bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Semianalytical Thermal Multiphase Wellbore Flow Model for Use in Reservoir Simulation
Authors: Livescu S. , Durlofsky L. J. , Aziz K. 
Published: September 2008

Abstract
The detailed interactions between the reservoir and the wellbore are especially important in thermal processes such as steam flooding and in situ upgrading. These linkages must therefore be captured in thermal simulations. Although fully-coupled thermal wellbore-reservoir flow simulators have been developed, the implementation of the thermal well model is somewhat complicated and the simulations are computationally demanding. In this paper, we present a semianalytical treatment that enables a fairly straightforward extension of existing isothermal wellbore flow models to the nonisothermal case. The procedure entails the use of analytical solutions for wellbore temperature applied in conjunction with numerical solutions of the reservoir mass and energy balance equations coupled with wellbore mass and momentum balance equations. The approach thus enables a degree of decoupling between the wellbore flow and energy problems. We proceed by first presenting analytical solutions for wellbore temperature, developed under various assumptions (some of these solutions have been obtained previously). We then describe the use of one of these solutions, which allows for general variation of in situ phase fraction and other properties along the wellbore, within the semianalytical context. The implementation of the overall method into a general purpose research simulator is also described. Results are presented for several cases involving multiphase flow in monobore and multilateral wells. Close agreement with reference solutions, obtained from a fully-coupled thermal wellbore-reservoir model, is demonstrated for all of the examples. The semianalytical treatment is additionally shown to provide comparable or improved computational efficiency relative to the fully-coupled model. The overall procedure is therefore very well suited for use in general thermal reservoir simulation.
Risk Analysis as Decision Tool to Upgrade Aging Offshore Trunk Lines
Authors: Angibeaud L. 
Published: September 2008

Abstract
All over the world, the operation of old and aging pipelines, all potentially subject sooner or later to internal corrosion, raises concerns about the risk and the consequences of pipeline failures. With the exception of third party damages, most cases of failure are caused by internal and external corrosion. In Saudi Arabia Offshore Operations, old pipelines were originally designed for "dry" oil operations and constructed without scraping facilities. Therefore, the observation and monitoring of internal corrosion is virtually impossible without significant modifications. In new pipelines, facilities allowing the internal condition monitoring are included at the design stage. Indeed, loss of production and detrimental environmental impacts are less and less acceptable to society. They are indicators of poor performance in the public's opinion, and create costly business expenses.
Observations:
Saudi Arabian Offshore Operations operate a very large number of old pipelines for which intelligent scraping facilities have not been retrofitted. This upgrade requires very large capital expenditures and for that reason cannot be performed on every offshore line. To respond to the dilemma of either doing "nothing" or to invest a substantial amount of money without an absolute certainty of success, a risk analysis has been performed.
Approach:
Several alternative decision trees are developed to portray the decision process. The pipelines are analyzed based on the risk analysis described as: –Possible events which may occur during a pipeline's lifetime.–Investments and costs associated with the event described.–The cumulative risked capital and total risked capital.
Significance:
The risk analysis allows a comparison of different pipeline situations, and the analysis helps in building the business case to install intelligent scraping facilities. When the scraping scheme is applied, the investment increase is associated with a risk reduction in pipeline failure.
High Gas-Rate Production: Expandable Solutions in the Mediterranean Sea
Authors: Pierfelici Stefano , Tacconelli Antonella , Ripa Giuseppe , El Nagar Hesham Mahmoud , Bowen Eddie G. , Elsakhawy Tamer , Mohamed Omar Y. 
Published: September 2008

Abstract
An operator facing the need for sand control in multiple maturing fields investigated the possibility of using expandable technologies to address their needs. Years of production and the onset of water production has affected that need. After an extensive study of rock mechanics and properties and how sand production might be initiated based on these properties, the investigation for an optimized sand control technique began.
A systematic approach ensued between operator and Service Company in an attempt to define an optimized solution for sand control in each of these fields. Conventional cased hole gravel packs were excluded due to the need for a larger flow area for handling the high gas rates. Open hole gravel packing was investigated yet ruled out due the exposed unstable shales during the packing operations. Ultimately the optimized solution led to the deployment of an expandable screen system to ensure sand control for the remaining life of each well.
The undesirable shales were isolated with the installation of expandable blank pipe and expandable packers. Expandable screens were positioned across the clean sand bodies. Many wells had multiple sand bodies exposed. These separate reservoir sections were isolated with expandable blank pipe and packers as well. The entire expandable assembly was deployed in a single trip and hung off in the parent casing with an expandable hanger. Sand-free production data obtained from more than 20 wells will be presented and discussed.
Expandable technologies provided the operator with a sand control technique that previously didn't exist., After exploring this new technology, the operator conducted multiple installations of expandable sand screen for sand control in the maturing fields of the Mediterranean Sea. This became the new philosophy for sand control by the operator in the Mediterranean Sea as well as other parts of the world where they have sand control needs.
Multiple Reservoir Simulations Integration: An Alternative to Full Field Simulation in the North Kuwait Jurassic Complex
Authors: Ghorayeb Kassem , Limsukhon Manoch , Dashti Qasem , Aziz Rafi Muhammed 
Published: September 2008

Abstract
The North Kuwait Jurassic Complex consists of five fields, each with three identified reservoirs within the naturally fractured Jurassic carbonate formation. These reservoirs contain multiple fluid types at near critical conditions with flow properties ranging from fracture to matrix dominated flow. Multiple-scenarios production forecasts, using dual-porosity, dual-permeability reservoir simulation models, are required to prepare an optimal development plan for the complex.
In this paper we discuss available options to simulate multiple reservoirs which, although isolated based on the current compartmentalization understanding of the complex, they cannot be run in isolation because of global production targets. We show that using multiple-reservoirs integration through controller to couple the separate reservoir models through global production targets/limits provides an optimal simulation framework for the NKJC: flexibility and computational efficiency of multiple segment models and comprehensiveness of full filed simulation modeling.
Investigation of VOC Emission Control by the Use of Clay Aqueous Foams
Authors: Sani A. M. , Mohanty K. K. 
Published: September 2008

Abstract
During the process of crude oil/gasoline loading, significant amounts of volatile organic compounds (VOCs) can be emitted to the environment. Stable aqueous foam can be spread as a flexible blanket before crude oil/gasoline loading to control the VOC emission by providing a mass transfer barrier during the loading process. In this work, novel aqueous foams have been formulated by incorporating special type of clay nano-particles in an aqueous solution of surfactants and polymers. Experiments to investigate the foam stability and VOC emission were carried out in a bench-scale foam column. These foams are found to be very stable and can last much longer a day. There was a decrease of the rate at which liquid is drained out of the foam and thus, a decrease of the rate of quality increase. There is also a significant reduction of vapor emission for the first 40 hours. Increasing polymer and clay concentrations increases the foam stability and mass transfer resistance.
A Multistage MCMC Method with Nonparametric Error Model for Efficient Uncertainty Quantification in History Matching
Authors: Ma Xianlin , Datta-Gupta Akhil , Efendiev Yalchin 
Published: September 2008

Abstract
Uncertainty quantification is generally carried out in a Bayesian framework whereby multiple reservoir models can be evaluated by sampling from a posterior distribution that incorporates the observed production data and the prior parameter distribution. Rigorous sampling methods such as the Markov Chain Monte Carlo (MCMC) method provide accurate sampling but at a high cost because of their high rejection rates and the need to run flow simulation for every proposed candidate.
We propose a methodology that combines coarse- and fine-scale information to improve the efficiency of MCMC methods without loss of its rigorousness in sampling. Our proposed method employs off-line computations for establishing a mathematical relation between coarse- and fine-scale error responses. This relation is modeled using non-parametric approaches that correlate the error responses via optimal transformations. The resulting statistical models are then used in efficient sampling within an MCMC framework. We propose a multi-stage MCMC where inexpensive coarse-scale simulations are performed to determine whether or not to run the fine-scale simulations. The latter is determined based on the non-parametric error model developed off-line. Our proposed method substantially improves the efficiency of existing multistage MCMC methods that only rely on coarse-scale or other approximate models. Most importantly, our proposed method does not depend on the proximity of the coarse and fine-scale models and thus, can employ much coarser and inexpensive models to guide the fine-scale simulations.
We will present a synthetic and a field example involving three-phase flow to demonstrate that the proposed approach is both robust and computationally efficient. In these examples, water cut and GOR are integrated to generate multiple reservoir models and assess uncertainty in the production forecasts.
Integrated Geomechanical Study for Hole Stability, Sanding Potential, and Completion Selection: A Case Study From Southeast Asia
Authors: Khaksar Abbas , Rahman Khalil , Ghani Juanih , Mangor Hapiztuddin 
Published: September 2008

Abstract
A full scale geomechanical study was carried out to evaluate hole stability during drilling and production, and sanding potential of Lower Miocene oil bearing sands in horizontal wells with planned open hole completion in a Malay Basin field, offshore Malaysia. Drilling information, well logs and rock mechanical test results were used to determine in situ stresses, pore pressure and rock mechanical properties in the field. This paper highlights the use of geomechanics principles integrated with sound drilling and completion practices to achieve and deliver highly productive wells in the field.
An analytical 3D elastic-shear failure model and a 2D elasto-plastic yield zone growth model were used to evaluate the sanding risk over life of field conditions. Using conservative critical sand failure parameters, both the elastic and elasto-plastic sanding models indicate that the risk of sand production during the life of field would be very low to none; therefore, no sand control would be required for the planned horizontal wells. 2D elasto-plastic hole stability modelling, using Mohr-Coulomb failure criteria, showed that the sandstone sections should remain stable over the life of field in an open hole (barefoot) completion, even with water cut. However, the stability of intra-reservoir shales in a barefoot completion might be at risk under high reservoir pressure depletions, if no depletion occurs in shales.
Planned horizontal wells were drilled successfully with no major drilling problem by using the recommended mud pressures and good drilling practices, confirming the reliability of the geomechanical model and wellbore stability analysis. The wells were completed with predrilled liners to minimise the risk of hole instability in shales. The wells are currently producing sand free with the planned drawdowns while water cut is approaching 70%, confirming the accuracy of sand production predictions. Integration of geomechanical analysis with rational engineering judgment and practices resulted in avoidance of unnecessary sand prevention installations which could be expensive and have adverse effects on well productivity.
Public Perception of the Natural Gas Industry: Insights From Two Barnett Shale Counties
Authors: Theodori G. L. 
Published: September 2008

Abstract
Data collected in a general population survey from a random sample of individuals in two counties located in the Barnett Shale region of Texas were used to empirically explore issues associated with public perception of the natural gas industry. Moderate support was found for the hypothesis that individuals residing in places with diverse levels of energy development exhibit dissimilar perceptions of the energy industry. Bivariate and multivariate logistic regression analyses indicate that residents of the county where the natural gas industry is more mature (Wise County) exhibit somewhat more negative perceptions of the energy industry than do residents of the county where natural gas industry is less established (Johnson County). The results also reveal that mineral rights ownership is a relatively strong and consistent factor associated with public perception of the natural gas industry. Possible implications of these findings for the energy industry are proposed, as are suggestions for future research.
On the IPR Curves of Horizontal Wells in Solution-Gas Drive Reservoirs
Authors: Jabbari H. , Economides M. J. 
Published: September 2008

Abstract
Inflow performance relationship (IPR) curves have been extensively studied in the petroleum engineering community; from the classic Vogel's method for vertical wells to modified models for horizontal wells. Previous works have indicated that the performance of horizontal wells can be different from that in vertical wells due to their more complex geometries. Hence, this encourages us to aim for modified IPR correlations.
Modeling the production performance in a horizontal well requires an understanding of the parameters that may affect the fluid flow geometry and well/reservoir interface. In this work, numerical modeling was employed to study the performance of horizontal wells under different well/reservoir conditions. A new IPR relationship was proposed for horizontal wells producing from solution-gas drive reservoirs along with a modified absolute open-flow potential (AOFP) which was proposed initially by Kabir. This was to introduce new terms that accounted for the effect of bubble-point pressure and recovery factor which were found to be significant. The developed model was tested against field data, and it was also evaluated and compared with the current IPR curves.
In order to generate an IPR curve for a horizontal well at the specified recovery factor, simulation models were constructed and run for each bottomhole pressure. Then, computer codes were used to extract the results from each results file. Next, the coefficicents and parameters of the equations were obtained from non-linear regression and curve fitting. Then, IPR curves from the analytical model were generated at specified well/reservoir conditions, and at a certain recovery factors. Finally, the results from the model were compared to the simulation model and field data.
This work confirmed that the IPR curves in horizontal wells producing from a saturated reservoir may need modified relationships due to more cmplex flow geometry and well/reservoir interactions. The developed three-parameter IPR relationship presented reasonable accuracy as was compared to the currenmt models and field/simulation data. Also, the new AOFP equation showed a reasonable error of 3% compared to the simulation results.
Development and Field Application of a New, Highly Stable Emulsified Acid
Authors: Nasr-El-Din Hisham A. , Al-Dirweesh Saad , Samuel Mathew 
Published: September 2008

AbstractAcid-in-diesel emulsified acid has been used in the oilfield for many years. It is known that the emulsified acid should be stable at ambient conditions for a long period of time. It should be stable also at downhole conditions for a period of time long enough to pump the acid without encountering operational problems. Application of emulsified acid at higher temperatures requires 20 to 30 gpt of a cationic emulsifier.A thorough laboratory study was conducted to select an emulsifier that can be used at lower loadings, and meet the stability criteria that are needed to stimulate oil and gas wells. Laboratory work included measuring stability, apparent viscosity, and droplet size distribution as a function of emulsifier type and concentration, temperature, and additive type and concentration.A new emulsified acid was developed and used to acid fracture over ten wells in a deep gas reservoir in Saudi Arabia. The formation is predominantly limestone and dolomite with streaks of anhydrite. Acid fracturing practices consist of pumping 28 wt% emulsified acid (acid to diesel volume ratio = 70:30), a pad and in-situ gelled acid to create long conductive fractures.The new emulsified acid used a significantly lower amount (4 to 6 gpt) of the emulsifier, albeit it produced a stable emulsion over a wide range of temperatures (from 75 to 275?F). The droplet size of emulsions produced from the new emulsifier was much smaller and, as a result, the apparent viscosity of the acid-in-diesel emulsion was higher. Field data showed greater reduction in the time needed to prepare the new emulsion in the field. The performance of wells stimulated with the new emulsifier was significantly better than those stimulated with the old emulsifier.
Modeling Leakage Through Faults of CO2 Stored in an Aquifer
Authors: Chang Kyung Won , Minkoff Susan E. , Bryant Steven L. 
Published: September 2008

Abstract
For secure storage of CO2 within geologic formations, the integrity of caps – overlying strata that are impervious to CO2 – is an important factor. Geologic structures, notably faults and the damage zones surrounding them may provide a conduit for CO2 to escape through a cap. If the fault encounters shallower permeable formations, the CO2 rising along the fault can enter them. This lateral migration would attenuate the rate at which CO2 enters sensitive formations such as aquifers used for drinking water. Thus, CO2 leakage along faults will have three behaviors: upward migration from the storage formation along a fault, lateral movement from the fault into permeable layers, and a continued but attenuated CO2 flux along the fault above the layers.
Here we develop a quasi-1D single-phase flow model for these three behaviors. The model is highly simplified and intended to be suitable for inclusion in a certification framework for geologic storage projects. The model accounts for flow from the fault into a permeable formation using a leakoff coefficient. The coefficient can vary spatially and depends on the geometry and petrophysical properties of the formation. We apply a commercial simulator to verify the quasi-1D model. A series of examples illustrates the controlling mechanisms for leakage rate from the reservoir and its attenuation by flux into shallower layers.
Nonlinearities arise even in this simple model. For example, leakage flux and the degree of attenuation vary nonlinearly with the permeability of the fault and the permeability of the shallower layer(s) intersected by the fault. Layers nearest the CO2 storage formation produce the most attenuation. But the percentage of CO2 entering overlying formations from the fault varies linearly with the ratio of fault permeability to leakoff coefficient. A simple estimate of the leak-off coefficient compares favorably with 2D, full-physics simulations. If the permeable layer is dipping, CO2 enters it asymmetrically and estimating the leakoff coefficient is less straightforward. The difference arises because of preferential flow within the layer (CO2 in the upper part, water below).
Screening Strategy for Chemical Enhanced Oil Recovery in Wyoming Basins
Authors: Alvarado V. , Thyne G. , Murrell G. R. 
Published: September 2008

Abstract
This paper presents results of a screening procedure for chemical EOR methods based on fuzzy-logic and data clustering algorithms. EOR processes considered included combinations of polymer, alkali and surfactant. Reservoir parameters are represented as triangular distributions with validity limits for each EOR process, and a most likely validity value of the distribution. Another triangular distribution was used as a reference for each of the reservoir and fluid parameters. The limits of validity were defined by mining a database and also by using technical limits, e.g. maximum stability temperature for polymers. The most relevant variables were dictated by availability of data and by comparing screening results with reported field cases. Wyoming basins have a long tradition of oil and gas exploitation, so many of the assets are at an advanced stage of maturity. The current energy market has revitalized the opportunities for further exploitation of numerous reservoirs in Wyoming. Enhanced-Oil Recovery (EOR) represents an attractive target for increasing the recovery factor in many of currently underexploited reservoirs, particularly by CO2 and Chemical Flooding. Associated decision-making workflows demand screening procedures, simulation and detailed economic evaluations. Sensible screening procedures are necessary to guide decision-making exercises. In practice, it was not possible to generalize success in field cases. Our results show this simple screening procedure requires a relatively small dataset for each asset, which contains bounds and likely values for the relevant rock and fluid properties. This has been implemented in a way that facilitates its use by final users. Many of the Wyoming reservoirs represent good candidates for processes such as alkaline-polymer or straight-polymer flooding, based on published field experience and our results. This EOR screening strategy is viewed as a significant improvement over go-no go criteria based on look-up table methods, because the developed method yields indicators ranking candidates for chemical EOR strategies. This provides a more assertive search for EOR candidates and allows reservoir types to be grouped on the basis of suitability. A similar philosophy will be developed for screening of CO2 projects, providing a further step in the decision making process and risk management associated with CO2-based EOR projects.