bluuebunny/crossref_metadata_2025_split huggingface dataset:
Debris Management System for Pressure-Controlled Wellbore Drilling and Intervention Operations
Authors: DeMong K. , King G. E. , Odegard S. 
Published: September 2011

Abstract
In shale gas horizontal wells with multiple intervals completed, the predominant completions method has been multistage fracturing while plugging with drillable bridge plugs and jet perforating the cemented casing. Typically the bridge plugs are drilled out under pressure with coiled tubing. The ability to optimize drilling/milling parameters while drilling out with pressurized coiled tubing has been hampered by the lack of information in the coiled tubing cab about the speed that debris is generated, the size of debris generated, and whether the circulation fluid properties and rate are sufficient to remove the debris from the hole. In response to dealing with challenges of drilling out bridge plugs and performing other pressurized intervention work in long horizontals, a new surface debris management system was developed and successfully tested. Using the new system, a clearer picture emerges regarding the conditions being created down hole. This system has aided in optimizing drilling and circulating parameters and has resulted in faster bridge plug drill outs, cleaner casing and fewer drilling and intervention problems.
Modelling of Depletion-Induced Microseismic Events by Coupled Reservoir Simulation: Application to Valhall Field
Authors: Zhang Xing , Koutsabeloulis Nick , Kristiansen Tron , Heffer Kes , Main Ian , Greenhough John , Hussein Assef Mohamad 
Published: September 2011

Abstract
Reservoir depletion/injection results in changes in effective stress, which may cause formation failure, propagation of existing fractures/faults and initialisation of new fractures/faults. A flow-deformation coupled reservoir geomechanical modelling approach has been applied to compute the change in reservoir effective stress and associated propagation of fractures and reactivation of faults. The computed inelastic strain change was used to predict the magnitudes of microseismic emissions associated with fault reactivations. The moment magnitude of microseismic events, consistent with the Richter scale, can be computed from the scalar value of their moment tensor. In a discontinuous model, the moment tensor can be calculated directly; in finite element models, the moment tensor is calculated by integrating the change in inelastic shear strain over the volume of the elements containing the failed fault.
Coupled 3D geomechanical (deformation and fluid flow) simulations for Valhall field were conducted. Well rate and reservoir pressure histories were used as inputs to simulate reservoir depletion/injection. The 99 faults visible on seismic interpretations and 22 subregional fracture sets were included in the model. An elasto-inelastic cap model including water-weakening mechanism was used to model the chalk reservoir; the failure of faults and fractures were simulated by Mohr-Coulomb criterion. Prior to performing production simulation, preproduction stress modelling was carried out to reach an equilibrium stress state that was consistent with the in-situ condition, in terms of magnitude and orientation. Then, oil production at 112 wells and water injection at 15 wells for the period from 1982 to 2006 were simulated, during which the simulated microseismic events were in a good agreement with observations. The computed formation deformation in the reservoir and overburden was related to the in situ stress and faulting structure and was correlated over long distances. These characteristics are indicative of a near-critical process (and are also observed in flow rate correlations in the field). The coupled 3D geomechanical simulation provides a tool for validating modelled reservoir geomechanical effects against specific field data, and so enhances confidence in the implications predicted for drilling operations and reservoir management.
An Analytical Method for Predicting the Performance of Gravitationally-Unstable Flow in Porous Media
Authors: Farajzadeh R. , Meulenbroek B. , Bruining J. 
Published: September 2011

Abstract
In this paper we follow a similar procedure as proposed by Koval (1963) to analytically model the performance of gravitationally unstable flow in porous media. The Koval model is analogous to the Buckley-Leverett method and multiplies the heterogeneity index of the system as an input (H-factor) with the fluid-flow (here gravity) induced instability factor, E to obtain the Koval factor KG = HE. This paper only considers the gravity induced instability factor E (H=1). The Koval factor is implemented in a modified fractional flow function that includes a dilution effect when the CO2 moves away from the interface to describe countercurrent gravity flow. The pseudo two-phase flow problem provides the average concentration of CO2 in the brine as a function of distance. The KG-factor can be used in commercial simulators to account for the density-driven natural convection, which cannot be currently captured because the grid cells are typically orders of magnitude larger than the wavelength of the initial fingers. Such natural convection effects occur in storage of greenhouse gases in aquifers and EOR processes using carbon dioxide or other solvents.
A comparison of the analytical model with the horizontally-averaged concentrations obtained from 2-D numerical simulations provides a correlation for calculation of the KG-factor for different Rayleigh numbers. The model shows a rarefaction followed by shock-like behavior because the CO2 concentration decreases away from the gaseous CO2-liquid interface. The agreement between the analytical model and full numerical simulation is practically acceptable. We leave the introduction of the heterogeneity factor for future work.
Application of Toe-to-Heel Air Injection (THAI) Process in Fractured Carbonate Systems: 3D Simulation of the Effect of Fractures Geometrical Properties, Reservoir and Operational Parameters
Authors: Fatemi S. Mobeen , Ghotbi Cyrus , Kharrat Riyaz , Badakhshan Amir 
Published: September 2011

Abstract
Toe-to-Heel Air Injection (THAI) Technology, a new heavy oil recovery process to overcome Conventional Fire Flooding (CFF) defects, has been studied on non-fractured sandstone models and is found a promising Enhanced Oil Recovery (EOR) method for certain heavy oil reservoirs, but its applicability on fractured carbonate heavy oil reservoirs, such as those in Middle East, remained questionable. The objective of this paper was to evaluate the effect of fractures geometrical parameters such as fracture density, orientation and networking on the THAI process performance for a low permeable naturally fractured carbonate heavy oil reservoir in Persian Gulf coast namely "Kuh-E-Mond". To approach the problem, a combustion tube test using field crude oil and crushed carbonated rock performed and numerical model developed and validated according to the experimental results. Validated model modified to 3D to investigate the performance of THAI. THAI performance was studied in conventional and fractured models consisting fractures in Between Wells Region (BWR), Horizontal Well Region (HWR), vertical, horizontal and networked fractures. Ultimate oil recovery and recovery rate decreased in all fractured models as compared to the conventional case. Higher traversal fractures density reduced ultimate oil recovery. Near injector traversal fractures have less disastrous effect on the process performance. In the case of networked fractures (presence of both longitudinal and traversal fractures), accompany of longitudinal fractures enhanced the recovery achievable in the case of traversal fractures. Simulation results showed that THAI is more applicable on highly networked fractured reservoirs such as those occur in Middle East compare to lower density fractured reservoirs
A New Model for Predicting Water Cut in Oil Reservoirs
Authors: Kewen Li , Yangtze U. , Xianghai Ren , Yangtze U. , Li Li , Xiaodong Fan 
Published: September 2011

Abstract
Water cut is an important parameter in reservoir engineering. For example, water cut data may be used for the estimation of reserves and ultimate oil recovery as well as reservoir surveillance and management. However it is difficult to predict water cut in water flooding reservoirs. Simulation technique could be used to forecast the water production, but it is time consuming, expensive, and often require information that is not readily available. Fractional flow analysis can easily be conducted using only a spreadsheet. However, most of the traditional models represent water cut as a function of cumulative oil production instead of production time. Note that cumulative oil production itself needs to be estimated or predicted. To this end, we derived a new model that correlates water cut and production time in oil reservoirs. It is easier to predict water production and estimate the performance as a function of production time when using this new model than when using traditional ones. The proposed model has been tested using production data from many oil wells and several reservoirs with a wide permeability range. The results have demonstrated that the proposed new model works satisfactorily in most of the cases studied.
Experimental Study of Water Shut-Off by Wettability Alteration to Gas Wetness
Authors: Li Kewen , Yangtze U. , Zhang Haoping , Peking U. 
Published: September 2011

Abstract
Gas wells may suffer significant decline in gas production or even get killed because of the water invasion into production zones. Closing off the water producing zone may not be acceptable in many cases. In this study, the feasibility of reducing the water production in gas wells by changing the wettability of the gas zone from preferential water- to gas-wetness using fluorine carbon surfactant has been investigated experimentally. The basic mechanism was that the entry capillary pressure has to be overcome prior to water entering the gas zone. Naturally water can imbibe into gas zones spontaneously because the rock in gas zones is water wet, most probably. After the wettability alteration from water- to gas-wetness, water cannot enter into gas zones if the differential pressure is less than the entry capillary pressure and the water flux will be significantly reduced even if the differential pressure is greater than the entry capillary pressure. An artificially made, consolidated two-layer core model was used to conduct the study. The two layers had different permeability and the top layer was served as the gas zone and the bottom layer served as the bottom aquifer. The gas production was measured at different initial water saturations with and without wettability alteration from preferential water- to gas-wetness in gas zone. The experimental results showed that the water breakthrough time could be postponed and that the amount of water invaded into the gas zone could be reduced significantly by altering the wettability of the gas zone to gas wetness. The advantages of this approach to reducing water production were: 1) the permeability of the gas zone was not affected notably by the chemical treatment for wettability alteration; 2) the chemical treatment for wettability alteration had great longevity.
Combining Experimental Design with Proxy Derived Sensitivities to Improve Convergence Rates in Seismic History Matching
Authors: Arwini Saleh , Stephen Karl D. 
Published: September 2011

Abstract
An assisted history matching method has been developed where simulations are quantitatively compared to observed 4D seismic and production data and then updated in an objective manner. The approach uses experimental design to initialise a stochastic parameter search but also to derive a proxy model of the misfit between observations and predictions. The proxy model is then used to guide the stochastic search algorithm to speed up convergence. Updating of the proxy model periodically during the search improves convergence further.
The approach was applied to the Schiehallion UKCS field where we use 6 years of production along with six 4D seismic surveys. The proxy model, a quadratic regression equation, was derived for the combined misfit of both production and seismic data. Transmissibility of a number of barriers and faults as well as permeability and net:gross (NTG) were modified to improve the history match.
The approach improves the efficiency of finding the best models. Experimental design reduces the number of models to initialise the stochastic approach by a factor of 10. Continuous updating of the proxy not only leads to three times faster convergence but also enables better models to be found. History matching without experimental design or proxy derived gradients reduced the production misfit by sixty six percent while our new method gained a further ten percent reduction. We improved the exploitation of misfit information without compromising exploration of the parameters.
History matching is a very important activity during the development and management of petroleum reservoirs. Obtaining matched models is fundamental to ensure reliable future forecasts, and give an improved understanding of the geological description and the dynamic behaviour. Improved recovery factors can then be achieved by accurately locating infill wells and maintaining production longer.
The Potential of Smart Well Solutions for the Development of Thin Oil Rims during Gas Condensate Production in the Yamal Region of Russia
Authors: Fayzullin M. F. , Nasibullin A. Z. , Yazkov A. V. 
Published: September 2011

Abstract
The paper focuses on the simulation case study of smart technologies for horizontal wells for the development of thin oil rims in the center of Russian gas condensate production.
Operating companies worldwide are turning to intelligent completions to mitigate the consequences of uneven drawdown and reservoir heterogeneity along the wellbore. The proposed enhancements have proved its applicability to increase oil-part profitability of the highly productive formations offshore Africa and the North Sea. Following recent completion advances, the oil rims common in the Yamal region of Russia could be good candidates to be smart instead traditional well interventions which may be more costly or ineffective.
We describe a systematic workflow that can be used to evaluate the viability of such technologies, specifically in thin oil rims. The intent then is to improve oil recovery at the simultaneous production from oil and gas zones. We analyze a number of horizontal well completion designs with stingers and ICV by means of simulation models. The models consist of a multisegment well option from a commercial software program. The ICV simulation, compared with models of conventional reduced well designs, predicted an additional 2–3% of oil recovery over 10 years. Additionally, it also indicates CAPEX would be 5-7 times more and operating risks are much greater. Summarizing, the results showed current limitations and effects of each smart solution but also forced us to consider production on the supercritical gas rate modes: naturally flowing production with gas breakthroughs controlled at the wellhead. Finally, the economic and risk screening criteria are introduced pointing to the optimum recommendations for development decisions.
Estimation of Multiple Petrophysical Parameters for the PUNQ-S3 Model Using Ensemble-Based History Matching
Authors: Li Heng , Yang Daoyong 
Published: September 2011

Abstract
Reservoir simulation and modeling remains a cost-effective tool to characterize geological structure, determine fluid saturation, and optimize reservoir performance. In spite of extensive research work, it remains a challenge to generate multiple reservoir models conditional to static and dynamic data that represent a correct sampling of the true posterior probability density function. Although many challenges remain, the ensemble Kalman filter (EnKF) technique has recently been proved to be an efficient data assimilation method and successfully used in assisted history matching for estimating reservoir petrophysical parameters, such as porosity, absolute and relative permeability, and fluid-contact depth. Few attempts have been made to study impacts of simultaneously tuning multiple parameters on the estimation results. In this study, the ensemble-based history matching has been successfully applied to simultaneously estimate multiple petrophysical parameters for the PUNQ-S3 model. More specifically, the selected tuning petrophysical properties include horizontal and vertical permeability, porosity and three-phase relative permeability curves. Four data assimilation scenarios with different combination of the tuning parameters have been evaluated. The ensemble-based history matching technique is found to be capable of estimating multiple petrophysical parameters by conditioning the reservoir geological models to production history. The uncertainty range of production data generated from the updated models is reduced compared to that of initial models. However, the history-matched models may not always provide good production prediction results, especially when absolute permeability and relative permeability are tuned simultaneously. This further illustrates the non-uniqueness of the history matching solutions. In addition, for the PUNQ-S3 case examined in this study, three-phase relative permeability curves can be estimated with good accuracy when absolute permeability fields are known.
Relative Permeability Prediction from Image Analysis of Thin Sections
Authors: Hossain Zakir 
Published: September 2011

Abstract
The objective of this study is to define the physical basis approach to calculate relative permeability of reservoir rocks from image analysis of thin section. Relative permeability is one of the most important parameter and widely used for reservoir characterization. Relative permeability is only measured in the laboratory. To measure relative permeability in the laboratory are expensive and time consuming. Alternatively relative permeability may be estimated from numerical methods such as Lattice-Boltzmann and network modeling. To applying the all method need lot of computational effort and the physical justification of relative permeability estimation remains hidden. A simple and powerful equation to estimate the absolute permeability from porosity and specific surface area is the Kozeny’s equation. Darcy’s assumption was applied to Kozeny’s equation to calculate relative permeability of two phase-fluid flow without introducing any empirical factor. Numerical simulation and image analysis processing technique were applied to check the consistency of Kozeny’s approximated relative permeability model. Relative permeability predicted from Kozeny’s approximation was compared with permeability predicted from Lattice-Boltzmann flow simulation as well as with laboratory measured data. Relative permeability predicted from numerical simulation and image analysis techniques are well agreed with permeability predicted from Kozeny’s approximation. Relative permeability predicted from Kozeny’s approximation are also comparable with permeability predicted from Lattice-Boltzmann flow simulation as well as with laboratory measured data. Given permeability model in this study is the physical basis approach and may used to calculated relative permeability from image analysis of thin section.
Reversible Platform
Authors: Christino F.. , Costa B.. , Jacinto A.. , Melo M.. , Pereira O.. , Schlüter H.. 
Published: September 2011

Abstract
This paper presents a way to adjust an oil production offshore platform unit, specifically its liquid processing plants, to the new conditions of production that appear throughout the productive life of an oil field. For in such a way, due to the increase the amounts of water and decrease of produced oil, equipments, firstly, destined to the oil treatment can be converted into equipment for water treatment. In this way the connections between such equipments are modified in order to be adjusted to the new situation.
This invention, witch is the subject of a Brazilian Patent Application, can be useful to adequacy an oil offshore platform to its actual situation, i. e. when the produced water flow increase much more than its water treatment facilities. In this way we can debottleneck the produced water treatment system prevent closing the wells and, even so, boost the oil production. The invention can also be applied in new projects, in order to prevent such future difficulties.
As a results among, approximately, twenty platforms we've already been on board 80% of them was identified in such conditions, i. e, they are closing well and losing oil production, so we can do the modifications just now. Moreover we identify a situation where, just doing little arrangements, it will be not necessary to operate one of them (a semi submersible unit with a180 000 bpd capacity). It could be moved to another field to produce oil.
We must highlight that the proposal presented seems to be simple, but it is extremely advantageous, since it makes possible to adjust an installation in operation to a not foreseen situation of fluid treatment.
As a conclusion this methodology is mainly appropriated to a mature field optimization.
As a Significance of Subject Matter we can register that with these procedures it is possible to keep and, most of the time, increase the oil production and, moreover, to increase the platform's live.
Innovative Combination of Dynamic Underbalanced Perforating with Emulsified Acid and Non-Damaging Viscoelastic Surfactant-Based Fluids Boost Productivity in Low-Permeability Naturally-Fractured Carbonates
Authors: Cesin S.. , Fayard A.. , Camarillo J.. , Lian E.. , Flores J.. , Flores P. Tejeda , Mendo A. Rosas 
Published: September 2011

AbstractThe fields in southeastern Mexico have produced from Cretaceous and Jurassic-age naturally-fractured carbonate reservoirs since the early 1970s. Many recent exploratory wells drilled and completed in these high-pressure, high-temperature formations have yielded unsatisfactory results due to a combination of causes, including severe drilling-induced formation damage to low-matrix permeability reservoirs. Conventional completion and stimulation treatments to remove and bypass the damage have yielded satisfactory results in some cases but not in others. To increase productivity from new discoveries, an integrated approach to the completion and stimulation of low-permeability naturally-fractured carbonate reservoirs is proposed.An innovative technique, combining dynamic under-balanced perforating with a highly-stable emulsified acid and a non-damaging viscoelastic surfactant-based acid, is presented in this paper. Three successful applications in southeastern Mexico are documented, including a low-productivity development well; a well originally perforated and stimulated using conventional technology; and an exploratory well, resulting in substantial production increases in all three cases. These applications served to prove that the combined effect of the proposed completion and stimulation technologies was the enabler to achieve superior production results. The highly-retarded emulsified acid pumped through clean perforating tunnels produces longer fracture penetrations, positively impacting the performance of low-permeability reservoirs and resulting in improved production responses. At the same time, the viscoelastic system reduces leakoff, which is necessary to extend fracture lengths further in the reservoir. The fluids combined in a high-rate pumping technique that consisted of alternating stages of emulsified acid, main acid, and diverter reduced the creation of wormholes near the wellbore, thus increasing the penetration of the treatment in the reservoir.