in imaging complex formations around the wellbore. In this context, basing the inversions on an assumption of a layered medium is not always sufficient to decouple geometrical effects in complex formation scenarios.
Rather than attempting to invert all variables of a generic 2D formation model simultaneously, we describe in this paper how the use of 2D inversions can be enabled through a robust workflow specifically designed for a class of formation models, in this case the angular unconformity. We demonstrate how the successive application of 1D inversion to subsets of tool data gradually builds a formation model for use as input to a 2D inversion, which accounts for complex couplings present in the data in such environments.
The validity and the performance of the method are established through synthetic and field datasets.