bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Comprehensive Model of Temperature Behavior in a Horizontal Well
Authors: Yoshioka K. , Zhu D. , Hill A. D. , Dawkrajai P. , Lake L. W. 
Published: December 2007

Abstract
Use of distributed temperature sensors is becoming increasingly common for monitoring producing sections of horizontal wells through a real-time measurement of a temperature profile. This information can potentially be inverted to infer the types and amounts of fluid entering along the wellbore. This information is essential for reservoir management to identify excessive water or gas influx, to guide the action of sliding sleeves or other downhole flow control devices, and to decide if reservoir stimulation is needed in a particular horizontal section.
The inferences described above require a model to translate temperature information into flow information. This paper presents a model for predicting the temperature profile in a nominally horizontal well during normal production (steady-state flow). A forward model of the temperature profile caused by given flow conditions can be the basis of the inverse model needed to determine flow profiles
Prediction of the wellbore temperature profile requires models of all of the often-subtle thermal effects occurring in the reservoir and in the wellbore itself. For the reservoir temperature model, we couple mass and energy balances of fluid flow in a permeable media in a box-shaped homogeneous reservoir with a wellbore temperature model using a multisegment technique. Similarly for the wellbore, we couple mass, momentum, and energy balances to model pressure and temperature behavior. The models presented in this paper account for Joule-Thomson effects, and convective and conductive heat transfer. The primary results of the model are estimates of the extent of temperature change from geothermal temperature during flow. Results show that temperature changes of a few degrees are possible; temperature changes of this magnitude are certainly detectable with current technology. A second result is a demonstration of the inference of single phase and multiphase flow profiles from a synthetic case. Sensitivity studies with the model illustrate the flow conditions that cause measurable temperature changes or anomalies that could be recognized in an analysis of distributed temperature measurements.
Laboratory and Field Study of the Influence of Simple Carboxylates on Oilfield Corrosion and Inhibition
Authors: Martin R. L. , Logan P. D. 
Published: December 2007

Abstract
The influence of simple carboxylates on oilfield chemistry measurements, steel corrosion, and corrosion inhibition was studied. In most cases, the error in the field measurement of dissolved CO2 was found to be small. In all but two cases examined, the error in bicarbonate ion measurement was small because of the large actual bicarbonate ion to carboxylate ratio.
The presence of acetate and propionate ions in laboratory tests always accelerated the uninhibited corrosion rate of mild steel because of an increase in cathodic kinetics when the steel was behaving actively. In passive systems, anodic increases were seen.
Both acetate and propionate were detected in field samples; in only one case butyrate was observed. Corrosion inhibitors were effective at controlling corrosion even in the presence of these ions in both laboratory and field conditions.
Waterflood Surveillance and Control: Incorporating Hall Plot and Slope Analysis
Authors: Silin D. B. , Holtzman R. , Patzek T. W. , Brink J. L. , Minner M. L. 
Published: December 2007

Abstract
Waterflood automation at a field scale is a complex coupled problem. In our analysis, data from injecting and producing wells, as well as satellite differential interferograms (InSAR) are used as the inputs. Some information processing is carried out on-line automatically, and other needs personnel expertise. Dynamic adaptive control is performed in the mixed openloop-feedback mode. Our surveillance-control system is being implemented in Sections 32 and 33 of the Lost Hills diatomite field, CA, USA.
Modeling of Laser Spallation Drilling of Rocks for Gas– and Oil Well Drilling
Authors: Xu Z. , Yamashita Y. , Reed C. B. 
Published: December 2007

Abstract
High power lasers can weaken, spall, melt and vaporize natural earth materials with thermal spallation being the most energy efficient rock removal mechanism.The most interesting focus of recent laser rock drilling research is on developing a laser rock spallation technique to drill large and deep holes in rocks, a potential application in gas and oil well drilling having a rock removal rate higher than that of conventional rotary drilling as well as that of flame-jet spallation.Research is also focused on using laser rock spallation to make perforation channels with improved permeability of the perforated rocks.However, laser rock spallation is a very complex phenomenon that depends on many factors.Fundamental understanding of this complex phenomenon is crucial to the success of its application to the petroleum industry.
In this paper, we propose a combined approach to this complex problem, that is establishing models for each of the physical phenomena based on the finite difference method (FDM), then combining them into one numerical procedure using the Combined Unified Procedure (C-CUP) method.With this approach, the transient temperature and stress distributions in dry or water-saturated rocks exposed to a laser beam have been calculated.The spallation boundary and rock removal efficiency have been determined for different laser conditions.The modeling results provide a better understanding of laser rock spallation phenomenon and most importantly, guidelines for selecting processing parameters for fast rock removal.
Unified Modeling of Gas/Oil/Water Pipe Flow—Basic Approaches and Preliminary Validation
Authors: Zhang H. -Q. , Sarica C. 
Published: December 2007

Abstract
A unified model is proposed for the prediction of flow behavior during production and transportation of gas, oil and water through wellbores and pipelines.In gas-oil-water three-phase pipe flow, the phase distributions and hydrodynamics are described based on two criteria: gas-liquid flow pattern and oil-water mixing status.The three-phase flow is treated as gas-liquid two-phase flow if the two liquids are fully mixed or as a three-layer stratified flow at low flow rates in horizontal or slightly inclined pipes.Most three-phase flows fall between these two extremes: partially mixed with slippage between the two liquid phases.Closure relationships describing the distribution between the liquid phases, namely mixing and inversion are proposed.The model predictions are compared with experimental data of gas-oil-water pipe flows. Significant improvements are observed over the predictions by the two-phase unified model of Zhang et al.[1] which assumes fully mixed liquid phase.
Methodology of Investigating the Compositional Gradient within the Hydrocarbon Column
Authors: Hussein H. H. , Mahgoub I. S. 
Published: December 2007

Abstract
The phenomenon of variation of fluid properties with depth was investigated in many of the Gulf of Suez and Western Desert fields of Egypt. This phenomenon primarily exists in reservoirs with large closures (large thickness or high dip angle, even for thin formations) where the gravitational forces have a significant effect on the overall composition of the system over the geological time.[1,2,3] The phenomenon often exists also in high shrinkage oils, volatile oils4 and rich gas condensates as well as in black oils. Such compositional grading can have significant influences on various aspects of reservoir development. This must be taken into account during estimation of the stock-tank oil initially in place of such fields and well/reservoir behavior evaluation.
This paper presents an engineering evaluation for validating PVT lab analyses of many fluid samples collected at different depths from several reservoirs of different fields. As a result of this evaluation, the valid samples were supportingfluid property variation with depth where its properties can be correlated as a linear function of depth.
Two methods have been used for correlating the fluid properties with depth. The first method relies only on the experimental PVT data provided by the laboratories while the second method uses an equation of state to predict the fluid properties from the experimentally determined compositional analyses. The second method make use from the advantage that in this particular case the equation of state parameters assigned to each hydrocarbon and pseudo-hydrocarbon component within the oil column should be constant for all valid samples. In this method, the most accurate reservoir fluid composition for one of the valid samples was used to predict the reservoir fluid composition and its corresponding PVT properties at different bottomhole locations. The prediction procedure is a combination of stream blending and flash liberation processes to estimate the reservoir fluid properties at shallower and deeper depths from the depth of the selected sample.
Once the fluid properties of the compositional gradient are developed, the engineer can proceed using either black oil or compositional model to match the history and predict the performance of the reservoir under the acting drive mechanism.
Tidal Pressure Response and Surveillance of Water Encroachment
Authors: Langaas K. , Nilsen K. I. , Skjaeveland S. M. 
Published: December 2007

Abstract
A review of the tidal response in petroleum reservoirs is given. It is caused by periodic changes in overburden stress induced by the ocean tide. The "tidal efficiency factor" is derived by two different approaches and is in line with a recent well test in the Ormen Lange gas field.
For small geomechanical pertubations, like the tidal effect, we show that a simplified coupling of geomechanics and fluid flow is possible. The coupling is easy to implement in a standard reservoir simulator by introducing a porosity varying in phase with the tide. Simulations show very good agreement with the theory.
The observation of the tidal response in petroleum reservoirs is an independent information provider, i.e., it provides information in addition to the (average) pressure and its derivative from a well test. The implementation of the tidal effect in a normal reservoir simulator gives us the possibility to study complex multiphase situations and to evaluate the potential of the tidal response as a reservoir surveillance method. The case studies presented here focus on the possibility to observe water in the near-well area of a gas well.
Ultrafine-Scale Validation of Upscaling Techniques
Authors: Wang K. , Sepehrnoori K. , Killough J. E. 
Published: December 2007

Abstract
A combination technique of parallel simulation technology and upscaling algorithms is described. Based on our case studies, the results from the fine-scale model may appropriately be used to guide the upscaling procedure via a tuning procedure. This tuning procedure has been explored in the study to obtain results that are in close agreement with fine-scale simulation results. The combination of parallel simulation technology and upscaling algorithms can be used to provide a better estimation of the amount of uncertainty in predicted oil recovery for real fields. The concept of local global upscaling has been extended to include a technique that honors arbitrary faults in complex geological environments.
Several single-phase upscaling techniques are applied to an analog Gulf of Mexico reservoir model and a synthetic model. For the Gulf of Mexico reservoir model, we obtained results that were in close agreement with coarsened models obtained from the parallel simulations using the fine-scale model. In this case, the CPU time of one simulation run with 20 years of production time was significantly reduced from 22 hours, using a PC cluster with 8 processors computer, to 2 minutes, a single processor, applying upscaling methods. For the synthetic model, the agreement between coarse-scale model and the fine-scale model using the same upscaling method is within engineering accuracy.
Efficient Assessment and Optimization of a Deepwater Asset Development Using Fixed Pattern Approach
Authors: Ozdogan U. , Sahni A. , Yeten B. , Guyaguler B. , Chen W. H. 
Published: December 2007

Abstract
Decisions made during the reservoir development phase have major impact on the project economics. Due to reservoir complexity and severe nonlinear interactions between decision parameters, automated optimization algorithms may be needed to supplement intuitive reservoir engineering analysis. Previous algorithms, proposed for well placement optimization, search for optimum well locations without full consideration of engineering knowledge and practice. This may result in degradation of optimization efficiency (number of simulations) and output unrealistic suboptimal well configurations.
This study proposes an approach that superimposes engineering knowledge and practice on an automated optimization routine (the Hybrid Genetic Algorithm, HGA) to maximize the value and efficiency of field development optimization. The new approach is called the Fixed Pattern Approach (FPA), since it enforces the HGA to locate thewells on a user defined pattern inspiring from the idea that the wells are more likely to be drilled in specific patterns (line, staggered-line, five-spot etc.). The FPA essentially incorporates reservoir engineering concepts within the parameterization of optimization problem and reduces the search-space size considerably by eliminating the simulation of infeasible development scenarios.
The FPA was applied to a deepwater field to get a quick understanding about the possible optimum development scenarios. In the scope of this study, finding the optimum development plan was defined as determining the optimum number and location of producers and injectors, as well as production rates and the starting time of injection that maximizes the Net Present Value (NPV) of the project. These parameters were optimized simultaneously using a black oil reservoir simulator as the objective function evaluator. Comparison with respect to the conventional window approach showed that FPA significantly reduced the CPU time and resulted in practical and economical well locations. Uncertainty in the geological properties (porosity, permeability) and reservoir structure was also addressed for this field by performing optimization on five different models constructed by a Plackett-Burman experimental design. The new methodology recommended an optimum field development plan while taking the uncertainty of property distributions and reservoir structure into account.
Installation and Application of Permanent Downhole Optical Pressure/Temperature Gauges and Distributed Temperature Sensing in Producing Deepwater Wells at Marco Polo
Authors: Weaver M. , Kragas T. , Burman J. , Copeland D. , Phillips B. , Seagraves R. 
Published: December 2007

Abstract
The deepwater environment presents numerous challenges in the production of oil and gas wells. The expense of intervention operations and the corporate bottom line impact of production optimization have generated a need for more sophisticated data gathering and monitoring systems. However, implementing these new technologies in deepwater is challenging because of a lack of installation experience in this environment and difficulty quantifying full cycle benefits.
One recent successful application of new technology is the use of permanently installed downhole optical pressure/temperature gauges and distributed temperature sensors (DTS) to monitor well performance in the producing wells at the Marco Polo field in the deepwater Gulf of Mexico. Innovative techniques were utilized during the facility commissioning and completion operations, allowing these gauges to be installed more efficiently than in the past. The resulting cost savings helped to minimize the additional expenses associated with implementing this technology.
The information from the downhole optical monitoring system has proven useful not just in providing pressure data for reservoir management and drawdown maintenance, but in application of the DTS data in different production scenarios. DTS data has been used to monitor well performance for flow assurance purposes. It has been used with the gas lift system to define valve setting parameters during the job design and to monitor the point(s) of gas injection once the design is in place. To further enhance the value of information from the downhole optical monitoring system, the data is directly available via the internet for real time evaluation.
Platform-Free Fields for Stranded Gas Development: Science or Fiction?
Authors: Rivero M. , Nakagawa E. 
Published: December 2007

Abstract
The requirement for larger and complex production platforms for the development of deepwater gas fields worldwide makes the exploitation of these resources unfeasible. Aiming at reducing the size of these facilities and, consequently, the field development costs, the industry has been conducting, for several years, initiatives in sub-sea processing.
This paper proposes a drastic paradigm shift to meet the requirements of stranded gas: the substitution of surface hydrocarbons processing located in production platforms by down-hole and sub-sea facilities. The vision of Platform Free Fields (PF2) challenges R&D groups to provide real step changes for the feasibility of the gas business. A systematic pathway towards PF2 is analyzed considering economical drivers, an extensive review of the state-of-the-art technology, challenges associated to well architecture and construction, design of down-hole and sub-sea production processes and flow assurance implications.
An analysis of the existing R&D and efforts associated with the exploitation of offshore deepwater gas fields is presented. Based on such analysis and the major challenges involved in the PF2 concept, the paper discusses the viability of such vision and proposes an approach for it. The value creation for each stepwise development is commented along with the modularity and reliability of the concept.
The PF2 constitutes a vision to be shared by all parties involved in the development of stranded gas fields. The vision will guide and encourage industry collaboration towards the goal of making possible the exploitation of such stranded resources far more effectively and likely to succeed than if driven by isolated efforts.
Finally, the paper presents a technical and critical review of tendencies and highlights the most important issues to be addressed for a paradigm change: pushing limits and pulling innovation based on people's experience and knowledge.
Long-Term High-Temperature Laboratory Cement Data Aid in the Selection of Optimized Cements
Authors: Jennings S. S. 
Published: December 2007

AbstractCements placed in gas wells for Saudi Arabia drilling operations were evaluated for physical properties. Three intermediate casing cement compositions were tested. The cement systems tested were: 1) bentonite extended, 2) standard density class G and 3) optimized particle packing lightweight system containing hollow ceramic spheres. These tests were requested because of concerns that the cements that were currently being used were not durable in the long term. Khuff and pre-Khuff gas wells in Saudi Arabia have high production rate potential therefore the curing test temperature of 300 oF and test pressures of 3000 psi were applied to the samples. The samples were cured for one year.The tests performed were API compressive strength tests, permeability, shrinkage or expansion, Young's Modulus, Poisson ratio, rheology and settling. Data for 24 hour, 7 days, 1, 2, 3, 6, 9 and 12 months test periods are presented for all cements.Certain cements, for which there are no previously published shrinkage data, have been identified.New technology in cement laboratory testing identified undesirable properties in certain cements. Using this new lab technology, some cements exhibited undesirable short and long-term physical properties. Data representing various cement slurry designs and corresponding physical properties results are included in this paper.
Low Cost Multilateral on Gullfaks
Authors: Lie O. H. , Fraser S. 
Published: December 2007

Abstract
Gullfaks is a typical mature field where cost efficient solutions need to be in focus. There is also the challenge that old wells produce at low rates, but nevertheless at rates not drastically lower than those that an alternative use of the slot can deliver. One solution to this challenge is to maintain production from the old well while simultaneously gaining inexpensive access to new a drainage point(s).
B-1A on the Gullfaks field was drilled and completed in January 2003 using hollow whipstock technology. The operation was a technical success which proved that Multilateral (MLT) solutions can be delivered at costs only marginally above those of a conventional sidetrack. To further enhance the value of the slot, a second through tubing MLT lateral was added in January 2005.
The key considerations during the planning phase were proven solutions, cheap technology and low risk. This paper illustrates the decision process prior to choosing this particular technology, the installation process itself, the lessons learned and the strategy which may be applied in the future.
Improved Reservoir Management With Intelligent Multizone WAG Injectors and Downhole Optical Flow Monitoring
Authors: Sandøy B. , Tjomsland T. , Barton D. T. , Daae G. H. , Johansen E. S. , Vold G. 
Published: December 2007

Abstract
A 4-zone intelligent WAG injector was installed at the Statoil Veslefrikk Field in the North Sea, in May 2004. The completion includes one on/off and three variable downhole chokes for controlling injection rate into each of the four zones. The completion also includes three downhole optical flowmeters and three optical pressure and temperature gauges. Measurement of the surface injection rate and the rate from each of the three flow meters provides real-time measurement of injection rate into each zone, regardless of choke positions.
The well is on a Water Alternating Gas (WAG) cycle where one zone is primarily intended for gas injection and the other three zones are primarily intended for water injection. Therefore, equipment that can control and measure water and gas flow with no changes in hardware was critical for the success of this installation.
The combination of downhole chokes and flowmeters allow full control and monitoring of zonal injection rates and has proved to be a valuable tool in managing reservoir pressures and optimizing production. After more than one year of operation during water injection, all the valves and the optical monitoring equipment are functioning satisfactorily. It is estimated that up to about half of the well's value creation during its expected lifetime is due to the DIACS* installation.