bluuebunny/crossref_metadata_2025_split huggingface dataset:
Look Ahead VSP, Inversion, and Imaging from ZVSP and OVSP in a Surface Basalt Environment: Neuquen Basin, Argentina
Authors: Rodríguez Aias Leonardo , Galaguza Mario , Sanchez Adrian 
Published: December 2007

Abstract
In order to improve the seismic imaging and delineation of a reservoir, an OVSP was run in an exploratory well; Neuquén Basin; Argentina. A second purpose of this acquisition was to accurately locate an Intermediate Casing above the main target. Acoustic Impedance Inversion of the corresponding Zero Offset VSP plus the image interpretation generated from the OVSP data helped to define the position of a sill, which was one of the objectives in this project.
The thick (hundreds of meters) and extensive Auca Mahuida volcanic complex which covers most of the region, considerably reduces the signal to noise ratio of the seismic data; strongly attenuating the high frequencies of the data due to wavefields dispersion, hampering their separation at the processing stage. This effect is stronger in surface seismic than in borehole seismic, due to greater offset and two-way traveltime, so that VSP is used as a tool in this environment. Therefore, Q factor estimation (and consequently Q inverse filtering application) computed directly from Zero offset VSP, is a very valuable technique which allowed us to recover high frequencies in the field area improving vertical seismic resolution and helped to define the reservoir with greater accuracy.
An acoustic impedance inversion of the VSP trace was later obtained, and its interpretation was very useful to predict impedance variations, related to lithology and formation changes in the deeper portion of the stratigraphic column. This was the first deep exploratory well (4750 meters) in this part of the basin, so the implemented technique led to define deep formation tops.
The acquisition was performed by Schlumberger using the multilevel 3C high-fidelity downhole tool, Versatile Seismic Imager (VSI). It was used two vibrators simultaneously in flip-flop configuration for both source positions in order to reduce the operational time.
Increase Heavy-Oil Production in Combustion Tube Experiments through the Use of Catalyst
Authors: Ramírez-Garnica M. A. , Mamora D. D. , Nares H. R. , Schacht-Hernández P. , Mohammad A. A. , Cabrera-Reyes M. C. 
Published: December 2007

Abstract
In this research a catalyst was evaluated in a combustion tube using heavy oil from Gulf of Mexico. The underlying objective is to increase the mobility of the oil inside the reservoir by effect of the catalyst during the combustion.
The catalyst, used in the experiments was previously mixed with heavy crude oil of 12.5 °API. The catalyst, in liquid phase, is based in Molybdenum, Cobalt, Nickel and Iron. This organometallic catalyst is highly soluble and ultradispersed, and it was mixture with heavy crude oil with a concentration of 750 ppm wt.
The porous media used in the combustion tube was a triturated dolomite carbonated rock with a 41.9% of porosity, and a particle size of 0.42 mm. This rock was used for two experiments at the same saturation conditions: heavy crude oil (23.79%), and water (25.26%).
The results obtained shown the advantages of use of catalyst in relationship of a conventional combustion as follows: (1) oil production increases, (2) faster combustion front, (3) higher efficiency in the combustion, and (4) higher temperatures at the beginning of the combustion.
The use of this kind of organometallic catalyst at low concentrations is a potential application in order to upgrade the oil properties in-situ, saving the cost of facilities on surface required for the same purpose.
Optimization of Cyclic Steam Stimulation Under Uncertainty
Authors: Revana K. , Erdogan H. M 
Published: December 2007

Abstract
Heavy Oil is an increasingly important resource for securing future energy supply as conventional resources are depleted. The recovery of this resource is associated with high fixed capital investments. The underlying economics for developing heavy oil are heavily dependent on market demand and price of oil & gas1. On the upside, the geologic risk associated with the recovery of this resource is minimal and the in-place quantity is three times the combined world reserve of conventional oil and gas2.
Field development decisions must be made despite uncertainties of oil and gas price, well performance, facilities costs, and downstream demand. Several conventional thermal methods exist to recover heavy oil such of steam floods, cyclic steam stimulation and SAGD.
Cyclic Steam Stimulation represents a widely used thermal recovery process that can be optimized to achieve higher oil recovery. This paper presents a workflow for coupling physics based reservoir simulator with an economic model to optimize the hydrocarbon recovery under uncertainty. In this work, a synthetic single well heavy oil reservoir model was generated and coupled with a spreadsheet based economics model to understand the synergies between the two domains.
Rubiales Oil Field: A Heavy-Oil Colombian Example of Excellent Operative PCP Systems Development
Authors: Rubio C. A. , Doval J. M. , Medina J. A. 
Published: December 2007

Abstract
Rubiales is an oilfield located in Llanos Orientales Basin (Colombia) where was installed first PCP system in 2003. At the present, Meta Petroleum Limited, a private company in growing, established in our country, operates this oilfield.
From their beginning in Rubiales field there were 23 wells with PCP Systems of which today in day prevail 12 of them, operating under stable production conditions represented in an important volume portion of total recovered crude volume at oilfield. Some of these conditions are for example, torque, water cut (BS&W %) and each well fluid level, all them features that helping reservoir production mechanism.
This oilfield produces heavy oil (12,3 °API @ 60 °F) with high water cut (Rubiales’ average BS&W = 81%) in emulsion state that indirectly has allowed an excellent development of PCP Systems, description that constitute the main objective of this article because in this application the PCP System is featured for long run lives (over one thousand days of average).
Additionally is good to emphasize, MTBF (measured time before fail) of Rubiales’ PCP Systems like a good parameter to show into wide world petroleum industry in situations to choose any artificial lift system in oilfields with similar features that Rubiales. Also several wells have supported organic treatments in some cases during this time (applying dimethylbenzene) and operating at high velocities, keeping stable production tendency and registering a minimum quantity historically from interventions to wells by reason of fails in the systems.
To finish, in this writing are described components of these systems (showing main operation parameters), type of produced fluids, oilfield generalities, identified wells with best production developments and occurred fails, information translated in a strong evidence to reach the objective of this document.
Case Study: Application of a Viscoelastic Surfactant-Based CO2-Compatible Fracturing Fluid in the Frontier Formation, Big Horn Basin, Wyoming
Authors: Bustos O. , Chen Y. , Stewart M. , Heiken K. , Bui T. , Mueller P. , Lipinski E. 
Published: December 2007

Abstract
CO2 based fluids are commonly used to fracture stimulate formations with low reservoir pressure as well as formations that are more sensitive to water treatments (high capillary pressure, swelling clays etc). In particular, the Frontier Formation located in Bighorn Basin, Wyoming, has seen a variety of stimulation fluids used over the past years with varying degrees of success. When dealing with water sensitive formations, a common practice has been to use oil-based fluids. However, fluids of this nature can have detrimental effects on gas zones with low reservoir pressure and this might be the reason for erratic well performance of previously treated Frontier completions. It has also been determined that oil-based fluids can alter the reservoir wettability and hence cause formation damage. With this in mind and considering the environmental and economical benefits of using a water-based fracturing fluid, a novel visco-elastic surfactant based, CO2-compatible, high foam quality (&gt;60%) fluid was proposed as the main fracturing fluid. This paper will discuss the first application of this visco-elastic based fluid on wells in Park County, Wyoming.
This paper will discuss stimulation with the new fluid and how pin-point pressure measurement enabled the operator to make informed decisions to define fracturing/completion strategy. We also present the additional benefits of incorporating existing dipole sonic tool information to calibrate "in-situ" stress, Young's Modulus and Poisson's ratio. Finally, a production history match is conducted on wells treated with the new fluid.
Lessons Learned From Modeling Hydraulic Fracture Treatments in Coals Using a Fully Functional Three-Dimensional Fracture Model in a San Juan Basin Project
Authors: Ramurthy Muthukumarappan , Lyons Bill 
Published: December 2007

Abstract
The two main objectives of using a hydraulic fracture model in coals are: (a) optimization of job design and placement, and (b) post-fracture diagnostics. Though certain limitations still exist, hydraulic fracture modeling in coals has undergone major advancements in the past decade. Pseudo or lumped three-dimensional (3-D) models have usually been employed to try and meet the objectives mentioned above. The effectiveness of using such models in coals has been very limited. Fully functional 3-D models are currently available in the industry and can be used to obtain better estimates of the fracture dimensions. This paper shows that a grid-oriented fully functional 3-D fracture simulator with shear decoupling can be especially useful in coals for post-fracture diagnostics if sufficient input data can be fixed from logs and Diagnostic Fracture Injection Tests (DFIT).
When problems occurred with placement of fracture treatments, especially in the upper Fruitland coals of a San Juan basin project, instead of experimenting with various ideas arbitrarily, technical evaluation using DFIT data and fracture modeling with a grid-oriented, fully functional 3-D fracture simulator, was used to pin-point the issues and address them accordingly. This paper will discuss the deficiencies of using 2-D and pseudo-3-D fracture models in coals and also will discuss the lessons learned from using a grid-oriented, fully functional 3-D fracture simulator in this project along with the successful implementation of the results developed from the modeling work.
Fiber-Laden Fracturing Fluid Improves Production in the Bakken Shale Multilateral Play
Authors: Powell A. , Bustos O. , Kordziel W. , Olsen T. , Sobernheim D. , Vizurraga T. 
Published: December 2007

Abstract
Since the horizontal lateral Bakken dolomite play began in 1999 in eastern Montana, more than 330 wells have been permitted and more than 200 wells are now producing. The lateral play began in Richland County, Montana, and the success there is now accelerating the transfer of technology to the North Dakota side of the Bakken trend and is attracting several new and existing operators to the area. Different drilling and completion techniques have been tried since the start of the play with different degrees of success.
In June of 2005 a new technique was introduced utilizing chopped fibers within the fracturing gel slurry to help suspend proppant in the slurry both during the fracture pumping and also during fracture closure. The primary goal was to be able to create a more even distribution of proppant in the created fracture while reducing the polymer requirement for the fracturing gel slurry. A secondary goal was to use slugs of the fiber to bridge at the fracture entry face and divert the treatment into new fracture planes, thereby improving the completion efficiency of the treatment. Lastly, it was hoped that the introduction of the fiber, which would dissolve shortly after placement, would improve proppant retention within the hydraulic fracture and impede flowback into the horizontal leg of the wellbore.
The results from this new technique have been encouraging; with an estimated 24% improvement in average well productivity since the fiber designs have been implemented. Additional benefits have been realized like elimination of chokes cutting out due to sand production and associated wellbore fill clean out, lower polymer requirements reducing gel costs, and a reduction in premature screenouts.
Forecasting Oil Production in Waterflooded Reservoirs
Authors: de França Corrêa Antonio Cláudio 
Published: December 2007

Abstract
A three-parameter model relating the decline of the oil cut with the fractional oil recovery for waterflooded petroleum fields or reservoirs is described. The model is based on observation of the behavior of several Brazilian oil fields, in which the oil displacement occurs either by water injection or by natural aquifer influx, or both.
The model is used to derive equations to forecast the oil and water production rates in waterflooded systems. These equations may also be used to design a waterflood expansion in any phase of a field's life.
An example of the application of the model equations to forecast the behavior of a waterflood in a mature heavy oil field is presented. Because the results of the analysis indicated that the field will still be profitable at the end of the concession period, the model equations are applied to design and forecast an augmented waterflood for the field.
The model equation may be used to estimate the oil reserves at any stage of maturity of an oil field.
The model parameters are obtained by fitting the model equation to historical field data by means of a least square algorithm. A type-curve procedure is applied to obtain the initial guesses of the model parameters required by the mathematical algorithm.
A relation between the oil cut decline model and the classical rate-time decline is derived for the case in which the total liquid flow rate is constant.
Examples of oil cut decline of several Brazilian fields are presented and the decline model is used to determine the ultimate oil recoveries of these fields. The ultimate oil recovery is proportional to the amount of water produced during the field's life, which is related to the water-oil ratio at abandonment conditions.
When the operating conditions of a field change, so does the oil-cut decline trend. An example of the change in the oil-cut decline trend is presented for a heavy oil field submitted to a late steam drive.
Estimating Critical Velocity to Prevent Bed Development for Horizontal-Inclined Wellbores
Authors: Ozbayoglu Evren M. , Saasen Arild , Sorgun Mehmet , Svanes Kare 
Published: December 2007

Abstract
Hole cleaning is one of the major considerations at both design and application stages for a drilling operation. This concept is more emphasized as the wellbore inclination is high, and the size of the wellbore flow area is lower. Especially at horizontal or high inclinations, if the fluid velocity is lower than a critical value, a stationary bed develops, which may cause various problems such as high drag, higher probability of pipe stuck, higher hydraulic requirements, etc, if not removed properly. Therefore, it becomes important and essential to identify the critical velocity. This study aims to estimate the critical fluid flow velocity for preventing the development of a stationary bed using empirical correlations that can be used easily at the field. Also, a rough estimation of bed thickness is also introduced if the flow velocity is lower than the critical velocity. For this purpose, extensive cuttings transport experiments with water have been conducted at Middle East Technical University, Petroleum and Natural Gas Engineering Department, Cuttings Transport Flow Loop for various inclinations, flow rates and rate of penetrations. The inner pipe is subjected to a sagging, therefore, more realistic annulus representation is achieved. Observations showed that, a stationary bed can be developed even the inclination of the wellbore is down to 50 degrees. Results showed that, the critical velocity could be estimated using the proposed correlations with a reasonable accuracy when compared with the experimental results. Also, for flow velocities less than the critical values, the thickness of the stationary bed can be detected within an error range of ± 10%.
An Engineered Fiber for the Fracturing of Unconsolidated Sand in Highly Deviated Wells in the Tali Field of Brunei
Authors: Law Matthew , Chao George W. , Alim Hafeez A. , Hashim Ahmad F. , Samuel Elsamma , Samuel Mathew 
Published: December 2007

Abstract
This paper discusses the application of fibers for the Frac and Pack application for Brunei Shell Petroleum (BSP). Seven wells with a total of seventeen fracturing treatments in this study are on a multilayered unconsolidated formation, where sand control is a part of well management during the production life of the wells. Previous techniques of open hole external gravel packing and cased hole Internal Gravel Packing (IGP) for controlling formation sand were challenged by reduced flow efficiency of the wells. The recent development of Expandable Sand Screen (ESS) combined with fracturing treatment could not control produced sand, due to failure in perforation techniques. An improved idea of perforating only the lower side of deviated wells using minimum viscosity fluids and minimum amount of pad with limited proppant sand concentration resulted in low net pressure build up.
These challenges were prevailed over by the application of a new fiber technology in which fiber is used (1) to transport higher sand concentration to the fracture, and (2) to control the sand flow back during production as well. Since this technology is physical rather than chemical, the proppant flowback is controlled without specific shut-in time, temperature, or pressure constraints. The use of fiber technique prevents sand falling down from perforations and ensures the ESS running smoothly. This technique enabled Brunei Shell Petroleum to cost effectively complete the highly deviated wells with stimulation and sand control. In presence of the fiber, higher proppant concentrations upto 9 ppa could be used successfully even with linear guar gel. This promotes the net pressure build up which is vital for fracturing treatment in high permeability reservoir. Eleven fracturing treatments on five different wells have been performed with excellent results.
Evaluating Reservoir Production Strategies in Miscible and Immiscible Gas-Injection Projects
Authors: Farzad Iman , Amani Mahmood 
Published: December 2007

Abstract
Successful design and implementation of a miscible gas injection project depends upon the minimum miscibility pressure (MMP) and other factors such as reservoir and fluid characterization. The experimental methods available for determining MMP are both costly and time consuming. Therefore, the use of correlations that prove to be reliable for a wide range of fluid types would likely be considered acceptable for preliminary screening studies. This work includes a comparative evaluation of MMP correlations and thermodynamic models using an equation of state by PVTsim1 software. We observed that none of the evaluated MMP correlations studied in this investigation is sufficiently reliable. EOS-based analytical methods seemed to be more conservative in predicting MMP values. Following an acceptable estimate of MMP, several compositional simulation runs were conducted to determine the sensitivity of the oil recovery to variations in injection pressure (at pressures above, equal to and below the estimated MMP), stratification and mobility ratio parameters in miscible and immiscible gas injection projects. Simulation results indicated that injection pressure was a key parameter that affects oil recovery to a high degree. MMP determined to be the optimum injection pressure. Stratification and mobility ratio could also affect the recovery efficiency of the reservoir in a variety of ways.
Use of Single-Step 9% HF in Geothermal Well Stimulation
Authors: Rae Phil , bte Ahmad Atikah , Portman Lance , Acorda Edgar Paul 
Published: December 2007

Abstract
Geothermal wells represent an important source of energy in many parts of the world, yet they receive little attention in the mainstream literature. Annual worldwide production of geothermally-derived electrical power is some 57000 GWh from 8900MW of installed capacity and Philippines is the second largest producer with almost 2000MW of capacity.
In general, geothermal wells produce steam, generated by the contact of water with hot metamorphic rock, and this is used to drive turbines for electricity generation. Geothermal fields usually comprise both production, and injection, wells and, like oil and gas wells, these can suffer from production (or injection) impairment. The most common forms of impairment in geothermal wells are mineral scales dissolved in the hot water and then deposited as a result of thermal disequilibrium or phase changes. Many mineral species can be present, depending on rock composition and injection water quality, but one of the more prevalent is silica (SiO2). Normally, such mineral deposits are removed, periodically, by acidising with combinations of hydrochloric and hydrofluoric acids.
This paper describes work performed on geothermal wells in Philippines in early 2006. Laboratory testing demonstrated that acid formulations with 3-6% HF, as had been used historically, were capable of dissolving only a fraction of the scale deposits, even with a large stoichiometric excess of acid. Surprisingly, increasing the HF concentration to 9%, in a specially buffered acid system, resulted in total scale dissolution, in laboratory tests. Furthermore, the high silica content of the scale, absence of problematic minerals in the formation and fractured nature of the reservoir, persuaded us to eliminate the HCl preflush on these treatments, a novel concept that had never been tried in Philippines.
The application of this system in the field posed some special technical and HSE challenges. However, all the treatments were carried out safely and successfully, without incident, and with excellent results as briefly described in this paper.
Bayesian Characterization of Subsurface Lithofacies and Saturation Fluid
Authors: Teixeira Raquel , Braga Igor , Loures Luiz 
Published: December 2007

Abstract
Bayesian decision theory is a statistically based theory that is used to assess the degree of certainty and the potential costs when making decisions. This paper presents a methodology, based on the Bayesian decision theory, used to infer subsurface lithofacies and saturation fluid by integrating different data sources, such as well logs data and seismic attributes, which are derived from an elastic seismic inversion. This methodology was applied on a data volume from an offshore Brazilian field to generate, as a final product, a lithofacies model and a fluid indicator for this field. Uncertainty quantification of the models was also analyzed at this work.
To infer the subsurface lithofacies, the existing facies were identified from well logs data, using the expectation-maximization (EM) algorithm. This step defines the lithofacies behavior in seismic attributes domains through the use of probability density functions (PDF). Next, the subsurface lithofacies were classified by applying the maximum posterior probability (MAP) classification, using the seismic attributes as input and the PDFs computed previously. The environment was divided into cells, then the probability and uncertainty was assessed to infer the lithofacie for each cell.
After inferring the subsurface lithofacies, the fluid was inferred for the cells identified as reservoir lithofacies. Assuming an oil-water system, the fluid substitution theory and the Bayes theorem were applied to the well log data to determine the PDFs for each scenario. Following the Bayesian decision theory, the most likely fluid and the associated error was determined for each cell identified as reservoir.