bluuebunny/crossref_metadata_2025 huggingface dataset:
Developments of SiC DioMOS (Diode Integrated SiC MOSFET)
Authors: Kitabatake Makoto
Published: June 2014

SiC power devices can handle large power and high frequency switching beyond the Si power devices. Typical full-SiC power modules are composed of both SiC-MOSFETs and SiC-SBDs to suppress the degradation of Ron of SiC-MOSFET during the bipolar reverse-current flow while there will be unfavorable consequences such as increased material cost, larger area, and larger wiring inductances. Panasonic has proposed the SiC-DioMOS which successfully integrates the unipolar reverse diode without any increase of chip size from the original DIMOS transistor. The SiC-DioMOS utilizes the highly-doped n-type epitaxial channel under the MOS gate for the FET channel and also for the reverse conduction path of the diode. Thickness and concentration of the highly-doped n-typed channel are carefully designed to achieve reasonable Vth of the MOSFET and Vf0 barrier constituting the diode current. The MOSFET and also the MOS-channel diode completely operate under unipolar mode. The SiC-DioMOS with BVds=1700V, Ron=20mΩ、Vth=4.5V, Vf0=0.8V is successively fabricated using the state-of-the-art epitaxial-growth technique. Fast switching of tr=58ns and tf=13ns is confirmed. The SiC-DioMOS meets practical standards for safety operation of high-power fast switching without SiC-SBD.
Working platform design case study for heavy tracked plants
Authors: Wong P. , Moyes P.
Published: June 2014

This paper describes an innovative approach of proof rolling a large-scale construction site with associated testing and interpretation to enable the existing pavement to be used as the working platform to support heavy tracked plants. The existing pavement is underlain by granular fill, which may potentially be variable due to previous site development, and was classified as non-engineered fill. Proof rolling was successfully adopted and avoided the construction of a new working platform over a 2 ha site, which would have been time consuming and costly. Non-linear stiffness theory was used to enable a lower than ultimate and practical proof rolling pressure to be adopted. It is considered that the performance-based approach adopted on this project may be similarly applied to a range of other projects to derive economic solutions.
Earthquake-induced bending moment in fixed-head piles in soft clay
Authors: BANERJEE S. , GOH S.H. , LEE F.H.
Published: June 2014

This paper examines seismic effects on fixed-head, end-bearing piles installed through soft clay, using centrifuge and numerical modelling. The numerical analyses were conducted using a non-linear hysteretic, stiffness-degrading model for the clay and were validated using centrifuge data. Numerical analyses were used to extend the range of soil, pile and ground motion parameters which could not be studied in the centrifuge. Based on the centrifuge and numerical results, a framework for estimating earthquake-induced bending moments in fixed-head piles was established, which takes into account superstructural mass, ground motion and, in an approximate way, non-linear stress–strain behaviour. In this framework, pile response is sub-divided into two kinds, namely, ‘stiff' and ‘flexible', based on the notion of an active length over which significant bending moment is developed. A relationship for the active length is developed based on regression of the centrifuge and numerical data. If the pile length is shorter than its active length, it is considered to be stiff and significant bending is expected to develop over its entire length. The regressed bending moment relationship for stiff piles shows that the stiffness of the pile–soil system is dominated by that of the pile, and non-linearity in the stress–strain behaviour of soil does not feature strongly. Piles whose lengths are longer than their active lengths are termed ‘flexible' piles. The regressed bending moment relationship for flexible piles shows that the supporting effect of the soil is more significant, and the non-linearity in the stress–strain behaviour of the soil correspondingly becomes more important. For all piles, the study shows that the pile head and soil masses have significant influence on the bending moment.
Mammals of Kenya's protected areas from 1888 to 2013
Authors: Tóth Anikó B. , Lyons S. Kathleen , Behrensmeyer Anna K.
Published: June 2014

Kenya is a world leader in conservation and host to one of the most diverse array of mammals on the planet. As a focus of scientific attention, it is important to be able to assess not only the current state of Kenya's mammal communities, but also how they have changed over anthropogenic timescales. Comprehensive lists of mammal species from known areas are essential for this goal, and these also provide comparative baselines for assessing changes in mammalian diversity in the future and in the fossil record. Though there is considerable literature available for mammals inhabiting Kenyan protected areas (National Parks and Reserves), species compilation projects vary greatly in scope, completeness, agreement, and accuracy. We combine the information in these databases for Kenya and supplement them with the most up‐to‐date knowledge available up to November 2013. Comprehensive historical species lists were compiled from specimen lists collected during 1888–1950 in ecosystems that today correspond to 13 different protected areas. We also provide analogous modern species lists based on data collected during 1950–2012. The data sets include both large and small mammals. A master list of a total of 413 species provides ecological information including body mass, diet, feeding and shelter habitat, and activity time. Historical data are based on museum specimens and sighting records, and modern data are based on museum data as well as literature, books, field guides, written accounts, photos, and videos. We used this compilation for an analysis comparing the two data sets (excluding volant and domestic species) for six protected areas with the most complete historical records and have shown in a separate publication that species richness is preserved, but beta diversity, based on pairwise comparisons of sites in this database, is being lost over the entire study area.
A Novel Fluid-Loss Control Pill That Works Without Filter-Cake Formation: Applications in High-Rate Gas Subsea Frac-Pack Completions in Indonesia
Authors: Gunawan I. , Bailey M. , Huffman C. , Simancas R. G. , Sanchez M. , Choudhary S. , Samuel M.
Published: June 2014

Loss of completion fluid during a completion or work over operation not only increases the chance of losing control of the well, but also can severely damage the formation. The best industry recognized method to stop fluid losses into the formation is to use mechanical fluid loss control devices. However, sometimes, the use of mechanical fluid loss control device is not applicable. Two examples where fluid loss control devices are not applicable are (1) Shoot and Pull Tubing Conveyed Perforating (TCP) before a gravel pack or a frac pack, and (2) Single trip perforating and gravel pack or frac pack completions. In these cases the use of fluid loss control pills is necessary. Traditional fluid loss control pills are associated with formation damage, clean up trips and annular pack plugging. This paper presents the application of a Viscoelastic Surfactantbased non-damaging lost circulation pill (VES-PILL) during the completion of sub-sea gas wells in the South China Sea for ConocoPhillips.

This novel solids-free fluidloss control pill was applied to insure well control after perforating and before frac packing. This paper describes the cases from the two wells of which one was completed as a single trip multi-zone frac and pack completion and the other as commingled stack frac packs. These commingled stack frac packs consisted of multi-zone frac packs and gravel pack on bottom and a conventional frac pack on top. Both single trip completions considerably exceeded the world record for the longest single trip gravel packed completion. In the first well, well control was achieved and the losses were controlled from 322 bph to 8 bph. In the second application, during a traditional shoot and pull, the losses were controlled from 60 bph to 0 bph. After completion, the wells were tested at 87 and 55 MMSCFD at 400 psi WHP, and were found to exceed pre-drilling production estimates by about 17-24%. This further confirms the non-damaging property of this VES-PILL.
Constrained LWD Resistivity Modeling for Improved Formation Evaluation of Horizontal Water Injectors
Authors: Al-Hajari A. A. , Ma S. M. , Geier R. , Butt P. , Hibler A. P. , Crary S. F.
Published: June 2014

Formation evaluation in horizontal wells is always a challenge because factors affecting resistivity measurements are difficult to identify and evaluate. These factors include shoulder beds, anisotropy, borehole size, and mud-filtrate invasion. In thick carbonate reservoirs, uncertainties in resistivity have only a minor effect on the formation water saturation of producers due to high formation resistivity which dominate the saturation calculation. Formation evaluation of water injectors drilled in water swept areas of thick carbonate reservoir is different due to low formation resistivity; errors in formation resistivity directly translate to errors in calculation of formation water saturation. Therefore, accurate formation evaluation of water injectors requires an accurate estimate of formation resistivity.

In this study, 1D and 2D resistivity modeling was performed on two horizontal water injectors each drilled between two vertical water injectors. The 1D modeling was used to identify the dominant factors affecting resistivity measurement and correct for environmental effects. These results, along with logs from the two vertical wells were used to construct a local geological model as input to 2D modeling. This geological model was refined by using logging while drilling density images of the two horizontal wells. Both 1D and 2D modeling results were constrained with the two vertical wells. Without modeling, formation water saturation calculated in the horizontal wells was too low. With the modeled formation resistivity, a more accurate water saturation was obtained in the horizontal injectors when compared to the vertical wells. This study demonstrated the power and usefulness of resistivity modeling in formation evaluation of water swept areas.
Effect of Gas Recycling on the Enhancement of Condensate Recovery, Case Study: Hassi R'Mel South Field, Algeria
Authors: Adel H. , Tiab D. , Zhu T.
Published: June 2014

Gas condensate reservoirs suffer losses in well productivity due to near wellbore condensate dropout when the flowing bottom-hole pressure declines below the dew point pressure. Pressure maintenance and gas cycling are the common practices used in the oil and gas field to alleviate this problem and develop gas condensate reservoirs. The injection of dry gas into a retrograde gas condensate reservoir helps in vaporizing the condensate and increases its dew point. This paper discusses a case study done on Hassi R'Mel South (HRS) field, Algeria to demonstrate the effect of gas recycling on condensate recovery. This study provides an insight into the effect of gas injection process in reducing gas-well productivity losses due to condensate blocking in the near wellbore region. This study also outlines some of the techniques for predicting the performance of gas-condensate reservoirs where gas-cycling is employed. An equation of state (EOS) with 6 pseudo components was used to characterize the complexity of hydrocarbon column. The model uses a grid system comprising of 22560 cells (94×120×2), and was historically matched with pressure and production data. The simulation study showed that recycling 100% of the gas produced is the best development scheme for HRS field. A total of 24% of gain in the condensate was obtained when 100% of the produced gas was recycled during the production. The condensate recovery was appeared to increase as the volume of gas injection increased. Based on an economic analysis, the simulation study indicates that recycling at 100% of the produced gas is the best development plan for HRS field.
Optimization of the Prediction of Hydrocarbon-Producing Zones Through Integration of Petrophysical Evaluation Methodologies in the Estancia Cholita Field, Gulf of San Jorge Basin
Authors: Vittore Franco , Pompei Javier , Ortiz Oscar , Pol Anthony
Published: June 2014

Up to now, different petrophysical methodologies have been developed to improve the success rate in selecting oil intervals in the Gulf of San Jorge Basin oilfields. These methodologies have been successful only in a limited number of cases and a solution that has field-wide applicability has been lacking. This project attempts to optimize previous results using an integrated petrophysical characterization workflow.

The geological complexity of the Estancia Cholita Field which is mostly due to limited lateral continuity and small reservoir bed thickness, particularly in the Castillo Formation, makes layer-by-layer correlation difficult. Several other factors add to the complexity of petrophysical evaluations, these include: alteration of petrophysical properties in certain zones near faults, variation of tuffaceous material content, formation damage, invasion of drilling fluids, zones with viscous oil, low and variable formation water salinity.

During this study, a two step petrophysical evaluation workflow was developed. The first step considers the application of quick-look log analysis techniques, specially the "Ratio" methodology, and the free fluid and permeability indexes (NMR), with the aim to evaluate those intervals of major potential in the well. The following step consists of a detailed analysis, in the zones where water production forecast has been identified, to calculate a formation water resistivity profile along the well.

Preliminary results of the study confirm that combining this methodology with local experience, layer-by-layer correlations, formation pressures data, log analysis, and supplementary information helps improve predictions of oil bearing zones in the Estancia Cholita Field.
Improving Oil Displacement Efficiency by Wettability Adjustment
Authors: Wagner O.R. , Leach R.O.
Published: June 2014

Because of unfavorable wetting conditions much residual oil is left when a porous material is flushed by water. Methods suggested to change reservoir wetting to improve oil displacement efficiency are generally expensive. The present laboratory study was undertaken to gain all understanding of the factors which determine reservoir wettability, and to find out if oil displacement efficiency might be improved by a wettability change accomplished at low cost in an oil reservoir.

Contact angle measurements were made on mineral surfaces using several sets of reservoir oil and water samples. Results of the contact angle studies suggest that reservoir wettability may be primarily determined by natural surface-active substances present in the reservoir fluids. The effect of changing salinity and pH of the water phase was studied. The results suggest that gross changes in preferential wettability might be accomplished by injection of water containing simple chemicals to alter pH or salinity in the reservoir. Such treatment could be much less expensive than injection of commercial surface-active agents.

Waterflood tests have also been made using synthetic cores and oil and water having wetting characteristics similar to those of reservoir fluids. Cores initially oil-wet were flooded in such a way that they were made preferentially water-wet by the advancing flood water. This reversal in preferential wettability achieved greater oil displacement efficiency than when either oil-wet or waterwet conditions were maintained throughout the flood. For the systems studied, the higher the oil viscosity the greater the percentage improvement obtained over conventional waterflood recovery. This suggests that a flooding process making use of wettability-reversal may extend the oil viscosity range over which water flooding is attractive.

Because a precise adjustment of reservoir wettability does not seem to be required, and because altering the pH or salinity in some reservoirs may be inexpensive, it appears that a waterflooding process employing wettability- reversal could find successful field application.
Identification, Characterization and Modeling of Naturally Fractured Reservoir Validated by Simulation Model
Authors: Bachiri Salim , Dahroug Ahmed , Belharache Mouloud
Published: June 2014

Hassi Messaoud field heterogeneous and tight reservoir modeling has for decades been a challenge.

While the matrix contains most of the fluid and the fractures contribute most to the fluid flow, conductivity is the result a complex network of fissures and fractures. The challenge here is to simulate naturally fractured reservoirs from both a reservoir description and numerical computation standpoint.

Current commercial numerical simulators are capable of handling flow in such complex reservoirs; the correct application of those simulators for representative reservoir models is yet another challenge.

The capability of numerical simulators to model reservoir performance is dependent on the quality of reservoir description. Thus the main task of any reservoir description technique is to divide the reservoir into subunits such as layers and grid block and to assign representative values of all petrophysical parameters to each unit.

This paper discusses parametric ways to improve construction of representative reservoir models of a sector of the largest field in North Africa. Discussion will focus on transition from single porosity representation to dual porosity models and the process employed in between. The study is categorized within the following three segments First, the petrophysical model construction for zone fourteen of the Hassi Messaoud field. Here an effective technique is used to uniquely describe all the petrophysical properties of naturally fractured reservoirs in terms of matrix porosity, fracture porosity, and cementation exponent at formation in-situ.

Secondly the identification and characterization of the reservoir via through integration of core analysis, well log interpretation, and pressure transient analysis.

Thirdly the validation of the generated model after up scaling of calculated reservoir properties, then the simulation and history matching of each well individually.
A Numerical Simulation Study on Surfactant Flooding and it's Field Application in Daqing Oilfield
Authors: Yin Daiyin , Pu Hui
Published: June 2014

Based on the non-Darcy flow characteristics of surfactant flooding, considering the changes of threshold pressure and influence of surfactant on convection, diffusion, adsorption and retention, a surfactant flooding mathematical model of three-dimensional, two-phase, three-component was established. A new method for the treatement of relative permeability curve and theoretical calculation equation for adsorption quantity of surfactant were derived, which enhances the matching degree between mathematical model and field practice. The method of implicit pressure, explicit saturation, and implicit concentration was used to solve equations and a simulator was developed. This simulator was used to perform the numerical simulation study for the pilot test of surfactant flooding in Chao 522 Block of Daqing oilfield, the optimal injection scheme was selected. After the optimized plan was carried out in oilfield, the desirable effects, like pressure-reducing, injection rate increase, and oil recovery increase, were achieved. The average oil increase for single well reaches 30%, the ratio of cost to revenue is above 1:3, so the very good development effect and economic effect were obtained.
Offshore Chemical EOR: The Role of an Innovative Laboratory Program in Managing Result Uncertainty to Ensure the Success of a Pilot Field Implementation
Authors: Zainal Suzalina , Manap Arif Azhan A. , Hamid Pauziyah A. , Othman Mohamad , Chong Mizan Omar , Yahaya A. Wafi , Darman Nasir , Sai Rithauddin M.
Published: June 2014

Ensuring a pilot project a success operationally, while gathering reliable data for a full-field implementation is critical. For this reason, various aspects of project planning and operational considerations need to be addressed. This include conceptual design, facilities and operational considerations, resources planning, integration of activities and most importantly, pilot objectives. However, all these planning will not be successful without a properly designed and executed laboratory test program. Such laboratory program will minimize result uncertainty and ensure the proposed pilot meet its objectives.

The first Chemical EOR (CEOR) pilot project in Malaysia involved an Alkaline-Surfactant injection utilizing high salinity injection water in a high temperature reservoir. It pioneered the Single Well Chemical Tracer (SWCT) method for EOR project evaluation in Malaysia. The main objective of the pilot is to assess the effectiveness of the Alkaline-Surfactant formulation to improve oil ultimate recovery through the reduction of residual oil saturation.

Being the first of its kind in Malaysia, an extensive laboratory program is required to ensure the injected alkaline-surfactant formulation performed at its most optimum and conclusive data is gathered. This data will be used as input to the future field development plan.

This paper presents a comprehensive laboratory test program covering pre-pilot, pilot and post-pilot laboratory analysis designed for offshore high salinity injection water and high temperature reservoir. It highlights the challenges imposed by offshore operation to design an optimum chemical solution considering that salinity and hardness of the water used to dissolve the chemicals are critical for an alkaline-surfactant system. It also discusses the continuous and controlled quality check process to validate the performance of the alkaline-surfactant solution. Finally, it presents the chemical adsorption study to evaluate chemical flood potential for the future full field CEOR implementation.
Modeling Fluid Flow in Deformable Fractured Reservoirs using Full Tensor Permeability
Authors: Bagheri M. , Settari A.
Published: June 2014

Several issues related to fluid flow in naturally fractured reservoirs are generally ignored or inadequately considered in ordinary reservoir simulation. These aspects include the variation of fracture permeability with stress and tensorial nature of the permeability field, either pre-existing or developed due to stress dependence. This study presents a methodology for taking into account these interrelated aspects of fluid flow and describes their implementation in a new advanced reservoir simulator. In order to capture all the interactions involved, a modular simulation system was developed consisting of a geomechanical model iteratively coupled with dual porosity reservoir simulator with the ability to handle variable full tensor permeability. The geomechanical solution uses the equivalent continuum approach, considering both rock and fracture deformation properties. The nonlinear stiffness of fractures varies with the effective stress according to a law typical for joints. The overall deformation is obtained considering the stress field and pore pressure provided from the flow module. The effects of the deformation of fractured media on fluid flow are rigorously captured using the decomposed deformation components of each media. Flow properties of each individual media (matrix and fractures) are then translated from their deformation components. Flow model then carries on with these new properties using a 27-point discretization technique of Multi Point Flux Approximation (MPFA).
Response Surface Methodology Approach for History Matching and Uncertainty Assessment of Reservoir Simulation Models
Authors: Slotte P. A. , Smørgrav E.
Published: June 2014

We present theory and application of a new approach for assisted history matching and uncertainty assessment. In a Bayesian framework the a priori geological information is conditioned to the production history to give the posterior probability distribution function (pdf). The full posterior pdf is explored to assess the uncertainty through ensembles of reservoir models sampled by a Markov chain Monte Carlo algorithm. To achieve this we construct proxy functions for the output of the flow simulator for all measurements that enter a global objective function. The proxy functions are constructed using polynomials and multi dimensional kriging. An iterative loop, in which ensembles of reservoir models are sampled from the posterior pdf, is run to improve the quality of the proxy functions.

The power of the application is demonstrated on two reservoir models. First we apply the method on a synthetic case. A modified reservoir simulation model from a small StatoilHydro operated oil field is investigated with a synthetic production history and 20 tuning parameters. Finally we apply the method to the StatoilHydro operated Heidrun field. A model which covers the upper formations of the field with 26 production wells, 11 injector wells, and 56 tuning parameters is conditioned to 11 years of production history. We show that it is possible to construct proxy functions accurate enough to describe the full posterior pdf and thereby assess the uncertainty associated with these reservoir models.
Modeling the Downhole Choking's Impacts on Well Flow Performance and Production Fluid Allocations of a Multiple-Zone Intelligent Well System
Authors: Sun Kai , Coull Craig , Constantine Jesse , Albrecht Kenneth , Tirado Ricardo
Published: June 2014

The intelligent well system (IWS) is normally operated with multiple-zone production/injection in the commingled condition, which makes it difficult to predict the effect of IWS operations on well flow performance and zonal deliverability. This is because: 1) The production string, downhole control equipment and isolation tools separate production fluids into different flow paths (tubular/annulus), and the different flow paths have different resistance to each zone's outflow; 2) the reservoir and fluid properties of individual zones are normally different, and these varying properties will cross-impact the outflow of each other's zones when fluids are commingled; 3) downhole choking operations will impact the wellbore pressure profile, thus impacting the production profile from each zone; and 4) Simulate the fluid temperature profile and the effect on pressure and flow profile for the IWS completion is a complex task. The current published works have not covered the whole spectrum.

To address this situation, an analysis tool has been developed, combining the developed comprehensive thermal model with integrated inflow performance relationship (IPR) technology and innovative operation point searching algorithm. For any downhole choking operation scenario, the flow allocations and profiles of wellbore pressure, temperature and fluid velocity can be predicted. This provides the operators insight into how to choke the downhole valves to meet the production enhancement target. It also gives an insight of how we customized the design of the downhole valve settings to achieve the production objectives. In addition, the threshold pressure at commingle point to control crossflow can be predicted through this technology, which provides potential ability to control/monitor possible crossflow of multiple-zone production through the intelligent well monitoring and control system. For demonstration purpose, a potential case study of a typical deep-water two-zone IWS was used for analysis. Model verifications were provided by comparison with the third-party software. Analysis and comments of the comparison have been provided.
Deriving Matrix Properties, Fluid Types and Saturation from RST-CHFR Combination in Siegenian Reservoir of Bir Berkine Field, Algeria
Authors: Okuku Chris , Abdellatif Zanoun , Ali Hamoudi , Noureddine Kanit , Mokrani Nabil
Published: June 2014

Drilling under severe borehole instability conditions can result in the well being side tracked or worse, abandoned. In some cases, casing can be run quickly, but this leaves the well completed without the opportunity to acquire the essential openhole suite of logs for quantitative formation evaluation. In the absence of openhole data, the use of Analysis Behind Casing (ABC) suite of tools such as the Reservoir Saturation Tool (RST) and the Cased Hole Formation Resistivity Tool (CHFR) allows rock matrix properties, fluid type and saturation to be derived.

This approach was implemented in the Siegenian formation for a well in Bir-Berkine Field. Casing restriction of 4.5" limited the option of the ABC logging suite to only RST-C (111/16") and CHFR (33/8"). The RST was used mainly for acquiring data for formation matrix estimation, porosity and oil saturation through the inelastic and Sigma acquisition modes. Moreover, the CHFR tool was used to obtain the resistivity of the formation. Offset wells information was used for the calibration of the cased hole data.

Three independent saturations were derived from the Inelastic, Sigma and CHFR measurements. Comprehensive comparison and integration of those results were carried out.

Quantitative formation properties like clay, calcite and quartz volumes combined with porosity and water saturation were estimated. The three independent estimated saturations indicated that the zone of interest was a potential oil bearing formation. The reservoir was perforated resulting in good oil recovery.

Integration of ABC logs in contingency situations like this one provides a successful alternative to quantitative formation evaluation with openhole logs.
Immiscible Gas Injection: Challenges, Example of the 16th TH Horizon, Austria
Authors: Gruenwalder Markus , Clemens Torsten
Published: June 2014

The 16th TH horizon is a mature oil reservoir located about 20 km east of Vienna. Screening of the reservoir and EOR technologies revealed that from one of the reservoir compartments incremental oil might be produced by gas injection.

In 2007, injection of various gases into this reservoir compartment (OOIP 86 MMstb) was investigated. An EOS model was created and slim tube experiments were performed. The results of the slim tube experiments indicated that neither CO2, CH4 or N2 are miscible with the 24.8 API oil under reservoir conditions of 120 bars and 60 degrees centigrade.

Injection of CO2, CH4 and N2 was investigated using a sector and full-field model. The results show that incremental recovery compared to the base case is only about 1.5%. Owing to the oil viscosity 5.5 cP, the gas viscosity 0.02 cP, the oil density 855 kg/m3, the CO2 density 290 kg/m3 and the reservoir thickness of 30 m, severe gas override occurs in the reservoir. The small dip of the reservoir of 2-4 degrees and high in-situ oil viscosity lead to a small gravity drainage rate, hence the incremental recovery is limited.

At a first glance, the project could be economically attractive though. The field is located close to Vienna where some pure CO2 is emitted. The CO2 emitted could be injected to reduce greenhouse gas emissions and generate emission trading certificates.

However, in the course of the study, it was seen that significant acceleration potential exists in this horizon. Accelerating oil production leads to faster perforation of the wells upwards towards top structure. Combining gas injection with acceleration of oil production reduces the incremental oil production by this technology. The reason is early gas breakthrough in the production wells perforated at the top of the formation due to gas override.
Optimization of Well Placement Using Evolutionary Algorithms
Authors: Ding D. Y.
Published: June 2014

Non-conventional wells allow to increase considerably hydrocarbon recovery. By considering the high drilling cost and the potential earn in well productivity, optimum implementation of non-conventional wells is an important issue in petroleum industry.

Considering large number of parameters involved in well placement and high reservoir heterogeneities, stochastic methods such as evolutionary algorithms are the most efficient approaches for optimization. In this paper, we present the CMAES (Covariance Matrix Adaptation - Evolution Strategy) method, which is based on evolutionary approach and has been considered as one of the best stochastic optimization method for non-linear problem. The application of CMAES to the problem of well placement optimization is presented. CMAES is an alternative approach for the well placement, and it gives comparable results with respect to the genetic algorithm.

Although the evolutionary methods such as CMAES or genetic algorithm are suitable for the modelling of well placement, their efficiency depends on various parameters involved in the model. In this paper, the impacts of model parameters in the optimization of well placement are also discussed.
Fluid Flow Simulations on Core Samples Containing Natural Fractures and Stylolites
Authors: Basquet Rémy , Rennan Lars , Ringen Jon Knut , Wennberg Ole Petter
Published: June 2014

This study aimed to understand the impact of natural open fractures and stylolites on flow in a porous sandstone reservoir by analysing fluid flow behaviour at small scale (core sample). This analysis was done both experimentally and with fluid flow simulations within full core samples.

Two core samples (seal peels) from the Snøhvit field in the SW Barents Sea were selected. These contain natural open fractures mostly associated with stylolites. Since no test data exist from the intervals with highest fracture intensity, it remained uncertain whether these fractures will affect the flow in the reservoir. Two series of flooding experiments were conducted on these core samples, one by tracer injection and the other by injecting gas (Nitrogen) in the 100% brine saturated seal peels.

Computed tomography (CT) scans were used to image the fracture/stylolites system, to monitor the flooding experiments and to build a consistent simulation model.

Single and two phase flow simulations were performed to mimic the experiments. First, the fractures and stylolites effective properties were determined via tracer injection experiments by matching the tracer production profile. Then, to simulate the gas injection, relative permeability and capillary pressure (Kr-Pc) curves generated from special core analysis (SCAL) measurements were applied for the matrix medium. For the stylolites, the same Kr curve was used and modified Pc applied. For the fractures, a linear Kr curve and no Pc were used. As a result, a good quality match was obtained, giving an understanding of the influence of a fracture/stylolites system on the flow within porous sandstone.
Next-Generation Sand Screen Enables Drill-In Sandface Completions
Authors: Coronado Martin P. , Pickle Brad R. , O'Malley Edward J. , Patel Paresh
Published: June 2014

Following successful field applications of solid-liner drill-in systems, efforts now focus on drill-in sand screen liners. This paper will discuss enabling technologies to meet the peculiar challenges of drill-in sand screen liners.

The screen liner must contain pressure when drilling to allow circulation through the bit and wellbore inflow during production. The screen's filtration media must also be protected from possible plugging during drilling. Rotating the screen liner to allow circulation may damage screens, so a drilling motor at the bottom of the liner drives the bit. Conveying fluid to the motor using a conventional inner circulating string may add sufficient weight to significantly limit horizontal and highly deviated well angles.

This paper addresses a technology that temporarily blocks flow through the screens during drilling to allow a pressure-tight circulation path through the liner to the motor without the need for an inner circulation string. Once drilling is complete and the liner is in place, the screen joints are simultaneously opened using hydraulic pressure applied within the liner, and the well is ready to be put on production. Temporarily closing off of the screen joints also has additional applications, such as simultaneously setting hydraulically-set open-hole packers without an inner circulating string.

The paper also discusses a time- and temperature-sensitive protective film applied to the screens during fabrication to prevent fluid egress into the filtration media until the film dissolves. Sufficient time for dissolution is designed into the film to allow the liner to be drilled into place while protecting the screen's filtration media from possible plugging during drilling.

Testing and applications of these technologies are discussed, along with economic advantages resulting from savings in rig time and improved success rates for properly placing screen liners. Operational aspects associated with this new system are outlined with regard to system components and job design.
Over 100 Conformance Fracturing Operations in Brazil: Results and Improvements
Authors: De Melo Ricardo C. B. , Aboud Ricardo S.
Published: June 2014

Many of the mature oil fields in the world produce commingled water. Water production increases the lift cost of a barrel of oil, as it needs surface handling when it is to be disposed, re-injected into other wells, or used for a different purpose.

Several techniques and chemistries have evolved over the past decades to address reduction of unwanted produced water. These different approaches to minimize water production are grouped under the name of water conformance. Selecting the proper water conformance method for a well depends on the correct understanding of the reservoir. Economics remains the main decision driver as to which technique and chemistry to use.

A quite effective technique among the different water conformance methods is conformance fracturing, a combination of hydraulic fracturing and water control. Among several operating companies, hydraulic fracturing still is the preferred technology to increase well productivity. The development of a family of lightweight proppants for hydraulic fracturing has allowed a more uniform fracture height and width, due to a lesser degree of proppant settling inside the fracture, resulting in a better connectivity with the wellbore and lower chance of breaching nearby water zones. On the other hand, chemistry of relative permeability modifiers (RPM) has been greatly improved over the past decade, and one can observe longer life on water control treatments done using RPMs.

In Brazil, we have conducted over 100 conformance fracturing operations to date, using conventional as well as lightweight proppants, and relative permeability modifiers, to meet the different targets they were deployed for.

This paper will summarize these treatments (design, logistics, materials, equipment), with obtained results (oil and water production over time), showing the improvements made over time.
Optimized Recovery from the Fram Øst Development through Extreme Well Design
Authors: Thorsen Arve K. , Gravem Trond , Manseth Arvid , Klausen Trond Skei , Øvrebø Torbjørn
Published: June 2014

Field development in mature areas of the Norwegian Continental Shelf (NCS) is changing from giant fields to minor localized hydrocarbon traps often made up of isolated and rotated fault blocks. The existing infrastructure needs to be utilized to make the additional reserves economic. Being a marginal part of a mature area, the existing subsurface and reservoir information is very limited.

The cost involved in field developments on the NCS is substantial and additional appraisal wells are often too costly, delaying the field development and increasing total cost. The solution to gain the information needed and to place the well optimally within the reservoir, is to have enough flexibility in the well design to evaluate and change the planned well trajectory based on the information acquired during drilling. The well trajectories in these cases are horizontal producers with normally one main bore in each fault block.

This case describes the application of precise 3D Rotary Steerable System and LWD measurements which enable accurate identification of the Oil-Water-Contact, Gas-Oil-Contact and top reservoir, for a horizontal well through multiple branches drilled from one main bore in a single continuous operation. The valuable information, obtained through controlled sidestep exploration drilling, provides additional knowledge to optimize the producing main bore. Horizontal wellbore placement is supported by real-time reservoir characterization through real-time formation pressure measurement to validate any fluid movements and fluid compartmentalization of the reservoir. Being able to perform this in a single run accentuates the unique effectiveness and flexibility available in the well construction process.

In this marginal field development in the North Sea realtime data acquisition and accurate well placement play a significant part in the success of the field development and illustrates to what extent precise 3D RSS and answers from LWD data help in effectively optimizing well placement and reservoir characterization.
Finite Element Modelling of Casing in Gas Hydrate Bearing Sediments
Authors: Salehabadi Manoochehr , Jin Min , Yang Jinhai , Haghighi Hooman , Ahmed Rehan , Tohidi Bahman
Published: June 2014

Casing integrity in shallow marine sediments could be challenging if natural gas hydrates exist in the sediments. Elevated wellbore temperature during drilling of deeper sections of deep offshore wells can cause in-situ gas hydrates to dissociate, thereby increasing pore pressure and altering the mechanical properties of the sediments. Gas hydrate can also dissociate during setting and/or cementing, causing gas release which could result in delaying completion of the wellbore due to the flow of gas around the casing (conductor pipe) or affecting the casing integrity or casing stability by creating voids (channels) in the cement sheath leading to non-uniform stress loadings.

In this communication, a numerical model is developed using a finite-element code to simulate the stability of casing in gas hydrate bearing sediments by considering the interaction between the formation, the casing, and the cement with coupling the thermodynamic stability of the hydrates to hydraulic, mechanical and heat transfer terms. The mechanical and hydraulic terms are fully coupled and the coupling between mechanical and thermal terms is modelled through staggered technique (one-way coupling).

To model the worst-case scenario, the permeability of gas hydrate bearing sediments is assumed very low as a result the gas and water generated during gas hydrate dissociation cannot flow and will increase pore pressure. The mechanical property degradation of formation due to hydrate dissociation is represented in the model by cohesion softening as a function of dissociated gas hydrate saturation.

The developed numerical model is found to be very useful in understanding the behaviour of wellbores drilled in gas hydrate bearing sediments, which will help the determination of the resultant stress fields and enable a more accurate determination of the required casing strength.
Effect of Heterogeneity of Layered Reservoirs on Polymer Flooding: An Experimental Approach Using 5- Spot Glass Micromodel
Authors: Emami Meybodi H. , Kharrat R. , Ghazanfari M. H.
Published: June 2014

Despite the numerous experimental studies, there is a lack of fundamental understanding about how the local and global heterogeneity control the efficiency of polymer flooding. In this work a series of water and polymer injection processes are performed on five-spot glass micromodels which are initially saturated with the crude oil at varying conditions of flow rate, water salinity, polymer type and concentration. Three different pore structures in combine with different layer orientations are considered for designing of five different micromodel patterns. It has been observed that the oil recovery of water flooding is increasing with the salinity concentration, for the ranges studied here. While, it shows there is an optimum value of concentration in which maximize the oil recovery in polymer flooding. The results confirmed that the highest oil recovery is obtained when the layers are perpendicular to the mean flow direction for both water and polymer flooding. Also, the oil recovery in polymer flooding increases with the increase of layer inclination angle, however it does not increase for waterflooding. In addition, the oil recovery is strongly affected by the local heterogeneity which is near injection zone. This study demonstrates the applicability of micromodel for studying of enhanced oil recovery techniques in locally and globally heterogeneous five-spot models.
A New 3-D Numerical Model to Effectively Simulate Injection Tests
Authors: Verga F. , Viberti D. , Borello E. Salina
Published: June 2014

Conventional well testing is becoming less and less attractive due to environmental constraints and high costs. It is likely that injection/fall-off tests will largely replace the conventional production/build-up sequence since they eliminate surface emissions and can significantly reduce testing costs. However, the welltest interpretation is complicated because of the presence of two phases, the fluid originally in place (hydrocarbon) and the injected fluid (diesel or brine). Fluid saturations vary during injection and the assumption of a piston like displacement is valid only for very favourable mobility ratios. Thus the variation of fluids distribution with time is governed by effective permeabilities, but also gravitational and thermal gradients, heterogeneity and anisotropy might strongly affect the flow. As a consequence, the conventional analytical approach used to describe the pressure transient behaviour is no longer applicable, and only numerical simulations can thoroughly describe the evolution of saturation and pressure fields in the reservoir during injection and subsequent fall-off. The correct determination of the fluid distribution is critical for evaluating the skin due to the presence of two phases in the reservoir, and in turn the skin value, together with permeability, is essential to calculate the well productivity.

A new near wellbore, 3D numerical model was developed and implemented for properly designing and interpreting injection tests in both oil and gas reservoirs. The model accounts for all the aspects that can impact on fluid and pressure distribution. The simulation results are provided in terms of pressure and pressure derivative for subsequent analyses. The reliability of the results were verified against commercial well testing software packages under simplified conditions, i.e. isotropic and homogeneous formation, negligible gravitational, capillary and thermal effects. The advanced options of the model were then applied to simulate injection tests with thermal exchange between fluids in oil and gas reservoirs. The results are presented in this paper.