bluuebunny/crossref_metadata_2025_split huggingface dataset:
Phase Behavior and Minimum Miscibility Pressure in Nanopores
Authors: Teklu Tadesse Weldu , Alharthy Najeeb , Kazemi Hossein , Yin Xiaolong , Graves Ramona M. , AlSumaiti Ali M. 
Published: June 2014

Summary
Numerous studies indicate that the pressure/volume/temperature (PVT) phase behavior of fluids in large pores (designated “unconfined” space) deviates from phase behavior in nanopores (designated “confined” space). The deviation in confined space has been attributed to the increase in capillary force, electrostatic interactions, van der Waals forces, and fluid structural changes.
In this paper, conventional vapor/liquid equilibrium (VLE) calculations are modified to account for the capillary pressure and the critical-pressure and -temperature shifts in nanopores. The modified VLE is used to study the phase behavior of reservoir fluids in unconventional reservoirs. The multiple-mixing-cell (MMC) algorithm and the modified VLE procedure were used to determine the minimal miscibility pressure (MMP) of a synthetic oil and Bakken oil with carbon dioxide (CO2) and mixtures of CO2 and methane gas.
We show that the bubblepoint pressure, gas/oil interfacial tension (IFT), and MMP are decreased with confinement (nanopores), whereas the upper dewpoint pressure increases and the lower dewpoint pressure decreases.
The Use of Single and Multi-Phase MPD and UBD Techniques on Numerous Wells and Hole Sections Have Made it Possible to Drill the Un-Drillable in Mexico
Authors: Beltran Paredes Juan Carlos , Lupo Cecconi Corrado Pier , Chable Marcos Adrian , Moreno Hermogenes Duno , Bonilla Carlos Andres 
Published: June 2014

Abstract
The first commercial discovery of oil in Mexico took place in 1904, with the Pez-1 well located in the area of Ébano, San Luis Potosí. This well produced 1,500 barrels per day of crude oil. At the time, any well producing one tenth of this production was considered a great findthroughout the world.
Conventional overbalanced techniques were used to drill oil and gas wells in Mexico to control reservoir pressures and the mechanical stability of rocks where different formations intersected. It wasn’t until 1995 that PEMEX began to implement near/underbalanced drilling (UBD) techniques with the primary intent of drilling depleted reservoirs. Later on, managed pressure drilling (MPD) was implemented as a solution in several of the Mexico oil pay zones to overcome operational problems such as fluid losses, differential sticking, and influx events induced not only by the narrow margin operating window, but also the high frictional pressure losses due to increasingly complex wellbore geometries. Years ago, these hole sections were drilled conventionally, but the constant influxes and subsequent partial and/or total losses of circulation during the well control events made feasible alternative techniques mandatory to reach section TD without influx/loss events.
Single and multi-phase MPD techniques are now widely used across most all Mexico fields and have become a standard in well operations, unlike a few years ago when the technology was considered new. These techniques are used effectively to overcome operational problems in high pressure, high temperature (HPHT), high pressure, low temperature (HPLT) and low pressure, high temperature (LPHT) wells in deep reservoirs, delivering success by avoiding NPT and by successfully reaching planned TD.
Today Mexico is encountering a stage of MPD deployment that involves the use of state-of-the-art single andmulti-phase MPD techniques and UBD. Combined with dedicated engineering support, this approach has provided an increased level of safety and performance, and in some cases, allowed realtime formation evaluation through bottomholeprecise bottomhole pressure management with surface backpressure and nitrogen gas injection systems.
This paper summarizes the single and multi-phase MPD and UBD techniques performed on more than 400 complex and diverse hole sections in Mexico oil and gas basins, both exploration and development fields. Highly complex, specialized applications, such as foamed mud and concentric casing nitrogen injection drilling, will also be discussed.
Production Data Analysis of Overpressured Liquid-Rich Shale Reservoirs: Effect of Degree of Undersaturation
Authors: Behmanesh H. , Hamdi H. , Heidari Sureshjani M. , Clarkson C. R. 
Published: June 2014

Abstract
Liquid-rich shale plays (LRS) in North America have recently gained a lot of attention. Commercialization of these plays is now possible due to new technology, such as multi-fractured horizontal wells (MFHW). Along with such developments, there is an increased requirement to develop consistent reservoir-engineering methods to analyze multi-phase production data in such reservoirs. Large drawdowns required to produce these very low permeability formations complicate production analysis due to condensate drop-out near the wellbore or fracture face.
Hydraulically-fractured vertical and horizontal wells completed in tight formations typically exhibit long periods of transient linear flow. This paper discusses a novel production data analysis technique for constant flowing bottomhole pressure (pwf &lt; pdew) wells producing from fractured LRS reservoirs. Our focus in this work is on cases where the initial reservoir pressure is well above the dew point pressure, as occurs in highly-undersaturated portions of the Eagle Ford Formation. A theoretical basis is developed for analysis of the transient linear flow period for these cases, and the effect of initial pressure on well performance is studied. The governing flow equation is linearized using appropriately defined two- phase pseudopressure and pseudotime functions, where the liquid solution analogy can be applied. This approach provides an accurate estimation of the linear flow parameter (xf√k) in multi-phase flow situations. Fine-grid compositional and black oil numerical models are used to validate the results. This work provides a robust analytical framework for production analysis of liquid-rich shale reservoirs as well as practical guidelines for real world applications.
Immediate Gas Production from Shale Gas Wells: A Two-Phase Flowback Model
Authors: Adefidipe O. A. , Dehghanpour H. , Virues C. J. 
Published: June 2014

Abstract
Although existing models for analysing single-phase flowback water production at the onset of flowback in tight oil and gas reservoirs provide estimates of fracture volume, they are not applicable to shale gas reservoirs. This is because flowback data from shale gas wells do not show this single phase region. Instead, they show a surprising trend of immediate gas breakthrough. This paper attempts to (1) understand the fundamental reasons for this early gas breakthrough, (2) develop a representative mathematical model that describes this behaviour and (3) estimate the effective fracture volume and equivalent fracture half-length by history matching the early-time two-phase flowback data.
From the diagnostic plots generated from of rate/pressure data of 8 multi-fractured horizontal wells completed in the Muskwa Formation, the gas-water ratio (GWR) plots indicate the presence of initial free gas in the complex fracture network. This conclusion is backed by the imbibition experiments conducted on shale samples collected from the same formation showing the presence of gas-saturated natural fractures. The linear diffusivity equation is solved for early-time two-phase gas/water flow in the hydraulic fractures. The primary drive mechanism at the onset of flowback is initial free gas expansion within the fracture network. Secondary drive mechanisms considered include fracture water expansion and fracture closure. The driving forces are modeled by an effective compressibility term analogous to the total compressibility in conventional multiphase flow formulations. Also, two-phase water/gas flow is handled by an explicitly determined relative permeability function of time. Eventually a new pseudo-time function is defined to account for the changes in gas properties and relative permeability with time. Rate normalized pseudo-pressure versus pseudo-time plots give a straight line when applied to field data, thus the solution can be used to characterize hydraulic fractures in a manner similar to conventional well testing methods.
A Study of Dynamic and Static Factors That Are Critical to Multi-Well Reservoir Simulation of Liquid Rich Shale Plays
Authors: Miranda Carlos , Yang Huade 
Published: June 2014

Abstract
The development of unconventional resources has increasingly focused in liquid rich systems in the recent years in the USA, due to relatively low natural gas prices and conversely high oil prices. In order to maximize production and optimize the development of these resource plays, adequate modeling of wells and reservoir performance is required. Reservoir simulation has been recognized as one of the most acceptable tools to model the performance of liquid rich shale (LRS) systems. Analytical solutions (DCA, RTA, PTA) exhibit several limitations to properly model the effects of multiphase flow, stress and pressure dependent permeability, condensate banking, flow through hydraulic fractures and stimulated rock volume (SRV) region, etc. on the reservoir performance of LRS plays.
Single well modeling has been extensively used to model well and reservoir performance from shale plays, but multi-well or sector modeling is not frequently performed mainly for two reasons: 1) The requirements to capture the behavior of multiple horizontal wells with multiple hydraulic fractures could be computationally prohibitive and 2) The wells in extremely low permeability formations would have minimal interaction. Although the first reason could be a legitimate limitation depending on the objectives of the reservoir project, the second one is arguable. Depending on the spacing and the volume of the fracturing treatments, in many cases, production data collected from shale plays have shown that horizontal wells may interfere with each other during production. Therefore, in projects where the main objective is well spacing or completion optimization (among other important objectives) a comprehensive multi-well reservoir simulation study is required.
This paper discusses several aspects that highly impact the reservoir simulation workflow for LRS plays: Geomodeling (seismic, geology and petrophysics), gridding (tartan grids, Cartesian grids, and unstructured gridding), PVT, flow models (dual/single porosity models), hydraulic fracture modeling, microseismic and SRV estimations, among others. The study suggest that in multi-well reservoir simulation of LRS plays, optimum grid design, proper capture of SRV and natural fractures corridors, and adequate modeling of PVT properties are the most critical factors to accurately optimize wells and completions spacing. Finally, a reservoir simulation workflow is proposed to properly address the critical factors. Field examples from the Eagle Ford and another emerging shale play are presented to support the proposed workflow.
Excitable Nanoparticles for Trapped Oil Mobilization
Authors: Soares Fernando Saint-Martin , Prodanovic Masa , Huh Chun 
Published: June 2014

Abstract
Ferrofluid is a stable dispersion of paramagnetic nanoparticles in a liquid carrier. The easily controllable magnetization of ferrofluids has motivated their use in a broad range of applications, from bioengineering to sealing of bearings. Recently, it was verified that nanoparticles with specifically-designed coating can be injected into reservoirs without significantly compromising permeability and with little retention. This suggests a potential for ferrofluid applications in enhanced oil recovery (EOR). We investigate this potential numerically through a method which, for a given external magnetic field, provides the equilibrium configuration of an oleic phase inside some pore geometry in the presence of dispersed excitable nanoparticles in surrounding brine. We adapted an existing level-set-based method for fluid-fluid displacement to include magnetic forces exerted on the fluid interface. Level set functions can easily accommodate complex shapes by representing the fluid-solid and fluid-fluid interfaces implicitly. The magnetic pressures depend locally on the magnetic field intensity and direction which in turn depend on the fluid configuration. Interfaces represent magnetic permeability discontinuities and hence cause disturbances in the spatial distribution of the field. The magnetic field solver handles these discontinuities through an immersed interface method.
Results indicate that, aside from its straightforward dependency on the ferrofluid susceptibility, magnetic pressures are strongly influenced by the pore geometry. Stresses are amplified near the contacts between a ganglion and the pore wall. The oil ganglia tend to adjust to the stress configuration by detaching from the wall.
The stresses produced by the magnetization of ferrofluids could help to overcome strong capillary pressures and displace oil ganglia. A synergy of existing EOR methods (e.g. surfactant injection) and ferrofluids excited by a magnetic field has a potential to mobilize more trapped oil near wellbore.
Wettability Alteration in High Temperature Carbonate Reservoirs
Authors: Chen Peila , Mohanty Kishore K. 
Published: June 2014

Abstract
The objective of this study is to develop strategies to improve oil recovery in highly fractured carbonate reservoirs at high temperatures (100°C and above). Such reservoirs usually contain high salinity and high hardness formation brines. The use of nonionic surfactants or anionic surfactants (Carboxylates and Sulfonates) to alter oil-wet reservoirs towards more water-wet was investigated under harsh reservoir conditions. A nonionic surfactant Ethomeen® T/25 has shown aqueous stability at high salinity and temperature with high effectiveness in wettability alteration and imbibition oil recovery. Anionic surfactant formulations were developed to recover oil mainly by gravity drainage since they did not show wettability alteration effect in hard brine. Both experimental and simulation studies have shown that sulfonate/carboxylate surfactants achieve high performance in wettability alteration and spontaneous imbibition only when they mix with chelating agents in formulations. Chelating agents, especially EDTA.4Na and sodium polyacrylate (NaPA) have been tested for their compatibility and effectiveness in the surfactant formulations. By sequestering divalent ions in hard brine, chelating agents free anionic surfactants to react at the solid-fluid interface to alter wettability of carbonates from oil-wet towards more water-wet. The chelating agents trigger mineral dissolution, but that does not lead to wettability alteration or contribute to the imbibition oil recovery directly.
Well Placement Optimization Constrained to Minimum Well Spacing
Authors: Awotunde Abeeb A. , Naranjo Carlos 
Published: June 2014

Abstract
Efficient recovery of hydrocarbon resources is one of the challenges facing the oil and gas industry. In an enhanced oil recovery (EOR) scheme, optimal placement of wells plays an important role in determining the amount of oil that can be recovered with the selected EOR process. Once the reservoir flow paths have been established, it necessary to find an optimal configuration of wells that will yield the highest net present value (NPV). Traditionally, well placement optimization (WPO) has been done through experience and use of quality maps. However, in recent times, there has been a gradual shift from traditional methods to automatic well placement that uses gradient-based or stochastic search algorithms to locate the optimal positions of wells. This technology has enabled improvement in the decision making process. Despite the successes achieved, the optimization tools rarely enforce well spacing constraints during the optimization process. This often results in well configurations with high NPV but also with physically unrealistic well positions.
In this paper, we propose to solve the well placement optimization problem constrained to any desired minimum well spacing. Minimum well spacing here refers to the minimum distance between any two wells that a company or an asset team considers technically safe. First, we develop the nonlinear inequality constraints needed to enforce minimum well spacing, then formulate the well placement problem as a constrained optimization problem and subsequently adopt the penalty approach to solve the constrained well placement problem. The covariance-matrix adaptation evolutionary strategy (CMA-ES) was used as the global optimizer in solving the optimization problem.
Two examples were used to show the effectiveness of the approach. Results obtained from this approach were compared with those obtained from the unconstrained WPO. The results show that the method can successfully determine optimal well locations without violating any of the constraints. In contrast, the unconstrained optimization approach failed to satisfy some of the nonlinear constraints and in some cases yielded well configurations in which two or more wells are placed at exactly the same location (on top of each other).
Use of Laboratory Scale Apparatus for Simulation of Downhole Stimulation Monitoring With Distributed Temperature Surveys
Authors: Pinto Hardy , Frederico Eira Carlos , Rosas Fabio , Carneiro Fernando , Bobula Deny 
Published: June 2014

Abstract
Adequate fluid placement and complete zonal coverage during a matrix acid stimulation is critical to the success of a treatment. The use of distributed temperature sensing (DTS) is a relatively new technique that can be used for monitoring downhole fluid placement during a treatment. It uses a fiber-optic distributed-temperature-monitoring system to provide continuous temperature profiles throughout the entire length of the well, giving relevant information to perform qualitative and, in some cases, quantitative analysis of fluid placement downhole.
This paper describes the design and construction of a laboratory scale flow-loop apparatus to demonstrate the application of DTS technology for downhole fluid placement monitoring. The apparatus constructed contains three inlet and exiting points to simulate well perforations, a method to raise or lower fluid temperature and thus introduce temperature spikes or tracers, and optical fiber and sensing equipment and instrumentation to measure and compare measured and calculated rate data. The system is capable of simulating several well flow conditions, such as fluid injection, fluid production and crossflow.
The designed apparatus has proven to be versatile, compact, and useful for understanding and training professionals regarding how DTS technology can be used for monitoring downhole fluid flow and placement.
Completion Influence on Production Decline in the Bakken/Three Forks Play
Authors: Gullickson Geoffrey , Fiscus Kirk , Cook Peter 
Published: June 2014

Abstract
Recent developments in completion techniques and stimulation efficiency have allowed many unconventional resource plays to reach economically viable levels. The Bakken/Three Forks play of the Williston basin has rapidly evolved during recent years, and its predominantly successful completion techniques continue to emerge as programs are tailored to geographic areas. As completion intensity increases to facilitate higher early time production returns, so does the need for the critical analysis of production decline rates to meet economic targets.
The application of decline curve analysis in unconventional reservoirs, such as the Bakken/Three Forks play in North Dakota, is often problematic because of very long periods of transient flow. This has caused the development of various decline curve relations outside the conventional Arp's equations in an attempt to better explain the transient flow period. Additionally, it has sparked interest in quantifying the uncertainty associated with production and the estimated ultimate recovery (EUR) from these various techniques.
The Bakken/Three Forks system is exploited using a large variation of publically reported completion techniques throughout a significant geographic area. Because of the uncertainty in assessing the performance of unconventional wells and the multitude of variables that could affect their production, it is often difficult to determine dominant influencing parameters of completion design. Efficiently implementing optimal completion techniques, provided there is high variability within a continuous horizontal target lithology, is critical because of the large geographic extent of the Williston basin.
The focus of this study is to evaluate the completion efficiency of individual wells using decline curve analysis and to quantify uncertainty using this performance metric. A comprehensive completions database of the Bakken/Three Forks play is used to evaluate the expected costs and benefits of various completion designs used throughout the basin. This paper provides examples of stimulation methods optimized to specific regions of the Bakken/Three Forks system using this methodology.
Use of Conventional Well Logs In Selective Completion Designs for Unconventional Reservoirs
Authors: Barree R. D. , Conway M. W. , Miskimins J. L. 
Published: June 2014

Abstract
A common issue in unconventional reservoir completion and stimulation design is the selection of fracture initiation points to effectively contact producible reserves. One solution is to equally space initiation points along the entire well, with the trend being to closer spacing to increase reservoir contact. A second approach is to use some combination of logs in the lateral to selectively complete sections that appear to have better reservoir quality or producing capacity. In areas where the rock properties are relatively consistent in terms of reservoir quality, the two methods may overlap so that uniformly spaced fractures offer the best opportunity to for effective stimulation. In other cases, where sections of the lateral are out of zone, or in identifiably inferior reservoir quality, portions of the lateral may be skipped to decrease overall completion cost. This paper presents a method to use and integrate multiple well logs in both vertical and horizontal wells to identify hydrocarbon bearing intervals (storage) and highly productive zones (possibly "natural" fracture sets) for selective completion.
Correlations have been found between acoustic velocity, resistivity, gamma-ray, and porosity logs and core-derived properties such as hydrocarbon saturation and TOC%. These correlations have been expanded to include mud log gas shows and ROP (rate of penetration) to differentiate between matrix and secondary fracture contributions to production. With very little core data it is possible to derive a regional model that predicts TOC% from simple log measurements that are commonly available. The analysis strongly suggests areas of a well that should be primary targets for stimulation, zones that can be bypassed with little economic downside, and sections of the well that should not be considered for zonal isolation such as packer setting points. The method has been applied in many unconventional development areas, including the Marcellus, Utica/Point Pleasant, Wolfcamp/Avalon, Duvernay, Montney, and Eagle Ford with equal success. Results have been confirmed by post-frac production logs in cases where complete data sets are available.