bluuebunny/crossref_metadata_2025 huggingface dataset:
Simplified Near Wellbore Reservoir Simulation To Predict the Performance of Viscous Oil Horizontal Well With Water Coning From an Active Aquifer
Authors: Jurus W. J. , Stanko M. , Parra A. , Golan Michael
Published: November 2015

This paper describes the development of a comprehensive 2D near wellbore reservoir model to history match and predict the not yet fully understood production performance and deliverability of horizontal wells producing a heavy viscous oil (~300 cp). This in the presence of water conning from an active aquifer. The target application is heavy oil reservoirs (e.g. Rubiales field, Colombia) with rapidly increasing or high producing water cut (~90%), constant reservoir pressure maintained by an active aquifer, and high horizontal pay zone permeability (~15 D).

The methodology employs a simplified 2D horizontal wellbore reservoir model with enough flexibility (i.e. tuning parameters) to match the measured wells production profile (i.e. water production and producing water cut). One well with full production record was analyzed.

The following modeling strategies were tried out: providing an adequate pressure support from the aquifer, increasing artificially the oil mobility in the porous media as the water saturation increases and hindering the vertical water migration from the aquifer towards the well. These modeling strategies added additional tuning variables besides the conventional formation parameters.

Model parameters were varied automatically using an optimization engine minimizing the difference between the simulated and the measured data.

Several modeling approaches were tried out in the simulator: standalone variation of the oil viscosity, oil viscosity variation with water saturation, oil-water emulsion behavior using inversion point and Richardson model, Fetkovich type numerical aquifer, water injector with constant bottom-hole pressure and tunable injectivity index, initial water saturation variation with depth within oil zone.

Almost all the modeling approaches yielded an acceptable history match (<6%) for water production profiles. The match of the bottomhole pressure is more challenging, as satisfactory residuals are only obtained in certain production periods. It was not possible to reproduce the bottomhole pressure trend considering simple aquifer volumetric expansion and emulsion behavior throughout the entire reservoir domain.

The present paper proposes the utilization of a simplified 2D near wellbore reservoir model to successfully represent the performance of viscous oil high water cut producing wells with complex physics. The results show that it is possible to overlook the complexity of such reservoirs by "wrapping them up" in a few macro parameters and still keeping physical consistency.
A Novel Method to Calculate Asphaltene Solubility Parameter
Authors: Souza M. M. , de Melo S. A. , Costa G. M.
Published: November 2015

Asphaltene precipitation is a challenging and complex problem in all sections of the oil industry including oil production, transportation and processing. Asphaltenes can plug pumps, valves, tubing and flow lines, cause fouling in surface handling facilities and even act as coke precursors and catalyst poisons. For these reasons, the occurrence of asphaltene deposits may result in productivity losses and sometimes even production shutdowns. For many years, much effort has been done on modelling asphaltene precipitation because experimental investigation is a hard task. Thermodynamic models based on Flory-Huggins theory have been used by several oil companies to predict the asphaltene onset conditions due to the depletion or gas injection. However, the main requirement to accomplish a successful calculation of asphaltene precipitation is an accurate solubility parameter. A variety of models to calculate asphaltene precipitation based on the solubility parameter is available in literature but most of them are complex due to inherent assumptions that are built-in. In this work, a new simple and accurate method to calculate the asphaltene solubility parameter is proposed, which requires only SARA (saturate, aromatic, resin, and asphaltene) analysis, the oil composition and the reservoir temperature. Once it is sufficient to know up to C7+ fraction, a much detailed analysis of the oil composition is unnecessary. Soave-Redlich-Kwong (SRK) (Prausnitz et al. 1999) equation of state (EOS) and Pedersen's characterization method (Pedersen et al. 1984) were used to calculate the liquid phase molar volume and SARA analysis was employed to determine the number of fractions that correspond to the amount of asphaltene in the oil. Five oils were selected from literature and calculation of their asphaltene solubility parameter was performed without needing their composition in details. Just one fraction was sufficient to include the amount of asphaltene indicated in SARA analysis for all oils tested. Each oil was considered as a mixture of 26 components. The values of asphaltene solubility parameters calculated by a simple method based on SRK EOS were comparable to those given by perturbed-chain statistical associating fluid theory (PC SAFT) EOS available in literature (Punnapala and Vargas 2013), which requires an extremely detailed characterization of the oil. Therefore, the proposed simple method is preferred because it is much more useful to the oil industry.
Mature Oil Field Reservoir Characterization Integrating Well Logs and Wireline Pressure Transient Diagnostics Data
Authors: Gelvez C. , Torres C. , Lozano E. , Avila R.
Published: November 2015

A mature oil field reservoir is characterized by gathering the geological and petrophysical data with the dynamic data. The product allows the defining of vertical reservoir units and their continuity along the field. Reservoir properties, seals and barriers are determined by pressure data and compared with the petrophysical interpretation.

This document presents a profound study on pressure data interpretation and how to integrate this information with a petrophysical-geological model obtained by well log data analysis. The sands correlation, reservoir properties, faults location and vertical seals, are interpreted at first with the well log data (GR-SP-RES-DN-PE) and seismic data. Then the pressure data points are analyzed taking into account the previous interpretation to confirm the sands vertical connectivity, fluid gradients and the fluid contacts. Additionally, the mini PBU transients are diagnosed by means of computer-aided type curves to evaluate flow regimes in the near wellbore region and to calculate the permeability. Finally, a fully integrated static petrophysical model is built based on the previous study.

The geological cross section is compared before and after the pressure data integration. Ten recently drilled wells from three different reservoir areas with pressure data available are analyzed and presented in this paper. The pressure data evaluation allows identifying the 4 different formation units and its water oil contact (WOC), according to the pressure gradients. The pressure behavior along the horizontal section permits to estimate the sands continuity and the connectivity between three areas. The static reservoir pressure analysis serves to validate and improve the basic well log interpretation and should be a part of the formation evaluation workflow. In addition, a near wellbore model is a strong tool to support and improve the type curve diagnose and interpretation of dynamic data.

This paper provides a great insight on reservoir characterization and the benefits of the pressure logging tool for gathering static and dynamic information into geological models. In many cases formation testing data interpretation is based solely on the spherical flow analytical model. This straightforward approach might bias some features of the near wellbore region, which can only be assessed by pressure transient diagnosis (e.g. pressure derivative). Modeling of formation pressure testing as an interpretation tool strongly improves the near wellbore region dynamic description.
Recognition of Oil-Water Contact Architecture in Water Drive Reservoirs by Rock Typing Implementation, Sacha Field of Ecuador
Authors: Rodriguez L. , Leal J. , Sanchez H. , Hinojosa G.
Published: November 2015

This paper discusses the successful, fully integrated petrophysical and geological modeling of the Hollin formation in the Sacha field of Ecuador. The goal of the modeling project was to unravel aquifer heterogeneities and hydrodynamic effects; it focuses on suitable petrophysical rock typing, supporting the establishment of a tilted water/oil contact (WOC) that follows a particular architecture across the field.

Documenting WOC changes is extremely important during reservoir modeling. Changes in fluid levels can be related to, among other things, structural complexities, rock heterogeneities, and hydraulic movement effects. However, when dealing with a mature field characterization that has undergone an accelerated production, flow capacity differences and remaining reserves become critical points to delineate aquifer heterogeneities. The identification of aquifer heterogeneities and possible hydrodynamic flow were considered separately to address this problem, using available core data, a log-derived water saturation (Sw) model, and dynamic performance integrated with a rock typing approach.

Such factors were considered when studying the Cretaceous Lower Hollin formation in the Sacha field. The Sacha field is a mature field in Oriente basin, Ecuador, and the reservoir is characterized by a sequence of amalgamated sandstones deposited primarily by a braided stream system. A strong aquifer underlies this sequence of amalgamated sandstones and maintains a stable pressure. As a result, various WOCs are displayed at different levels in the wells with a variation of up to 70 ft across the field. Aquifer heterogeneities were identified as facies changes, faults, and capillarity effects that perhaps triggered these WOC irregularities. Although these anomalies do not prevent vertical fluid communication within the reservoir, they represent an important step for proper electrical rock property interpretation; thus, providing a more realistic reservoir Sw model. The construction of rock-fluid surfaces helps to identify the aquifer heterogeneities related to steady state WOC depths. The textural features of the rock in conjunction with an identified water recharge point created an WOC surface that vary the inclination rates from 2 ft/km northward, 13 ft/km eastward, and southward across the field, creating a predictable WOC architecture that affected water production.

This improved understanding of key petrophysical aspects and methods arising from work undertaken to solve various problems related to the tilted WOC have revealed new opportunities to the field edges. These opportunities have been tested with newly drilled wells with excellent results. The results obtained from these tests are having a significant effect on future drilling programs.
The Catalytic Effect of Clay on In-Situ Combustion Performance
Authors: Kozlowski M. L. , Punase A. , Nasr-El-Din H. A. , Hascakir B.
Published: November 2015

The in-situ combustion (ISC) is highly effective thermal enhanced oil recovery process in which high displacement efficiencies can be accomplished. While several physical and chemical factors affect the ISC performance, there is a little knowledge about how each parameter changes the ISC fate. In this study, we investigate the catalytic effect of clay on different crude oil types.

Six one-dimensional combustion tube experiments were conducted on three different crude oil samples; one from Mexico and two from Alberta, Canada. The combustion behavior of each crude oil sample was tested with two combustion runs; by preparing reservoir rock with only sand (E1, E3, and E5) and by preparing reservoir rock with 3 wt% clay and 97 wt% sand mixture (E2, E4, E6). The combustion characteristics were monitored with temperature profiles, produced gas compositions, and produced liquid yields. The level of in-situ oil upgrading were determined by comparing the viscosities of produced oil samples with the original ones.

The results showed that the catalytic effect of the clay controls the combustion front propagation, the fuel formation, and the produced oil quality. Clays visualized on postmortem samples in the shape of lumps indicate that clay alteration occured at elevated temperature due to interaction of clay with crude oil and due to thermal decomposition of clay. It was observed that the lump formation was associated with mainly saturates and asphaltene contents of initial oil and asphaltene-clay interaction during fuel formation.

Our results support that the clay presence in reservoir rock had an impact on ISC performance. However, this impact did not have a linear trend and the response of the catalytic effect of clays were different from one crude oil to another; while one crude oil favored combustion more with the presence of clay, the other did not and led to lower oil production by producing more gas.
New Opportunities Identification Workflow, Pañacocha Field, Oriente Basin, Ecuador
Authors: Guerrero J. Rodas , Vega J. , Alvarez I. , Lafournère J. , Henson R. , Fonseca C. , Bravo L. , Minchala J. , Morales O.
Published: November 2015

Over the years, simulation models have been helping oil companies and stakeholders to make investment decisions. However, these models are not always available to help with the field development planning. A fast and efficient workflow performed for the identification of new opportunities in the Pañacocha field is presented.

To start the workflow, a conceptual geological model was identified for each reservoir, based on the available data and nearby analog fields. Quality control, updating and reinterpretation of well top data, petrophysical parameters maps (net pay, porosity, and water saturation), and original oil in place estimations were carried out to identify untouched areas. A total of 45 locations that may still contain oil were identified.

For the next step, a decline curve analysis was carried out, and well type curves were generated to determine the estimated ultimate reserves (EUR), drainage area, and recovery factor by well. The range of recoverable oil associated with each location was estimated by varying all the parameters involved in the volumetric formula.

Finally, the locations were ranked based on their production potential. The selection of drilling targets included the associated geological and operational risk. A base case, based on the contract minimum commitments, is presented. However, this study shows that a more aggressive drilling campaign is possible.

In conclusion, this workflow allowed us to have a better understanding of the field potential. Oil in place volumes and recovery factors were updated. Analysis of produced fluids helped to assess reservoir performance. The economic analysis following this study will help in selecting the best option to develop the field.
Applying Horizontal Wells to Develop Oilfields with Complex Low Relief Structure in High Water Cut Stage in Tarapoa
Authors: Zhang Haikuan , Zhang Xing , Zhao Xinjun , Hu Quan , Wan Xuepeng , Serrano Fabrizio , Zhang Kexin , Lei Zhanxiang , Wang Yusheng
Published: November 2015

The feasibility of horizontal well technology is analyzed for the M1 reservoir of the Tarapoa Block. Applying advanced location deployment technologies of horizontal well, and optimizing key parameters are aimed to expand the application scale of horizontal wells in the Tarapoa Block.

The approach is based on the research of genetic model of lithologic reservoirs, reservoir distribution characteristics and remaining oil distribution. The successful application of using combined drilling and completion technologies is already confirmed, and methods are described which focus on key parameters for optimizing horizontal well drilling and completion technology.

From 2006 to 2014, nearly 67 wells have been successfully put on production on Tarapoa Block. According to petrogenesis, remaining oil of micro-structural type and well pattern imperfect type in M1 sandstone are major potential areas of applying horizontal technology. Because most wells are in a high water cut phase with thin net pays and bottom water drive, the optimal horizontal segment position, horizontal section length and well flow regime, need to be studied in order to ensure its economic benefit. Studies suggest that the relative height of the horizontal section to avoid bottom water should be more than 70%. Due to the small size of the remaining microstructures for the M1 reservoir, the longer the horizontal section, the greater the difficulty for controlling the trajectory. Considering that the produced water needs to be treated, the initial fluid volume of the horizontal wells should be controlled.

Horizontal well technology in the Tarapoa Block has been successfully applied. Horizontal wells have accounted for 44% of the production of all new wells during the period and production from horizontal wells is 2.75 times that of the directional wells. They play a key role in stabilizing oil production, slowing declines and maintaining water control.
Experimental Investigation of Polymer Assisted WAG for Mobility Control in the Highly Heterogeneous North Burbank Unit in Oklahoma, Using Anthropogenic CO2
Authors: Tovar Francisco D. , Barrufet Maria A. , Schechter David S.
Published: November 2015

This work investigates the use of polymers during CO2 WAG using a physical model. Coreflooding experiments were conducted to compare polymer assisted WAG, conventional WAG, continuous CO2 flooding, and polymer flooding. The effect of miscibility in the CO2 – oil interface was evaluated from coreflooding at two different pressures, above and below the MMP of 1563 psig The MMP was experimentally determined using a fast version of the slim tube procedure with a shorter column. The influence of reservoir heterogeneity was observed by conducting corefloodings in homogeneous and heterogeneous rocks with permeability ranging from 13 to 1300 md. The core plugs were selected using computed tomography to ensure the presence or absence of heterogeneous features.

Our results show that under miscible displacement in a homogeneous rock, continuous CO2 injection can reduce residual oil saturation (Sor) to less than 10%, even for a permeability as low as 13 md. The implementation of conventional WAG and polymer assisted WAG in this case was detrimental for the process as water saturation shielded a portion of the oil preventing CO2 contact. The departure from the ideal miscible displacement resulted in a Sor as high as 32 %. For the heterogeneous rock, at 285 psig above MMP, the WAG CO2 was able to reduce Sor to as low as 11%, whereas at 260 psig below MMP a Sor of 23% was reached. As the level of heterogeneity increases, the oil recovery of polymer assisted WAG relative to conventional WAG increased suggesting that a certain degree of heterogeneity is needed for the polymer assisted WAG process to be beneficial. A throughout discussion on the recovery mechanisms and the interactive / combined role of miscibility, heterogeneity, permeability and viscosity is presented.

This work adds to the understanding of the CO2 flooding process implemented in the North Burbank Unit (NBU) and the potential to use WAG and polymer assisted WAG to improve mobility control. Sweep efficiency is the most important challenge from a reservoir engineering standpoint for CO2 flooding, but it is particularly critical in the NBU for two reasons. The high vertical heterogeneity in the field, with a permeability variation of three orders of magnitude within 30 ft of reservoir thickness, which greatly exacerbates viscous fingering, and the use of anthropogenic CO2 which makes the economics of the project more sensitive.
Estimates of Stress Dependent Properties in Tight Reservoirs: Their Use with Drill Cuttings Data
Authors: Lopez Bruno , Piedrahita Jaime , Aguilera Roberto
Published: November 2015

The objective of this paper is to present a methodology using drill cuttings for making estimates of porosity, permeability and compressibility as a function of confining pressures in tight formations.

An easy to use correlation is developed by comparing results from experimental work including hysteresis at various combinations of overburden and pore pressures in vertical and horizontal core plugs, and permeabilities and porosities determined in the laboratory from drill cuttings. The work is important because of the presence of stress-dependent slot and/or microfracture porosities and permeabilities in tight formations that can affect significantly reservoir performance and forecasting.

Recent work has shown that drill cuttings can be used quantitatively for complete petrophysical evaluation (for example determination of porosity, water saturation, pore throat aperture, Young Modulus, Poisson's ratio and brittleness index (Olusola and Aguilera, 2013; Ortega and Aguilera, 2014). The methods have been shown to be useful in those instances where cores and specialized well logs are scarce. Those methodologies are extended in this paper to quantitative evaluation of stress dependent properties.

It is concluded that drill cuttings are important direct sources of information that can be used for developing estimates of stress-dependent properties particularly in those cases where cores and specialized logs are scarce or not available. The methodology and correlation are presented in detail as well as a practical application. Although the main and novel contribution is the development of an easy to use correlation for stress-dependent tight reservoirs using drill cuttings, the correlation can obviously be used if only plug data are available.
An Approach for Steam Propagation and Production Performance in SAGD and Solvent SAGD: Lab Experiment and Simulation
Authors: Zare A. , Hamouda A. A.
Published: November 2015

Steam Assisted Gravity Drainage (SAGD) is considered a successful EOR method for heavy oil and bitumen.

A two-dimensional physical model is designed to conduct experiments in this study. The consistency of the experimental data obtained was tested. The designed model was instrumented with 15 temperature sensors at different locations aimed at capturing the temperature propagation with distance and time. The experimental consistency tests for stream propagation have helped in understanding the important controlling parameters for the experiments. Steam propagation was mapped to understand the various processes taking place for oil recovery from steam chamber size and shape. The recovery mechanism could, to some extent, be realised.

A simulation approach has been developed to history-match the production, and is compared to the used approach in the literature. Numerical simulation of the effect of Solvent SAGD on EOR was investigated. The developed steam chamber by simulated Solvent SAGD, simulated and experimental SAGD, is addressed in the paper. The results present an excellent practical approach to obtaining a developed steam chamber and accordingly identifying mechanisms. The match quality of the history-matched experiment allows a good assessment for production forecast, with understanding and development of the process.

The paper contributes to generating more in-depth understanding of heat propagation, chamber development, and the heat transfer mechanism of SAGD.
Synergism Between Ionic and Nonionic Surfactants for Producing Low Interfacial Tension at Oil-Water Interface
Authors: Martiz A. , Samaniego S. , Aray Y. , Paredes R.
Published: November 2015

The synergism of mixtures of anionic and non-ionic surfactants adsorbed at the water/alkane interface was studied using mesoscopic Dissipative Particle Dynamic simulations. The effect of the mixtures of sodium m, p-exylbenzenesulfonate and sodium m, p-octylbenzenesulfonate with the nonionic surfactant lauryl alcohol polyoxyethylene (9) ether on the surface tension of the water/alkane interface was explored. Alkane scanning curves for n-alkanes from hexane to tetradecane are reported. Our results suggest that dissolution of lauryl alcohol polyoxyethylene (9) ether in the hydrocarbon phase is the origin of this behavior. For the sodium m, p-octylbenzenesulfonate case, the mixture with lauryl alcohol polyoxyethylene (9) ether induces a synergism for alkanes with low carbon number. A moderate lipophilic behavior of the mixture was observed for hexane and as a result 95% of the mixture stays at the interface forming a really compact layer at the interface. Additionally, increase on the carbon number alkane produces an increase in the hydrophilic behavior of lauryl alcohol polyoxyethylene (9) ether inducing higher interfacial tension values.
Effect of Oil and Gas Prices on Unconventional Resource Plays
Authors: Aguilera Roberto F. , Aguilera Roberto
Published: November 2015

The objective of this paper is to examine the effect of oil and gas prices on the development of tight and shale reservoirs including oil, gas and condensate.

The methodology uses a variable shape distribution (VSD) model for examining past, present and futures prices of oil and gas. The VSD matches historical annual changes in oil and gas prices with coefficients of determination that are generally larger than 0.98. Contrary to several commentators and specialized organizations around the world that were forecasting continuous oil price escalation up to US$ 300/bbl (e.g. in 2008, when the oil price was around US$ 140/bbl), the VSD was used successfully to anticipate a significant drop in prices, leading to the on-record statement that the oil price was a bubble and was going to burst (June 13, 2008).

The VSD was also used to build a case at LACPEC in 2014 (Aguilera and Aguilera, 2014) indicating that "with the vast global oil resource base and the significant technological advances being implemented by the industry, oil prices could actually decrease in the future". This is a painful fact being faced today by the oil and gas industry worldwide.

In this paper, the VSD has been used with a global energy market (GEM) model to examine possible future outcomes of unconventional resources development in light of forecasted oil and gas demand and anticipated price-changes calculated with the VSD.

The methodology provides a novel approach for examining some realistic possibilities regarding future development of unconventional oil, gas and condensate reservoirs.
Experimental Study of Heavy Oil In-Situ Upgrading Using High Temperature Gas-Oil Gravity Drainage in Naturally Fractured Reservoirs
Authors: Suarez Ricardo G. , Scott Carlos , Hejazi S. Hossein , Pereira-Almao Pedro
Published: November 2015

Heavy oil recovery from matrix blocks of Indiana limestone and Silurian dolomite core samples was studied using a cylindrical core holder set-up. Fractures in the system were represented by a gap between the core sample and core holder wall. Core samples and fractures were respectively saturated with heavy oil and gas. Oil recovery experiments were conducted in batch-mode using two different gases, nitrogen and carbon dioxide, at 1000 psi and various temperatures (200, 250, and 300 °C). N2 was employed as an inert gas to study the effect of temperature in oil production from the cores without affecting its chemical properties. Consequently, CO2 was used to investigate the role of mass transfer between matrix and fracture fluids in oil recovery.

The produced oil from the matrix was collected and the recovery factor for each experiment was calculated. Moreover, the remaining oil in the core was extracted. Viscosity determinations and simulated distillations of the two samples, produced oil and remained oil in the core, were carried out in order to assess oil quality distribution.

Experimental results revealed that with immiscible gas injection at high temperatures oil segregation occurred in the porous media. Consequently, lighter components of oil were produced while the heavier ones were left behind inside the matrix. Results also demonstrated a relationship between the amount of oil produced and the oil segregation in the porous media.

This research provides a systematic analysis to investigate the main recovery mechanisms from carbonate matrix blocks under various hot gas injection scenarios, which is of great interest to determine the most appropriate enhanced recovery method to be applied for heavy oil production from naturally fractured reservoirs.
Design and Implementation of the First Polymer Flooding Project in Colombia: Yariguí-Cantagallo Field
Authors: Maya G. , Jimenez R. , Castro R. , Mantilla J. , Vargas J. , Cardenas F. , Fernandez F. , Quintero H. , Zaitoun A. , Manrique E. , Romero J. , Putnam J.
Published: November 2015

Waterflooding is one of the oil recovery processes best known and applied worldwide. However, this method has limited efficiency to displace oil. That is why the implementations of chemical Enhanced Oil Recovery (CEOR) processes is necessary, with the objective of increasing both volumetric and displacement efficiencies and maximize the recovery factor, even at the early stages of waterflooding.

The first Polymer flooding Project of ECOPETROL S.A. spent 18 months designing and assuring the stages of screening, area selection, experimental feasibility, numerical simulation, infrastructure, financial analysis, automation, execution and online monitoring of a polymer flooding EOR pilot in the Yariguí-Cantagallo field. Strategically, the pilot has two injection patterns operated by two different globally recognized services companies.

The first injection pattern started on 17 March 2014 with an injection rate of 1,000 BPD and a polymer concentration of 1,500 ppm in YR-504 injection well. The second injection pattern began on 27 April 2014 with the same injection rate and a polymer concentration of 800 ppm in YR-510 injector.

The first seventeen months of polymer injection have allowed the assimilation of learned lessons, best practices for continual improvement in the operation of such processes, incremental oil production; water cut reduction and increases in the fluid levels for the first row of offset producers. The development of the first polymer flooding pilot in Colombia by Ecopetrol broadens the expectations for expansion in the field and implementing this type of technology to other Colombian oil fields, and has become one player to leverage the achievement of production goals of the business group.

This work presents the implemented procedure during design, execution and initial monitoring of the polymer flooding project, which is the first project of its kind carried out in Colombia by Ecopetrol and can be considered successful at a cost per incremental barrel of $US 4.60.
Designing a Development Plan with a Constrained Multi-Layered Reservoir Model Using Pressure Transients and Downhole Fluid Analysis
Authors: Dubost F. X. , Rocha M. , Lavin L. M. , Fuentes R. , Ramirez J. R. , Guzman D.
Published: November 2015

A new method is presented to assess layer connectivity and determine dynamic reservoir properties for use as inputs in a numerical model for a multi-layered reservoir. Large scale formation tester transient measurements and downhole fluid analysis information are used to construct the reservoir model. Pressure and fluid measurements distributed vertically at the wellbore and laterally in different wells are used to delineate the sands and model the complex fluid behaviors. Pressure transients recorded in different wells from a wireline formation tester (WFT) in small scale drill stem test (DST), or from conventional well tests, are then used to constrain the dynamic model properties through a grid-based inversion technique, so that observed test data and the model response match.

Our workflow consists in constructing initial reservoir models using the acquired log and test data, and constraining the model properties to the transient test data. Wireline conveyed tests and downhole fluid analysis (DFA) measurements from different wells are inputs to the geomodel, and building steps to assess layer connectivity from pressure gradient and fluid matches. Then a fluid model equation of state (EOS) is built from PVT experiments on the fluids in the laboratory, and tuned to the observed changes against depth in the fluid properties from downhole measurements, such as solution gas-oil ratio or saturation pressures. Initial dynamic layer properties, such as horizontal and vertical permeabilities are typically obtained from logs and cores. In our workflow we calibrate these properties to interval pressure transient tests (IPTT) and conventional well tests. These modeled properties are constrained to match the IPTT or well tests. An optimization routine is conducted, using adjoint simulations, to minimize an objective function composed of observed bottomhole pressures given different flowrates during a transient test and the pressure response of the model. In this optimization step, the skin values are introduced explicitly in the model, but the dynamic properties are modified until a match is obtained. Once the model is constrained, it is then used to develop an optimum development strategy.

We present a case study to illustrate our methodology, in a new field development setting, with transient tests and WFT measurements acquired in three different appraisal wells, which traverse multiple channel sands reservoirs. These tests were used to build an optimal model which respected all acquired measurements. We finally show how this calibrated model was used to help make a decision about the development strategy.
A Material Balance Equation for Stress-Sensitive Shale Gas Condensate Reservoirs
Authors: Orozco Daniel , Aguilera Roberto
Published: November 2015

During the last few years, production of liquid hydrocarbons has been reported from the gas-condensate window of the Eagle Ford, Barnett, Niobrara and Marcellus shale plays in the US. This paper presents a new Material Balance Equation (MBE) for estimation of Original Gas in Place (OGIP) and Original Condensate in Place (OCIP) in shale gas condensate reservoirs. This material balance methodology allows estimating the critical time for implementing gas injection in those cases where condensate buildup represents a problem. Additionally, the proposed MBE considers the effects of free, adsorbed and dissolved gas condensate production, and also takes into-account the stress-dependency of porosity and permeability. An extension of the methodology is implemented for estimating the optimum time for hydraulically re-fracturing shale condensate reservoirs.

The new MBE applies to shale gas condensate reservoirs by incorporating a two-phase gas deviation factor (Z2) and total cumulative gas production (Gpt) that includes both gas and condensate. If a crossplot of P/Z2 (pressure/Z2) vs. Gpt is prepared for a conventional gas condensate reservoir, a single straight line is obtained. However, when the single-phase gas compressibility factor (Z) is used, a deviation from the linear behavior is observed once the reservoir pressure falls below the gas dew-point. This methodology is applied in this study to unconventional shale gas condensate. Since there are three characteristic stages of production in a shale gas reservoir (production of free, adsorbed and dissolved gas), the location of the aforementioned deviation will provide a hint of the production stage that will be affected by condensate buildup. For example, if the deviation point is located in the region where production of free gas is predominant, then the production due to desorption mechanisms will be negatively impacted because condensation will have already occurred in the reservoir, resulting on reduction of effective permeability to gas. This methodology allows then estimating the critical time for implementing gas injection on the basis of the total cumulative gas production.

Results are presented as crossplots of 1) P/Z2 vs. Gpt, 2) Gpt vs. time and 3) gas rate vs. time. It is concluded that estimation of the critical time for implementing gas injection is useful for improving the performance of those shale gas condensate reservoirs where condensate buildup represents a threat that can negatively impact the gas production rate.

The novelty of this work resides on the fact that the combined effect of free, adsorbed and dissolved gas production mechanisms on stress-sensitive shale gas condensate reservoirs has not been considered previously in the literature for estimation of OGIP and OCIP using an analytical MBE.
New Seismic Base Reservoir Characterization (SBRC) Geomechanical Model Based on Mogi Empirical Rock Failure Relationship
Authors: Li Qi , Yousefzadeh Adam , Aguilera Roberto
Published: November 2015

The objective of this paper is to develop a seismic based reservoir characterization (SBRC) geomechanical model using a non-linear relationship between the maximum and minimum principal stress and taking into account the intermediate principal stress.

The proposed geomechanical model is constructed based on Mogi's (1967) empirical rock failure relationship. This allows introducing for the first time in the SBRC the intermediate principal stress. In order to do it, in-situ stress variations as a function of depth are used to match failure stresses for five groups of rock failure experiments that have different values of least principal stress. Next the relationship is integrated with the diffusivity equation for estimating large-scale permeability.

German Continental Deep Drilling Project (KTB) data are used to test the validity of the new SBRC model. Two ‘hydraulic fracturing’ depths (9100 and 6360m) in the KTB site are used to demonstrate the methodology. Minimum permeabilities are calculated with the new SBRC to be 2.9×10−20 m2 at 6360 m and 3.1×10−20 m2 at 9100 m. Maximum permeabilities are 2.3×10−16 m2 at 6360 m and 2.9×10−16 m2 at 9100m. Thus the maximum permeability is approximately 4 orders of magnitude larger compared with the minimum permeability (1 m2 = 1.013E15 md).

Novelties of the approach can be summarized as follows: (1) the use of Mogi's (1969) empirical rock failure relationship for integrating intermediate principal stress into the SBRC geomechanical model (this cannot be done when using for example the Mohr-Coulomb rock failure criterion), (2) using a nonlinear relationship between the maximum and minimum principal stress and (3) calculating large-scale permeability.
Analysis of the Influence of LPG Density on the Performance of a Centrifugal Pump-Impeller Through CFD Simulations
Authors: Lara-Rodriguez G. , Begovich O. , Naredo J. L.
Published: November 2015

This paper deals with the performance analysis of a centrifugal pump-impeller of diffuser type for transporting liquefied petroleum gas (LPG). The performance analysis is conducted here through numerical methods and computational fluid dynamic (CFD) simulations. The focus of the study is on the behavior of the centrifugal-pump as the diffuser-blade angles change. A methodology of dimensional analysis is employed here to combine both, real operating conditions and simulations with a commercial-grade CFD software. The analysis lakes into account the decrease in the density of the transported fluid, along with temperature increases due to the external environment. The monitoring of these two variables is necessary in practice to guarantee a constant flow-rate and it is done analytically since the corresponding experiments are deemed risky and difficult.

To evaluate LPG pump-efficiency it is considered here that the range of densities is from 490 to 550 kg/m3. The CFD software SolidWorks is used here to conduct the simulations of a centrifugal impeller by varying the fluid density. Operating data from a real-life pump are further used to corroborate the simulations.

The vast majority of LPG pumps being installed at industrial parks must hands the fluid as two-phase gas-liquid one. However, most studies elsewhere consider it as a homogeneous flow. In real operating conditions, when dealing with volatile liquids like LPG, pressures lower than the ones of vapor can be produced and this should be avoided to prevent cavitation. Unfortunately, the specialized literature in this topic does not include considerations on the varying physical properties of liquefied gas, such as density. These variations have been at the simulations reported in this paper. It is concluded here that these factors must be taken into account to avoid the poor performance of installed LPG pumps.

Analysis of the influence of LPG Density on the Performance of a Centrifugal Pump-Impeller through CFD simulations.
Microseismic 101: Monitoring and Evaluating Hydraulic Fracturing to Improve the Efficiency of Oil and Gas Recovery from Unconventional Reservoirs
Authors: Yousefzadeh Adam , Li Qi , Aguilera Roberto
Published: November 2015

Hydraulic fracturing will be main drive force in oil and gas production from tight hydrocarbon reservoirs in the future. We present a comprehensive literature review on applications, advancement, and limitations of geomechanics and microseismic monitoring of hydraulic fracturing treatments for exploitation of unconventional reservoirs. Microseismic method is the sate-of-the-art technology to monitor the hydraulic fracturing process. Visualization of microseismic events determines the spatial extent of hydraulic fracturing at first glance. Advance analysis of microseismic measurements provides more detailed information about the fracturing mode and fractures geometry. It can even be used for determination of the state of stress in the reservoir and for helping in reservoir characterization at a large scale. Microseismic imaging has successfully been used on stimulation design and control, reservoir characterization and simulation of unconventional reservoirs particularly in North America. Geomechanical, petrophysical, and geophysical mechanisms of hydraulic fracturing and associated seismicity which are not fully understood are topics of ongoing research.

The goal of this study is to provide a comprehensive guideline and a study reference for geoscientists and engineers who would like to get familiar with the theoretical and practical aspects of microseismic monitoring. Starting with a brief history of exploitation of tight reservoirs and microseismic monitoring, the mechanism of hydraulic fracturing and microseismicity are described. Applications, processing, interpretation, and limitations of the methods are explained as wells as how microseismic technology has responded to some of the public concerns about environmental aspects and safety of the hydraulic fracturing process. In closing, four case studies are reviewed to provide some insights into the practical application and limitations of microseismic monitoring.
Anomaly detection and localization by diffusion wavelet-based analysis on traffic matrix
Authors: Sun Teng , Tian Hui , Mei Xuan
Published: November 2015

Diffusion wavelets (DW) transform has been successfully used in
Multi-Resolution Analysis (MRA) of traffic matrices because it inherently
adapts to the structure of the underlying network. There are many potential
applications based on DW analysis such as anomaly detection, routing
optimization and capacity plan, which, however, have not been well developed.
This paper shows how to apply two-dimensional DW transform in traffic matrix
analysis and anomaly detection. The experimental results demonstrate the
effectiveness of DW-based technique in traffic matrix analysis and anomaly
detection in practical networks. It also shows this new technique is
potential to be used in many other network applications.
Attractiveness of real time strategy games
Authors: Xiong Shuo , Iida Hiroyuki
Published: November 2015

Game refinement idea is a unique theory that has been proposed based on the
uncertainty of game outcome. A game refinement measure was derived from the
game information progress model and has been applied in the domains such as
board games and sports games. The present challenge is to apply the game
refinement theory in the domain of RTS games. To do so, we use StarCraft II
as a testbed and introduce a concept of strategy tree in order to construct a
game tree of a RTS game. Then, game refinement values are calculated and
compared with other type of games. It is found that StarCraft II has a zone
value of game refinement.
Visual analytics for BigData variety and its behaviours
Authors: Zhang Jinson , Huang Mao , Meng Zhao-Peng
Published: November 2015

BigData, defined as structured and unstructured data containing images,
videos, texts, audio and other forms of data collected from multiple
datasets, is too big, too complex and moves too fast to analyze using
traditional methods. This has given rise to a few issues that must be
addressed; 1) how to analyze BigData across multiple datasets, 2) how to
classify the different data forms, 3) how to identify BigData patterns based
on its behaviours, 4) how to visualize BigData attributes in order to gain a
better understanding of data. It is therefore necessary to establish a new
framework for BigData analysis and visualization. In this paper, we have
extended our previous works for classifying the BigData attributes into the
"5Ws" dimensions based on different data behaviours. Our approach not only
classifies BigData attributes for different data forms across multiple
datasets, but also establishes the "5Ws" densities to represent the
characteristics of data flow patterns. We use additional non-dimensional
parallel axes in parallel coordinates to display the ?5Ws? sending and
receiving densities, which provide more analytic features for BigData
analysis. The experiment shows that our approach with parallel coordinate
visualization can be efficiently used for BigData analysis and visualization.
Estimation of input function from dynamic PET brain data using Bayesian blind source separation
Authors: Tichý Ondřej , Smídl Václav
Published: November 2015

Selection of regions of interest in an image sequence is a typical
prerequisite step for estimation of time-activity curves in dynamic positron
emission tomography (PET). This procedure is done manually by a human
operator and therefore suffers from subjective errors. Another such problem
is to estimate the input function. It can be measured from arterial blood or
it can be searched for a vascular structure on the images which is hard to be
done, unreliable, and often impossible. In this study, we focus on blind
source separation methods with no needs of manual interaction. Recently, we
developed sparse blind source separation and deconvolution (S-BSS-vecDC)
method for separation of original sources from dynamic medical data based on
probability modeling and Variational Bayes approximation methodology. In this
paper, we extend this method and we apply the methods on dynamic brain PET
data and application and comparison of derived algorithms with those of
similar assumptions are given. The S-BSS-vecDC algorithm is publicly
available for download.
Anonymization on refining partition: Same privacy, more utility
Authors: Zhu Hong , Tian Shengli , Du Genyuan , Xie Meiyi
Published: November 2015

In privacy preserving data publishing, to reduce the correlation loss between
sensitive attribute (SA) and non-sensitive attributes(NSAs) caused by
anonymization methods (such as generalization, anatomy, slicing and
randomization, etc.), the records with same NSAs values should be divided
into same blocks to meet the anonymizing demands of ?-diversity. However,
there are often many blocks (of the initial partition), in which there are
more than ? records with different SA values, and the frequencies of
different SA values are uneven. Therefore, anonymization on the initial
partition causes more correlation loss. To reduce the correlation loss as far
as possible, in this paper, an optimizing model is first proposed. Then
according to the optimizing model, the refining partition of the initial
partition is generated, and anonymization is applied on the refining
partition. Although anonymization on refining partition can be used on top of
any existing partitioning method to reduce the correlation loss, we
demonstrate that a new partitioning method tailored for refining partition
could further improve data utility. An experimental evaluation shows that our
approach could efficiently reduce correlation loss.