bluuebunny/crossref_metadata_2025_split huggingface dataset:
History Matching Using the Ensemble Kalman Filter With Multiscale Parameterization: A Field Case Study
Authors: Zhang Yanfen , Oliver Dean S. 
Published: January 2011

SummaryThe increased use of optimization in reservoir management has placed greater demands on the application of history matching to produce models that not only reproduce the historical production behavior but also preserve geological realism and quantify forecast uncertainty. Geological complexity and limited access to the subsurface typically result in a large uncertainty in reservoir properties and forecasts. However, there is a systematic tendency to underestimate such uncertainty, especially when rock properties are modeled using Gaussian random fields. In this paper, we address one important source of uncertainty: the uncertainty in regional trends by introducing stochastic trend coefficients. The multiscale parameters including trend coefficients and heterogeneities can be estimated using the ensemble Kalman filter (EnKF) for history matching.Multiscale heterogeneities are often important, especially in deepwater reservoirs, but are generally poorly represented in history matching. In this paper, we describe a method for representing and updating multiple scales of heterogeneity in the EnKF. We tested our method for updating these variables using production data from a deepwater field whose reservoir model has more than 200,000 unknown parameters. The match of reservoir simulator forecasts to real field data using a standard application of EnKF had not been entirely satisfactory because it was difficult to match the water cut of a main producer in the reservoir. None of the realizations of the reservoir exhibited water breakthrough using the standard parameterization method. By adding uncertainty in large-scale trends of reservoir properties, the ability to match the water cut and other production data was improved substantially.The results indicate that an improvement in the generation of the initial ensemble and in the variables describing the property fields gives an improved history match with plausible geology. The multiscale parameterization of property fields reduces the tendency to underestimate uncertainty while still providing reservoir models that match data.
Field Applications of a Semianalytical Model of Multilateral Wells in Multilayer Reservoirs
Authors: Pan Yan , Kamal Medhat M. , Kikani Jitendra 
Published: January 2011

Summary
Advanced drilling technology has been widely and successfully applied to construct multilateral wells in reservoirs. This paper presents several field applications of a generalized semianalytical segmented model accounting for multilateral-well systems in commingled layered reservoirs. Cases include a heavy-oil field, Al Rayyan oil field offshore Qatar, and Dos Cuadras field offshore California.
The model can predict the production performance under either constant-rate or constant-pressure conditions of a well system with any number of arbitrarily oriented laterals of any length and nonuniform formation damage. The reservoir layers, with different porosities, anisotropic permeabilities, and drainage areas, are noncommunicating except through the wellbore. The solution is valid for large reservoirs and when no-flow or constant-pressure boundaries affect the pressure behavior.
Results of applying this method in the field cases showed that the model enabled us to predict multilateral-well performance, to obtain information about reservoir connectivity, and to estimate well and reservoir properties in a multilayer system. Uncertainty caused by the large number of unknown parameters in such a complex system represents the main challenge in using this method. It is recommended to use other means together with pressure transient data to reduce the uncertainty.
The presented model and the lessons learned from the field applications provide engineers with a tool enabling the use of transient data collected from multilateral wells in multilayer systems for reservoir characterization and performance forecast.
An Integrated Workflow for Granitic-Basement-Reservoir Evaluation
Authors: Farag S.. , Mas C.. , Maizeret P.D.. D. , Li B.. , Van Hung Le 
Published: January 2011

Summary
In recent years, energy companies in the Asia Pacific region have focused increasing attention on granitic basement reservoirs, following several new oil and gas discoveries in these complex reservoirs. However, accurate formation evaluation in fractured, crystalline, granitic reservoirs is notoriously difficult. Furthermore, relatively little research has been conducted to understand loggingtool response or pressure-transient behavior, or to develop suitable workflows for formation evaluation in these types of reservoirs. In this paper, we propose a method for integrating various openhole logs, production logs, and well-test data to better evaluate the reservoir potential of fractured granitic formations. Because the wells are either horizontal or highly deviated, this workflow also serves as a primary method of assessing the lateral extent of a reservoir. We include a case study from the region to illustrate the workflow. Image-log interpretation, advanced acoustic measurements, nuclear logs, and production logs with distributed local sensors are combined with well-test data to derive the best possible evaluation of the fracture network around the borehole and the degree of connectivity with the reservoir at large. We also discuss the advantages and limitations of the proposed workflow and set the stage for further work in this complex environment.
Planning and Procedures for the Initial Startup of Subsea Production Systems
Authors: Duhon H.J.. J. , Garduno J.L.. L. , Robinson N.A.. A. 
Published: January 2011

Summary
Projects progress through phases of design, construction, installation, commissioning, initial startup, and operations. This paper addresses issues that arise at initial startup. Initial startup is defined here as the period when reservoir hydrocarbons are produced for the first time.
Initial startup of a subsea development is one of the most challenging periods in the operational life of the facility. Many issues complicate this period, including People issues. Many people from many teams are required to execute a startup; roles and responsibilities may be unclear and will change over the course of the startup; persons-onboard (POB) issues limit the number of people who can participate; personnel involved may not be fully trained in the operation of the facility.This will be the first time much or all of the equipment is used in live hydrocarbon service. Design flaws, commissioning omissions, and infant mortalities will reveal themselves.Preserving completion integrity requires low rates and slow bean-ups during initial startup because of high formation skin. Chokes designed for high rates and low pressure drops may not be capable of controlling the well at low rates. Also, topside systems designed for peak rates may not function well at low flow rates.Low flow rates and low initial temperatures result in hydrate risk, which may challenge the flow-assurance strategy.Completion and stimulation fluids returned during the initial well cleanup are corrosive and are difficult to treat. Typically, specialized water-treatment equipment is installed temporarily at topside to treat these fluids. The flowback fluids may also contain solids from the reservoir and from construction debris that may cause problems such as plugging small ports in control valves.Drilling, construction, installation, and commissioning activities [simultaneous operations (SIMOPS)] may still be in progress. The exact state of equipment items may be unclear and may change over the course of the startup.Reservoir engineers will seek to obtain reservoir information through well tests, especially pressure-buildup tests. Other data- collection efforts are important to validate the design and establish benchmarks.Some regulatory requirements apply specifically to the startup period.Special procedures are usually written for the initial startup. These will differ in important ways from the normal operating procedures. There is risk that there may be errors in the startup procedures, that operators may err in implementing the procedures, or that equipment designed for normal operation will not function well at the conditions imposed by the startup.Startup is one of the most hazardous periods in field life. Effective risk management is essential.
Careful planning is required to achieve a trouble-free startup. This paper describes the key requirements for generating effective initial-startup plans and procedures.
Simultaneous Interpretation of Pressure, Temperature, and Flow-Rate Data Using Bayesian Inversion Methods
Authors: Duru Obinna O. , Horne Roland N. 
Published: January 2011

Summary
Current downhole measuring technologies have provided a means of acquiring downhole measurements of pressure, temperature, and sometimes flow-rate data. Jointly interpreting all three measurements provides a way to overcome data limitations that are associated with interpreting only two measurements—pressure and flow-rate data—as is currently done in pressure-transient analysis. This work shows how temperature measurements can be used to improve estimations in situations where lack of sufficient pressure or flow-rate data makes parameter estimation difficult or impossible.
The model that describes the temperature distribution in the reservoir lends itself to quasilinear approximations. This makes the model a candidate for Bayesian inversion. The model that describes the pressure distribution for a multirate flow system is also linear and a candidate for Bayesian inversion. These two conditions were exploited in this work to present a way to cointerpret pressure and temperature signals from a reservoir.
Specifically, the Bayesian methods were applied to the deconvolution of both pressure and temperature measurements. The deconvolution of the temperature measurements yielded a vector that is linearly related to the average flow-rate from the reservoir and, hence, could be used for flow-rate estimation, especially in situations in which flow-rate measurements are unavailable or unreliable. This flow rate was shown to be sufficient for a first estimation of the pressure kernel in the pressure-deconvolution problem.
When the appropriate regularization parameters are chosen, the Bayesian methods can be used to suppress fluctuations and noise in measurements while maintaining sufficient resolution of the estimates. This is the point of the application of the method to data denoising. In addition, because Bayesian statistics represent a state of knowledge, it is easier to incorporate certain information, such as breakpoints, that may help improve the structure of the estimates. The methods also lend themselves to formulations that make possible the estimation of initial properties, such as initial pressures.
Mechanics and Upscaling of Heavy Oil Bitumen Recovery by Steam-Over-Solvent Injection in Fractured Reservoirs Method
Authors: Singh Rajpreet , Babadagli Tayfun 
Published: January 2011

Summary
Recently, the steam-over-solvent injection in fractured reservoirs (SOS-FR) method was proposed as a potential solution for efficient heavy-oil/bitumen recovery in oil-wet naturally fractured reservoirs. The method is based on initial injection steam (Phase 1), followed by solvent (Phase 2). In the third cycle (Phase 3), steam is injected again to recover more oil and retrieve the solvent. Solvent retrieval during the third cycle was observed to be fast if the temperature is at approximately the boiling point of the solvent. This process is controlled by efficient matrix recovery and the mechanics of the process need to be clarified to further determine the efficient application conditions for the given matrix and oil characteristics.
Single-matrix behaviour during the process was numerically modelled for static conditions and the results were matched with the experimental observations. The physics of the recovery mechanism was analyzed through visual inspection of saturation and concentration profiles in each cycle. The major observation was the substantial effect of gravity in oil recovery when the matrix were exposed to solvent. Special attention was given to the solvent retrieval rate and amount in Phase 3 and the permeability reduction caused by asphaltene precipitation in Phase 2. This phenomenon was modelled using a permeability function changing with spatial coordinates and time (i.e., k =f (x ,y ,z ,t ). It was observed that permeability reduction caused by asphaltene precipitation is significant and needs to be taken into account in the modelling process.
After showing the effect of the matrix size on the oil recovery and solvent retrieval, an upscaling analysis was performed. The log-log relationship between the time value to reach ultimate recovery and the matrix size yielded a straight-line relationship with a noninteger exponent less than two for all three phases of the process. The observed straight-line relationship (and the exponent values obtained) is highly encouraging to extend the study to obtain a universal scaling relationship.
Chemical Treatment To Mitigate Condensate and Water Blocking in Gas Wells in Carbonate Reservoirs
Authors: Ahmadi M. , Sharma M. M. , Pope G. A. , Torres D. E. , McCulley C. A. , Linnemeyer H. 
Published: January 2011

Summary
Many gas wells suffer a loss in productivity because of liquid accumulation in the near-wellbore region. Chemical stimulation may be used as a remedy by altering the wettability to nonliquid wetting. Successful treatments decrease liquid trapping, increase fluids mobility, and improve the well's deliverability. This paper presents the first effective chemical treatment to mitigate liquid blocking in carbonate gas reservoirs. Screening tests were developed to quickly and effectively identify suitable chemicals from a large pool of compounds. X-ray photoelectron spectroscopy (XPS) measurements and drop-imbibition tests with water and n-decane were found to be necessary but not sufficient indicators of the effectiveness of the chemicals and were used as screening tests.
An integral part of the development of the treatment solution was the selection of a solvent mixture capable of delivering the fluorinated chemical to the rock surface. The treatment solution, mixture of chemical dissolved in solvent, must be stable in the presence of both brine and condensate so that it will not precipitate and will not reduce permeability of the rock. We acquired measured relative permeability values in Texas cream limestone (TCL) cores from high-pressure/high-temperature (HP/HT) coreflood experiments before and after treatment. Measurements were made using a pseudosteady-state method with a synthetic gas/condensate mixture. To enhance the durability of the treatment, a special amine primer is introduced. The gas relative permeability increased considerably (approximately 80%) after the treatment compared to that before treatment. This increase remained substantial, greater than 60% after injection of more than 1,000 pore volumes (PV) of gas/condensate mixture. We found an even greater increase in gas relative permeability during unsteady displacement of water by methane. The improvement remained after injecting 20 PV of brine and increasing the temperature in the treated core from 175 to 275°F.
The chemical treatment developed in this research can be applied to increase well deliverability of both gas and condensate in the field, providing that it is properly designed by considering key parameters such as reservoir pressure and temperature, brine salinity, and initial water saturation.
Two Issues in Wellbore Heat Flow Modelling Along With the Prediction of Casing Temperature in the Steam Injection Wells
Authors: Bahonar Mehdi , Azaiez Jalel , Chen Zhangxing 
Published: January 2011

Summary
Although several models to determine the formation temperature in the modelling of thermal production and injection processes have already been suggested, there is no rigorous or systematic comparison between these models' predictions that can guide the choice of the most appropriate one. Another issue in thermal wellbore simulators is the commonly used assumption of semisteady-state heat transfer from the wellbore up to the cementing/formation interface. The effect of the semisteady-state assumption vs. the unsteady-state assumption for the heat transfer from the wellbore up to the formation has not received much attention in the literature and can be important in some cases.
The results of a detailed analysis of the two previously described issues can be implemented in all thermal wellbore and reservoir simulators to increase their accuracy.
The previously described stated issues will be addressed in the present work by developing a numerical nonisothermal two-phase wellbore simulator coupled with tubular and cement material and surrounding formation. The first issue will be studied in detail by comparing five different models for the formation temperature treatment (FTT) plugged in the developed thermal wellbore simulator.
Investigation of the second issue will be achieved by analyzing the three critical items: first, a 2D heat transfer PDE model of the formation is discretized in a general form; second, the gridding system is shifted from the formation toward the casing; and third, an effective specific heat capacity for the casing is used. The effects of choosing different models for FTT and using either the unsteady-state or the semisteady-state assumption in the heat loss from the wellbore up to the formation will be investigated. The model will be validated against field data to show its merits in predicting the casing temperature.
The entire wellbore system contains wellbore, tubing, insulation, annulus, casing, cementing and formation. A fundamental understanding of this system is still a challenging issue in the petroleum industry, and its accurate modelling and coupling with reservoirs has become increasingly significant as more energy resources are sought.
Numerical Study of Gas Evolution and Transport Behaviours in Natural Gas-Hydrate Reservoirs
Authors: Uddin Mafiz , Wright Fred , Coombe Dennis A. 
Published: January 2011

Summary
Gas hydrates are a potentially vast untapped source of natural gas. Recent numerical and field studies suggest the Mallik gas-hydrate field in Canada's Mackenzie Delta may represent a technically producible and potentially economically viable reservoir of natural gas. Our initial reservoir simulations using a kinetic reaction approach indicate that gas evolution and transport within porous geologic reservoirs have a significant effect on fluid production characteristics, while field and laboratory data suggest that significant amounts of evolved gas can be trapped for some time within the reservoir, depending on the field operation.
In this work, we invoke modelling concepts extensively employed in quantifying gas ex-solution from viscous oils to further assess the kinetic behaviour of gas-hydrate ex-solution through depressurization. Here, the gas bubbles can be categorized into three groups with explicit transport behaviour: small bubbles (water phase), large bubbles (immobile) and connected bubbles (or free gas). These concepts allow the development of a new set of kinetic reactions for hydrate dissociation: one representing the (possibly delayed) conversion of hydrate into water and dispersed gas bubble phases, and one representing the evolution from dispersed bubbles to connected bubbles. These reactions can effectively capture the nonequilibrium fluid-flow behaviour observed in field production tests.
For modelling of the transport phenomenon, we assumed two explicit mobility formulations: (1) trapped bubbles (no mobility) and a flowing water phase and (2) large connected gas bubbles and flowing water (with relative mobility). Relative mobility can be estimated by using traditional gridblock-relative permeability curves. We then develop a simple mechanistic gas bubble trapping tool as a function of the capillary number, which can easily be incorporated into our numerical simulator. This entrapment of the nonwetting gas-phase results in higher values of critical gas saturation.
Two case studies based on alternative representations of a Mallik-like gas-hydrate reservoir demonstrate that significant errors can result in reservoir modelling if these fluid transport phenomena are not adequately represented in numerical simulations. Aspects of the model developed here have been applied to history matching and prediction of natural gas recovery from a clastic, sand-dominated reservoir at the Mallik site.
CO2: One-Component Two-Phase System as Model Fluid for High-Pressure Hydrocarbon Systems
Authors: Dupuy P.M.. M. , Fernandino M.. , Svendsen H.F.. F. , Westra R.. 
Published: January 2011

SummaryIn the process of performing either scientific experiments or research and development related to the design and optimization of high-pressure liquid-from-gas separator units, both laboratory experiments and tests in prototypes are needed. In order to emulate the low interfacial tensions often experienced in high-pressure hydrocarbon systems, the use of carbon dioxide (CO2) as model fluid is studied. This paper describes how the CO2 system behaves at saturation conditions. It describes this system and compares it with traditional laboratory systems and real fluids (from the field). CO2 at saturation pressure under normal temperatures presents an interesting system with low interfacial tension, below 3 mN/m, while the liquid/gas-density ratio is approximately 3. The availability of the fluid (CO2) in research centers and academia is high. When planning a matrix of experiments as part of a database of reproducible laboratory fluids, the present system is an independent base vector ideal for studying the high-Weber/low-Reynolds-number regime. This paper shows how a dispersed CO2-droplet phase, representative of a hydrocarbon-gas/condensate system, can be achieved in the laboratory and used for studying collision outcomes.Results show that it is possible to obtain streams of droplets for droplet experiments. The mean diameter in the studied regime with the particular nozzle used was on the order of 100 µm, while the smallest droplets possible to track with the presented technique were approximately 40 µm. Droplet/wall-collision experiments were focused in this work. Both coalescence and bouncing were observed on both dry and wet walls.The absence of real fluid experiments at laboratory conditions generates a lack of basic knowledge about what is happening in real scrubbers. This system is proposed to be representative for a part of the flow-property region of interest in real gas/liquid scrubbers. This basic knowledge is fundamental when designing separation units at high pressures for gas-processing stages such as subsea gas-separation concepts.