bluuebunny/crossref_metadata_2025 huggingface dataset:
Viscosity Modelling of Pyrenees Crude Oil Emulsions
Authors: Tjoeng A. Y. , Loro R.
Published: October 2016

The formation of oil-water emulsions presents a major challenge for the petroleum industry. Emulsions in wells and flowlines cause higher viscosities and lead to larger pressure drops, reducing production performance.

The empirical modelling of emulsion viscosity as a function of water cut is presented. Measurement techniques for emulsion viscosity in a laboratory are explored and their use in a multiphase flow simulator to predict well and flowline pressure drops is explained. The reverse of this methodology can also be used with field data to back calculate the ostensible emulsion viscosity curve.

Using the BHP Billiton operated Pyrenees oil development as a case study, this paper contrasts the laboratory derived and reverse engineered viscosity curves generated across a number of wells that have produced to the point of natural emulsion inversion. A possible mechanism for the differences between the two is proposed.

In the latter part of 2014, a campaign of downhole demulsifier dosing across the Pyrenees fields was intiated with considerable success. The impact of this chemical injection on emulsion viscosity modelling is also explored in detail.
What Conventional E&PD Companies Should Learn from Unconventional Operators
Authors: Ahmad Aladasani , Qutaiba Okasha , Ali Ameen
Published: October 2016

In any economic environment the success of a business is based on the growth of its profits. In that context, today oil and gas E&PD (Exploration and Production Development) companies are challenged with about two thirds decline in revenue and disproportionate operating costs. The situation becomes direr for NOCs (National Oil Companies) where revenue must be compensated to balance the State's budget. Similarly, IOCs and other operators are challenged by taxes, royalties and/or concession agreements with unfavorable return on investment at low oil price regimes. As such there is an inclination to augment hydrocarbon production rates albeit at disproportionate operating costs. Therefore, a need exists to significantly improve business performance.

The objective of this paper is to present an overview of what contributes to an effective business model for oil and gas E&PD companies aimed at reducing operating expenses in addition to augmenting and optimizing revenue. Key strategic programs are discussed such as policy, organization, field development plans, workforce, and contracting philosophy.

The conclusions indicate that typical E&PD planning systems should be fluid in par with the performance of development plans and sensitivity to profitability margins. Observations in this paper capture opportunities to exploit organization capabilities, effectively focus capital investment, and evaluate benefit of acquiring support services versus spinoff in addition to establishing criteria for retaining and selecting specialized services and adopting successful contracting strategies.
The Influence of Gas-Wetting Nanofluid on the Liquid-Blocking Effect of Condensate Reservoir
Authors: Jin Jiafeng , Wang Yanling , Wang Lushan , Zhang Xing , Ren Jinheng
Published: October 2016

Gas condensate reservoirs often experience a sharp reduction in gas deliverability when the wellbore pressure drops under its dew point, this is known as liquid-blocking effect in gas condensate reservoir. Many solutions with limited effectiveness were proposed to figure out the problem, and wettablity alteration is proven to be one of effective measures for liquid-blocking effect. Recent investigations show that the wettability of core near wellbore region can be permanently altered from water-wet or oil-wet to intermediate gas-wetting with the fluorosurfactant treatment, and the mobility and distribution of fluids in porous media can also be significantly improved after gas-wetting alteration. The objective of this study was to find out the effect of gas-wetting alteration by fluorosurfactant modified nano-silica on the gas recovery in methane-liquid-rock system.

The fluorochemicals are widely used to change the surface properties of solid to achieve a surface with a low surface free energy. In this study, gas-wetting alteration on solid surface is achieved with fluorosurfactant and fluoropolymer. In order to obtain a super gas-wetting, nano-silica particles with a size of 40 nm was functionally modified by fluorosurfactant. Contact angle measurement, Owens two-liquid method, and capillary rise in methane-liquid-core system were conducted to evaluate the effect of gas-wetting alternation on the cores wettability and gas recovery.

Data of Contact angle measurement showed that the core wettability can be altered to gas-wetting or super gas-wetting after FG40, FP-2 and FG40 modified nano-silica solution treatment, the contact angles of brine and decane on core surface increased from 23° and 0° to 152° and 127° after treated by 0.5% FG40 modified nano-silica solution, respectively. The surface free energy of cores before and after treatment shows that the sueface free energy decreased from 70 mN/m to approximately 0.61 mN/m. The results of capillary rise and imbibition test verified that of the contact angle measurement and surface free energy, the liquid levels of brine and decane significantly decreased to -20 and 7 mm when the wettability of capillary atered to gas-wetting. Analysis of SEM and TEM indicated that the gas-wetting nano-silica can form a gas-wetting adsorption layer with coarse structures on core surface, which play a vital role in super gas-wetting.

In summary, the cores wettability can be altered from liquid-wetting to super gas-wetting by the novel fluorosurfactant modified nano-silica, and gas deliverability can be significantly improved due to super gas-wetting alteration.
Usability of Geopolymers for Oil Well Cementing Applications: Reaction Mechanisms, Pumpability, and Properties
Authors: Khalifeh Mahmoud , Hodne Helge , Saasen Arild , Integrity Obara , Eduok Ekom I.
Published: October 2016

Portland cement has become the prime material used for zonal isolation; sealing annuli between casings, between casing and formation and finally for plug and abandonment (P&A) operations. However, there are concerns regarding Portland cement such as autogenous shrinkage, high permeability after cracks has occurred, gas influx during waiting on cement (WOC) time, instability at high temperature, ductility and durability. Geopolymers have been suggested as an alternative to Portland cement for oil well applications. Geopolymers are inorganic aluminosilicate cementitious materials condensed as result of a complex reaction known as geopolymerization.

The current work presents the usability of a geopolymeric material specially designed for oil well cementing applications, known as aplite rock-based geopolymer. The chemical reaction of the geopolymeric slurries was determined using calorimetry measurements. The rheological behavior of the geopolymers, such as consistometer consistency and viscosity were examined besides their mechanical properties. The investigation of mechanical properties included uniaxial compressive strength, sonic strength and tensile strength. The pumpability and setting time have been studied by changing mix design of the geopolymeric slurries along with the addition of selected retarders. Finally, microstructure of the cured geopolymers was studied using Scanning Electron Microscopy (SEM).

The results show that slurries have a non-Newtonian behavior like a Bingham material with a small yield stress. The curing pressure reduced the pumpability of the geopolymeric slurries; however, the reason remained unclear. Addition of sucrose by 1.2 wt.% of the total solid content resulted in an optimal accumulative heat release, which showed the highest strength development. Pumpability of the mixes was prolonged by introducing sucrose to the geopolymeric slurries. Tensile strength of the geopolymers was found to be approximately 5 percent of their compressive strengths.
A New Method to Determine Friction Factor of Cuttings Slip Velocity Calculation in Vertical Wells Using Neural Networks
Authors: Kamyab M. , Dawson R. , Farmanbar P.
Published: October 2016

The slip velocity of cuttings is a calculation of the settlement velocity of a particle in a stagnant fluid. In dynamics, the slip velocity is defined as the difference between the solid and the fluid velocities. If the cuttings velocities are low, the cuttings may not be transported efficiently to the surface, causing a variety of inefficiency issues. For example, they may accumulate at the bottom of the wellbore and get regrinded by the bit. Determination of the correct value of this parameter in vertical wells has been the concern of many investigations in the oil and gas industry.

API RP 13D (2010) standard uses Walker and Mayes' study (1975) to calculate the slip velocity for vertical wells but as discussed below, this model does not show accurate results compared to other models. Moore's model (1974) provides better slip velocity calculation compared to Walker and Mayes' model. These methods are based on providing three sets of equations for laminar, transition, and turbulent to correlate Reynolds number to friction factor for an average value of sphericity for the drilling cuttings.

This paper describes a new method to determine the cuttings slip velocity in vertical wells using neural networks. Artificial neural networks have been successfully implemented in many disciplines in the oil and gas industry. The interconnected network between the neurons provides a nonlinear approximation of the data to solve complex models. The "Reynolds number vs. friction factor" data at different particles' sphericity graphs has been used to determine the friction factor and then apply it to the Stokes slip velocity equation.

Moore's model does not consider the sphericity of the particles because it uses a generic value for this figure, however, the new technique covers a wider range of the sphericity of particles from 0.125 to 1.0. In addition, this model gives higher accuracy compared to the afformentioned models.
World's First Optical Venturi Flowmeter
Authors: Ünalmis Ö. Haldun , Raul Vishal V.
Published: October 2016

A new downhole optical Venturi flowmeter (OVFM) was developed that makes use of world's first optical differential pressure sensor (ODPS) and an optical pressure/temperature gauge. The use of Venturi flowmeters for downhole applications is not common because of the short life span of the associated electronics in the challenging downhole environment. The OVFM may therefore represent a more reliable solution for downhole applications when compared to its electronic versions.

The heart of the OVFM, the ODPS sensor, was developed between 2007 and 2014 as a part of a downhole multiphase flowmeter program that required differential pressure (ΔP) measurements. The ODPS measures the true ΔP with low uncertainty and is, therefore, superior to using two independent static pressure sensors with higher measurement uncertainties at the high pressures in a typical downhole environment. The performance of the OVFM was recently demonstrated in a multiphase flow loop test as a by-product of the aforementioned multiphase test program. The 100-bar test pressure represented a realistic downhole condition and the data from the single-phase test points and from one-phase dominant two-phase test points (i.e., liquid-rich/gas, gas-rich/liquid, and wet-gas flows) were analyzed to evaluate the performance of the OVFM with the ODPS sensor. In the process, modeling equations for Venturi discharge coefficient were also developed based on the multiphase flow data.

The results showed that the OVFM is in excellent agreement with the reference flow rates for single-phase, wet-gas, gas-rich/liquid, and liquid-rich/gas flows. By dynamically adjusting the density and viscosity of the fluid at the measured pressure and temperature (P and T) for the single-phase and one-phase dominant flows, and by using the ΔP measurements from the ODPS, the total-flow rates were successfully calculated. Because the ΔP measurement across the Venturi tube is fundamentally a static measurement, the OVFM is orientation-free and can be installed in any angle. Furthermore, this type of measurement is equally applicable to turbulent and laminar flows and, as a result, is a viable candidate for nonturbulent heavy oil applications. This paper provides a detailed discussion of performance results of the OVFM from the multiphase flow loop tests.

The OVFM represents a novel technology because the ODPS sensor is the first and only optical ΔP sensor for downhole applications. The optical nature of the sensor prevents any significant drift in the signal, and its true ΔP measurement capability provides increased accuracy in the flow measurement.
Transient Temperature Effect on Well Test Interpretation of HPHT Gas Wells
Authors: Wei Pang , Hanxiu Peng , Zuqing He , Qian Hou
Published: October 2016

Yuanba Gas Field is one of the most difficult fields categorized as super-deep and HPHT reservoirs to develop in China. It’s buried in vertical depth (TVD) of more than 6700 m, and with pressure up to nearly 70MPa while temperature above 150oC, meanwhile, the average concentration of hydrogen sulfide and carbon dioxide are 5.14% and 7.5%. Well testing interpretations are hard for wells in this field because of phase segregation, and temperature effect on sour gas PVT especially if the wells are wellhead shut-in.

In this paper, the first horizontal well in Yuanba gas field is reviewed. The backflow pressure test and pressure buildup test were conducted in order to quantify the wells’ AOF and optimized daily rate. The test lasts for one week and one AOF of more than 6 million cubic meters is interpreted. However, severe temperature effect in wellbore is induced because the well is wellhead shut-in and the pressure & temperature gauge are located in wellhead. The testing was conducted in late autumn and the atmosphere temperature difference is as large as 20°C between day and night which caused severe pressure dilation. One well test interpretation model is built by taking atmosphere temperature dependent pressure dilation into consideration.

Results show that both the log-log plot of pressure & pressure derivative and the history match plot have good agreement with measured data after that the models convert the wellhead pressure into downhole pressure and implementing the ability of considering the pressure dilation caused by transient temperature. Without considering the temperature effect for super-deep wells, the wellhead pressure recording cannot truly converted into downhole pressure, which can not reflect the formation information and interpretation results are not believable. Using the new method, the weird well testing data for well-head shut-in wells can be interpreted.

The research is helpful for super-deep HPHT sour gas wells for wells and formation appraisal especially when the pressure and temperature gauge cannot be installed down into target layer. It can also be used to compare the commercial software models used for downhole pressure data.
Damage Appraisal of Massive Hydraulic Fracture Stimulation in Unconventional Oil and Gas Reservoirs
Authors: Bo Cai , Guoqiang Bi , jiangwen Xu , Chunming He , yuebin Gao , jin Chen , ning Cheng , jia wang
Published: October 2016

Over the past decade, multi-stage fractured horizontal wells have been widely applied to develop tight oil and gas reservoirs. Therefore, it has become a standard practice to pump more and more numbers of treatment proppants and fluids with higher and higher pumping rate during hydraulic fracturing treatment in China, but things always did not get the expected results, field test application has displayed that not all wells production have positive correlation with increasingly treatment scales but rather lead to high costs. To investigate this problem, we established a new fracture face damage skin (FFDS) mathematical model based on the classical model of Perkins-Kern-Nordgren(PKN) and Khristianovic-Geertsma-Daneshy(KGD) using fracture mechanics and fluid coupling method. Furthormore, a new evaluation experiment by computed tomography (CT) scanning and rock mechanics and some key factors were revealed. Compared with original model the influence of FFDS on productivity was increase from 5% to 51% using new model when the permeability is 0.1mD. The results indicated the lower of permeability and the greater of impact for a specific low permeability reservoir. A case study was put forward with four different volume of proppants and fluids while different pumping ratel located in the same stratum with a same pay thickness in X tight oil reservoir. The reason was studied that some large-scale fractured well not produce that expected much oil and some small-scale fractured wells even perform better than massive treated ones owing to the fracture face damage skin. What's more, a comprehensive low FFDS treatment was put forward as following: Firstly, utilizing the low damage fracturing fluids such as slick water, low concentration and low molecular weight fluid, etc.; Secondly, optimizing the viscosity value of fracturing fluid with corresponding pumping rate for a certain permeability reservoir;Thirdly, optimizing combination between fracturing fluid and proppant types according new mathematical model; Fourthly, using such as acid-fracturing to minimize fracture face damage skin for an optimized fracture profile.

These new observations have significant implications for field development stratedies and hydraulic fracturing design. More than 45 wells have been put into field application using new technology. The performance of post-fracturing is remarkable and it has a great significance in unconventional oil and gas development in China.
Robust Chemical EOR Modelling from Coreflood to Full Field Scale in a Brown Field, Offshore
Authors: Ghadami Nader , Zakaria Nur Atiqah , Manap Arif Azhan , Wahid M Izad
Published: October 2016

Chemical flooding is one of the challenging EOR methods to improve the oil recovery. The objective of this work is to examine a systematic approach for upscaling Alkaline Surfactant Polymer (ASP) coreflood data to field scale and design the single well chemical tracer (SWCT) test. Appropriate upscaling can help to determine the effect of crucial parameters on process mechanisms and oil recovery. Besides, uncertainty assessment should be conducted thoroughly to evaluate the impact of key parameters.

In this paper, a robust approach for modeling the ASP flood from core to reservoir scale including the data uncertainty would be presented. Experimental work was aimed to screen and select the suitable chemicals for implementation in the field. Coreflood tests include ASP flood with and without polymer chase with the objective to evaluate the effectiveness of chemical flood and sweep efficiency. Sensitivity analysis by response surface methodology (RSM) would help to find the crucial parameters during the history matching of coreflood tests and reservoir modeling for ASP implementation.

Coreflood modeling was performed to represent the flow behavior of lab tests and investigate the mechanisms through the experimental efforts. Assisted history matching of the coreflood test was carried out to incorporate waterflood and chemical flood processes. Some variables such as relative permeability characteristics, trapping number, adsorption, and residual resistance factor were included as matching parameters. The next step was to upscale the model from core scale to reservoir scale by an appropriate method. Velocity and pressure were preserved during the scaling procedure. The parameters obtained from scaling exercise were used for SWCT design and full field model. Thus, radial models were used to describe and improve the design of SWCT tests for candidate wells. The next step was to evaluate the ASP flood on reservoir model. Sensitivity analysis was conducted on key parameters e.g. adsorption, injector-producer spacing, residual oil reduction by chemical, and ASP slug size to identify the impact of these parameters on oil recovery. RSM was applied to develop a suitable proxy model based on the results of sensitivity study. The proxy model can be used to find the optimum well spacing and slug size for field implementation.

Appropriate technique of chemical flood modeling is presented in this work. Moreover, upscaling of lab data to reservoir scale for pilot design and evaluation of ASP flood on reservoir scale by considering how to address risks and uncertainties are other outcomes of this work.
Subsea Multiphase Flowmeter: Performance Tests in Multiphase Flow Loop
Authors: Ünalmis Ö. Haldun , Raul Vishal V. , Ramakrishnan Vijay
Published: October 2016

Performance of a new three-phase (3-P) flow measurement system is presented using multiphase flow loop data. The system consists of two currently available products: an optics-based flowmeter and a near-infrared (NIR) water-cut meter. The measurement capability and performance of a combined system comprising two robust and field-proven technologies under realistic flow conditions is demonstrated for the first time. The new 3-P flow measurement system represents a viable alternative for subsea multiphase flow measurement and can also be used on offshore platforms, onshore as well as downhole, in single-zone or multizone applications.

The flowmeter system relies on three main measurements: bulk velocity and sound speed measured by the optics-based flowmeter, and water-cut measured by the water-cut meter. The velocity measurement is a robust measurement based on turbulent flow and is not affected by upstream flow conditions. The water-cut measurement is based on NIR absorption of water and oil molecules, and therefore, is immune to water salinity and the presence of gas (such as free gas, gas in solution, and oil foaming). Total flow rate is calculated using the bulk velocity measurement; liquid holdup and density of the mixture are obtained by introducing the mixture sound speed and the water-cut measurements into a flow model.

The results of the multiphase flow loop test demonstrated that the new flow measurement system is capable of resolving total volumetric flow rates as well as phase volumetric flow rates in a broad gas-volume-fraction (GVF) band. Furthermore, mixture density can be successfully calculated from the flow model and, as a result, the mass flow rates can also be determined. The test data also confirm that the water-cut measurement is not affected by foaming issues and associated density variations. The test results are discussed in detail in the paper.

The new flow measurement system offers several advantages. The flowmeter can be installed in any orientation and does not require recalibration. Its nonintrusive and fullbore features mean no permanent pressure loss, and high resilience to erosion and corrosion. The nonnuclear water-cut meter measures water cut in the broad GVF spectrum and is not affected by challenging flow conditions, such as slug flow. Installed inside a wellbore, an optics-based flowmeter can provide reliable flow measurement for the life of that well with no significant drift in signal.
Application of Liquid CO2 Fracturing in Tight Oil Reservoir
Authors: Wang Feng , Wang Yucai , Zhu Yongzhi , Duan Yongwei , Chen Shi , Wang Cuicui , Zhao Wei
Published: October 2016

The low control reserve of a single well and the difficult on energy supplement in the reservoir are two key problems in tight oil reservoir development. It is testified that non-liquid CO2 fracturing not only efficiently increases the reservoir energy but also intensifies the reservoir transformation through the field test in Jinlin oil field.

The transformation volume of non-liquid CO2 fracturing is confirmed, through micro-seismic data monitor in the borehole during fracturing, that it is 2.5 times of that of normal hydraulic fracturing with the same liquid volume usage, which can remarkably increase the complexity of the fracture. Through the laboratory experiments and the oil sampling analysis after fracturing, CO2 is verified that it can reduce the oil viscosity efficiently, therefore, it can make oil miscible and enhance the flooding efficiency by non-liquid fracturing implementation. The results of reservoir static pressure test after fracturing prove that reservoir pressure remarkably increases compared with that before fracturing and has the effects of advanced energy storage.

Five tight oil wells fracturing have been successful in Jilin oil field until now. Oil production after fracturing increases obviously compared with that before fracturing. The average oil production increase per well is 2.31 ton. According to the research, the stimulation effects of non-liquid CO2 fracturing are seriously underestimated and there is wide prospect in the application of the technique during the tight oil reservoir development.
Experimental And Discrete Particle Modelling Of Solid Particle Transportation And Deposition In Pipelines
Authors: Wong C. Y. , Boulanger J. , Feng Y. , Wu B.
Published: October 2016

Transport of solid particles in oil and gas pipelines is a common occurrence in the oil-gas industry. Solid particle transport occurs at various phases of an oil-gas development project: transport of drill cuttings during exploration and completion, and transport of sand particle during production. Current research and development in this space focusses on the physical and numerical modelling of the phenomenon. The concentration of sand within a pipeline will determine the type of modelling required. The literature provides a suite of empirical models to study flows with sand concentration greater than 1% by volume, especially during wet drilling operations. Although suspended sand concentration in production pipelines is nominally much less than 1% when adequate sand control is deployed downhole, there are flow velocities below which result in sand deposition, accumulation and blockage in a pipeline. There are presently limited models to simulate sand transport and deposition in the dilute sand concentration regime as it applies to the production phase. This paper will present some preliminary results using Discrete Particle Modelling to predict the transport and deposition characteristics of low concentration solid particles flowing in a liquid medium. Simulations are also supplemented by physical experiments conducted in a 2″ pipeline systems with water as the carrier fluid.
Regaining Oil Production by Overcoming Emulsion Problems After Artificial Lift Installation
Authors: Uetani Takaaki , Furuichi Naoto , Yorozu Hirokazu , Sasaya Kazuyo , Shibuya Takehiro , Kiminami Narihito , Yonebayashi Hideharu
Published: October 2016

An oil well, referred to in this paper as Well B, experienced a serious emulsion problem soon after the introduction of artificial lift using a hydraulic jet pump. This forced the operator to reduce the production rate to meet sales oil specifications. During its natural flow production period, this well experienced relatively emulsion-free operation. Consequently, the operator continued to use the same demulsifier, after the jet pump production began.

This paper presents results of a number of field trials that took place over 1.5-year period to control emulsions and to improve oil production. Initially, the operator raised the separator temperature but this was not effective. Next, the operator injected xylene into the formation. Although this was reasonably successful, the effect was short-term. It became necessary to open the separator dump valve to drain the emulsions, and reduce the basic sediment and water (BS&W). This expensive operation was only undertaken to maintain production. The operator then explored changing the demulsifier dosage rate and changing the location of the demulsifier injection port, but neither measure was effective. Finally, a series of bottle tests were conducted to find a better demulsifier to replace the original chemical, which was no longer effective. Soon after injection of the new demulsifier, the emulsions disappeared, and the operator regained the production rate.

Based on the field observations and the preliminary laboratory investigations, the emulsions that affected Well B over a period of 1.5 years were most likely caused by the introduction of artificial lift augmented by the continued used of the original demulsifier chemical, the increased production rate, and the presence of asphaltene and clay particles. An important lesson learned from this project was that emulsion treatment programs should be reviewed periodically, especially when operating conditions change.
Integration of Wireline Formation Tester Pressures with Advanced Formation Evaluation and Image Logs in Fractured Marine Slope Carbonates
Authors: Roche Jeff , Harfoushian Jack , Datey Ashish , Lewis Dale , Advent Francis
Published: October 2016

Fractured slope to deepwater carbonates in Papua New Guinea present significant challenges from the perspective of calculating hydrocarbons in place and assessing reservoir productivity. Given the heterogeneous nature of the carbonates, significant difficulties arise when attempting to determine productive intervals using only petrophysical evaluations and borehole image logs. This paper discusses how productive intervals are identified by integrating mobility from formation pressure testers.

To determine the role exerted by diagenetic processes (mainly cementation and compaction) on the fluid storage and migration pathways within the slope to deepwater carbonates, permeability structures had to be appraised. Over the past several decades, wireline formation testers have proved to be an efficient method of assessing mobility and inferred productivity, in addition to gathering representative fluid samples for accurate pressure, volume, and temperature (PVT) analysis. Recent advancements have further improved the efficiency of wireline testers in such environments by combining the benefits of straddle packer systems with enhanced probes.

In this paper, in-depth analysis is presented on the integration of a comprehensive pressure and productivity data set acquired using the latest-generation wireline tools with advanced formation evaluation and image logs. The revolutionary advances provided by a new multifrequency dielectric tool were also used to provide an Archie mn exponent log from continuous in-situ measurement of rock texture.
Permeability Limits of Advanced Water Injection Technology in Low Permeability Reservoirs
Authors: Wang Shuai , Tian Ji , Tan Xianhong , Wang Ling , Zhang Shaohui
Published: October 2016

The low permeability reservoir development effects can be effectively improved with the use of advanced water injection technology, which means the water is injected several months before the oil production. Advanced water injection can improve the formation pressure in advance, and establish an effective displacement system. However, with the increase of reservoir permeability, the increasing value of recovery tends to decline in advanced water injection. Therefore, it is necessary to study the permeability limits of advanced water injection.

In this paper, the laboratory experiments of the low permeability natural core from A oilfield were carried out, and the changes of core permeability, pore structure and oil displacement efficiency in advanced water injection were analyzed. Meanwhile, the changes of sweep efficiency and recovery in advanced water injection were figured out with numerical simulation method, and the effect of advanced water injection tested in A oilfield was analyzed.

The results of the laboratory experiments showed that, for the cores of permeability less than 10.0 mD, as the core pressure drops from 19.0 MPa to 17.0 MPa, the permeability declines by 15.0 percentage points. When the pressure is restored, the degree of permeability recovery is 2.0 percentage points. Also, with the pressure increase, the oil displacement efficiency of the core permeability less than 10.0 mD increase 1.2 percentage points, while the oil displacement efficiency of the core permeability above 10.0 mD increase only 0.3 percentage points. The results of numerical simulation showed that, with the use of advanced water injection in the formation of permeability less than 10.0 mD, the sweep efficiency increases by more than 5.0 percentage points and the ultimate recovery increases by more than 0.4 percentage points.

In addition, the effect of advanced water injection tested in A oilfield was much better than that of the conventional water injection oilfield. The daily single well oil production was 1.6 multiple higher than that of the conventional water injection oilfield, and the annual decline rate was 13.0 percentage points lower than that of the conventional water injection oilfield.

Taken together, the permeability limits of advanced water injection is 10.0 mD, and better development effect and higher recovery can be obtained with advanced water injection technology for reservoirs of permeability less than this value.

This paper can provide a reservoir screening criteria for the advanced water injection technology and can guide the further application of this technology in low permeability reservoirs.
Upscaling Technique for High Resolution Coal Bed Methane Reservoir Model
Authors: Sugiarto I. , Mazumder S. , Gan T.
Published: October 2016

Upscaling of a reservoir model is normally conducted when a high resolution model has been generated and it is practically impossible to run the simulation using a high resolution model. Reservoir model upscaling is done in order to have a reasonably coarse model for reservoir history matching and forecasting purposes without losing some of heterogeneity in the reservoir model. A high resolution static coal reservoir model (around 0.1 metre thickness) is generated based on the detailed single coal ply correlation in order to capture complexity and heterogeneity of the coal sediment. A case study is presented in this paper.

Several upscaling methods for reservoir properties such as permeability and gas content were tested and analyzed. The upgridding process on the geocellular model mainly focused on vertical direction in order to identify which ply could be merged into the sub layer level. The next step identifies whether the ply can be merged with neighboring ply individually. The results of the upscaling and upgridding are analyzed using the combination of recovery ratio, simulation running time ratio and cell count ratio plot. Histogram and area map analysis is also used to evaluate the result of the upscaling work.

The expected results of the upscaled model are lower running time, lower cell count and very close recovery value to the high resolution model, while still capturing the heterogeneity. The results of the upscaling exercise for this case are reduction of running time by 72%, reduction of the cell count by 64% and recovery difference of 3%. Some of the plies in one of the layers cannot be merged into a sub layer level which indicates a high degree of heterogeneity. This upscaling technique for the coal reservoir model provides more information about the reservoir characterization methodology for unconventional reservoirs, and coal bed methane reservoirs specifically.
Characterising the Behaviour of Hydraulic Fracturing Fluids via Direct Numerical Simulation
Authors: Leonardi Christopher R. , Regulski Wojciech , McCullough Jon W. , Wang Duo , Mitchell Travis R. , Jones Bruce D. , Williams John R.
Published: October 2016

Current design tools used for predicting the placement of proppant in fractures are based on the solution of a simplified conservation equation that is heavily dependent on empirical relationships for particle settling and suspension viscosity. In light of these shortcomings, this paper presents the development of a computational fluid dynamics (CFD) model capable of micromechanical simulation of hydraulic fracturing fluids. The model developed in this research employs the discrete element method (DEM) to represent the proppant for a range of sizes and densities. For the fluid phase, the lattice Boltzmann method (LBM) is utilised in a generalised-Newtonian form. Full hydrodynamic coupling of the LBM and DEM is achieved via an immersed moving boundary condition. The developed model has the ability to simulate Navier-Stokes hydrodynamics, a range of rheological models (e.g. Bingham, power law), thermal effects as well as electromagnetic and electrostatic forces between particles and walls. The model captures the detailed interactions of proppant particles as well as the non-Newtonian rheology of the fracturing fluid in both experimental and fracture geometries. Simulations of small-scale experiments are used to describe suspension rheology as a function of proppant concentration while small-scale fracture models explore the settling and injection of a number of candidate formulations. These results show that the direct numerical simulation (DNS) approach presented in this paper represents a potentially valuable complement to contemporary models which can provide insight on the rheology of new or novel fracturing fluid formulations as well as explore the influence of complex in-situ features on the efficacy of a hydraulic fracture. More detailed knowledge of how proppant is transported from the wellbore to the fracture tip will provide insights that could be used in the optimisation of the hydraulic fracturing process. This is particularly relevant in coal seam gas reservoirs which can include bi-directional fracture networks, non-planar fracture paths, interburden terminations and other leak-off points.
Well Failure Mechanisms and Conceptualisation of Reservoir-Aquifer Failure Pathways
Authors: Wu B. , Doble R. , Turnadge C. , Mallants D.
Published: October 2016

This paper presents a critical review of literature on bore and well failure mechanisms and rates, and conceptualisations of probable reservoir-aquifer failure pathways. The objective was to gain a better understanding about bore and well induced inter-aquifer connectivity and the potential consequences to groundwater resources. This comprehensive review included Australian and international literature on onshore conventional oil and gas wells, water bores, coal seam gas wells and coal exploration bores. Failure mechanisms and rates were discussed for the entire well life cycle. Reservoir-aquifer failure pathways were then conceptualised based on the failure mechanisms and risk analyses considering the likelihood of failure and detection, repair and potential impacts on hydrogeology.
Aquitard and Fault Simulation Approaches for Use in Regional-Scale Assessments of Coal Seam Gas Extraction Impacts
Authors: Turnadge C. , Mallants D. , Peeters L.
Published: October 2016

Low permeability formations (aquitards) and geological faults play a key role in determining the degree of isolation of groundwater resources (aquifers) from hydrocarbon reservoirs. Reliable assessment of the potential risks associated with groundwater extraction and depressurisation for coal seam gas (CSG) development necessitates accurate characterisation of aquitards and faults and incorporation in regional-scale groundwater flow models. We provide an overview of a range of approaches by which aquitards and faults may be represented in such models. A range of approaches that may be used to upscale and spatially interpolate aquitard hydraulic properties for inclusion in regional-scale groundwater flow models was examined. These methods vary in complexity and in the level of data support required. They range from simple analytical averaging approaches and flux-based methods to complex approaches based on geostatistical characterisation and facies reconstruction. Representations of geological faults and associated fracture systems in groundwater flow models include the common use of transmissibility multipliers to represent faults. For the simulation of groundwater flow in fractured porous media, three categories of methods are available, ranging in complexity from equivalent porous media approaches to discrete fracture network models. A review of regional-scale groundwater flow models developed for Australian CSG impact assessments identified that aquitard heterogeneity and geological faults are typically omitted or highly simplified. For aquitards, simplifications typically involve neglecting the spatial heterogeneity of hydraulic properties through the adoption of spatially uniform values. For geological faults and fault networks, a paucity of data currently exists with regards to both fault architecture (e.g. orientation, location, size and frequency) and flow properties of faults.
Revisiting the Ideal Packing Theory with a Novel Particle Size Measurement Approach
Authors: Amer A. , Carter B. , Hudson II E. , Du H. , Judd C.
Published: October 2016

Drilling into production zones requires the use of special fluids with minimal formation damage potential. These fluids typically include a blend of carefully designed bridging particles. The selection of these bridging particles is based on particle size distribution (PSD) and may include other attributes such as acid solubility depending on type of rock and the well completion method. One of the theories that addresses the design of these fluids is the Ideal Packing Theory (IPT).

Two of the most common ways to obtain PSD are laser diffraction (LD) and sieve analysis (SA). Each method has its own bias in measurement. For instance, SA tends to emphasize the second largest dimension of a particle (Kumar et al. 2013) while LD calculates PSD based on the assumption all particles are spheres. Particles in drilling fluids are not all spherical, therefore it was deemed worthwhile to investigate PSD measured by other techniques such dynamic imaging analysis (DIA) which takes in consideration the parameter aspect ratio when generating its PSD.

Sphericity of the bridging particles is a key assumption for the IPT to work. However, the use of dynamic image analysis (DIA) in the field of particle characterization in drilling fluids has led to significant findings. A key finding is that most bridging particles used are neither spherical nor uniform.

This study evaluates whether there are differences in the PSD results for the same sample of bridging particles. The study then examines the effect of using the data from the various PSD techniques on the bridging algorithm thus impacting the fluid sealing ability of porous media represented by ceramic disks.

This study also examines the phenomena of "packing behavior randomness" and its impact on porosity and permeability of blends of bridging particles.
Development of a Novel Sand Retention Cell
Authors: Wu B. , Lupton G. , Barton T. , Denke R. , Wong C. Y. , Feng Y. , Boulanger J. , Choi S. K.
Published: October 2016

Sand screens are widely installed to control unacceptable amount of sand produced from oil and gas wells. Sand retention tests are often used to select optimal sand screen size that minimizes sand production and maximizes hydrocarbon production. However, there is currently no agreed industry standards as to how the tests are conducted and results interpreted. This paper presents development of a novel sand retention cell and the associated experimental procedure with the objective to overcome some of the limitations in the existing sand retention tests. The improvements incorporated into the new sand retention cell and experimental procedure include i) measurements of fluid pressures close to the screen surface and sand pack to allow in-situ measurement of the screen and sand pack permeabilities; ii) delivery of a uniform sand slurry over the entire screen surface that ensures formation of a uniform sand pack over the screen by using a heavy fluid; iii) transparent cell body to allow sand retention and production process to be visually observed and sand pack height to be measured; and iv) sand slurry flow as well as pre-pack sand retention test and assessment for fines migration through gravel pack.
Dispersive hydrodynamics of nonlinear polarization waves in two-component Bose-Einstein condensates
Authors: Congy Thibault , Kamchatnov Anatoly , Pavloff Nicolas
Published: October 2016

We study one dimensional mixtures of two-component Bose-Einstein
condensates in the limit where the intra-species and inter-species
interaction constants are very close. Near the mixing-demixing
transition the polarization and the density dynamics decouple. We study
the nonlinear polarization waves, show that they obey a universal (i.e.,
parameter free) dynamical description, identify a new type of algebraic
soliton, explicitly write simple wave solutions, and study the
Gurevich-Pitaevskii problem in this context.
Drought management policies – from global collaboration to national action
Authors: Pischke Frederik , Stefanski Robert
Published: October 2016

The article provides an overview of the development of national drought management policies (NDMP). It explores collaborative efforts that were started at the High-level Meeting on National Drought Policy – whose declaration provides the backdrop to this article – and are implemented through the World Meteorological Organization (WMO)/Global Water Partnership (GWP) Integrated Drought Management Programme (IDMP) and related initiatives. Early outputs, e.g., the National Drought Management Policy Guidelines – A template for action and the Handbook on Drought Indices and Indicators, provide an indication of how expert-reviewed guidance is brought together and applied by drought practitioners for developing NDMP and applying drought indices/indicators. Regional examples from Central and Eastern Europe and the Horn of Africa, including a brief country example from Kenya, highlight how these guidelines and collaborative efforts and outputs are applied. The role of IDMP is to provide a framework and commensurate technical support to countries but the actual development and implementation of national drought plans and policies still needs to be done by governmental ministries and national stakeholders. The article emphasizes how information from different sources is used to support countries to shift from only reacting to droughts when they occur to adopt proactive national drought policies that focus on improved collaboration and the mitigation of drought impacts.
Effect of Sowing Dates and Maize Cultivars in Growth and Yield of
Maize along with their Agro-Climatic Indices in Nawalparasi, Nepal
Authors: SHRESTHA UMESH , AMGAIN LAL PRASAD , KARKI TIKA BAHADUR , DAHAL KHEM RAJ , SHRESTHA JIBAN
Published: October 2016

A field experiment on different maize cultivars planted at different sowing dates were
accomplished at Kawasoti-5, Nawalparasi during spring season of 2013 to find suitable sowing
date and maize cultivar for the location. Along with this, effect of sowing dates and maize cultivars
on different agro-climatic indices were also calculated using formulas. Result showed that RML-
4/RML-17 produced higher kernel rows ear-1 (13.77), kernel per row (30.42) and test weight (244.9
g). Significantly higher grain yield was also found for RML-4/RML-17 (6.03 tha-1) compared to
Poshilo makai-1 (4.73 t ha-1), Arun-2 (3.55 t ha-1) and Local (2.92 t ha-1). Earlier sowing date (7th April)
produced higher kernel row-1 (27.97), kernel rows ear-1 (12.89) and 1000 grain weight (230 g).
Significantly higher grain yield (5.13t ha-1) was obtained in earlier sowing date (7th April). Although
the mean ambient temperature during research period was increasing with delayed sowing, days
to attain different phenological stages decreased with late sowing. The statistically similar GDD
was recorded for different sowing dates and higher PTI values were noticed with delay in planting.
Similarly, heat use efficiency (HUE) was found higher in early sowing date. Arun-2 had small
reduction in HUE so, it can be considered stable and best cultivar among the tested cultivars.