bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Novel Improved Condensate-Recovery Method by Cyclic Supercritical CO2 Injection
Authors: Millán Arcia Einstein , Gerder Y. , Gil J. 
Published: December 2007

Abstract
In the Eastern Venezuela gas assets, mid to long term planning business portfolio considers an increasing gas production potential and recoverable reserves under secondary or improved recovery methods. Most gas reservoirs are originally under or near saturation pressure. Native thermodynamic conditions along with typical production practices favor in-situ liquid condensation, leaving behind considerable non-recoverable liquid hydrocarbons. This liquid condensation is triggered by unfavorable pressure gradients developed under natural production as reservoir static pressure drops below saturation pressure, primarily in the near wellbore region. In addition, as gas expands due to the adiabatic real-gas-expansion Joule-Thompson effect, a reduction in the surrounding temperature is also expected. This effect, in turn, often favors a sharp reduction in the relative permeability to gas when "In Situ" liquid condensation takes place at interstitial level hence promoting a drastic decay in the gas productivity. Consequently, a considerable amount of liquid hydrocarbon is left behind in the reservoirs.
Based on the nature of the experimental findings, the availability for flue gas in the Eastern Venezuelan region, and the environmental concerns, a breakthrough improved Condensate Recovery (ICR) project is being considered by "Cyclic Supercritical CO2 Injection".
The cyclic nature of the process combined with the favorable equivalent density for the CO2 at reservoir condition is expected to positively impact thermal diffusion and accelerated mass transfer processes respectively mainly in the near wellbore region. In this project, pilot temperatures are expected to be in the range of 350 to 450 °F.
A combined effort to integrate experimental results into a numerical model was undertaken. A number of laboratory tests were programmed to typify both fluid and rock interactions and also to characterize the thermodynamic profile for the CO2 and In Situ live fluid.
The interaction coefficients of the equation of state (EOS) for the enhanced process were experimentally characterized reproducing the multiple contact events between the in situ liquid hydrocarbon and the foreign fluid (CO2) as a function of temperature.
Expected sweep efficiencies and residual liquid saturation after multiple contacts with CO2 were experimentally determined via core displacement tests using actual core samples. Soaking time extent was also optimize for energy diffusion purposes.
At a second stage, a single well model will be assembled, to numerically reproduce the experimental results, to match primary depletion and to predict enhanced recovery production profile. For field implementation, a pilot area was selected in the Santa Rosa Field belonging to Petroleos de Venezuela assets.
A Case Study of Latest Technologies Enables Successful Completion of ERD Exploration Project Off the Coast of Tierra del Fuego
Authors: Kulakofsky David , Oliveira Alessandro , Almaraz Angel 
Published: December 2007

Abstract
To help satisfy the demands for petroleum products, operators are being forced to drill in increasingly challenging environments. Combine cold winters, some of the strongest winds in the world, and a very remote location in the waters off the coast of Tierra del Fuego certainly could be considered challenging. In this case study, the operator successfully constructed extended reach wells through low fracture gradients under the previously described harsh environment.
Attempting to circulate long columns of cement slurry when constructing extended reach drilling (ERD) wells under these conditions stretches the limits of current technology. Nowhere else in the world has success required more preplanning and implementation of the latest technologies. Failure to achieve a seal could have a large impact on the cost of drilling these wells and the operator's ability to effectively produce the new field. In addition to the cost of the required remedial work, which is easy to quantify, additional costs can be accrued from delays in production delivery, which are harder to quantify.
This paper presents case histories from Tierra del Fuego illustrating preplanning methodology, design strategies, and new technology implementations required to make this exploration project a success.
Time-Based Real-Time-Drilling-Operations Excellence Delivered
Authors: Strathman Michael , Elley Dave , Meirerhoefer Norbert 
Published: December 2007

Abstract
E&P companies have managed drilling operations from central locations for sometime. However, operators remain limited in their ability to use the data to develop better procedures for drilling complex wells, to compare data across various vendors working on the same well, and from being able to look at the well data in time not just in depth. Realtime drilling solutions from major drilling companies focus on data they capture, are based on depth not time, and do not lend themselves to comparison's between wells.
Statoil examined this problem and has worked with Aspen Technology to develop and implement a time-based drilling solution. This solution is used in parallel with the depth based systems provided by its drilling contactors. Data is captured from the well site in real time, stored in a historian, and made available in vertical trends through time. The solution is configurable by the operator to look at different data sets side by side in time sequence. It enables closer collaboration between the geoscience, petroleum and drilling engineers working on a well. The solution leverages the data standard of WITSML to ensure compatibility between vendors.
Statoil has reduced the cost to access its data from wells, improved its ability to develop better drilling plans. Drilling is a critical, data intensive process and reliability and ease of use are essential. This system provides that reliability. Because it is reliable and real-time the decision making across disciplines can be brought to a common collaboration center where all well data is displayed and available.
This paper will present the business issues addressed the solution and benefits achieved.
Successful Application of Underbalanced Coiled-Tubing Drilling in Horizontal Short-Radius Re-Entry Well To Enhance Oil Production in Hassi Messaoud Field, Algeria
Authors: Amor Bachir Ben , Ferhat Ali , Messas Rafik , Arnone Maurizio , Stulberg Michael , Khan Rashid , Schoch Fritz , Fordyce Charles , Qutob Hani , Chopty James 
Published: December 2007

Abstract
Drilling in the Cambrian Reservoir, in the peripheral zone of Hassi Messaoud field, specifically the 1A, 1B and 1C zones (Figure 1) is a real challenge, basically due the petrophysical reservoir complexity, the low reservoir pressure, the extremely hard and abrasive sandstone and quartzite formation associated with numerous vertical and sub vertical fractures that connect the reservoir with deeper formations leading to major problems related with the salt saturated water production. Many of the vertical wells drilled in that zones have more than 30 years from completed and a large proportion of them have been shut in since being drilled.
Well E was the 5th re-entry well in the Sonatrach Coiled Tubing – Underbalanced Drilling campaign. A total of 372 m from KOP and 316 m from landing point were successfully drilled in a continuous underbalanced condition inside D1 formation. As a result, the well productivity while drilling, the Reservoir characterization and rate of penetration was significantly improved, compared with offset wells, due to the positive impacts of UBD operations.
The combination of Underbalanced and Coiled Tubing Drilling technologies has been proven to be a viable solution to successfully drill horizontal re-entry wells in mature fields where the reservoir pressure is adequate to induce underbalanced conditions using single phase or multiphase drilling fluid.
The experience in this field has validated the benefits of the combination of these technologies and has been attributed to the excellent balance between drilling cost and improved productivity. For example, the drilling cost in the short radius re-entry wells drilled with coiled tubing are highly reduced due to the elimination of pipe connection procedures, the increase in rate of penetration, the prevention of conventional drilling problems such as fluid circulation loses and related differential sticking events, the increase in the bit life and reduction in time and drilled distance to reach the profitable production level.
This paper describes the technical basis for the design and implementation of the Coiled Tubing Underbalanced Drilling project in Hassi Messaoud and highlights the operational key factors and challenges faced during this particular and successful application in Algeria.
Optimal Development Strategies to Different Scenarios of Reservoir Properties: Application to a Real Field
Authors: Salomão M. C. , Figueiredo F. P. 
Published: December 2007

Abstract
In petroleum industry, scarce information is available at the time of adopt the exploitation strategy, and the expected production profiles comprise a high level of uncertainty. Depending on the range of the uncertainty variables, the best decision may be to collect more information by drilling more wells, performing a new seismic acquisition or making long term tests. But, sometimes, the best way to protect the project is to assume an uncertainty-proof development strategy. These ideas were applied to help decision in two real cases, in Marlim Sul field, Campos Basin, Brazil. In the first case, the main uncertainty source is the quality of the flow transmissibility between producers and injectors wells. If that communication is restricted, the production decline is more accentuated and the best strategy would be to place the injectors nearer the producers, although the displaced oil is reduced. In order to elect the best strategy, we have compared two different plans containing different positions of injector wells, applied to three different scenarios of flow transmissibility. In the second case, we have a channeled reservoir, with an extensive fault in the middle, the transmissibility along which is unknown. In a scenario of good communication, the best strategy is to position the injectors on one side and the producers on the other side of the fault. But in scenarios of restricted communication, the best scheme could be to place injectors and producers on both sides of the fault. To make the best decision, we have used different plans, applied to different scenarios. The results demonstrate that, in both cases, the alternate plan has not the higher net present value (NPV) in the moderate scenario, but presents the higher expected monetary value (EMV), having also a lesser sensitivity to the reservoir uncertainties, being more protected to the risk. In both cases the original plan has been abandoned and the alternative plan started being implemented.
On Equation of State
Authors: Ahmed Tarek 
Published: December 2007

Summary
To predict the phase and volumetric behavior of hydrocarbon mixtures by using an Equation of State; e.g. the Peng and Robinson Equation of State "PREOS", the critical properties in terms of the critical pressure "pc" and critical temperature "Tc" as well as the acentric factor "ω" must be given for each component present in the mixture including the plus-fraction. For pure compounds, the required properties are well-defined, but nearly all naturally occurring gas and crude oil fluids contain some heavy fractions that are not well defined and are not mixtures of discretely identified components. These heavy fractions often are lumped and called the "plus-fraction" (e.g. C7+ fraction). Adequately characterizing these undefined plus fractions in terms of their critical properties and acentric factors has long been a problem. Changing the characterization of the plus fraction can have a significant effect on the volumetric and phase behavior of a mixture predicted by the PREOS. The inaccuracy of any the cubic equation of state results from the following two apparent limitations:
improper procedure of determining coefficients a, b, and α for the plus fraction Equations of state treatment of hydrocarbon components with critical temperatures less than the system temperature (i.e. methane and nitrogen).
Numerous authors have suggested that the EOS is generally not predictive and extensive splitting of the C7+ fraction is often required when matching laboratory data.
This paper presents a practical approach for calculating the coefficients a, b, and α of the plus-fraction from its readily available measured physical properties in terms of molecular weight "M" and specific gravity "γ" with the objective of improving the predictive capability of equation of state. The predictive capability of the relationship is displayed by matching a set of laboratory data on several crude oil and gas-condensate systems. In addition; the performance of the proposed method was also compared with predictive PVT results as generated by using PVTSimTM software of Calsep. Additional comparisons are made by comparing the proposed modified PR EOS results with those of Coats and Smart4 regression methodology with PR EOS.
This study concludes that when the coefficients of the plus-fraction, i.e. a, b, and α, are determined based on the proposed methodology; splitting of the C7+ into a number of pseudo-components is essentially unnecessary.
Hydraulic Fracturing Using Heated Fluids Brings Success in High Pour Point Waxy Oil Reservoir in India
Authors: Shaoul Josef , Ross Michael , Spitzer Winston , Wheaton Stuart , Mayland Paul , Singh Arvinder Paul 
Published: December 2007

Abstract
Most existing production of waxy oils occurs from high permeability formations, and wax issues are mostly a problem in the production tubing or pipeline. Large reserves do also exist in low permeability formations that require hydraulic fracturing for economic production. Such a reservoir was recently discovered in Rajasthan (northwest India), overlying a more typical high permeability formation, both with high pour point waxy oil. Since a very large amount of oil-in-place is present in the low permeability formation, two fracturing campaigns were performed in two different horizons to assess the potential for successful well stimulation. The first fracturing campaign (on four wells) showed limited success. A study was performed to determine the reason for the failure, and significant changes were made for the 2nd campaign. This paper documents the 2nd campaign. This campaign featured the first successful use of heated fluids in India to stimulate a shallow, low permeability, massive oil reservoir containing high pour point waxy oil.
A Multiphase Flow Correlation for Low-Rate and Low-GLR Gas Wells
Authors: Vidal Manuel , Kusanovic Guido , Hoffmeister Carlos , Gilardone Carlos , Lervasi Juan , Canel Carlos 
Published: December 2007

Abstract
The analysis of alternatives of development of gas deposits and condensed is usually carried out by using the coupling between the balance of materials in predictive mode and the nodal analysis or also using numerical simulation models. In both cases it is required a suitable model of the multiphase flow behavior in vertical pipes in order to be able to predict with accuracy the flowrates the wells will produce through the different life stages of the reservoir.
The correlations for the multiphase flow, with which it is modeled the flow in vertical tubes, show a big dispersion of results in flowrates less than 50 km3std/d with gas – liquid relationships less than 10000 m3/m3. This area of low flowrates and low gas – liquid relationships is usually observed in the gas and condensed reservoirs final phase due to the decline in the production because of the fall of the static pressure and the fall of the gas – liquid relationship and the increase of the water cut.
Consequently, the dispersion in the correlations generates important differences in the production forecasts, with the associated high economic impact, because the pressures for abandonment of the wells are very different according to the multiphase correlation used.
In this work we show an exhaustive statistical analysis of the behavior of the multiphase flow correlations in vertical tubes, contrasted with measurements of pressure gradients in wells, in the majority of the cases within the ranges of flowrates and gas – liquid relationships mentioned in the previous paragraph.
From the results of this analysis, it is developed a new correlation of multiphase flow for gas – condensed – water systems that allows predicting the pressure gradients in vertical tubes within the reasonable error ranges.
We show the methodology used for the development of the correlation and the statistical analysis of the results of the application of it based on the data from the studied cases.
Strategic Plan of SCADA, Automation and Control Systems for Business Unit Las Heras
Authors: Diaz Gonzalo , Gonzalez Del Port Jorge 
Published: December 2007

Abstract
The main purpose of this work is to show the strategic plan regarding to Automation & Control Systems built for the Telesupervision of the oil fields and upstream of the Business Unit Las Heras (UELH).
This work arose from the necessity of developing a system that must enter into a process of technology renovation in the Telesupervision system of the Area. This paper also shows the description of each one of the components of the new system to be put into operation in the years to come, the process of transition from the existing system and the migration to the new technologies to be applied.
The necessity of a new, integral and reliable System arose from the requirements of a trusted, real-time data delivery and safety-oriented System. This integral system hast to cover the demands of the Production Area, in two main aspects: solid data delivery of the oil fields and the capacity of interconnection between other monitoring software systems used to develop production strategies.
Given this, for the principal actors of the Engineering Department of the UELH, a whole new philosophy and perspective got into account. They must merge the Production Area needs and build the architecture based on new, fast and reliable technologies in order to improve the communications and control system.
The strategic plan was then organised in the development of a instrumentation and control standard for the main facilities in the Upstream Production Area for the Oil&Gas industry. These are: Batteries and Auxiliary Collectors, Satellite Water-Injectors, Water Injection Plants, Oil Treating and Dehydration Plants, Gas Compressors. In addition, above this, a new –standardized SCADA System and a fast, improved and redundant Communication and Networking System.
Applications of Electric Logs and Geomechanical Models to Optimize Drilling and Well Completions in the Burgos Basin
Authors: Monroy-Ayala Norberto , Hernández-Patiño Antonio , Celis Eduardo , Sheridan Judith , Ward Chris , Torne Juan Pablo 
Published: December 2007

Abstract
Electric logs and borehole imaging were used to build a geomechanical model to predict wellbore instability during drilling and to optimize casing designs and completions to control sand production in the Burgos Basin.
This paper describes how geomechanical models can explain several problems in drilling and completion during the development of some of the fields in Northern Mexico. The total stress tensor model, the pore pressure model, and the mechanical properties model are discussed. Validation of the model is a critical step before it can be applied to design new wells.
The geomechanical model was used to design a new well and to optimize drilling, completion, and production techniques for the reservoir. The model was used to optimize the placement and orientation of perforations, evaluate proposed hydraulic fracturing designs, and select the critical draw-down to produce a well. Actual drilling, completion, and production events for the new well were analyzed, and conclusions about how the geomechanical model supported the complete design are also included in this paper.
Predictive Data-Mining Technologies for Oil-Production Prediction in Petroleum Reservoir
Authors: da Silva L. C. F. , Portella R. C. M. , Emerick A. A. , Ebecken N. F. F. 
Published: December 2007

Abstract
This paper describes the use of neural network approach as a time series tool to represent the field as a black box, to make predictions of fluid production.
The classical tools available and widely used are numerical reservoir simulation and analytical methods, like decline analysis and material balance. These classical methods are not problem-free. Although the analytical methods are easy to use, sometimes they do not provide good results in several situations (changes of injection rates, opening or closing production intervals, etc.). On the other hand, numerical reservoir simulation, which usually gives better results, it is a very complex tool that may require several months to build a flow model of a field, especially when the field to be modeled is a mature field with several years of production history. Besides that, the flow models require an update from time to time, usually once a year, that also requires a lot specialized work for a long time.
Neural network techniques were applied in two sets of data from real fields to evaluate the possibilities of using this technology in this specific problem using only a small amount of production data as input for the predictive method. For that situation a short term prediction was performed. A synthetic reservoir was also used to generate a long production history in order to test how the technique would behave in a long term production forecast. For both cases, a comparison with classical methods is presented. Neural network architecture design and optimization techniques are also discussed. Results showed that the neural network models performed better than the decline curve analysis in all cases.