bluuebunny/crossref_metadata_2025_split huggingface dataset:
Application of Neural Network Model for Prediction of Asphaltene Precipitation
Authors: Abedini A. , Ashoori S. , Saki Y. 
Published: July 2010

Abstract
The Precipitation and deposition of crude oil polar fractions such as asphaltenes in petroleum reservoirs reduces considerably the rock permeability and the oil recovery. Therefore, it is of great importance to determine "how" and "how much" the asphaltenes precipitate as a function of pressure, temperature and liquid phase composition. In present work, an Artificial Neural Network (ANN) model was designed and applied to predict the amount of asphaltene precipitation at a given operating condition. An extensive experimental data for the amount of asphaltene precipitation at various temperatures (293-343 K) was used to create the input and target data for generating the ANN model. The predicted results of asphaltene precipitation from ANN model was also compared with the results of some proposed scaling equations. The results revealed that scaling equations fail to predict the amount of asphaltene precipitation adequately for different ranges of temperature and dilution ratio, especially at lower values of dilution ratio. While an acceptable agreement between experimental data and predicted amount of asphaltene precipitation for all ranges of dilution ratio, solvent molecular weight and temperature was obtained through using ANN model.
Hierarchical Pixel-Based Geostatistical Modeling of Estuarine Reservoir Through Streamline Simulation in Ceuta-Tomoporo Field, West Venezuela
Authors: Acosta Alejandro 
Published: July 2010

Abstract
The geocellular models developed by geostatistical techniques are the key of the integrated studies of reservoirs because they are the link between the geological and dynamic models, where they must represent consistently the heterogeneities described by the geologists and geophysicists in the numeric simulation grid.
The study was developed in the B-4 Unit of the "B-Sup VLG-3729" reservoir, located in the off-shore and on-shore Ceuta- Tomoporo Field, west Venezuela. It is dominated by an estuarine sedimentary ambient, with an area above 32000 acres and a thickness of 500 feet. Contains an OOIP above 3 MMMSTB of medium gravity oil, and up-to-date 100 wells have been drilled.
In addition to the traditional stages required to build a geostatistical model, this case of study involved an evaluation of the dynamic response of several equi-probable geostatistical realizations developed by pixel-based algorithms like Sequential Indicator Simulation[3] (SIS) and Sequential Gaussian Simulation[3] (SGS), obtaining the statistical OOIP. Due to the large number of cells considered in the fine grid, a streamline was necessary instead of a finite differences simulator in order to run the model in a reasonable time. In this stage, it was also necessary to apply a conventional reservoir analysis, in order to represent its dynamic behavior.
Substantial Decrease in Subsurface Equipment Failures in a Mature Field in Western Venezuela
Authors: Baptista L. A. , Gomez C. I. , Balzan N. E. , Medina E. J. , Bravo B. J. 
Published: July 2010

Abstract
This paper presents the results of the implementation of several remedial actions to reduce the sucker rod pumped well failure frequency, during the 2006-2008 period in La Concepcion field, Western Venezuela. Before 2006, the presence of a pulling rig to put wells back into production was a constant.
Wells failed continuously caused by rod wear, sand production, paraffin deposition and also subsurface pump valves wear, resulting in a failure frequency of 0.810 failure/well-yr.
Sucker rod pumped wells have been produced from the shallow Eocene reservoir since 1924. The current average production rate is 30 BFPD per well and a low productivity index (around 0.09 BFPD/psi).
Continuous rod system was implemented to reduce failures related to rod wear. Other actions were artificial lift method change to plunger lift and chemical treatment improvement to control paraffin deposition. Furthermore, custom-made changes in pump materials components and accessories were necessary to control the consequences of sand production.
At the end, these changes have enabled Petrowayuu to reduce the Eocene reservoir wells failure rate from 0.810 failure/well-year to 0.361 failure/well-year, which represents a 55% failure reduction and savings of more than 1,700,000 USD/yr.
Water Handling Project at TSP, Trinidad
Authors: Rampersad K. , Lom S. , McLean H. 
Published: July 2010

Abstract
This Paper describes how it is possible to modify existing equipment and chemical treatment and effectively separate approximately 94% of water produced and treat it offshore. The aim is to separate water from oil on the platform abiding by environmental regulations and hence reduce operating costs with a defined budget. The engineering described is basically that of creating secondary and tertiary separation at each facility, improving chemical treatment and designing for redundancy and future production increases.
Dealing with the Challenges of Hydraulic Fracture Initiation in Deviated-Cased Perforated Boreholes
Authors: Fallahzadeh S. H. , Shadizadeh S. R. , Pourafshary P. 
Published: July 2010

Abstract
Hydraulic fracturing is an extensively valuable stimulation method in oil and gas wells, which are no more producing efficiently, to improve the recovery of hydrocarbon from the reservoirs. The challenge of fracture initiation pressure and near- wellbore fracture propagation is a complex problem especially in deviated and cased perforated holes. In this paper a computer model is developed for estimating the initiation pressure as well as the orientation geometry of the fracture in the perforations around the borehole.
Deviated well drilling techniques are used commonly all over the world to develop the reservoirs which are not well produced by vertical wellbores. Most of such wells are perforated after they have been cased and cemented. The existence of the casing along with the cement properties, considerably influence the stress distribution around the wellbore. In this model analytical equations are applied along with the numerical methods to analyze the stress profile around a cased cemented borehole with arbitrary inclination and azimuth. In addition, new analytical formulas are derived and applied to simulate the stress profile around the perforations, taking account of cement sheath and formation mechanical properties as well as perforation gun orientation.
Results of this model are presented using common parameters at different in situ stress regimes, cement and rock properties, and also perforation and well trajectory limits. Wellbore tensile zone, fracture initiation pressure, and investigating the micro- annulus creation are among the main outputs of this modeling. It is concluded that, optimum well inclination and azimuth in conjunction with perforation orientation as well as cement properties can be derived at various stress regimes. As a result lower fracture initiation pressure with better fracture orientation geometry in terms of linking up of small fractures and less fracture tortuosity can be achieved. The significance of this model is its ability in analyzing the stress profile along the perforations tunnel and casing cement sheath, so more realistic fracture initiation pressure and near-wellbore fracture geometry would be anticipated.
Trinidad Columbus Basin Petrophysics Field Study Part 1: Volume of Shale and Porosity
Authors: Ali-Nandalal J. , Smith D. R. , Ramoutar R. , Teelucksingh S. 
Published: July 2010

Abstract
A Petrophysical Refresh of the bpTT fields in the Columbus Basin in Trinidad has been carried out. The objectives of the Refresh were to provide continuity and consistency in petrophysical interpretations in this mature basin where over the years multiple vendors and differing interpretational approaches have been employed.
In an effort to create a more robust core data set, data gaps were identified in the existing core analyses and supplemental analysis performed. The core data set was expanded to include additional porosity and permeability measurements at net mean stress, laser particle size analysis was conducted on shaley intervals from 4 wells to confirm volume of shale method.
New models were developed for volume of shale, porosity and net cut-offs and each of these models were calibrated against the robust core dataset. A curvilinear volume of shale was confirmed to be the most appropriate to estimate volume of shale for the bpTT fields. A total porosity model has been recommended, replacing the legacy effective porosity models. Core derived mini- permeability profiles were combined with core photos, and log-derived volume of shale and effective porosity log curves to explore the limits of what might constitute net.
An Innovative, Low-Cost Approach to Deriving Stress Conditions to Maximize Reserve Recovery in Unconventional Reservoirs
Authors: Kneedy Jason , Atteberry Jeff , Smith Charles H , Menendez Eli 
Published: July 2010

Abstract
Accurate well placement and spacing, especially when using horizontal wells, is essential for optimizing reservoir development and production. In order to develop such a plan, the production mechanisms governing the reservoir must first be fully determined. Several approaches and techniques have been used to achieve this objective. The capacity of the reservoir to deliver hydrocarbons to the horizontal well bore must be understood and defined by a technique that will enable intelligent construction of a reservoir management philosophy. A variation of as little as a 30 degrees from the optimum well bore direction can result in reductions of reservoir efficiency as much as 14%.
Fracture propagation achieves greater length and height when a borehole is oriented in the direction of the minimum stress. The orientation of the in-situ stress field is the critical information needed to achieve optimal placement of horizontal wells. Crossed-dipole sonic logs with directional information enable the magnitude and orientation of acoustic anisotropy to be determined, which provide representations of the in-situ stress field (Fogal 2002). After the direction of maximum horizontal stress is known, the well can be placed and the direction of the horizontal wellbore oriented to attain maximum reservoir exposure after fracture treatment. Compressional- and shear-wave slowness provided by the dipole sonic tool also enable the direct calculation of the rock mechanical properties that define fracture treatment initiation and propagation (Cipolla 1994).
Because the cost of acquiring of crossed-dipole sonic data can be prohibitive, an alternative, cost-effective method for acquiring the necessary data about the in-situ stress field orientation was evaluated. Wellbore elongation is an indicator of stress anisotropy. A directional package was added to an openhole multiarm caliper and the observed borehole deformation was evaluated to determine the implied direction of the horizontal stresses. This defined regional horizontal stress information was then used to orient the horizontal component of each well. This paper compares the results derived from the examination of borehole elongation with the more precise data derived from the dipole sonic logs. This technique provides a cost-effective alternative for determining the orientation of the stress anisotropy in unconventional reservoirs.
Effect of Gas Recycling on the Enhancement of Condensate Recovery in an Iranian Fractured Gas/Condensate Reservoir
Authors: Moradi B. , Tangsirifard J. , Rasaei M. R. , Maklavani A. Momeni , Bagheri M. B. 
Published: July 2010

Abstract
Gas condensate reservoirs have complicated fluid flow and thermodynamic processes. The reservoir temperature of these systems lies between the critical point and cricondentherm. As reservoir pressure decreased, the gas condensate system exhibits a dew point. As pressure is reduced, liquid condenses from the gas to form free liquid in the reservoir. The condensate is deposited at such low liquid saturation that is usually trapped by surface tension forces, is therefore immobile, and cannot be produced. Condensate liquid builds up near wellbore causing a reduction in gas permeability and gas productivity. The injection of dry gas into a retrograde gas condensate reservoir helps in vaporizing the condensate and increases its dew point.
This study prepared an insight into the mechanism of gas injection process in reducing gas-well productivity losses due to condensate blockage in the near wellbore region. The main goal of this work is to investigate the lean gas recycling into the reservoir to enhance condensate recovery and to prevent permeability reduction. In this work, these subjects were studied: fluid phase diagram changes in gas condensate reservoir, initial gas in place and prediction of the amount of condensate, recovery factor evaluation at different scenarios (Natural depletion and gas injection), implementation of gas recycling to enhance recovery and comparison of this method with CO2, N2 and methane injection.
This research was done on a retrograde gas condensate reservoir through compositional simulator. Five possible scenarios: natural depletion, gas recycling, methane, CO2 and N2 injection, were compared. In each scenario, changes in reservoir fluid composition after injection were investigated. Results indicated that CO2 injection yields better recovery that others and methane injection has the least recovery.
Study of Various Water Alternating Gas Injection Methods in 4- and 5-Spot Injection Patterns in an Iranian Fractured Reservoir
Authors: Darvishnezhad M. J. , Moradi B. , Zargar G. , Jannatrostami A. , Montazeri G. H. 
Published: July 2010

Abstract
In the common methods of water and gas injection, high and unsuitable mobility ratio within the injected fluid and the oil in the reservoir, leads to viscose fingering and reduction of sweep efficiency. It was originally intended to improve sweep efficiency during gas flooding, with alternating slugs of water and gas (WAG injection) designed by and large to follow the same route through the reservoir.
WAG injection has been widely applied since the late 1950s. The typical improved oil recovery (IOR) potential for WAG injection when compared with water injection is quoted in the literature at 5-10%. In this method, injection of water slugs followed by gas, leads to triple region, increase the contact level of injected fluid and reservoir, stable the movement front, and finally increase the recovery. However, depend on the conditions, type and pattern of injection, improvement of recovery is variable and different. WAG injection in five methods, immiscible, miscible, hybrid, simultaneous and selective simultaneous.
In this work, scenarios of WAG injection such as Immiscible WAG (IWAG), Hybrid WAG (HWAG), Simultaneous WAG (SWAG) and Selective Simultaneous WAG (SSWAG) and water and gas injection are compared to specify the appropriate injection method. Then ultimate oil recovery, residual oil saturation, daily and total oil production are compared in these scenarios. Also these scenarios in four and five spot injection patterns were compared.
Results indicated that, SSWAG injection has the higher oil production and lowest residual oil saturation. In addition, among these scenarios, SSWAG in 4-spot pattern had the highest recovery and daily oil production. 4-spot pattern had the higher recovery and lower residual oil saturation than 5-spot pattern, so adding the number of wells could not raise the recovery.
An Improved Triple Porosity Model for Evaluation of Naturally Fractured Reservoirs
Authors: Al-Ghamdi Ali , Chen Bo , Behmanesh Hamid , Qanbari Farhad , Aguilera Roberto 
Published: July 2010

Abstract
Many naturally fractured reservoirs are composed of matrix, fractures and non-touching vugs (it can also be any other type of non- connected porosity that can occur, for example, in intragranular, moldic and/or fenestral porosity). An improved triple porosity model is presented that takes into account these different types of porosities. The model can be used continuously throughout a reservoir with segments composed of only matrix porosity, or only matrix-fractures, or only fractures-vugs, or the complete triple porosity system.
The model improves a previous triple porosity algorithm by handling rigorously the scale associated with each, matrix, fractures and vugs. This permits determining more realistic values of the cementation or porosity exponent, m, for the composite system and consequently improved values of water saturation and reserves evaluations. The values of m for the triple porosity reservoir can be smaller, equal to, or larger than the porosity exponent of only the matrix blocks, mb, depending on the relative contribution of the vugs and fractures to the total porosity system.
It is concluded that not taking into account the contribution of matrix, fractures and vugs in the petrophysical evaluation of triple porosity systems can lead to significant errors in the determination of m, and consequently the calculation of water saturation, hydrocarbons in place, recoveries, and ultimately poor economic evaluations, either too pessimistic or too optimistic. This is illustrated with a couple of examples from Middle East carbonates.
Cumulative Gas Production Distribution on the Nikanassin Tight Gas Formation, Alberta and British Columbia, Canada
Authors: Solano Nisael , Zambrano Liliana , Aguilera Roberto 
Published: July 2010

Abstract
271 wells producing exclusively from the Nikanassin and equivalent Formations in a very large area of over 15,000 square kilometers in the Western Canadian Sedimentary Basin (WCSB), Alberta and British Columbia, Canada, have been evaluated with a view to determine the distribution of cumulative gas production and the possibilities of intensive infill drilling.
The Upper Jurassic to Lower Cretaceous Nikanassin formation is generally characterized as a tight gas formation with low values of permeability (typically a fraction of millidarcy) and low porosities (usually less than 6%). It is likely that natural microfractures and slot pores dominate the productivity of the formation. The study area was divided into 6 smaller narrow areas (A to F) approximately parallel to the NW-SE trending thrust belt of the Canadian Rocky Mountains. Area ‘A’ is located to the west of the deformation edge, area ‘B’ is on the deformation edge, and areas ‘C’ to ‘F’ are located to the east. Area ‘C’ is the deepest and closest to the thrust belt, whereas area ‘F’ is the shallowest and furthest from the thrust belt.
Cumulative production characteristics within each area were evaluated with a variability distribution model (VDM) developed recently for naturally fractured reservoirs. The evaluation of each one of the 6 areas (271 wells) resulted in coefficients of determination, r2, greater than 0.99 in all cases. The results indicate that the gas cumulative production distribution per well is more homogeneous along the deformation edge (area B), where 80% of the wells contribute approximately 50% of the cumulative production. The highest heterogeneity was found in area F (the shallowest) with 80% of the wells contributing only 25% of the cumulative gas production. Areas A, B, D and E have more or less the same distribution with 80% of the wells contributing between 35% and 45% of the cumulative gas production. Preliminary, there is an association between the cumulative production distribution and lateral variations of borehole breakouts in the Nikanassin formation on a transect perpendicular to the deformation belt of the WCSB.
Analysis of the distributions leads to the conclusions that the Nikanassin is a very heterogeneous formation and that there is significant potential for massive drilling to efficiently drain the formation. The possibilities of horizontal wells and multi-stage hydraulic fracturing jobs are being investigated at this time.
Successful Coiled-Tubing Drilling-Hole Enlargement Improves Production
Authors: Ortega R. , Kowalski R. , Escobar J. , Garcia R. 
Published: July 2010

Abstract
Schlumberger coiled-tubing drilling (CTD) initiative was implemented in west Venezuela (Lake Maracaibo) in 1993 from a CTD Barge. This purpose-built barge was assembled to minimize the risk to personnel and equipment while drilling superficial zones for a Venezuelan operator where the presence of shallow-gas sands makes safety a priority (Adamson S.J. 1994). To date, this project has drilled over 300 wells.
Nowadays, the operator has new challenges: to continue draining the remaining oil reserves, new process and designs are required to successfully achieve their expectations.
The new CTD challenge is focused on the Field C and Field D and more specifically the Eocene primary target zone and, as a secondary target zone, the Miocene. These zones are separated by a discordance1. From the discordance and around the upper Eocene, formation pressure is significantly reduced (around 400 psi lower) with respect to the Miocene age reservoir pressure. This issue represents a serious challenge during the drilling phase because fluid losses might be present when crossing the discordance zone. To address this situation, an intermediate casing can be placed at the end of Miocene; however, this will limit the subsequent completion by reducing the final tubing size and therefore, affecting the potential well production.
The proposed solution is based on drilling a larger surface hole, 14¾ in., and setting larger surface casing, 10¾ in., allowing the operator to run larger completions (intermediate and/or production casings). If isolation is required across the discordance, this design will provide an optimal completion without compromising the well's oil production.
Several studies and analysis were implemented to adapt the design and execution phase with the new requirement from the operator and the operating capabilities of CTD Barge.
To date, four wellbores have been successfully enlarged to 14¾ in., completed with 10¾-in. casing, and cemented. Subsequently, a conventional drilling rig / barge has been used to complete these wells to their production phase, and represent an incremental production gain, estimated at over 150 bbl/day of oil for the four wells.
A New Approach to Low-Cost, High Performance Chemical Flooding System
Authors: Elraies K. A. , Tan I. M. , Awang M.. , Fathaddin M. T. 
Published: July 2010

AbstractThis paper presents a new Acid-Alkali-Surfactant (AAS) flooding formulation as an alternative to conventional alkaline/surfactant/polymer (ASP) process. It is a cost-effective formula that is able to overcome precipitation problems prevalent with ASP flooding when natural sea water was used. The acid was evaluated in an AAS formulation using sodium carbonate and introducing a new polymeric surfactant derived from Jatropha oil. The feasibility of applying the new AAS formula was demonstrated by a series of experiments involving fluid compatibility test with natural sea water having a large quantity of divalent metal cations, interfacial tension between Angsi crude oil and AAS solution, surfactant adsorption, and core flood using Berea core samples. The acid effectively prevented divalent metal cations from precipitating and all solutions remained clear for 90 days at 90°C. The optimum acid concentration was found to be proportional to alkali concentration in the ratio of 1.66:1. A combination of the new system was found to significantly reduce the IFT and the adsorption level of the surfactant. The best chemical concentrations were then validated in core flood tests using various alkali and surfactant concentrations. The optimum alkali and surfactant concentrations were confirmed as 0.6% and 0.6% respectively. Using the optimum concentrations, another series of core flood tests were conducted by changing the injection volume. Only a small incremental recovery was obtained with slugs higher than 0.5 PV. Injection of 0.5 PV of the formulated slug followed by chase water produced an additional 18.8% OOIP over water flood, accomplishing a total oil recovery of 77.3% OOIP. This makes the new AAS formula an attractive and cost-effective agent for CEOR particularly for offshore field application.