bluuebunny/crossref_metadata_2025 huggingface dataset:
A CFD Compositional Wellbore Model for Thermal Reservoir Simulators
Authors: Shahamiri A. , Heidari M. , Buchanan W. L. , Nghiem L. X.
Published: September 2015

A robust, fast, and accurate wellbore model is essential for a reliable reservoir simulation. There has been significant interest to improve the wellbore models as the operations and behavior of advanced wells have become more complicated, in particular for thermal Steam-Assisted Gravity Drainage (SAGD) process. The non-linear and dynamic nature of the processes involved, as well as the necessity for prediction and control of such wells under rigorous operating conditions, makes the development of such a model complicated. The majority of current models use simplifying assumptions, especially with respect to the fluid dynamics involved. This work uses CFD techniques to solve the complete form of Navier-Stokes equation along with the mass and energy conservation equations. The objective is to develop a robust and efficient CFD numerical procedure for flow in wellbores where the slippage between phases, phase change, and radial mass/heat transfer between the wellbore and reservoir, are taken into account. A finite volume approach is employed to discretize the conservative form of the balance equations using a staggered grid arrangement. A Drift Flux model estimates the physical phase velocities, and the modified Beggs and Brill pressure-drop model is used to estimate the frictional pressure term in the momentum equation. Both of these models are valid for all multiphase flow regimes, at upward and downward flow conditions with different inclination angles from -90ᵒ to 90ᵒ. The phase fractions, component mole fractions, and temperature distribution are obtained using isenthalpic flash calculations. The system of equations is solved implicitly using Newton's method. The model was validated for a wide range of operating conditions against available data for different single and multi-phase flow conditions. The results of CFD wellbore model is also compared with the current thermal wellbore model FlexWell of CMG's STARS™ reservoir simulator.
Model for a Shale Gas Formation with Salt-Sealed Natural Fractures
Authors: Merry Hoagie , Ehlig-Economides C. A. , Wei Pang
Published: September 2015

Most multiple transverse fracture horizontal wells in shale gas formations remain in transient bilinear or linear flow for very long periods, typically several years. Some plays show very different behavior that has been attributed to pressure dependent permeability. Often, there are reported cases of shale wells that exhibit boundary dominated flow in a very short period that implies a stimulated rock volume (SRV) much smaller than would be expected based on the hydraulic fracture treatment design. This paper offers an alternative explanation for the early boundary dominated flow related to dissolution of salt-sealed natural fractures in the shale. Three plays are the target of this study, namely, the Haynesville shale, the Marcellus shale, and the Horn River Basin.

Flowback of water with significantly higher salinity than the injected fracture fluid may suggest that the injected low salinity fracturing fluid dissolved salts that seal an existing natural fracture system. Evidence would be seen in long-term transient rate and pressure production data as early boundary dominated flow providing the natural fracture pore volume dissolved by injected low salinity fracturing fluid that leaked off during the hydraulic fracture treatment. In this scenario, the effective permeability would represent that of the natural fracture system induced by salt dissolution, and the stimulated rock volume would be directly related to the leakoff volume.

This study first discusses a plausible diagenetic history for generation of a salt-sealed natural fracture system in shale gas and how core, log, and conventional test data may behave. We then present a material balance model for behavior of the salt-sealed fracture porosity, the shale matrix porosity, and fracture pore volume dissolved by the leaked off fracture fluid, during the fracture treatment and subsequent early and long term production. We show the resulting permeability loss as residual water vaporizes. The significance of the model is a new rationale for a correlation between apparent stimulated rock volume and injected fluid during hydraulic fracturing.
Pore Connectivity and Permeability Assessment in Carbonate Formations using NMR Log-Inject-Log Method
Authors: Cheng Kai , Heidari Zoya
Published: September 2015

Nuclear magnetic resonance (NMR) logging is a well-established technology for estimating porosity, pore-size distribution, and permeability in conventional reservoirs. However, the uncertainty associated with these estimates can be significant in complex heterogeneous carbonate reservoirs, such as those with variable pore size and pore network connectivity. In such cases, distinguishing isolated pore space is often impossible using well-log measurements and conventional well-log interpretation methods, which makes permeability evaluation unreliable. This paper proposes a new application of the NMR log-inject-log method to improve assessment of permeability and to distinguish isolated pores from connected pores. We propose injecting manganese-bearing solution in the rock samples and simultaneously analyze NMR measurements before and after injection of the contrast solution. We introduced a method to eliminate the impact of isolated pore space from the NMR T2 distribution, which is then used for improved permeability assessment.

To confirm the feasibility of the proposed method for field applications, we conducted NMR laboratory measurements in two carbonate rock types. We injected manganese-bearing solution into rock samples using a coreflood experimental procedure and measured NMR T2 distributions before and after injection. We then estimated isolated porosity and interconnected porosity by taking into account the difference between the NMR T2 distributions acquired before and after the injection of the contrast solution. We introduced a method to calculate geometric mean of T2 distribution for interconnected pores, and also to obtain effective free fluid volume and bound fluid volume. Finally, we used the T2 distribution corrected for the impact of isolated pores in conventional NMR-based permeability models to improve permeability assessment. We cross-validated the NMR-based permeability estimates against Kinkenberg permeability measured by an unsteady-state gas permeameter. The results confirmed that the proposed method enables quantifying the isolated and connected pore volume, and finally improves NMR-based permeability assessment. The new method provided estimates of permeability with approximately 10% average error in eight carbonate rock samples, which was a significant improvement compared to the errors observed before correcting T2 distribution for the impact of isolated pores.
Description of In-situ Oil Upgrading Mechanism for In-situ Combustion Based on a Reductionist Chemical Model
Authors: Hascakir B.
Published: September 2015

Oil recovery following in-situ combustion (ISC) is highly dependent on initial oil saturation. The mechanisms leading to this dependence are not well understood due to the complexity of the reaction pathways leading to oil upgrading. We hypothesize that this dependence can be explained through a reductionist chemical model based on Saturates, Aromatics, Resins, and Asphaltenes (SARA) fractionation. We then substantiate this model with five combustion tube experiments, and by performing SARA fractionation on produced oils. The combustion tube experiments are conducted at identical experimental conditions but varying initial oil saturations of 13%, 26%, 34%, 42%, and 53%. The produced oil samples are examined with viscosity and API gravity measurements and weight of SARA fractions. Analysis of SARA fractions is performed with Fourier Transform InfraRed Spectroscopy (FTIR). The oil recovery and the produced gas and temperature profiles are used to define the dominant reaction type that occurred throughout the experiments, namely High Temperature Oxidation (HTO) or Low Temperature Oxidation (LTO) reactions. Metal content of the produced water samples are determined with Inductive Coupled Plasma-Mass Spectroscopy (ICP-MS). The highest temperature, with greatest oil recovery and the highest carbon dioxide concentration are observed in the experiment conducted with 42% initial oil saturation in which the HTO reactions dominate the reaction path. However, the higher oxygen and lower carbon dioxide yields observed during the experiments with 13% and 26% initial oil saturations indicate that those experiments are controlled mainly by the LTO reactions. The experiments which show dominance in HTO reactions produce low density but higher viscosity oil. On the other hand, a reverse relationship is observed for cases with LTO reaction dominance. The analysis of SARA fractions with FTIR displays significant variations in molecular structure of aromatic fractions only. A quantitative analysis of resins to aromatics ratio strongly correlates with the viscosity of the samples. Hence, we conclude that resins to aromatics ratio governs the viscosity reduction and the molecular structure of the aromatic fraction seems to be the leading factor of density improvement. ICP- MS analysis on produced water show that the dominance of the HTO reactions reduces the water-oil interaction, which leads to the production of more neutral pH water. ISC is one of the most efficient thermal enhanced oil recovery methods in which maximum oil recovery can be attained. However, the complexity of the chemical reactions taking place during the process make this process difficult to understand and control. In this study, we provide a reductionist chemical model based on SARA fractionation to explain the reaction pathways describing the in-situ oil upgrading mechanisms and the dependence of oil recovery on initial oil saturation.
Discrete Fracture-Vug Network Modeling in Naturally Fractured Vuggy Reservoirs Using Multiple-Point Geostatistics: A Micro-Scale Case
Authors: Fadlelmula F. Mohamed M. , Fraim Michael , He Jie , Killough John E.
Published: September 2015

Most of the world's massive fields produce from naturally fractured vuggy carbonate reservoirs. However, modeling such reservoirs is a challenging task due to the co-existence of porous and free-flow domains over a wide range of scales. Realistic characterization of fractured vuggy reservoirs requires preservation of the geological structure and reproduction of patterns. In this study, we model a discrete fracture-vug network using microtomography and multiple-point geostatistics (MPG) modeling technique. For this purpose, one micro-CT scan image of a real core is used to generate a micro-scale geological model (the reference model and the first training image) having three structures; matrix, fractures, and vugs.

The structures in the reference model are also separated into matrix-fracture and matrix-vug to construct two other training images. The three training images are then used in MPG to generate multiple equiprobable models that mimic the original networks of the fractures and vugs. The models created using matrix-fracture and matrix-vug training images are combined into fracture-vug-matrix models by superimposing the fracture networks from the matrix-fracture models on their corresponding matrix-vug models. The spatial continuity, patterns reproduction, and flow performance of the generated models are compared with those of the reference model. The results show that, although the fracture patterns are not well reproduced, all the generated realizations preserved the structures and reproduced the spatial continuity of the reference model. In addition, the study revealed that the flow curves of the models generated with the introduced combined MPG method bracket better with the curve of the reference model than those of the direct MPG method. These results lay the foundation for future application of the presented method to field-scale modeling of naturally fractured vuggy reservoirs.
Enhancing Hydrocarbon Permeability After Hydraulic Fracturing: Laboratory Evaluations of Shut-ins and Surfactant Additives
Authors: Liang Tianbo , Longoria Rafael A. , Lu Jun , Nguyen Quoc P. , DiCarlo David A.
Published: September 2015

Fracturing fluid loss into the formation can potentially damage the hydrocarbon production in shale or other tight reservoirs. Well shut-ins are commonly used in the field as a way to dissipate the trapped water into the matrix near fracture faces. Borrowing from ideas in chemical enhanced oil recovery (CEOR), surfactants can be potentially used to reduce the impact of fracturing fluid loss on hydrocarbon permeability in the matrix as well. Unconventional tight reservoirs can differ significant from one another, which could potentially make the use of these techniques effective in some cases while not in others. We present an experimental investigation based on a coreflood sequence that simulates fluid invasion, flowback, and hydrocarbon production from hydraulically-fractured reservoirs. We compare the benefits of shut-ins and reduction in interfacial tension (IFT) by surfactants on hydrocarbon permeability for different initial reservoir conditions. From this work, we identify the mechanism responsible for the permeability damage in matrix and we then suggest criteria that can be used to optimize the fracturing fluid additives and/or manage flowback operations to enhance hydrocarbon production from unconventional tight reservoirs.
Reservoir Flow Geometry from Primary Production: F-F Curves
Authors: Dean R. M.
Published: September 2015

A major challenge while implementing waterfloods is estimating flow heterogeneity and potential water cycling issues. Core data, being static, does not accurately represent flow in a reservoir. Isolated zones may only contribute near wellbore, and cross-flow may make reservoirs act more homogeneously than estimated by core data. A new method is proposed that can estimate flow heterogeneity in reservoirs from primary production.

This method has potential application in a wide area of study such as high-grading waterflood candidates, building accurate reservoir models to aid in rapid history matches, building reasonable models for pressure transient analysis, identifying potential thief zones, and potentially analyzing flow back distribution of fractured unconventional wells.

The method relates hyperbolic decline rate to a flow geometry, specifically flow paths with both a fraction of the total flow capacity and storage capacity. The rate at which decline occurs is related to the size of the flow path and ability to cross flow fluid from other flow paths. Hyperbolic exponents and initial declines are fit to historical decline then a solver function is used to manipulate two separate F-Φ curves, one a purely exponential fit and another fit which has the ability to match a reservoir with a thief zone. Both F-Φ functions can be adjusted by one heterogeneity fitting parameter “n”.

Matching the F-Φ curve gives the ability to estimate heterogeneity factors explicitly such as the Lorenz coefficient and Dykstra-Parsons coefficient by defined mathematical functions. The match also provides the weighted average decline exponent which is a function of pore volume, productivity index, and total compressibility. Therefore if a curve is fit, pore volume can be inferred. For water drive reservoirs, aquifer size can be calculated if oil pore volume is known, and similarly oil pore volume can be solved if total reservoir volume is known.

Synthetic data sets have been used to confirm the equation produces correct results. Several fields have been analyzed and a good relationship is shown between the F-Φ curve match and core data or tracer data depending on the application.
Direct Observation of the Impact of Nanopore Confinement on Petroleum Gas Condensation
Authors: Parsa E. , Yin X. , Ozkan E.
Published: September 2015

Condensation of petroleum retrograde gas and especially that around a wellbore can decrease the deliverability of the well significantly. Better estimation of the point of phase transition is the key for reservoir engineers to devise management strategies to reduce condensate dropout and improve production and ultimate recovery. It has been established theoretically that the point of phase transition obtained from bulk PVT experiments does not represent the phase behavior of hydrocarbon fluids confined in nano-pores. However, very few experimental data are available. In this study, we measured the impact of nano-confinement on the phase behavior of propane using nano-fluidic devices. Direct observations of phase changes show that nano-confinement led to reductions in the vapor pressure that are consistent with the theory of capillary condensation. The shifts in the vapor pressure, however, were not always in good agreement with the Kelvin equation.
Modeling of Low-Tension Surfactant-Gas Flooding Process in a Four-Phase Flow Simulator
Authors: Lashgari Hamid R. , Sepehrnoori Kamy , Delshad Mojdeh
Published: September 2015

This paper presents modeling of a novel tertiary enhanced oil recovery (EOR) method. In this process, slugs of gas and surfactant solution are injected (coinjection or alternate injection) to mobilize and then displace the residual oil saturation. The objective of this paper is to model the mechanisms behind the process through history matching the experimental data and simulation of a field-scale reservoir pilot. A four-phase chemical flooding reservoir simulator (UTCHEM) was used to history match a recently published coreflooding experiment and simulate the field-scale reservoir. The results from the history matching and reservoir simulation revealed that interfacial tension (IFT) reduction between oil and water by the surfactant, displacement of oil by gas, and mobility control of gas are believed to be the main contributors to increase oil production. Based on these key findings, modeling of low-tension surfactant-gas flooding achieves a recovery of 91% of initial oil (Sio=0.56) in laboratory coreflood and a wide range of recovery factors between 65–88% of residual oil trapped by water in the numerical models in reservoir scale.
Numerical Study of Production Mechanisms and Gas-Oil Ratio Behavior of Liquid-Rich Shale Oil Reservoirs
Authors: Khoshghadam M. , Khanal A. , Lee W. J.
Published: September 2015

This paper summarizes our investigation of production mechanisms and well production performance in liquid-rich shale (LRS) oil wells and introduces a new methodology for modeling LRS oil well performance. It discusses the impact of nanopore confinement on PVT properties, transport properties, rock compaction, how these phenomena affect produced GOR of LRS oil wells, and how to incorporate these phenomena into reservoir modeling studies.

The proposed methodology has been applied to construct a compositional simulation model using a hydraulic fracture reservoir model with logarithmically-spaced local grid refinement (LS-LGR grids). We incorporated the impact of nanopore confinement on phase behavior by using new correlations for modifying PVT properties in nanopores. The model was divided into three zones, hydraulic fracture, nanopores, and micro pores; each zone had different PVT, rock compaction and relative permeability properties. Production data from several LRS oil wells in the Eagle Ford shale were used for history matching and model calibration.

Our numerical model is able to simulate producing GOR behavior of LRS oil wells accurately. The “flat” GOR's in early stages of production are caused by delayed development of two-phase flow as a result of reduction of the bubble point pressure in nanopores. Enhancement of critical gas saturation delays mobilization of gas molecules in nanopores and could extend non-intuitive GOR behavior further when reservoir pressure drops below the bubble point. We found that the impact of permeability reduction due to compaction on ultimate oil recovery could be more than 20%. The study reveals that the period of constant produced GOR depends on the volatility of the reservoir fluid and on the pore size distribution in the reservoir. For moderate-GOR oil reservoirs, the constant GOR duration is greater than for highly volatile oil reservoirs.

Several unique phenomena in LRS oil reservoirs were explored in this study. As a result, we were able to introduce new correlations for modifying bulk PVT properties under confinement. These new correlations and the effects of nanopores can be combined with numerical models to simulate the performance of LRS oil reservoirs and to estimate EUR more accurately.

We concluded that numerical models with PVT model based on fluid bulk properties are not able to accurately simulate unconventional LRS oil reservoir fluid flow. Confinement impact on PVT and rock-fluid property of nanopores play key roles in complex production behavior of these resources. We also concluded that, for numerical models to capture accurately fluid distribution and compositional variability in nano Darcy LRS oil reservoirs, it is necessary to have correct knowledge of pore/pore throat size distributions in the reservoir.
Flowback Fracture Closure: A Key Factor for Estimating Effective Pore-Volume
Authors: Ezulike D. O. , Adefidipe O. A. , Fu Y. , Dehghanpour H. , Virues C. J. , Bearinger D. , Hawkes R. V. , Jones R. Steve
Published: September 2015

The importance of evaluating well productivity after hydraulic fracturing can not be overemphasized. This has necessitated the improvement in the quality of rate and pressure measurements during flowback of multistage fractured wells. Similarly, there has been corresponding improvements in the ability of existing transient models to interpret multiphase flowback data. However, the complexity of these models introduces high uncertainty in the estimates of resulting parameters such as fracture pore-volume, half-length and permeability. This paper proposes a two-phase tank model for reducing parameter uncertainty and estimating fracture pore-volume independent of fracture geometry.

This study starts by using rate-normalized pressure plots to observe changes in fluid flow mechanisms from multistage fractured wells. The fracture “pressure supercharge” observations form the basis for developing the proposed two-phase tank model. This model is a linear relationship between rate normalized pressure and time, useful for interpreting flowback data in wells which show pseudo steady-state behavior (unit slope on log-log rate normalized-pressure plots). The linear relationship is implemented on a simple monte-carlo spreadsheet. This is then used to estimate and conduct uncertainty analysis on effective fracture pore-volume, using probabilistic distributions of average fracture compressibility, and gas/water saturations respectively. Also, the proposed model investigates the contributions of various drive mechanisms during flowback including fracture closure, gas expansion and water depletion.

Application of the proposed tank model to flowback data from fifteen shale gas and tight oil wells estimates the effective fracture pore-volume and initial average gas saturation in the active fracture network. The results show that fracture pore-volume is most sensitive to fracture closure compared to gas expansion and water depletion, making fracture closure the primary drive mechanism during early flowback periods. Also, the initial average gas saturation for all wells is less than twenty percent. The parameters estimated from the proposed model could be used as input guides for more complex studies (such as discrete fracture network modeling and transient flowback simulation). This reduces the number of unknown parameters and uncertainty in output results from complex models.
Advances in Understanding Wettability of Tight Oil Formations
Authors: Habibi Ali , Binazadeh Mojtaba , Dehghanpour Hassan , Bryan Donald , Uswak Gordon
Published: September 2015

This paper presents comprehensive rock-fluid experiments, using reservoir rock and fluids, to investigate wetting affinity of the Montney (MT) tight oil play located in the Western Canadian Sedimentary Basin. Wettability characterization is essential for selecting optimum fracturing and treatment fluids by completion engineers and for selecting appropriate relative permeability and capillary pressure curves by reservoir engineers. Application of the conventional techniques for wettability evaluation of tight rocks is challenging primarily due to their extremely low permeability and complex pore structure. The objective of this paper is to develop an alternative laboratory protocol for evaluating the wettability of tight oil rocks reliably.

First, we conducted systematic spontaneous imbibition tests on fresh core samples from two different wells drilled in the MT formation. We measured air/brine, air/oil, and brine/oil contact angle for all samples. We used the end pieces of the samples to conduct SEM and elemental mapping (EDS) analysis. Finally, we investigated the spontaneous imbibition of brine (or oil) into the samples partly saturated with oil (or brine). Both oil and brine spontaneously imbibe into the fresh samples, composed of quartz, carbonates (dolomite/calcite), clay minerals, feldspars, and organic matter. The results indicate that the effective pore network exhibits a mixed-wet behavior. Moreover, brine spontaneously imbibes into and forces the oil out of the oil-saturated samples, while oil cannot imbibe into the brine-saturated samples. This indicates that in the presence of both oil and brine, the rock affinity to brine is higher than that to oil.
The First Master in Geothermal Engineering Offered by a Petroleum Engineering School: Curriculum Challenges and Opportunities
Authors: Falcone Gioia , Pawellek Claudia , Teodoriu Catalin
Published: September 2015

Renewables are seen as the future source of energy to meet the world’s growing demand, with geothermal resources offering a constant and independent supply. Trained staff will be needed to ensure successful implementation of ever more geothermal energy projects to help lower the dependency on energy imports and to develop a broader base in the future energy mix.

The exploitation of geothermal resources faces many of the technical and commercial challenges that are encountered in oil and gas exploration and production, as well as analogous issues of social acceptance and environmental impact. Hence, it is logical to create more synergy between these two energy sectors and enhance the technology transfer, beginning with university education.

A 2-year Master of Science (MS) in Geothermal Engineering, fully taught in English, has been developed at the Institute of Petroleum Engineering of Clausthal University of Technology (CUT), Germany. It is the first dedicated MS of its kind offered by a Petroleum Engineering school. Following its accreditation, classes began in earnest in October 2014.

A number of courses are offered in common with the MS in Petroleum Engineering at CUT to encourage graduates to acquire the broadest skill set they can, and so improve their global marketability and career prospects. Sharing classes also offers a unique, more balanced view of the global energy panorama.

This paper describes the process of assessing the need for this new MS program and the potential market acceptance of a “geothermal engineer” professional profile. It then discusses the implementation of the lessons learnt from Petroleum Engineering curricula to build a geothermal program focused on the full project cycle, from exploration to production, with the associated challenges and opportunities ahead.

It is hoped that other Petroleum Engineering departments in the world will follow CUT’s lead by expanding their curriculum offerings to include Geothermal Engineering.
Modernizing Petroleum Engineering Education: A New Global Online Petroleum Engineering University Serving all Universities
Authors: Aggour T.. , Donohue T.. , Donohue D. A.
Published: September 2015

This paper presents an initiative to establish an online petroleum engineering educational resource that provides electronic learning to universities to enhance the learning experience of students and address many of the challenges and ambitions of petroleum engineering programs worldwide.

In recent years there has been much discussion of the difficulty in recruiting quality petroleum engineering faculty. A confluence of industry and demographic circumstances has resulted in petroleum engineering programs with very high enrollment levels and excessive student-faculty ratios, leading to a diminished learning experience for students.

The way today's students process information is fundamentally different from previous generations, yet in most cases academia continues to teach them as they always have. Progressive universities are striving to adapt their models to the changing learning styles of their student bodies, while trying to leverage technology as best as possible.

To address these issues, an online resource is being established that will allow students from different universities to access electronic learning that will complement the instructor-led training that currently exists. Electronic learning is well suited to academic learning, where the focus is on fundamental theory and concepts in addition to the basic application of these concepts.

This paper provides details on how this resource has been developed and how it will be implemented. A significant portion of undergraduate petroleum engineering education can be covered by innovative electronic learning, allowing faculty to focus on problem-solving while spending fewer hours in the classroom. By soliciting corporate support from industry to support the centralized resource, individual universities will have cost-effective access to a resource that will enhance the educational process by catering to the learning styles of this generation, alleviate some of the challenges faced due to faculty shortages, and progress petroleum engineering university learning farther into the modern digital era.
Description of the Results of Experiments on Developed Miscibility With Nonequilibrium Gas/Oil Gravity Drainage
Authors: Zobeidi K.. , Fassihi M. R. , Rasaei M. R.
Published: September 2015

This paper describes the results of several experiments that were carried out to investigate the block-to-block interaction in fractured limestone reservoirs for both gas/oil and solvent/oil systems by use of carbonate cores. The focus of this research was to understand gravity drainage, reinfiltration, and mixing in fractured systems with a set of laboratory experiments. The designed setup included three kinds of models (i.e., a transparent rectangular box filled with a glass-bead pack and two cylindrical models with single and stacked carbonate blocks inside to cover all important cases in this area); then, several factors are defined to correlate the results of glass-bead-pack model with the two other kinds of models. Also, the survey of the experiments and the properties of the fluids used takes a relatively wide range of the applicable laboratory experiments to provide a better understanding of the mentioned mechanisms. In general, this paper can be very revealing to other researchers in the field because it provides some experimental data for future theoretical and simulation studies.
Analytical and Experimental Investigations of Gas-Flow Regimes in Shales Considering the Influence of Mean Effective Stress
Authors: Moghadam Alireza A. , Chalaturnyk Rick
Published: September 2015

Flow conditions determine the flow regimes governing gas flow in porous media. Slip-flow regime commonly occurs in laboratory gas-permeability measurements, and one must consider the physics of that when finding the absolute permeability of a sample. Accurate permeability estimates are paramount for production forecasts, financial planning, and recovery estimation. Slip flow is present in low-permeability rocks, both in the laboratory environment and at reservoir conditions. Gas flow through the matrix lies under the slip-flow regime for the majority of low-permeability-reservoir production scenarios, and accurate prediction of pressure and production rate requires a good understanding of the flow regime. In this paper, an analytical study is conducted on the dominant flow regimes under typical shale-gas reservoir conditions. A flow-regime map is produced with respect to gas pressure and matrix permeability. Steady-state gas-permeability experiments are conducted on three shale samples. An analytical model is used to match the experimental results that could explain the order-of-magnitude difference between the permeabilities of gas and liquid in shales. Experimental results are combined with further tests available in the literature to inform a discussion of the model's parameters. The results improve the accuracy of gas-flow modeling and of absolute-permeability estimates from laboratory tests. Similar tests performed at various mean effective stresses investigate the influence of mean effective stress on flow regime and apparent permeability. The results indicate that flow regime is a function of mean effective stress, and that the apparent permeability of shale rocks is a function of both flow regime and mean effective stress.
Simulation and Testing of the Hydraulic Performance of the Sliding Vane Pump
Authors: Zhao Yanlong , Wang Zhiming , Xue Liang , Zhang Lixin , Hao Zhongxian
Published: September 2015

A new all-metal sliding-vane pump (SVP) and matching lift system were developed as an alternative to the low efficiency and poor high-temperature performance of conventional artificial-lift systems. Numerical simulation and laboratory tests were used to conduct a comparative study of the hydraulic performance of the pump. The effects of pump-lifting-pressure difference and rotational speed on pump rate and efficiency were studied. The test results showed that, if the rotation speed is fixed, the pump rate and efficiency will decrease with an increase in required pressure difference. With a constant pressure difference, the flow rate can be controlled by varying the pump speed.

On the basis of computational fluid dynamics (CFD) and finite-element-method (FEM) numerical simulation, a numerical model of the SVP was created. The pressure and fluid-flow distribution in the vane pump were determined under zero pump-pressure-difference condition, which helped realize the working principles of the pump. The simulation results agreed well with the test results, thus validating the reliability of the numerical models in this paper.
The MSE Ratio: The New Diagnostic Tool to Optimize Drilling Performance in Real-Time for Under-Reaming Operations
Authors: Abbott Andrew
Published: September 2015

The Mechanical Specific Energy Ratio (MSER) is a correlation that optimizes drilling performance when used as a real-time trending tool. This paper specifically addresses its use in under-reaming operations of deep water wells. Mechanical Specific Energy is an equation combining multiple drilling parameters to determine overall efficiency, but it does not explicitly identify the location of various inefficiencies. The MSE Ratio solves this problem. Through a simple ratio of the MSE surface values to the MSE downhole values, the locus of inefficiency is more easily identified.

In deepwater operations, the bit or the under-reamer often causes inefficiency, and the MSE Ratio helps to diagnose the trouble area. An increase in the values returned by the MSE Ratio indicates under-reamer inefficiency, while a decrease in the returned values indicates drillbit inefficiency. By pinpointing the zone of the problem, system inefficiencies can be better predicted, avoided, and mitigated. The information contained in this paper outlines the original study that was completed to analyze the MSE Ratio and the conclusions of that study. All data was taken from a deepwater well drilled by Statoil in the Gulf of Mexico (GOM) during the summer months of 2014.

The MSE Ratio can be used to accurately locate areas of inefficiency on the drillstring so performance may be optimized, it was both developed and proven in field trial, and it can be used in both real-time and for post-analysis. Further field studies should be conducted to refine the use of the Mechanical Specific Energy Ratio in drilling operations and to determine other trend-line signatures of the data.
Extension of the Gray Correlation To Inclination Angles
Authors: Oyewole Adeoluwa
Published: September 2015

Proper design of gas wells requires accurate estimation of pressure profile. This task is usually carried out by integrating mechanistic models and correlations along the well trajectory. Gray (1975) correlation is widely used for gas wells where the liquid fraction is usually low. This correlation has been generated by extending the single phase gas equation to the two-phase flow case. The effect of the liquid in the frictional pressure gradient has been considered by a pseudo roughness. Also, a correlation for the holdup was proposed by Gray (1975). Unfortunately, these two correlation did not consider the effect of the deviation angle which became critical with the recent increment of horizontal well drilling. This paper aims to include the deviation angle effect on Gray (1975) correlation. Gas-liquid experimental data from horizontal to vertical has been considered for the calibration. The considered experimental data (Guner, 2012; Alsaadi, 2013) includes pressure drop and liquid holdup for a 3-in ID pipe. The calibration has been carried out through the inclusions of new dimensionless numbers. Comparison between the original and modified Gray correlation are also presented.
New Artificial Lift Design For Sidetracks Operations
Authors: Zaytsev Anton , Kirichenko Anastasia
Published: September 2015

A prolonged period of low oil prices (2014 – present) is known to affect the economies of oil-exporting country as well as the technologies applied in industry. Meanwhile it's becoming more important to use up-to-date highly cost-effective technologies for conventional field development to keep oil production rate fixed. Well stock analysis based on open-source data demonstrates in this paper and represents considerable quantity of idle, or uneconomical, wells in Russian Federation. Thus, they make up about 14% of the total number of production wells. Marginal wells, or wells with low flow rates, are considered to be the most subjected to be ‘uneconomical’.

Sidetracking as a stimulation of marginal well production seems like the most effective method to boost the production rate of mature oil field. But most of artificial-lift technologies aren't cost effective in sidetrack applications for some reasons. Review of up-to-date artificial-lift technologies used for sidetrack application is also presented in this paper.

The author designed new kind of equipment permitting operating inside sidetracks-rodless reciprocating electric submersible hydraulic pump unit. It consists of electric submersible motor, protector, and specially designed both transmission to transform mechanical energy into hydraulic and double-acting hydraulic pump. The key unit elements are reviewed in this paper. So, double-acting hydraulic pump is composed of two hydraulic cylinders (actuator) and two piston pump, connected with each other by valve box where suction and discharge valves are placed. Transmission representing by hydraulic fluid tank, power pump and sleeve valve is to drive hydraulic pump and also provide reciprocating pistons moving. Specially designed equipment meets all the sidetrack operation requirements.
Forecasting Production Performance in Reservoir-Network Coupled Systems with Asphaltene Modeling
Authors: Valbuena Ernesto
Published: September 2015

This manuscript presents the development and implementation of a new integrated reservoir-network compositional simulator for analysis of asphaltene precipitation within tubing and production pipelines. The need for integrated models for flow assurance analysis in assets with high potential of asphaltene precipitation is demonstrated for the following scenarios: i) natural depletion, ii) downhole asphaltene inhibitor injection, and iii) artificial gas-lift system.

Fully-implicit compositional formulation forms the basis for reservoir and network simulators. Implementation of a tightly-coupled solution allows assessing mutual interaction between subsurface and surface components. Compositional delumping from reservoir to network fluid characterizations enables accurate modeling of complex thermodynamic phase behavior for asphaltene precipitation. The Peng-Robinson equation of state with volume translation models phase equilibria in coupled solution and asphaltene precipitation in network pipelines. Asphaltene accretion to internal pipe walls is estimated with a mechanistic transport model to forecast reduction of flow area and its impact on production performance.

Solid precipitation and deposition in the production system have a negative impact on production rates, pressure management, and field operations. Results show increased thickness of asphaltene deposits in time, reaching up to 50% diameter reduction after a few months of production for the cases evaluated. Pipeline diameter increase at wellhead promoted asphaltene formation, caused by fluid velocity reduction. Bottomhole injection of asphaltene inhibitor reduced formation of solid deposits by 90%. Artificial gas-lift systems influence deposition profiles due to fluid compositional changes and velocity in the wellbore column.
Field Development Planning - A Key Towards Success in Rich Gas Condensate Reservoirs
Authors: Shoaib Muhammad
Published: September 2015

Phase behavior of a highly rich gas condensate reservoir, especially near critical one, is very difficult to predict. Presence of compositional gradient in these reservoirs further adds to the complexity. In these circumstances, it is very important that precise and detailed field development planning should be done in early phase of reservoir life (preferably before starting commercial production).

A compositional simulation model of rich gas-condensate reservoir is built and a representative fluid model based on Equation of State (EOS) is used for predicting phase behavior of a hydrocarbon reservoir which is a dynamic event. For pressure maintenance feasibility, comparison was performed between no gas injection, partial pressure maintenance and full pressure maintenance. Different sensitivities were performed to come up with an optimum case on the basis of NPV and IRR value from detailed economic analysis. To check for the presence of compositional gradient, compositional data was analyzed for different wells at different depths (at least two required). After establishing compositional gradient, different sensitivities were performed regarding location of wells to maximize recovery and improve economics.

Without pressure maintenance, high gas-oil ratio is produced from reservoir due to loss of valuable condensate in near wellbore region along with reduced gas recoveries. If compositional gradient is not recognized in rich gas-condensate reservoir and wells are drilled at shallow depths avoiding rich gas or oil rim at larger depths then it will ultimately lead to reduced oil recoveries.

On the basis of simulation results and economics, it is recommended to perform pressure maintenance to avoid dropout of heavier ends in reservoir especially in case of rich gas condensate reservoir. Along with that, it is better to produce from deeper wells in presence of compositional gradient and use shallow wells for dry gas injection (pressure maintenance).
Adsorption kinetics and thermodynamics of acid Bordeaux B from aqueous solution by graphene oxide/PAMAMs
Authors: Zhang Fan , He Shengfu , Zhang Chen , Peng Zhiyuan
Published: September 2015

Graphene oxide/polyamidoamines dendrimers (GO/PAMAMs) composites were synthesized via modifying GO with 2.0 G PAMAM. The adsorption behavior of the GO/PAMAMs for acid Bordeaux B (ABB) was studied and the effects of media pH, adsorption time and initial ABB concentration on adsorption capacity of the adsorbent were investigated. The optimum pH value of the adsorption of ABB onto GO/PAMAMs was 2.5. The maximum adsorption capacity increased from 325.78 to 520.83 mg/g with the increase in temperature from 298 to 328 K. The equilibrium data followed the Langmuir isotherm model better than the Freundlich model. The kinetic study illustrated that the adsorption of ABB onto GO/PAMAMs fit the pseudo-second-order model. The thermodynamic parameters indicated that the adsorption process was physisorption, and also an endothermic and spontaneous process.
Competitive removal of Cu–EDTA and Ni–EDTA via microwave-enhanced Fenton oxidation with hydroxide precipitation
Authors: Lin Qintie , Pan Hanping , Yao Kun , Pan Yonggang , Long Wei
Published: September 2015

Ethylenediaminetetraacetic acid (EDTA) can form very stable complexes with heavy metal ions, greatly inhibiting conventional metal-removal technologies used in water treatment. Both the oxidation of EDTA and the reduction of metal ions in metal–EDTA systems via the microwave-enhanced Fenton reaction followed by hydroxide precipitation were investigated. The Cu(II)–Ni(II)–EDTA, Cu(II)–EDTA and Ni(II)–EDTA exhibited widely different decomplexation efficiencies under equivalent conditions. When the reaction reached equilibrium, the chemical oxygen demand was reduced by a microwave-enhanced Fenton reaction in different systems and the reduction order from high to low was Cu(II)–Ni(II)–EDTA ≈ Cu(II)–EDTA > Ni(II)–EDTA. The removal efficiencies of both Cu2+ and Ni2+ in Cu–Ni–EDTA wastewaters were much higher than those in a single heavy metal system. The degradation efficiency of EDTA in Cu–Ni–EDTA was lower than that in a single metal system. In the Cu–Ni–EDTA system, the microwave thermal degradation and the Fenton-like reaction created by Cu catalyzed H2O2 altered the EDTA degradation pathway and increased the pH of the wastewater system, conversely inhibiting residual EDTA degradation.
Differences in the removal mechanisms of Undaria pinnatifida and Phragmites australis as biomaterials for lead removal
Authors: Soto-Rios Paula Cecilia , Nakano Kazunori , Leon-Romero Marco , Aikawa Yoshio , Arai Shigeyuki , Nishimura Osamu
Published: September 2015

This study offers the opportunity to utilize Undaria pinnatifida and Phragmites australis to remove lead from water in permeable reactive barrier (PRB) technology. Its efficacy was tested using batch experiments and PRB column systems. From the batch experiment results, a higher adsorption capacity was observed for Undaria pinnatifida. Nevertheless, Phragmites australis in the column system efficiently removed lead and the breakthrough occurred at the same time for both biomaterials. To dissipate this difference, a sequential extraction for metal speciation analysis was used for both columns. The results have shown that each biomaterial has a dominant mechanism. Phragmites australis removed lead by physical adsorption, whereas Undaria pinnatifida showed a higher tendency to bind lead due to organic matter, primary and secondary minerals.