bluuebunny/crossref_metadata_2025_split huggingface dataset:
Hydraulic Units in Traditional Areas of Eastern Venezuela
Authors: Rampazzo M. , González G. , Ferrer A. , Iraldi A. , Alvarez R. 
Published: December 2007

Abstract
The highly lenticular character of the reservoir sands present in the traditional fields of Eastern Venezuela Basin, led to the establishment of multiple reservoirs, which were completed individually for exploitation. This production scheme and the current low well production rates, result in a low profitability to maintain these reservoirs active. For increasing productivity, here it is proposed to complete more than one sand simultaneously.
In order to determine the possibility of sand layer communication, the information of six different traditional fields was reviewed, as a result, the Acema Casma area was proposed as the best area for a pilot project. This project will be used to monitor the results of a different completion outline, thus allowing the establishment of a general plan, to cover other fields in the traditional Eastern Basin.
According to the well simulation analysis the combined production of more than one sand, allows to produce the reserves in a shorter time, increasing in a significant way, the Net Present Value, and diminishing the risk of well mechanic damage. One of the big limitations of this study was the lack of enough reservoir information, for that reason the pilot project includes to take additional data like well pressure.
Where sand layers are not in communication, commingle production should be surely evaluated in the future, whenever, the compatibility of the crudes and the effective production monitoring is guaranteed. In order to make the appropriate decision regarding these traditional field exploitation, a detail reservoir characterization, that includes additional data is absolutely necessary.
Enhanced Drill Cuttings Analysis for Drill-in Fluids Design
Authors: Guzman Jose H. 
Published: December 2007

Abstract
Even though drill cuttings are first hand actual reservoir information, their conventional analysis during mud logging is limited and under estimated as source of relevant information. Drill-in fluid design becomes successful if bridging materials such as sized salt or calcium carbonate is matched with pore geometric attributes of formation rock.
A novell approach for drill cuttings analysis is being under use to select the optimum sizing for bridging material, when there is no core information available.
After using a combined technique of Scanning Electron Microscopy (SEM), chemical analysis by Energy Dispersive X ray Spectroscopy (EDS) and Backscattered Electron Images (BSEI) digital processing and analysis, it is possible to get key parameters to design a more efficient Drill-in fluid. It can help also in the selection of screens for solids control in surface equipment.
Textural parameters found with this technique include grain size distribution, shape and sorting. Porous space description such as (2D) porosity and pore throat size distribution, that can be obtained in grain clusters coming from drilling consolidated rock horizons. Rock fracturing trends, natural or induced can also be observed. Therefore a more detailed sample description is achieved in relation to conventional analysis.
Once this information has been processed, laboratory filtration tests can be performed on available reservoir or similar synthetic material, in order to recommend a better formulation of Drill-in fluid for field use.
Intermittent Gas Lift Optimization in Rosa Mediano Field
Authors: Hernandez A. , Perez C. , Lobo W. 
Published: December 2007

AbstractRosa Mediano is the field with the lowest reservoir pressure in Lake Maracaibo. For this reason, a large number of wells are currently producing on choke controlled intermittent gas lift. The objective of this work was to identify operating conditions that could be modified in order to optimize gas consumption and maximize liquid production.To carry out this objective, more than 50 down-hole pressure and temperature surveys were run in a total of 7 oil reservoirs. The survey procedure was such that an important number of engineering parameters could be obtained: real liquid pressure gradient, optimum cycle time, liquid fallback and the productivity index of the well.Important deviations of the dynamic behavior of spring loaded and nitrogen charged gas lift pilot valves were identified and they are presented in this work. The analysis of down-hole pressure surveys also shows that, in many cases, the liquid fallback was well above the usually assumed 5% of the initial liquid column length per thousand feet traveled. These measurements are presented in the paper, together with a discussion of possible causes.The proper gas injection pressures, gas volume injected per cycle and optimum cycle times were calculated from the reservoir inflow capabilities. An overall 30% increase in liquid production was obtained when these parameters were adjusted to new values calculated from the survey analysis. A shift from choke control to the use of surface controllers was necessary in some cases and detailed examples are presented in the paper.Finally, the analysis of down-hole pressure surveys performed on 6 double packer Gas Lift Chambers shows that this type of completion is highly inefficient for wells with moderate to high formation gas-liquid ratios.
Killing Methods and Consequences of 1120 Gulf Coast Blowouts During 1960-1996
Authors: Skalle P. , Jinjun H. , Podio A. L. 
Published: December 2007

Abstract
This paper focuses on what happened after wells are out of control by analyzing statistically a database that contains about 1120 blowout events from the Gulf Coast and adjoining states covering the period 1960-1996. The trends are extracted, including blowing fluid type, mode of control, duration of blowout, pollution, fire and explosion, and fatalities. Detailed differences between Outer Continental shelf (OCS) and Texas are given. A report form of blowout events is recommended in order to improve the data quality and standardize reporting.
Impact of Heterogeneities in Horizontal Well Performance
Authors: Portella R. C. M. , Lanzarini W. L. 
Published: December 2007

Abstract
In order to be viable economically, horizontal wells must present a high productivity. Reservoir heterogeneities can affect greatly this productivity; thus, a good evaluation of the well productivity in heterogeneous reservoirs is essential to guarantee the economical success of oil field development projects. Although tools based on analytical or semi-analytical techniques are useful for a preliminary evaluation of the performance of a horizontal well, their limitations (homogeneous reservoir, no gravity, and single-phase flow) can affect greatly the results. Hence, only the use of a full simulator model can provide an accurate response of the productivity of a horizontal well in a heterogeneous reservoir.
In this paper, we analyze the impact of the heterogeneities in the productivity of horizontal wells in channeled turbidite reservoirs, which are the most common reservoirs in offshore oil fields of Brazil. We use a conventional simulator to do the analysis, and a graphical front-end was developed to simplify the task of setting up simulation data sets. A Boolean stochastic technique was used to model these kinds of reservoir. Several conditional images were generated using this stochastic method. Flow simulations were performed in each of the images and the results were compared. The better characterization of the reservoir combined with a full simulator model provides a much better analysis of the risks involved in the development of a field with horizontal wells.
Asphaltene Stability in Crude Oils
Authors: Rogel E. , León O. , Espidel J. , González J. 
Published: December 2007

Abstract
The influence of different factors on the asphaltene stability in crude oils was evaluated. Compositional studies and structural characterization of resins and asphaltenes were carried out in order to study a possible relationship between these properties and the asphaltene deposition behavior. Asphaltenes were obtained by precipitation with n-heptane and characterized by elemental analysis and spectroscopic techniques. Low hydrogen to carbon ratios, high aromaticities and high condensation of aromatic rings were the main characteristics of the asphaltenes from unstable crude oils. According to these results, the stability behavior of the asphaltenes was strongly influenced by their structural characteristics. However, it was also found that stabilization by means of a commercial inhibitor was affected by the composition of the crude oil. In particular, a high content of basic functionalities in the crude oil can be related to the decrease of the inhibitor's effectiveness (dodecylbenzene sulphonic acid). Based on these findings, some useful suggestions applicable to the oilfield operations are made.
Pseudo Relative Permeability Functions. Limitations in the Use of the Frontal Advance Theory for 2-Dimensional Systems
Authors: Telleria M. S. , Virues C. J. J. , Crotti M. A. 
Published: December 2007

Abstract
To obtain a reliable characterization of complex reservoirs, they must be represented with fine scale models. However, detailed descriptions demand a huge amount of information and processing time. Therefore, less complex models are usually designed. To construct these simplified models, pseudo relative permeability curves are developed. Pseudos reduce the number of dimensions of reservoir models, trying to reproduce the behavior of the fine scale system. Simplifying 2-dimensional (2D) systems to 1-dimensional (1D) models allows reservoir engineers to apply them to simple calculations and less complex reservoir simulations. Once reduced to 1D, models are usually analyzed by means of frontal advance theory.
In this paper, stratified systems under no cross-flow and under vertical equilibrium (VE) conditions were studied by means of numerical simulation (NS), analytical methods and simplified pseudo relative permeability functions (PRPF). When frontal advance theory was used, some restrictions were found to the application of pseudo functions. These limitations, if overlooked, could yield wrong conclusions.
Volatile Oil. Determination of Reservoir Fluid Composition from a Non-Representative Fluid Sample
Authors: Cobenas Rafael H. , Crotti Marcelo A. 
Published: December 2007

Abstract
Volatile Oil reservoir are sometimes evaluated as gas and condensate systems when pressure in the well neighborhood reaches values fairly below saturation pressure. This pressure drop is common in almost all reservoirs at late depletion stages or from the beginning in tight formations. When this situation occurs, it does not matter how carefully the sample is taken, it always leads to non-representative PVT analysis. Based on a real case study on a tight formation, sampled at the beginning of production history, a dynamic data integration between petrophysical and thermodynamic information was conducted in order to understand overall reservoir behavior. As part of this integration, a compositional material balance was developed in order to describe the reservoir performance against pressure. A sensitivity case to relative permeability curves was run with the material balance. The fairly good matching of the material balance model with the production test allowed us to determine the most probable reservoir fluid composition. It was also noted that the relationship between GOR and separator fluid composition had negligible dependence on relative permeabilities.
Development and Validation of Interference Testing Analysis Model Using Boundary Element Method for Geometrically Complex Reservoirs
Authors: Sung W. , Lee W. , Kim I. 
Published: December 2007

Abstract
The primary focus of this paper is on the development of a well testing model to analyze the data from geometrically complex reservoirs. The model employs a boundary element method applying the weighting function of the free-space Green’s function which is applicable to multi-well system. Because of the characteristics of the methodology implemented in this study, the developed model is capable of handling the data acquired from multiple sources or sinks in an arbitrarily shaped system. This technique is free from the grid orientation effect and numerical dispersion as well. The proposed model has been verified and validated for simple geometrical systems (square and circular) whose solutions can be obtained by the image well technique, and their matches are found to be excellent. Finally, the applicability of the model has been checked by using the synthetic multiple well testing data in a geometrically complex bounded reservoir. In this test, from the anisotropic analysis, it was found that the anisotropicity (kmax, kmin, and direction of major flow) was determined.
Yakin Field: Innovation Breathes a Second Life to the Mature Oil Field
Authors: Kuntjoro M. B. , Palar S. , Bouclin D. 
Published: December 2007

Abstract
Yakin field, operated by Unocal Indonesia Co. was discovered in May 1976. The field was divided into three separate fault blocks and located offshore Balikpapan in 15-ft water depth. By the end of year 1996, the field had produced 33.9 MMBO and 25.2 BCF gas. The field’s daily production had declined to 2,900 BOPD and 4.4 MMSCFD gas from 19 producing old wells scattered on small platforms.
Prior to 1997, a transition zone 3D seismic was acquired over the whole area identifying potential for additional reserve recovery. Development drilling had not been done for eleven years due to high drilling cost to develop marginal reserves. The field is located in shallow water depth with platform size limiting drilling operations to a jack-up and workovers to a snubbing unit. However, with the innovation of a new wellhead platform structure, a less expensive tender supported rig could be used. Cost reductions in development drilling, made marginal reserves economic.
Field performance review, geological and 3D seismic work, pilot wells and reservoir simulation indicated reservoir development potential in the field through the application of horizontal drilling technology. In 1997 an additional fourteen wells were drilled and completed in Yakin field. With the addition of these new wells, the total field production increased to 7,200 BOPD. The cheaply drilled horizontal wells, were found suitable for controlling sand production in the unconsolidated Yakin reservoirs.
Marginal Field Development Strategy, Kartini Field, Offshore Southeast Sumatra
Authors: Thomas Budiyento , Galuccio Miguel M. , Dharma Wira , Mitrodihardjo Sudharmono , Pasaribu Jonny 
Published: December 2007

Abstract
Kartini field was discovered in 1977 and was followed by the drilling of three delineation wells. The reservoirs are fluvial sandstones of the Gita member, Talang Akar Formation that contain gas, oil and water. Kartini-1 and −2 tested at 4,485 BOPD and 2,944 BOPD, respectively. Trapping is created by combination structure and stratigraphic pinch out along the channel edges. In 1992 the initial plans were to develop the field by installing a 9-slot platform and drilling 8 development wells. The well locations were based on 2-D seismic and un-migrated 3-D seismic data. The first two wells were drilled in the field and resulted in uncommercial wells. Maxus ascertained that the development risk was high and put the field's development on hold.
Subsequently the seismic data was migrated which allowed Maxus to utilize the seismic attributes in conjunction with a new geological interpretation to remap the main productive reservoirs.
During this hiatus period, Maxus's experience with caissons progressed from a simple design with a maximum three wells without workover capability to the current technology allowing up to eight wells with workover capability. This improved technology results in significant cost savings and allowed the Kartini field to be developed economically. In addition to the deviated wellbores, three horizontal wells will be drilled and are designed to drain reserves from thin oil-bearing sandstones that would be uneconomic otherwise.
Based on new seismic and geological interpretations, installation of a low cost Guardian structure, and utilization of horizontal wells, Kartini field was developed as an economic field with production beginning in October 1998.
Reservoir Impairment Mitigation: Successful Use of Graded Carbonate Drilling Fluids
Authors: van Vliet J. P. M. , Hjh Rosita Hj Hassan 
Published: December 2007

Abstract
With the ongoing technological developments in horizontal drilling, multilateral wells and open hole completions, it has become very important to drill and complete the reservoir sections of a well inducing as little impairment as possible. Drilling, clean-up and completion practices should be tailored to minimise formation damage, thereby maximising the productivity of the well. Since mid ‘97, Brunei Shell Petroleum has drilled a number of horizontal well sections that were completed with a sandscreen only or with a horizontal gravelpack. The success of these operations is illustrated by the fact that the reservoir sections showed expected or better than expected productivity, even when in one case the reservoir was severely depleted.
Based on research work done before the drilling campaign started, the reservoir drilling fluid selected for these wells was a graded carbonate drilling fluid. This paper gives details on the selection process, and it describes the successful use of the drilling fluid in the field. It also details the procedures followed during drilling and completion of the wells, which successfully minimised impairment of the reservoir sections.
Overcoming the Challenges of Shallow Horizontal Drilling in the World's Largest Steamflood
Authors: French Michael R. , Siagian Mangojak , Thurston F. Kent 
Published: December 2007

Abstract
This paper is a case history that documents the drilling and completion program of a horizontal steamflood project in a very shallow sandstone reservoir. A total of nine (9) medium radius horizontal wells were drilled at a depth of + 600’ TVD using a vertical mast rig. The factors that influenced the decision to use a vertical mast rig instead of a slant rig are reviewed. This decision presented additional challenges to the drilling personnel, production engineers and the subsurface engineers. Steps taken to address these challenges are discussed as well as the development of special drill collars that played a key role in the success of this program.
Implementation of a Company-Wide Production Monitoring System
Authors: Hidayat Noor , Gadjah Mada Asli , Muchsan Asfaril , Ismayadi Budhi 
Published: December 2007

Abstract
PT Caltex Pacific Indonesia (CPI) is the largest crude oil producer in Indonesia under Production Sharing Contract (PSC) with PERTAMINA. Its field operation is located in Riau province, Central Sumatra.
Field and well performance monitoring for company-wide daily production monitoring systems in CPI is one of the very critical aspects to supporting company’s vision, mission, and performance measures. It even becomes more important after the commencement of the Strategic Business Unit (SBU) organization. Therefore, CPI needs to have an integrated and flexible systems operating on daily basis. We name the system DREAMS-NT (Data Resources for Engineering Analysis and Monitoring Support - New Technology), and it has been put on operation since January 1st, 1998.
This paper will discuss in brief all the phases involved in the project, with a guideline from CPI’s Asset Management Process, which includes Systems Requirement Definition, Alternative Solutions Assessment and Selected Solution Recommendation, Systems Implementation Plan Layout and Execution, and Post-Implementation Plan of DREAMS-NT.
The more focus aspect that will be discussed in this paper is the technology aspect for implementing the system: the IT infrastructure requirement, the server platform, the client PC requirement and configuration, the relational database platform, the distributed database configuration, the interface in the database level to other systems, and the interface to CPI intranet web server. In the application itself, there is a specific feature called GRANI (GRAphical Network Interface) that provide the easy of use and flexibility to draw the crude oil flow from well to gathering station, to shipment meter, to shipping tank, and to selling point. In other words, this GRANI represent the actual crude oil piping network from wells to the selling points. A mathematical formula can be embedded in this GRANI drawing of piping. At the end, we also discuss benefits gained with the implementation of this system with its ‘new’ technology.
Rod Pumping Technique Without Tubing
Authors: Xu Xiufen , zheng JiangMin , Jun Zhu 
Published: December 2007

Abstract
To minimize the initial investment of pumping wells, a rod pumping technique without tubing(hereafter referred to as tubingless rod pumping technique) is studied in this paper. Its principle is: a packer is lowered to the designed setting depth and set down, an inserted pump assembly is inserted into the inner bore of the packer, a seal and a fixation are formed between the pump barrel outer surface and the packer inner bore, the annular space between casing and rod string is the oil flow passage. The rod string is hollow, at its bottom, a downward check valve is screwed. When the oil well produces, the check valve is closed. When well cleanup is required, wellflushing fluid is pumped from ground to the bottom hole through the hollow rod string and check valve, and wellflushing fluid returns to ground through the annulus.
Compared with the conventional rod pumping system with tubing, one pumping well without tubing decreases its investment of tubing string by approximately 40-50 thousand yuan. This paper analyzes the reliability and economy of this technique. The field test results of three wells in the Daqing Oil Field are given in this paper, two of the wells have been producing normally for about one and a half years.
Pressure Transient Technique Adds Value to ESP Monitoring
Authors: Spath Jeff , Martinez Alex D. 
Published: December 2007

Abstract
A novel pressure transient technique is combined with routine performance monitoring of ESP's to economically characterize the well/reservoir producing system.
Information derived from the proposed procedure enables the engineer to compute the maximum production of the well and to decide what productivity improvements may be employed to achieve this maximum. Specifically, accurate values of permeability, damage and average pressure may be obtained as well as the presence of heterogeneities and their characteristics. In a multi-well implementation, the procedure allows both the temporal and spatial variation of reservoir properties and fluids to be monitored.
Fundamental to the technique is the modulation of the well's flow rate to produce an unambiguous pressure response. Flow rates are modified programmatically using variable frequency devices which vary the speed of the ESP; we consider several possible flow rate scenarios and discuss the practical implications of each. The resulting pressure response is modeled analytically, continuously and automatically, in a least squares sense, to monitor the well and reservoir properties. Computational considerations are discussed.
The objective of this paper is to allow operators to optimize production rates and recovery while minimizing capital investments and operating expenses. The efficacy of the technique described is demonstrated using simulated data.