bluuebunny/crossref_metadata_2025_split huggingface dataset:
Advances in Petroleum Reservoir Monitoring Technologies
Authors: Islam M. R. 
Published: December 2007

AbstractMost oil fields do not produce more than 45% of the oil-in-place, even after enhanced oil recovery schemes have been applied. Most of this unproduced oil is missing because most displacement techniques by-pass significant portion of the original reserve. Finding this missing oil can lead to significant economic windfalls because the infrastructure for additional oil recovery is already in place and the cost of production is likely to be minimal. In this paper, all existing monitoring techniques, including 4D seismic and downhole seismic sensors, are reviewed. This is followed by a comprehensive review of emerging technologies in subsurface monitoring. These techniques include multi-well seismic, electrical resistivity tomography, electromagnetic and ultrasonic imaging, acoustic and fibre-optic imaging, as well as laser/infrared or MRI/NMR visualization near the wellbore region.A detailed analysis indicates that for an accurate reservoir engineering analysis, geostatistical models should have information of 1m scale. This is the only scale that would satisfy the representative elemental volume (REV) requirement of an enhanced oil recovery (EOR) system. This scale length is orders of magnitude higher than that of core samples and at least an order of magnitude lower than the conventional seismic data. This data gap constitutes the weakest link between geophysical information and reservoir engineering. Any attempt to reconstitute the reservoir without information regarding petrophysical properties and fluid saturations in the 1m level, one risks falling into the trap of multiple solutions – a typical problem of history matching through reservoir simulation. To obtain a resolution of 1m scale, one must investigate the possibility of using 50-2000 Hz seismic frequency range. While this seismic range cannot be used with vertical seismic profiles (VSP) because of the travelling distance constraints, multiwell imaging can be used with multi-component receivers. This system, in combination with borehole seismic sources, can provide one with the desired resolution. The same system can be used in combination with resistivity tomography, a method that has recently given satisfactory results for tracking ground-water contamination. The images can be further refined with acoustic and fibre-optic imaging techniques. These techniques can provide satisfactory details to track viscous fingering, wormholes, and other time-dependent properties of an active reservoir. Finally, infrared/laser or MRI/NMR imaging of a wellbore is still in its nascent state of development, but holds great promises for the future applications of real-time monitoring and eventual dynamic reservoir management.
Enhanced Production in Horizontal Wells by the Cavity Failure Well Completion
Authors: Wang Yarlong , Tremblay Bernard 
Published: December 2007

AbstractHigh viscosity and weak cementation existing in heavy oil reservoirs present great challenge to us in rich heavy oil reservoirs in Northwestern Canada for production and well completion. On one hand, we attempt to increase the exposure of the reservoir to the well so that we can maximize the production potential. On the other, we must select an adequate strategy for well completion in order to maintain the integrity of the well during production. A well completion strategy by cavity-failure mechanism has been used for coalbed methane and heavy oil production during SAGD. The success of their previous operations leads us to investigate the feasibility of such a well completion strategy in both cold production and other enhanced production process in poorly consolidated heavy oil reservoirs. A coupled reservoir-geomechanics model is developed. A black-oil model is fully coupled to a Mohr-Coulomb type elastoplastic geomechanics model. An open hole condition with slotted liner is simulated. The wellbore pressure is rapidly reduced to create a massive dilation zone near the well so that the intact porosity can be mobilized. Consequently, an enhanced zone near the slotted liner with a higher permeability can be generated, leading to negative skin factor during the production. The field conditions reported in Cold Lake are used to evaluate our study and simulations.
Successful Mud Acid Stimulations Maintain Productivity in Gravelpacked Wells at Heidrun
Authors: Wennberg K. E. , Vikane O. , Kotlar H. K. , Poitrenaud H. 
Published: December 2007

Abstract
The Heidrun Field is located on the Haltenbanken area in the Norwegian Sea was discovered in 1985, and has been producing since October 1995. The hydrocarbons are present in 3 reservoirs of Jurassic age, the high quality Fangst group, and the more heterogeneous Tilje and Are formations. The initial reservoir pressure is 250 bar and the reservoir temperature is 88 °C. The drainage strategy utilizes injection of produced gas and seawater for pressure support.
The reservoir sands are in general poorly consolidated and contain fairly high quantities of clay with kaolinite content well above 25 % in Fangst and Tilje. Most of the producing wells have sand control devices (gravel pack or screen) installed. The cased-hole gravelpacks in the high-permeable Fangst formation have shown extensive productivity decline after water breakthrough. Initial oil rates in these producers exceed 6000 Sm3/d, but the rates drop rapidly even at very low water cuts. A team of engineers and scientist from the operator and service companies analyzed the problem and started to develop solutions. Migration of kaolinite fines was identified as the major cause for productivity decline. A mud acid/clay acid system to remove damage and maintain productivity was designed. Several successful treatments with this fluid system have now been carried out. Detailed monitoring and analyses of the fluids that are backproduced after the treatments have proven to be crucial in continuous improvement of the stimulation system. An extra oil production of approximately 500 000 Sm3 is ascribed to successful stimulation treatments in the first year following the treatment. It is now recognized that successful acid stimulation will be necessary to maintain production rates from the Heidrun field in years to come.
Details about the acid stimulation design, pumping schedule and ion composition analysis of the spent acid return will be given in the presentation.
Mechanisms of Arch Instability and Sand Production in Two-Phase Saturated Poorly Consolidated Sandstones
Authors: Bianco L. C. B. , Halleck P. M. 
Published: December 2007

Abstract
This paper addresses the problem of instability and sand production in poorly consolidated sandstones subjected to a water influx. New phenomenological evidences were collected in a series of unprecedented experiments, improving the understanding on the sand production mechanisms. Two different groups of experiments studied behavior, morphology, and stability of sand arches in two-phase saturated sand samples. The effects of changes in fluid flow velocity and water saturation were deeply analyzed, and the distributions of porosity and water saturation in the arched region were mapped during the sand production process.
The results showed that single-phase saturated sands did not develop enough cohesive strength to support a stable arch and sand was produced massively, generating a high-porosity and unstable zone. However, a small increase in wetting-phase saturation developed enough cohesive strength to stabilize an arch, reducing sand production. Within a defined range, a progressive increase in wetting phase saturation did not impact arch stability and sand production was sporadic and minimum. As the wetting-phase saturation exceeded critical value instability occurred; the arch was enlarged and massive amounts of liquefied sand were produced. A decrease in the non-wetting phase flow rate did not affect the stability of the arched zone and reduced sand production. Finally, it was observed that dilated, unconfined and agglomerated blocks of sands, with uniform porosity and wetting-phase saturation, filled the space inside the arched region.
Scale Inhibitor Squeeze Treatment Strategy on Heidrun
Authors: Wat Rex , Selle Olav Martin , Børstad Hege , Vikane Olav , Hagen Thomas , Chen Ping , MacLean Alan 
Published: December 2007

Abstract
The Heidrun Field, located on the Haltenbanken area, is one of the major fields which came on stream in the Norwegian Sea since 1995. At peak production the field is capable of producing 38,000 m3 of oil and 6 MSCM gas per day. It also takes in 22,000 m3 of injection water each day. The field is characterised by the large clay content in its three formation sands Fangst, Tilje and Are. Most of the producing wells are installed with gravel pack or screens due to poor sand consolidation. The reservoir has a bottom hole temperature of 85 °C and a relatively low reservoir pressure of 250 bar, hence seawater injection for pressure support is needed. With Ba++ level ranging between 180 to 700ppm in the different formations, the potential for downhole sulphate scale deposition within both the formation and the gravel pack, after seawater breakthrough is extremely high. A scale control strategy based on preventive squeeze treatment is therefore desirable to minimise any formation damage caused by such deposition.
However, two treatments using water based scale inhibitor carried out prior to 2000 had caused significant process problems during back flow. Severe emulsion problems were experienced, resulting in process upset and poor water quality. The low reservoir pressure meant that long clean up periods were needed with much deferred oil production. Such undesirable side effects make the operator less willing to take preventive action. Over the past 6 months, with the availability of an oil based scale inhibitor and a new ‘biodegradable, green’ water based product, we have successfully treated a number of oil producers with a wide range of water cut. In all cases, there was minimum process upsets on flow back and resumption of oil production shortly after. In the case with the ‘green’ product, it is most encouraging since this is the FIRST North Sea application and the chemical offers a high degree of biodegradability. This contributes significantly to the step improvement on the environmental impact when the return of a large peak of unwanted chemical is often associated with a traditional water based squeeze. In this paper we shall describe the processes of selection, evaluation, design, implementation and follow up of these new treatments. Based on these results, we have now established a treatment strategy which can be applied to wells producing from the different formations and with various water cut.
The Precipitation of Salt in Gas Producing Wells
Authors: Kleinitz W. , Koehler M. , Dietzsch G. 
Published: December 2007

Abstract
The entrainment of reservoir water from gas reservoirs and the associated precipitation of dissolved salts in the late production stage can impair the productivity and may even result in the abandonment of wells, even in reservoirs without active edge water drive. The causes of precipitation of dissolved salts from the entrained water, the chemical composition and plugging behaviour of the precipitates, as well as stimulation concepts with field results are discussed.
On the basis of the thermodynamic equilibrium between reservoir water and gas, on the one hand, and between the dissolved salts and the reservoir water, on the other hand, the effect of the reservoir pressure on the aqueous phase is investigated, and the mechanisms of the transport and precipitation of salts are explained.
Special emphasis is placed on early identification of downhole salt precipitation on the basis of the chemical composition and derived ionic parameters of wellhead water samples from different gas wells. The results obtained with water from Rotliegende, Dolomite and Bunter reservoirs are discussed. Experience gained in operations and stimulation with the measures thus derived for controlling the salt problems is described.
Numerical Modeling of Fracture Propagation Induced by Water Injection/Re-Injection
Authors: Longuemare P. , Détienne J-L. , Lemonnier P. , Boutéca M. , Onaisi A. 
Published: December 2007

Abstract
The evolution of water-injector injectivity is a complex phenomenon because of the opposite effects induced by thermal fracturing and formation damage. A numerical model HydFrac, based on a two-phase thermal reservoir simulator including descriptions of fracture mechanics and formation plugging by injected particles, is first presented. Special attention is paid to the analysis of fracture closure rate during injection shut-in and to the description of formation damage. The results show the importance of injection duration on fracture closure rate during shut-in. On the other hand, a case including a first step of clean water injection and a second step of produced water re-injection is presented. The obtained results indicate a stabilization of fracture length at the end of clean water injection followed by a rapid increase during produced water re-injection. The evolution of the effective fracture width is analyzed to indicate the start of fracture filling by particles.
Energy Strategies: An Industry View
Authors: Kircher John E. 
Published: December 2007

I feel like the man in the middle here today, sandwiched between Mr. Lovins and Mr. Guthrie on the one side and Miss Skelly and Mr. Lower on the other. You've had two tastes of this energy sandwich thus far, and now its my turn to try to add some flavor, and hopefully a little meat, to the menu. I only hope I don't spoil your appetite for what follows.
I do want to comment the program committee for bringing the participants in this panel together today. The groups and the participants in this panel together today. The groups and the points of view we represent cover the spectrum of significant points of view we represent cover the spectrum of significant opinion that must go into any resolution of the energy problem. Without input from any on e of the five - - environmentalists, government, industry, the public or the media - - any resolution of the energy issue would be incomplete, and thus probably also unsatisfactory.
Our comments, and the discussion that follows, are really a microcosm of the larger debate that has been taking place across the nation for the last few years, a give-and-take about energy that has culminated in the National Energy Plan and the actions that have been taken by Congress regarding it during the past several weeks.
Bear with me for a few minutes while I recap what I perceive our energy situation to be today.
Porosity Correction Method Developed for a High Vertical Relief Field in Eastern Venezuela
Authors: Clark Robert A. , Leza Fernando , Hetzel Allan , Minicucci David , Rigatti Vincent 
Published: December 2007

Abstract
A method has been developed that allows the estimation of porosity as a function of reservoir depth in high vertical relief fields. Porosity is known to decrease as net overburden pressure increases. This porosity reduction in turn leads to large reductions in reservoir permeability, the end result being a significant reduction in productive pore volume, net pay, and well productivity. The Eastern Overthrust Fields in Venezuela's El Furrial Trend produce from thick Miocene to Cretaceous sandstones and have very large hydrocarbon columns (two to three thousand feet is not unusual). Therefore, significant deterioration in pay quality is observed in the downdip areas. Using data from wells drilled in the Repsol/YPF Quiriquire Block, we observed that it was difficult to understand the true nature of the reservoir sands because the data was distorted by reservoir compaction in downdip wells. A method was developed to eliminate the distortion introduced by depth and overburden stress in porosity logs. This technique allows the well data to be interpreted as if all the wells had been drilled at a common datum. Once the undistorted data is interpreted and contoured, the data is re-shifted up or down using a depth grid map. Reservoir property grid maps can be prepared which better represent the sandstone properties at the depth at which they are found today. These maps can then be used in reservoir simulators to match and predict reservoir volumes and performance. The proposed method is most useful in development situations where there is sparse well control. Therefore, our first application has been in the Repsol/YPF operated Tropical Field, a 1998 discovery. Using this method, we prepared a reservoir description that depicts undrilled downdip areas much more accurately than would be possible using conventional methods. The new method resulted in large changes in our estimates of hydrocarbons in place and reserves and significantly impacted future development plans.
Dynamic Processes of Multiphase Flow in Subsea Flowline/Riser Systems During ESD Valve Shut Down
Authors: Chin Y. Doreen , Xu Zeng-Gang 
Published: December 2007

Abstract
Multiphase product transportation from offshore is facing the challenges of deepwater exploration and long-distance tieback. Prior predictions of the multiphase flow behavior, both steady state and transient, are crucial for successful design and operation of offshore facilities. The pressure surge and thermal stresses caused by transient multiphase flow during emergency shut down (ESD) are critical design criteria for pipeline systems.
Numerical methods have been developed to simulate the subsea HIPPS/ESD shut down and the ensuing system transient behaviors. These methods are able to predict pressure and temperature response during and after ESD valve closure. The analytic predictions are used in the design of deepwater pipeline and riser systems.
This paper demonstrates the use of transient multiphase flow analyses in the design of a deepwater subsea pipeline and riser systems. The pressure and temperature responses, and the pressure and temperature profiles from wellheads to the platform are investigated. The system design criteria are validated. The study improves the understanding of transient process in multiphase flow pipelines, and will benefit the deepwater production system design.
Compositional Variability in the Horizontal Section of Re-Entry Well, Orocual Field, Monagas State, Venezuela
Authors: Parra G. , Carvajal G. , Guevara J. 
Published: December 2007

Abstract
The description of the reservoir heterogeneities could be described utilizing diverse tools, one of these, the gas chromatograph in reentry wells and new horizontal wells. One of these wells is located to the northwest of the field, the objective was the base sands of the Las Piedras Formation, with 1425 feet of horizontal section. The analyzed parameters were: the Gas Ratio, relying on these outputs it is possible to estimate the API gravity. The Wetness Ratio (Wh) involves the light and heavy part of the mixture, this parameter by itself, estimates the gravity of the analyzed fluid with certain grade of confiability. The Balance Ratio (Bh) compares the light an the heavy fraction. The Character Ratio compares the components of the heavy fraction.
How To Determine The Best Exploitation Strategy From A Reservoir Simulation Model
Authors: Wences Acosta , Jesus Andrade , Hidalgo Oswaldo 
Published: December 2007

Abstract
A systematic approach showing a step by step procedure has been developed to guide the post calibration work of a reservoir simulation model to determine the best exploitation strategy.
The methodology presented on this paper appraises the best exploitation scheme based on economic analysis of reservoir simulation results.
Evaluation of mobile saturation distribution, cell productivity along with a net present value analysis provided a way to minimize the number of forecasts needed based on best-ranked cases.
The technique is able to estimate the optimum number of additional wells and their grid locations, to better define the most appropiate injection process and to determine the optimum injection rate.
A combination of primary, secondary and enhanced oil recovery exploitation strategies could be analyzed on the same scale to determine which is the most valuable in economical terms. Therefore, the best exploitation strategy can be selected.
The technique is an extension of a previously presented work to determine the optimum number of infill wells.
Chihuido de la Sierra Negra: Petroleum in Nonconventional Reservoirs
Authors: Comeron R. E. , Valenzuela M. E. , Ramírez J. L. 
Published: December 2007

Abstract
Chihuido de la Sierra Negra field is the main Repsol-YPF SA oilfield. It is located in the northeastern margin of Neuquén Basin. Main reservoir units are aeolian sandstones from Lower Troncoso Member (Huitrín Formation, Aptian) and Avilé Member (Agrio Formation, Hauterivian), with more than 1,000 MM stb oil in place. In 1993 oil was discovered in a thick basic intrusive body intruded pulling apart evaporitic rocks from Upper Troncoso Member (Aptian). The starting of the oilfield development was disappointing due to difficulties in locating wells with the 2D seismic that was available at that moment and the low production rates. 3D-survey acquisition, identification of fracture zones and drilling of horizontal wells increased dramatically the production rates. In this moment the field is under development, producing 12,000 bl/d with 11 wells.
This article discusses technical ideas, which have contributed the successful development of a nonconventional reservoir.
Enhanced Iterative Formation Evaluation of El Tordillo Field, San Jorge Basin, Argentina: Using Electrofacies and Production Prediction Index Determination
Authors: Stinco L. , Elphick R. , Moore R. 
Published: December 2007

Abstract
Formation evaluation, electrofacies and production prediction index determination based on inductive and deductive methodologies were completed in El Tordillo Field, North Flank of the San Jorge Basin, Argentina. The applied methodology consists of a number of steps including: data editing and normalization of the log data, modeling of the deep resistivity, electrofacies determination, standard log analysis, computing a production prediction index and summations. The 15 electrofacies determined were associated with the geological facies encountered within the field using cutting and core data. Consequently, porosity/permeability relationships were established between the core data and the productive electrofacies. These relationships permit to compute permeability from the computed effective porosity. A production prediction index was derived from the computed results which correlate well with existing production data. Zones of possible by-passed production were identified and some tested successfully. Finally, summations were used as input for original oil in place estimation, geological modeling and numerical simulation.