bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Approach for Using Surfactants to Enhance Oil Recovery from Naturally Fractured Oil-Wet Carbonate Reservoirs
Authors: Parra Jose E. , Pope Gary A. , Mejia Miguel , Balhoff Matthew T. 
Published: September 2016

Abstract
Recent research indicates that even small viscous transverse pressure gradients can increase the rate of surfactant imbibition into the matrix of a fractured reservoir. However, surfactants are commonly tested using static imbibition cells without any imposed pressure gradient. Therefore, the effect of viscous pressure gradients was investigated by conducting a series of surfactant corefloods using fractured Silurian Dolomite and Texas Cream Limestone cores. The viscosity of the surfactant solution was increased by adding polymer or by changing the salinity of the aqueous surfactant solution, which affects the in-situ microemulsion viscosity. The fractured cores had a permeability contrast between the fracture and the matrix ranging from 2500 to 90,000. Non-fractured corefloods were also performed and compared with the fractured corefloods. The more viscous surfactant solutions achieved greater oil recovery from the fractured carbonate cores. These results indicate that a viscous microemulsion can serve as a mobility control agent in naturally fractured reservoirs (NFRs) that is analogous to mobility control with foams and polymers, but with less complexity and cost.
Using Completion Diagnostics in Uinta Basin Vertical Wells to Reduce Completion Costs and Identify Horizontal Well Targets
Authors: Ramos C. , Dineen C. , Kolla J. 
Published: September 2016

Abstract
Over 13,000 active oil and gas wells and more than 740 million bbl of oil have been produced from conventional vertical wells in Utah's Uinta Basin (Fig. 1). Located within the basin, the Monument Butte area is among the top 100 oil fields in the United States. Operators with a strong presence in the Monument Butte area are also pursuing ideal target zone(s) for horizontal wells by evaluating various sections of the reservoirs and utilizing the availability of technological advances made in recent years in horizontal drilling. Determining the reservoir water source zones to curb water disposal costs and ascertaining the productivity of different segments of a well to evaluate its profitability are more important than ever considering the current economic situation.
This paper will highlight the completion diagnostic results obtained from using oil-soluble and water-soluble tracers during the completion of eight conventional vertical wells in the Monument Butte area. The eight wells selected for this study are located in Sections I, II and III in Uintah County; the wells were drilled through and completed for comingled production in the Green River and Wasatch formations. Through the deployment of hydrocarbon tracers and fluid tracers, oil contribution and water production were evaluated across all zones. Between 3 and 12 hydraulic fracturing treatments were pumped into each vertical well. The fracturing treatments were designed similarly and each stage was meant to stimulate a unique target zone or formation. Moreover, for each well, each stage design had a unique set of oil-soluble and water-soluble tracers. Oil-soluble tracers were used to quantify the hydrocarbon contribution for each segment from samples taken during the course of 30 and as long as 410 days. In addition, the water-soluble tracers were used to clearly determine the water source intervals, allowing the abandonment of deeper wet zones, thus realizing a significant cost savings from not drilling and completing the bottom 800 to 1,000 ft of each future well.
Finally, the unique sets of oil and water tracers were also used to evaluate the short-term and long-term productivity of each pay zone, with the intention of identifying the best formation(s) to target in horizontally drilled wells.
Highly Efficient Dehydration and Desalting of Crude Oil from Mature Fields in the Middle East
Authors: Sellman Erik , Mandewalkar Pavan 
Published: September 2016

Abstract
Mature crude oil fields are often prone to high water cuts and high content of fines. The large population of small water droplets and fines forms very stable crude oil emulsions that are difficult to break using conventional treaters. The high water cut creates a high-viscosity crude oil emulsion, often leading to a need for higher operating temperatures, high demulsifier dosage, and frequent production upsets.
The high water cut also causes arcing between electrodes. Typically, older crude oil dehydration and desalting treaters use AC-type electrostatic technology, which is less effective in treating crude oils with high water cuts. The use of AC/DC-type electrostatic technology provides a two-pronged approach—bulk water is removed in a weaker AC field, and the remaining smaller water droplets are removed in a stronger DC field. Further improvements to the AC/DC treaters include use of composite electrodes, modulated electrostatic fields, and improved fluid distribution inside the treaters.
AC/DC treaters provide an attractive opportunity for retrofitting existing AC treaters in mature fields and make the treaters more suitable for dehydrating the crude oil emulsions from these fields. Recent upgrading of a large number of older electrostatic treaters and desalters in the Middle East provided the operators with several benefits in the form of higher production, ability to operate the facility at a lower temperature, lower wash water consumption, and improved overall performance.
This paper describes a new enhanced electrostatic dehydration technology that provides improved efficiency in treating high-water-cut crude oil emulsions in mature fields and efficient test methods to optimize use of production chemicals and selection of electrostatic technologies. Several case studies from the Middle East are included.
Characterization of Rock Pore-Size Distribution and Its Effects on Wormhole Propagation
Authors: Dubetz D. , Cheng H. , Zhu D. , Hill A. D. 
Published: September 2016

Abstract
Carbonate rocks have complex heterogeneities that result from syn- and post-depositional stressors. These heterogeneities invariably affect the movement of fluid through the formation. When considering an acid treatment procedure, care must be taken to optimize the acid concentration and pumping schedule to encourage the formation of wormholes. Despite the abundance of carbonate formations (60% of conventional reserves), there is little consensus on the effect of physical formation properties related to acidizing efficiency. This study characterizes the pore-size distribution for different carbonates and evaluates how the optimum pore volume to breakthrough, PVbt,opt, and the optimal interstitial flux, vi,opt, are related to various physical properties of the rock.
The pore-size distributions evaluated in this study are constructed with micro-computer tomography (micro-CT) imaging, a non-invasive X-Ray imaging technique pioneered in the medical field. Micro-CT is improved over medical CT because it can scan at higher energies and higher resolution. In this work, resolution for scanned samples range from 5-8 μm/voxel and sample sizes are approximately 1cm3. Image processing is applied to the raw CT data to segment pore space from the surrounding matrix. Object counter software is used to identify and measure individual pores, which can then be organized into a pore-size distribution. Statistical parameters are calculated by fitting a lognormal distribution function to each sample's pore-size distribution. We find that the shape of the pore-size distribution is influenced by the type of carbonate rock and that fitting the distribution yields better correlations to optimum acidizing parameters than permeability or porosity alone.
Parallel Multilevel Monte Carlo for Two-Phase Flow and Transport in Random Heterogeneous Porous Media With Sampling-Error and Discretization-Error Balancing
Authors: Müller Florian , Jenny Patrick , Meyer Daniel W. 
Published: September 2016

Summary
We consider two-phase flow and transport in heterogeneous porous media, where the permeability is modeled as a random field. To assess the resulting uncertainty of flow and transport, multilevel Monte Carlo (MLMC) is used. MLMC involves two types of errors: a sampling error and a discretization error, which, under reasonable assumptions, can be conveniently estimated during execution. In this work, we address the question of how to balance the two errors. Furthermore, a simple MLMC parallelization strategy is presented. A numerical comparison of MLMC with standard Monte Carlo (MC) reveals significant gains in computational efficiency at equivalent accuracy.
Super-Large Scale Horizontal Well Position Optimization Method and Infilling Practice in High Water-cut Large Complex Fluvial Reservoir Based On Multidisciplinary Innovative Techniques
Authors: Wang Kai , Wang Haisheng , Shu Xiao , Zhou Dasheng , Wang Ruizhe , Li Yujun , Liu Ning , Su Zhikun , Ren Baicong 
Published: September 2016

Abstract
Tapping the remaining oil with horizontal wells is routinely used in high water-cut oilfields. However, it faces serious challenges in complex fluvial reservoirs with stacked sand body, horizontal interlayers, lateral barrier and complex water flooding conditions. Moreover, the depth uncertainty of the target interval, limited number of offset wells, rapid change of thickness, thin target intervals, and variable fluid contact have also increased the risks of the horizontal well placement. In order to locate the optimal positions of the horizontal wells, get the maximum recovery, reduce the risk of water flooding, minimize the drilling time, we propose a comprehensive well planning and optimization method based on multidisciplinary innovative techniques. New techniques from geology, geophysics, and drilling engineering are assembled to efficiently perform the challenging task.
Firstly, an improved interwell 3D correlation technique was proposed to characterize the single sand body. The technique can depict the vertical hierarcy of reservoir. Secondly, we propose a lateral boundary delineation technique based on seismic geometrical attribute. Combined with ant tracking algorithm, we are able to extract the 3D lateral discontinuous surfaces. Based on above technique, we can build detailed architecture model fast and optimize the positions of horizontal wells. Considering the geological uncertainty, the boundary mapping tool is used to optimize the well trajectories in real time to avoid the water flooded zone and shale zone, and to stay in the sweet zone.
We applied the integrated workflow in Q oilfield in Bohai Bay basin, East China. 112 horizontal wells are drilled. The drilling results proved that boundary mapping tool can achieve smooth landing of well path and delineate the accurate geometry and thickness variation of sand body which reduces the depth uncertainty of seismic horizon explanation, and keeps the horizontal well trajectories away from oil-water contact. The production results show that 86% horizontal wells have achieved low water-cut and high oil production rate. The total production rate of Q oil field has increased by 2.5 times.
Detecting Production Choke Wear in High Rate Dry Gas Wells using Graphical Trending of Production Parameters: An Offshore Saudi Arabia Gas Field Case Study
Authors: Ayoola Olakunle T , DeLandro Wendell WC , Muslim Ali M 
Published: September 2016

Abstract
A production choke is essential in regulating the pressure and flow rate of the produced hydrocarbon stream from a well in a field production system. Regulating the pressure and flow rate is necessary to achieve the production objectives of a field, which are to meet customer demand and optimally manage the reservoir over its life cycle. It is therefore important to have a means of effectively monitoring production choke performance to identify the onset of choke wear. Choke wear results from erosion of the choke due to impingement of particles carried in the produced hydrocarbon stream as it passes through the choke body. Choke wear increases the production rate and downstream pressure of a producing well, thereby upsetting the balance of the production system and resulting in ineffective field pressure management. Taking immediate action to replace a worn choke is therefore necessary to restore the production balance and achieve optimal pressure conservation of the production system. Choke performance monitoring is more critical for gas producing wells than oil producing wells because the velocity of gas is typically much higher than the velocity of oil, and consequently the risk and frequency of choke wear is much higher. Physical inspection of the production chokes to confirm wear for offshore gas wells is more laborious and time consuming due to the need to interrupt production, depressurize the flowline, decouple the choke body from the flowline, and ship the choke body onshore to the manufacturer's workshop for component inspections to confirm choke wear and, if necessary, choke replacement. A way to remotely monitor production choke performance and correctly detect choke wear for offshore gas wells without interrupting production is therefore operationally expedient, reduces exposure of personnel to unsafe rough sea conditions, and saves the cost of unnecessary physical choke inspections. The authors present a graphical method of monitoring the production rate and flowing tubing head pressure trends, with the choke size, of offshore high rate dry gas wells to detect choke wear using real-time production data. Examples of successful application of the method, which demonstrates that innovation can be simplification of processes, to detect choke wear and perform timely choke replacement are highlighted.
The Impact of Normalized Relative Permeability Data on Estimated Ultimate Recovery
Authors: Pollard Victoria , Yusuf Babatunde 
Published: September 2016

Abstract
A typical hydrocarbon reservoir consists of multiple rock types or facies. In reservoir modelling, capturing the properties of each rock type is essential. Relative permeability data, which describes rock-fluid and fluid-fluid interactions is normally developed for each rock types and is often a tuning parameter in History Match (HM); a very important element of reservoir simulation. The objective of this paper is to analyze the effect of applying normalized relative permeability data to model a reservoir. The effect is examined using both manual and automatic History Match, and then predicting the Estimated Ultimate Recovery (EUR) in two scenarios.
Relative permeability curves for each rock type are prepared using corey saturation function equations. The normalization phase requires using separate sets of equations, after which the normalized curve will be denormalized for input into the simulation model. The resulting relative permeability curve is then used in HM by applying manual and automatic methods, after which the resulting matches are used to predict recovery. The reservoir simulation output using the normalized relative permeability curve is then compared to the base case scenario, in which case, individual rock types relative permeability curves were utilized.
Reservoir simulation outputs from normalized relative permeability curves were found to compare very well with outputs using individual rock type relative permeability, with improved efficiency, for the reservoir under study.
Normalized relative permeability data, when used with sound engineering judgement, can be very efficient. Mostly desired as an essential part of History Match, having a single representative set of relative permeability data for the reservoir can improve efficiency and save costs.
Experimental and Numerical Investigation of Oil Recovery from Bakken Formation by Miscible CO2 Injection
Authors: Zhang Ke 
Published: September 2016

Abstract
Unconventional liquid reservoirs are characterized by small matrix permeability that is several orders of magnitude lower than conventional oil reservoirs. The combination of multi-stage hydraulic fracturing and horizontal drilling has improved the overall profitability of these tight-oil reservoirs by enhancing the wellbore - matrix connectivity. Under primary production, however, the recovery factor remains in the range of only 5% to 10% of original oil in place (OOIP). Considering such a large resource base, even small improvements in productivity could lead to millions of barrels of additional oil. Therefore, the need to develop a viable enhanced oil recovery technique for unconventional oil reservoirs is evident.
This study investigates technical feasibility of carbon dioxide as an enhanced oil recovery agent for tight-oil reservoirs. Above minimum miscibility pressure (MMP), CO2 and oil are miscible leading to reduction in capillary forces and therefore high local displacement efficiency. The miscibility pressure of CO2 is also significantly lower than the pressure required for other gases, which makes CO2 miscible injection attainable under a broad spectrum of reservoir pressures.
The coreflood experiments recovered more than 70% of the OOIP from a Bakken core sample with an average porosity of 7.5% and permeability of 1.8 μd. CT scans at dual energies were used as an additional tool to visualize fluid flow and distribution at core level. We discovered that the impact of CO2 penetration is better captured at a lower energy level where the X-ray attenuation mechanism of photoelectric absorption becomes dominant. To decipher the oil recovery mechanisms in the coreflood experiment, a numerical compositional model was constructed to reproduce the laboratory results. Vaporization of light hydrocarbon components into CO2 is shown as a major recovery mechanism. Other controlling factors include re-pressurization, oil swelling, viscosity and interfacial tension reduction. History matching with the laboratory experiment introduces additional complexities such as rock heterogeneities and presence of a fracture that promotes flow perpendicular to the core length. The above issues need to be addressed to match the displacement process exactly.
Applications of Additive Manufacturing to Rock Analogue Fabrication
Authors: Anderson Timothy 
Published: September 2016

Abstract
Enhanced oil recovery (EOR) is an effective method of petroleum recovery, having been shown to extract up to 70% of original oil in place compared to the roughly 50% for conventional oils and less than 50% for unconventional resources such as heavy oil and shale oil obtainable through primary and waterflood recovery methods. Research problems in EOR are often ill-posed due to the large range of relevant spatial and time scales and strong nonlinearities in the physical systems. Consequently, EOR experiments suffer from a lack of repeatability: slight variations in the experimental parameters or environment, including porous medium heterogeneity, may lead to dramatically different outcomes, making it difficult to determine which results are spurious and which are meaningful. Additive manufacturing (3D printing) technology has enabled the unprecedented ability to create repeatable experimental samples. Using 3D printing technologies such as stereolithography, selective laser sintering, and fused deposition modeling, it has become possible to create porous media samples from a wide range of materials with a reliable level of accuracy and repeatability. In this study, we present several applications of additive manufacturing to creating repeatable rock analogues for EOR experiments. Specifically, we outline potential applications of 3D printing to in-situ combustion and microfluidic flow experiments. For in-situ combustion, we demonstrate the efficacy of powder bed printing for creating repeatable sandstone analogues with consistent porosity and permeability. For microfluidics, we show the potential of using 3D printing for producing repeatable rock replicas at-scale in three dimensions. We also present flow visualizations using scaled-up printed rock models of silicates and carbonates. Overall, 3D printing is a very promising technology for applications in EOR experiments. Based on the results of this study, we believe that with further research 3D printing will soon offer an unprecedented degree of experimental repeatability and ability to create representative solid surfaces for EOR research.
A Mechanistic Computational Fluid Dynamic CFD Model to Predict Hydrate Formation in Offshore Pipelines
Authors: Neto E. T. 
Published: September 2016

Abstract
In this paper, a mechanistic computational fluid dynamic (CFD) model has been developed in order to understand the controlling mechanisms of hydrate formation. The conservation of mass, momentum, and energy were solved in order to obtain the velocity, pressure, temperature, and concentration profiles along the pipeline so that not only phase equilibrium but also the transport phenomena could be incorporated in the analysis. To predict the rate at which hydrate particles are formed, a reaction kinetic model was coupled with the transport equations. Also, due to low solubility of methane in water, the mass transfer of methane from gas to liquid phase was considered based on a two-film theory. The results showed that not all the methane dissolved in liquid phase is converted into hydrate particles due to low residence time of reactants, which proves that equilibrium is not reached under operating conditions encountered in offshore pipelines and it could be possible explanation for metastable behavior observed in field operations.
Mechanical Characterization and Corrosion Effects on Glass Reinforced Vinyl Ester Liners used for Oil and Gas Production
Authors: Carpenter Cole 
Published: September 2016

Abstract
In this study, a glass reinforced vinyl ester (GRV) liner was systematically designed to produce a corrosion resistant, toughened, liner with superior corrosion resistance and strength characteristics. This GRV liner system was designed as an alternative to previously tested glass reinforced epoxy systems [1]. The composite liner could theoretically be used in conjunction with standardized oil and gas production tubing to alleviate the effects of corrosion in offshore exploration applications. This particular system was designed using netting analysis for filament wound pressure vessels and tested in accordance with ASTM D2290 split-disk procedures. To ensure that the finalized design would be capable of withstanding the immense pressures and temperatures seen during use in offshore oil and gas production, the project used an API controlled steel alloy already employed by industry as a benchmark for determining the necessary yield stress and internal yield pressure required for the proposed application. To further define the physical characteristics of the proposed system, tests were conducted to verify the coefficient of thermal expansion (CTE) of the composite material. The CTE data was then used to evaluate the potential for interfacial thermal stresses induced when bonding dissimilar materials at elevated temperatures. Furthermore, the vinyl ester composite was environmentally conditioned in accordance with ASTM G202 rotating cage procedures, and evaluated to assess the proposed system's susceptibility to degradation caused by corrosive fluids. The study was conducted with the intent to utilize the design principles of filament wound pressure vessels to produce an oil and gas production liner that emulates the strength characteristics of its steel counterpart, while retaining the corrosion resistance associated with vinyl ester matrix.