bluuebunny/crossref_metadata_2025_split huggingface dataset:
Rotary Drilling US-Khuff Formation with PDC Bits
Authors: Salman Moh'd , El Raggal H. 
Published: December 2007

Abstract
Over the years in the Arabian Gulf Offshore Khuff gas wells have been drilled by turbodrilling technique in both 12 ¼' and 8 ½" hole and proved to be more economical and reliable compared with the application of rotary drilling with roller cone bits. However, bit sticking problems were experienced while the turbine was in the hole in most of the deep Khuff wells, resulting in fishing job or sidetracking operations.
A total of fifteen major occasions were quoted, more than half of them took place while making a drill pipe connection. The bit was the sticking point, in view of the facts, that it was possible to circulate and rotate with the turbine.
Operating company Adma-Opco's solution to this drilling problems, involved the use of new TSP or PDC bits technology combined with new turbine stabilization and the use of new PDC bits design and features on rotary drilling. The drilling performance that is analyzed in this paper, highlights the following:
Use of successful bit design as well as new bit technology and features in combination with turbine and on rotary assembly. Impact of new PDC cutter technologies on bit life and rate of penetration. Torque and vibration with PDC bits. Hydraulic requirements for PDC bits in deep well application. Influence of PDC cutter size on performance when drilling Khuff formation.
Influence of Temperature and Interfacial Tension on Spontaneous Imbibition Process
Authors: Chimienti M. E. , Illiano S. N. , Najurieta H. L. 
Published: December 2007

Abstract
Spontaneous imbibition is a mechanism that can significantly contribute to the production rate and final oil recovery in fractured and stratified reservoirs.
This mechanism is affected by rock and fluid properties and it has been reported by several authors to be strongly dependent on interfacial tension (IFT) and contact angle. Both magnitudes are influenced by system temperature.
In this work a laboratory study is performed on the influence of IFT and temperature on production rate and oil recovery for a given rock-fluid system. All sequences were performed on rock and fluid samples from Argentine basins. Rock samples were of medium permeability (56.1 to 83.1 mD) and porosity ranging from 18.7 % to 22.9 %. The fluids used were formation water and medium viscosity oil (45 cp at standard conditions). The samples were carried to irreducible water saturation before performing the imbibition tests resembling the assumed reservoir condition.
Initial tests were designed including representative water, oil and rock samples at several temperature levels. Another sequence of tests were performed with the addition of variable amounts of water dispersed surfactant. A noticeable influence of experimental conditions was found on the final results. As part of the tests, the same final temperature was reached through single and several steps observing the differences in overall performance.
SAGD, Pilot Test in Venezuela
Authors: Mendoza Humberto A. , Finol Jose J. , Butler Roger M. 
Published: December 2007

Abstract
PDVSA, began its first pilot test of a steam assisted gravity drainage (SAGD) production system in Latin America during June 1997. The "dual well" SAGD process requires the horizontal drilling of two wells one above the other. The upper well is dedicated to injecting steam in a continuous form and the lower to produce the reservoir fluids.
The pilot test was carried out in the Tia Juana Field, Western Venezuelan, where reservoir fluids are highly viscous (typically 20,000 cp. under reservoir conditions). Reservoir depth is approximately 1000 ft with a porosity of 38% and a permeability of 1-2 darcies. The pilot wells consisted of two pairs of infill wells within an original seven spot pattern with a well spacing of 231 meters.
The planning and implementation of the test was done between June and December 1997. Production started on December 15, 1997. The drilling stage of the pilot required the use of a "Magnetic Guidance Tool" (MGT) to drill the horizontal wells with a 5 meter distance between producer and injector along the horizontal section.
The paper shows pressure and temperature data acquired during the SAGD process from both conventional single point gauges and the latest generation of fibre optic distributed temperature measurements providing real time thermal profiles along the complete well bore.
The production results during the first year of operation show an average production of 700 bopd, which is above the initial production expected. This performance is promising, and it is expected that the initial objective of 60% recovery in the pilot area will be reached approximately 3 ½ years from the onset of production.
During the first year of production, a history match was performed using the Stars simulator. The comparison of real and simulated production shows close agreement and a final recovery in the order of 60 % of STOIIP has been estimated.
Effective Pay Zone Isolation of Steam Injection Wells
Authors: Blanco A. , Colina A. , Rodríguez W. , Bolívar R. 
Published: December 2007

ABSTRACT
The steam injection process is on of the main methods for enhanced recovery of heavy and extra heavy oil in shallow reservoirs. The cementing of such wells has conventionally been performed using a Portland cement slurry formulated with silica flour to prevent retrogression in compressive strength. The main disadvantage of this type of slurry is the incompatibility between the cement and mud system which results in problems of channeling an microannulus around the casing. Additionally, thermal stresses caused by the steam injection process affect th development of physical properties of set cement increasing permeability and decreasing casing – cement bonding. This paper shows the results of field applications of a new technology t isolate steam injection wells, based on blast furnace slag. Th new technology provides a cementing system that is compatibl with mud, has low permeability, is expansive and develops stabl mechanical properties during and after the steam injection process. These characteristics assure the zonal isolation of pa zones and offer potential incremental improvement to the stea injection process compared with conventional technologies.
Predicting Temperature Profiles in Producing Oil Wells Using Artificial Neural Networks
Authors: Farshad F. , Garber J. D. , Lorde J. N. 
Published: December 2007

Abstract
The prediction of flowing fluid temperature profiles in producing wells has become necessary in several design problems that arise in oil and gas production. The accurate prediction of temperature drop due to flow in oil or gas wells is required by engineers and scientists for many design calculations including developing programs to optimize deliverability of wells1, designing artificial lift installations2 and characterization of corrosion3. In addition, existing multiphase flow correlations require PVT data of the wellbore fluid which are temperature-dependent parameters.
Many correlations to predict temperature profiles of the wellbore fluid, for single-phase or multiphase flow, in producing oil wells have been developed using theoretical principles such as energy, mass and momentum balances coupled with regression analysis.
This paper presents a novel approach of using artificial neural networks (ANNs) for predicting temperature profiles. Two artificial neural network models that predict the temperature of the flowing fluid at any depth in flowing oil wells were developed. Backpropagation was used in training the networks. The networks were tested using measured temperature profiles from seventeen wells in the Gulf Coast area. The neural network models successfully mapped the general temperature-profile trends of naturally flowing oil wells. The better of the two models predicted the fluid temperature with a mean absolute relative percentage error of 6.0%.
The accuracy of the proposed neural network models to predict the temperature profile is compared to that of existing correlations. The neural network based model in this study exhibits significantly lower mean absolute relative percentage error than other correlations. Furthermore, in order to test the accuracy of the neural network models to that of the Kirkpatrick4 correlation, a mathematical model was developed for Kirkpatrick4 flowing temperature gradient chart.
Asset Based Technology Planning
Authors: Ungredda Alessandro , Carrasquel Aminta , Romero Edgar , Alfonzo Alvaro 
Published: December 2007

Abstract
As a means of enabling Petróleos de Venezuela's (Venezuelan State Oil Company), continuous quest for optimal business opportunities within its E&P operations, a Process has been designed and adopted for the Planning and Implementation of its R&D and Technology Effort. Said process, which has been adequately learned by the Corporation, aims at materializing value creation opportunities starting from a comprehensive matching of business needs and new technologies. As a second step, the process determines a close collaboration between Technology Organizations and the Operator Units in order to properly evaluate and transfer new technologies into their ongoing operations. Accurate understanding of current and future operation conditions, is the most important element to assure commitment from both groups.
A correct framing of the business case, including risk assessment for each proposed technology, secures high level support for the whole effort. Provisions are made to implement Projects for the proper integration of available and proposed Technologies for the optimum exploitation of each Asset. As a result each project reduce required time for the transfer and deployment of new technologies by the Asset Units thus materializing the optimum value for the Corporation.
The whole Technology Planning process here described has been fully integrated with the ongoing Business Planning and Budgeting system assuring its alignment with the main issues and needs that guide Short and Long Term vision of PDVSA's E&P business, therefore assuring proper funding and support for the Technology effort needed to achieve them.
Managing the Evaluation of Improved Oil Recovery Technologies
Authors: Mogollón J. L. , Romero L. , Cohen L. Anselmi 
Published: December 2007

Abstract
In the last five years PDVSA has dedicated a big effort to develop and evaluate new technologies in order to improve light-medium oil recovery factors, by optimizing: mobility ratio, surface tension and water conformance. As result of this, more than 50 wells have been treated with gels. Also, pilot tests of WAG and ASP are on schedule and a new technology to improve vertical sweep efficiency, by placing emulsion, is on testing. This situation contrasts with that of the previous 15 years, when no new EOR technology was tested in a Venezuelan field.
The process to evaluate a new technology is rather complicate, even for those technologies already proved by other companies. In this paper, the methodology used is exemplified through the scheme followed to evaluate the emulsion technology. The development started after the problem-opportunities analysis and establishment of the possible competitive advantage pointed that: i) a key problem of the oil industry was been addressed, ii) the process has clear success probability, and iii) the basic infrastructure and qualified human resources were available. A flat administrative structure, divided into 3 technical functional areas, was selected. The keys for the results obtained to the date are the integration of multidisciplinary teams, the continuous communication and the participation of potential users.
Among the barriers found, it is worth to mention the difficulties to start the fluently communication among disciplines and the right timing of the professional participation. In order to surpass them, technical leadership together with the appropriate management was necessary. The availability of an Intranet facility helped to disregard the geographical location problems in many cases.
Large Scale NOW/NORM disposal through slurry waste injection
Authors: Baker Brian D. , Englehardt John M. , Reid James D. 
Published: December 2007

Abstract
It has been established that large scale NOW/NORM (Non Hazardous Oilfield Waste/Naturally Occurring Radioactive Materials) disposal can be accomplished through SWI (Slurry Waste Injection). This process involves excavating the disposal site, mixing the material into the slurry with a resulting composition of 40% solids. The slurry is then pumped at or above fracture gradients into a suitably characterized reservoir. A series of fractures are created forming a sphere around the perforated interval. These fractures constitute the "disposal domain"1 which grow at different orientations around the wellbore. Due to the plastic nature of Louisiana sandstones (at shallow depths &lt;5000 ft), these "fractures" are not necessarily the vertical fractures associated with oil/gas production but more like capillary tube pathways into the formation. This process was accomplished by Chevron in the CP2 sand at Port Fourchon in Louisiana. The objective was to clean up a surface contaminated site (approximately 400 000 bbls). The results will show that this methodology is economic and environmentally safe. By duplicating this technology, other large surface non-hazardous oilfield waste sites may be remediated.
The SWI process involves cyclic injection12 of the slurry (30–40% solids) at 15 – 16 BPM with injection BHP (bottomhole pressure) of 3900 psia for a 12-hour period. Injection is then shutoff overnight and the fractures heal. The process is similar to a continuous tip screenout for each injection period and creates a disposal domain1 in the target sand. This paper describes this injection procedure, disposal reservoir selection and characterization, process variables, applicable models for multiple fractures, matrix injection (capillary tube type waterflooding model), wellsite data monitoring, pressure transient analysis and logging technology to show fracture containment. Also described are some of the current environmental concerns19 and typical permitting issues (State and Federal) associated with the process.
PVC Line Pipe for Conveying Oil Cuts Operating Cost
Authors: Barboza C. A. , Mata A. C. , Villamizar C. 
Published: December 2007

Abstract
This paper shows the results obtained in a field experience developed at the "Campo Ruiz", Valle de La Pascua, Venezuela, where a polyvinyl chloride (PVC) pipeline was used to convey oil down stream of the well with pressures up to 70 psi and temperatures below 90°F. It is also shown the potential for this type of application in Venezuela. The American Petroleum Institute provides standards for polyvinyl chloride (PVC) line pipe suitable for use in conveying oil, in the oil and gas producing industries (API 15LP). Pipe dimensions schedules and pressure ratings listed in these standards correspond to important applications used in these industries, and can be found down stream on the well, from the well head to the flow station. The reported values of our interest are pipelines from 3 to 6 inches of diameter and pressures ranging from 130–160 psi at 73°F (23 °C) to 65 – 80 psi at 120°F (49 °C). According to their chemistry nature, thermoplastic pipelines have certain advantages over the traditionally known metallic pipelines in corrosive environments. Additionally, its fit to mention factors as lower costs by meter, as well as lower costs in handling and installation. The development of this application in Venezuela, within the ranges specified by The American Petroleum Institute, could solve some corrosion problems and lower replacement costs.
Use of effective properties for characterisation of a naturally fractured reservoir in East Venezuela
Authors: Boardman D. W. , Porjesz R. , Cabrera J. R. 
Published: December 2007

Abstract
This paper present the results of an integrated reservoir characterisation study, and the methodology used to confirm the existence of an additional reservoir drive mechanism based on natural fractures, which has been used to explain the significant discrepancies between material balance and volumetric estimates of STOIIP.
A detailed core-based sedimentological study has defined the depositional environment and facies connectivity. Core, log, drilling and production analyses have been integrated to provide information on the natural fracture network, and geomechanical interpretation has been used to prove that the fractures seen in core are natural, and to explain the impact of regional stress variations on fracture properties and flow performance. Effective parameters have been estimated to represent the fracture network in the simulation model.
A non-stationary geostatistical simulation has been used to model the reservoir facies distributions, and the static model has been conditioned with interpreted DST permeability, to represent effective flow properties. A full field history matched simulation model has been used to confirm STOIIP, and to develop an exploitation strategy.
Analysis of Well Performance with Multiple Shut-in Periods
Authors: Helmy M. Wael , Wattenbarger R. A. 
Published: December 2007

Abstract
This paper presents a technique for the analysis of monthly production data of wells subjected to periodic shut-ins, and with limited downhole pressure data. The frequent shut-ins cause severe scatter in the monthly average rate, which hinders the analysis using conventional methods (specializedplots, deconvolution, etc..). We present an application of the superposition principle to identify an analytical reservoir model that gives a pressure response similar to that observed in the field. The model is then used to "filter-ouť" the scatter in the average production rate data, and construct a production trend without the effects of the shutin periods. The model and constructed trend are used to locate reservoir boundaries, calculate reservoir parameters and estimate the original hydrocarbon in place. Two field examples are given to illustrate the validity of the proposed method.
New Method of Analyzing the Pressure behavior of a Well Near Multiple Boundary Systems
Authors: Ispas Valentin , Tiab Djebbar 
Published: December 2007

Abstract
The accuracy of well test data interpretation is critical in obtaining several reservoir properties, such as permeability, porosity, drainage area, and well location. Well test analysis can be complicated by wellbore storage, skin, and especially by the presence of flow or no-flow boundaries in the system. Therefore, different methods for interpretation of the effects of reservoir shape and well location on wellbore pressure have been presented in the petroleum literature.
Starting with the use of the image method and conventional semilog interpretation technique developed in the 1950's, well testing analysis techniques have progressed rapidly by the introduction of the pressure derivative approach in 1976.
The present study uses two analysis techniques for interpreting the pressure and pressure derivative behavior for a well in multiple boundary systems, including wellbore storage and skin effects1. First, a type-curve analysis is performed using computer generated type-curve plots for different reservoir shapes and boundaries, such as (1) Well between two intersecting boundaries; and (2) Well between two parallel boundaries. The output results of the type-curve analysis are then used to develop a comprehensive technique of analyzing the well test data without type-curve matching, based on the Tiab's Direct Synthesis Technique18.
Interpretation of Multirate Tests by the Pressure Derivative - I. Oil Reservoirs
Authors: Tiab D. , Ispas I. N. , Mongi A. , Berkat A. 
Published: December 2007

Abstract
Pressure build-up data in low permeability reservoirs take too long and are usually of poor quality. It is often not economically feasible to shut in a well with a high production rate for a buildup test. Sand producing wells are not good candidates for long pressure drawdown tests. It is often impracticable to maintain a constant rate long enough to complete a drawdown test. In these cases, a multi-rate flow test should be run instead of buildup or drawdown tests. Actually a well-designed multi-rate flow test may minimize the influence of wellbore storage on pressure data.
A new technique based on the pressure derivative concept is presented for interpreting a multi-rate flow test. It is shown here that a Cartesian plot of the pressure derivative data versus a time group is a straight line from which the reservoir permeability can be estimated. It is also shown that for the case of two-rate test, Tiab's Direct Synthesis technique is applicable for calculating permeability and skin
A step by step procedure is presented for interpreting a multirate test using pressure and pressure derivative data. This new technique is illustrated by several numerical examples.
Buildup Solution in a System with Multiple Wells Producing at Constant Wellbore Pressure.
Authors: Camacho-V. Rodolfo , Galindo-N. Agustín , Prats Michael 
Published: December 2007

Abstract
This paper presents a new analytical solution to obtain the shut-in wellbore pressure in a two-dimensional closed-boundary reservoir with multiple wells producing at constant different wellbore pressures.
The analytical solution is obtained in the Laplace space, by using separation of variables, Green's functions, and the unit step function, similarly to the method proposed by Rodriguez and Cinco-Ley1 and Camacho-V. et. al.2 However, instead of using a large time approximation for Green's functions, we used a Taylor series expansion, which makes the inversion problem very simple, avoiding the use of a numerical inversion algorithm like that proposed by Stehfest, at early shut-in times.
This solution allow us to study the interference of producing wells during the build-up test.
Drilling in South America: A Wellbore Stability Approach for Complex Geologic Conditions
Authors: Willson S. M. , Last N. C. , Zoback M. D. , Moos D. 
Published: December 2007

Abstract
An analysis approach is described which includes the effects of rock fabric strength anisotropy on wellbore instability. When drilling in geologically complex conditions - shown to be commonplace in the Andean foothills of South America - bedding-plane slippage, resulting from an unfavourable interaction between in-situ stresses, the well trajectory and bedding, is shown to cause severe instability for certain well trajectories. Case-history examples from the Pedernales field (Venezuela) and Cusiana field (Colombia) are presented which confirm the analytical predictions.