bluuebunny/crossref_metadata_2025_split huggingface dataset:
Condensate Performance Trends in Trinidad Gas Reservoirs
Authors: Jemmott Susan , Hallam Richard , Maharaj Shivanand 
Published: December 2007

Abstract
The Cassia, Flamboyant, Immortelle, Mahogany, and Amherstia fields currently produce over 1.4 bcf/d for the Trinidad domestic gas market and Atlantic LNG Projects (Trains I and II). By early 2004 the gas rate should increase to about 2 bcf/d when two new projects start-up. These fields, plus the older Teak field are located in the Columbus Basin off the southeast coast of Trinidad.
The six fields have produced gas from 35 reservoirs, which are at depths from 5084 ft tvdss to 13,000 ft tvdss, and with initial pressures from 2305 psi to 7420 psi. The fluid samples and production data show that the gases are condensates. The gas is a mixture of biogenic and thermogenic gas, and the initial condensate yields vary from 1 b/MMscf up to 50 b/MMscf. For most fields, it was found that the condensate yield increased with depth or reservoir pressure.
The reservoirs exhibit a number of production mechanisms, including volumetric, volumetric with compartmentalization, and water-drive (weak to strong aquifers) (with or without compartmentalization). The paper reviews the condensate recovery factors, and produced yield trends for the different reservoirs and the different production mechanisms. It was also observed that for many of the waterdrive reservoirs that the condensate yield increased in late-life when water breakthrough occurred.
An analytical approach was used to predict whether near wellbore condensate banking would occur in the Trinidad reservoirs. The model and field data both showed that near wellbore condensate banking was not a major issue in these reservoirs because of the high permeabilities and low drawdowns. However, banking could occur in some low permeability reservoirs or if a well was produced with a large drawdown.
Synchronized Optimization Effort Significantly Reduces Drilling Time in Mature Valhall Field, Norwegian North Sea
Authors: Smith Richard , Simpson Mike , Wicker Armin K. 
Published: December 2007

Abstract
This paper describes a team approach adopted on Valhall to limit the occurrence of wellbore instability, lost circulation and stuck pipe problems by the development and implementation of field-specific operational practices while drilling in the Overburden. It will highlight the benefits of an 11-3/4" application specific liner that has been upgraded from a contingency liner to a planned intermediate liner in the drilling programme. Details will be presented explaining the importance of planning for success and dedicated offshore engineering support. Knowledge management tools and processes were used to help refine these procedures and practices over a period of 24 months.
During this time one key performance indicator, Dry Hole Days /10000ft has been improved by approximately 40% in wells drilled at an inclination higher than 50 degrees through the overburden. More importantly, the primary goal of setting 9 5/8" casing in the reservoir has been achieved successfully in the last 6 wells when previously failure to accomplish this was common.
Three-Phase Relative Permeability of Petroleum Reservoirs
Authors: Pejic Dragan , Maini Brij B. 
Published: December 2007

Abstract
This paper presents a critical review of recent experimental and theoretical developments in the area of three-phase relative permeability along with a comparative evaluation of several models for estimating the oil relative permeability under three-phase flow conditions.
Reported experimental data on three-phase relative permeability were screened for reliability and completeness and three representative data sets were selected for use in evaluation of the prediction techniques. Eight different prediction models were selected for evaluation. Each model was tested with the three selected data sets for its ability to match the experimentally determined oil relative permeability under three-phase flow conditions.
It was found that none of the models predicted all of the tested data sets with high accuracy. However, there are models that give significantly more reliable predictions of three-phase oil relative permeability compared to the other models.
Fire and Ice: Gas Hydrate Transportation - A Possibility for the Caribbean Region
Authors: Taylor Mark , Dawe Richard A. , Thomas Sydney 
Published: December 2007

Abstract
Natural gas hydrates, NGH, are crystalline solids composed of water and natural gas where individual gas molecules exist within cages of water molecules, CH4.nH2O where n≥5.75. NGH can contain up to 160m3 of methane per 1 m3 of hydrate. Hydrate technology development has focused on using gas hydrates to convert gas to a solid (GtS) to transport natural gas to market as a low cost solution to managing associated gas in regions lacking in gas infrastructure and/or market. There could be possibilities for NGH for transport of natural gas from Trinidad to the Caribbean Islands at volumes much less than those normally considered for LNG, but still commercial to the whole transport chain from producer to consumer.
Compared to alternative technologies such as LNG and gas to liquids, GtS hydrates conversion is relatively simple, low cost and does not require complex processes or extremes of pressure or temperature. It can be small-scale, modular and particularly appropriate for offshore associated gas applications. Put simply, the hydrate production concept amounts to adding water to natural gas and ‘stirring'. However, a comprehensive understanding of hydrate behaviour is necessary to design the technology for transoceanic gas transportation.
This paper describes a hydrate slurry production process and its integration into a system for delivering gas for small scale utilities in regions of the world that lack gas pipeline infrastructure. In particular, we discuss the market potential of gas transport by hydrate, present some laboratory and pilot scale studies of results on the stability of hydrates produced in a continuous stirred tank reactor, and consider the implications of these results on the process design and overall economics and the challenges to be met before the technology can be commercialised.
Automated Methodology for Field Performance Optimization Developed with Horizontal Wells
Authors: Nakajima L. , Schiozer D. J. 
Published: December 2007

Abstract
The main task of reservoir engineering is the development and management of a petroleum field in order to improve the profitability of a reservoir by raising production rates with minimum costs or increasing ultimate reserves. The performances of many horizontal well projects around the world demonstrate their effectiveness in achieving this objective, especially in offshore fields. However, this type of well has more complicated interaction with the reservoir, since its behavior is a function of a high number of parameters. The purpose of this paper is to present an automated methodology to optimize reservoir performance with horizontal wells, by using numerical reservoir simulation to provide the production forecast.
The methodology is developed through the performance analysis for individual wells, group of wells and field. The objective of this analysis is to identify the parameters that define horizontal wells productivity, to realize a comparison between wells performances, and to investigate the causes of inadequate field and wells performance. The analysis is based on selected objective-functions: net present values, cumulative oil, gas and water productions and water injection. The methodology is developed to propose changes to optimize a strategy set previously. A concept of well neighborhood is used to allow simultaneous changes, which yield a lower number of simulation runs.
A Comprehensive Approach to Modeling Sanding During Oil Production
Authors: Nouri Alireza , Vaziri Hans , Belhaj Hadi , Islam Rafiqul 
Published: December 2007

Abstract
Sand production has been a major dilemma facing operating oil companies over many years, sometimes substantially increasing production costs. On the other hand, a very controlled solid production can enhance oil production. A dependable predictive model is vital for planning production strategies in order to optimize well production. To date, despite several research studies, sand production remains the nightmare of petroleum engineers.
Even though many researchers have tried to predict sand production in the past, none of them suggested a comprehensive model that takes care of a variety of mechanisms at different points and different times. Moreover, rare models predict sanding rate and volume along with sanding initiation. This paper presents a comprehensive numerical modeling of sand production that appreciates the different behavior of the medium near and far well-bore from early to late life-time. Sanding criteria were adopted according to the physics of the problem, by taking the sequential nature of sand production into consideration.
The numerical model that was used not only assesses sand production qualitatively but can also give the sanding rate at different times. This was used to model the observations of sand production in a large block test, and the sanding rate and volume generated from numerical modeling agreed with experimental results. With each stage of increased drawdown or depletion, a burst of sand took place which enlarged the cavities initiated from the perforations. The expansion of the cavity was soon stabilized and this behavior was predicted by numerical modeling. Moreover, besides considering shear and tensile failure of the material, the possibility of volumetric failure has been discussed.
Integrated Global Optimization of Displacement Efficiency in Hydrocarbon Reservoirs
Authors: Yang Daoyong , Zhang Qi , Gu Yongan , Li Luhua 
Published: December 2007

AbstractIn this paper, an integrated numerical technique is presented to implement global optimization of displacement efficiency in hydrocarbon reservoirs. This technique chooses the net present value (NPV) as an objective function, which accounts for production- and injection- performance as well as reservoir performance. The flowing and various artificial lifting methods are incorporated into the production performance models, which have been successfully applied in more than forty oil fields. Meanwhile, the reservoir geological model is improved by continuous monitoring and surveillance. Then the objective function is maximized to generate the optimum field production-injection strategies at different development stages using a hybrid genetic algorithm (GA). Such an integrated technique can maximize the displacement efficiency in a fixed well pattern and/or an oil field under different practical constraints. This technique is applied in a water-alternating-gas (WAG) miscible flooding reservoir, and the field performance has shown that the displacement efficiency is significantly improved and the production-injection rates are well controlled. The field water-cut remains low and stable, though the gas-oil ratio is slightly higher than the original ratio. This method can be applied to develop the optimum production- and injection- strategies in a hydrocarbon reservoir so that the displacement efficiency is maximized and the reservoir life is extended.
Optimum Design and Control of the Production-Injection Operation Systems in Petroleum Reservoirs
Authors: Yang Daoyong , Zhang Qi , Gu Yongan 
Published: December 2007

AbstractThis paper presents a systems engineering approach to implementing optimum design and control of the production-injection operation systems. At first, a production performance model including flowing and different artificial lifting methods is modified from a well basis to an oil field basis. Secondly, the modified model, the injection models and surface pipeline network are integrated with a reservoir model in which the reservoir geological model is updated by continuous monitoring and surveillance. Finally, either the oil rate or the net present value (NPV) can be chosen as an objective function and optimized by a non-numerical algorithm so that the global optimum parameters for both producers and injectors are obtained. This systematic approach has been successfully applied in more than forty reservoirs. These field applications show that this technique can determine not only the optimum production operation methods for a newly discovered reservoir but also the optimum production- and injection- strategies for an existing reservoir. The success rate is over 85% for determing proper production operation methods among individual wells in a new reservoir. For a reservoir currently under production, the reservoir pressure can be kept in an appropriate range with slight increase in the water-cut and the gas-oil ratio. Thus such an integrated technique can be applied to increase the oil recovery and to extend the reservoir life.
Review of Case Histories of Two Shallow-Gas Reservoirs in China
Authors: Sheng Ruyan , Li Zhenquan , Liu Hua , Xiang Xiyong 
Published: December 2007

Abstract
Shallow-gas reservoirs (SGRs) in Shengli Oil Fields of China are mostly lenticular lithologic gas reservoirs controlled by structures, which are small-sized scattered gas reservoirs different from mid-deep structural reservoirs. Before 1980s, development of SGR often relied on experience to meet the need of practical gas demand, and matching techniques could not come into being. From middle term of 1980s, as gas being in short supply, a series of studies have been launching and better results have been getting. Gudao and Gudong shallow-gas reservoirs are two biggest SGRs in Shengli Oil Fields, which have similar geological factors but obviously different development results. Based on brief introduction on main geological characteristics, this paper describes chief similarities and differences and indicates some problems that should be paid attention to during gas production. Major methods used in Gudao include utilizing abandoned oil wells and/or water injection wells transferred as gas wells originally, high rate of gas production, later sand control and fine gas reservoir characterization during last production stage. Comparison with Gudao, which has better geological factors, overall development results of Gudong are advanced, such as ultimate recovery factor and utilization efficiency of gas wells etc. The main reasons including six aspects are as following: 1. Pay much attention to basic geological research. 2. Optimized gas reservoir engineering design. 3. Utilization of gas recovery techniques such as initial sand control. 4. Adoption of economic and effective measures such as drainage gas production during mid-later production stages. 5. Following the tracks of development plan and finding production potential continuously. And, 6. Introduction of modernized reservoir management methods. There are particular geological characteristics and development laws for SGR. So long as scientific and reasonable development strategies are taken, development results and economic benefits like mid-deep structural reservoirs could be gained as well.
Advances in Horizontal Oriented Perforating
Authors: Benavides Simon P. , Myers William D. , Van Sickle Edgar W. , Vargervik Kristian 
Published: December 2007

Abstract
Perforating in highly deviated or horizontal wells presents any service company with serious technical challenges. Attempting to maintain wellbore and perforation tunnel stability by perforating in the direction of maximum stress compounds the complexity of the perforating job. Ensuring that orientation remains valid while navigating through severe doglegs requires detailed pre-job design planning supported by applicable research data.
This paper discusses advances in horizontal oriented perforating in long horizontal sections designed to optimize perforation efficiency and production. The techniques and results discussed are applicable to any horizontal or highly deviated well where orientation of charges to maintain wellbore stability and control sand production is critical. New developments to navigate through severe doglegs and maintain orientation are significant contributions to perforation technology. Some of the results and experiences encountered while performing an oriented perforating job in a 2246-m horizontal section in a North Sea well for a major operator also discussed in this paper. A world record was set by perforating a total of 1496 m of the horizontal section in a single trip with orientation successfully verified. Additional discussion is presented on the testing and research that preceded the job.
As demonstrated in positive results from the North Sea well, perforating with oriented charges in horizontal sections will play a key role in the future to assist operators optimize production from new or declining fields.
Producing Trinidad Solids Free: A Retrospective Sand Control Completion Study
Authors: Krieger K. D. , Pucknell J. K. 
Published: December 2007

Abstract
Trinidad&s prolific reservoirs often require sand control completions to mitigate detrimental solids production. Cased-hole gravel packs, open-hole gravel packs, frac packs, and screen-only completions have all been implemented offshore in Trinidad; this paper summarizes lessons learned from these wells. In 2001 a retrospective study on the completion history in five of Trinidad&s Eastern offshore gas fields was initiated to help bridge the gap between previous completion performance and future wells requiring a step change in rate and reliability. The project goals were to compile a comprehensive data set of Trinidad sand control completion information, understand well failure mechanisms and recommend best practices for future well design. Outcomes from the 75 well study include a correlation from failed sand control completions leading to more conservative gravel sizing criteria and improved prediction of formation sanding potential. Where competent sand control completions have been installed, draw down restrictions have been relaxed enabling gas wells to produce at high rates. Several recommendations from the retrospective have been incorporated into the 2002 completion designs and are believed to be contributing factors towards the increasing reliability observed.
Different Techniques to Calculate Horizontal Permeability and Initial Water Saturation: Case Study
Authors: Fernandez Gustavo Jorge , Grinberg Mario , Valenzuela Marta 
Published: December 2007

Abstract
A case study is presented to compare results between a deterministic and probabilistic hybrid flow unit approach (FU) based on core-log analysis and classical models based on log and petrophysical interpretations in Chihuido de la Sierra Negra Field. Neuquén basin, Argentina.
The base of this paper comes from an exhaustive and detailed reservoir characterization model performed by a multidisciplinary team following the FU approach1. The objective of this work is to obtain more realistic values of OOIP and to compare different calculation techniques to achieve reliable absolute horizontal permeability and initial water saturation values.
The permeability obtained from different approaches was tested with several core data points available in the field. The main conclusion is that the permeability derived from FU was more accurate than the generalized relationships. The initial water saturation calculated was validated with field data and preserved cores. Besides, values obtained by FU-capillary pressure also were more precise than those models using straight well log data.
These improvements in reservoir description have provided the opportunity to increase the amount of OOIP and justify reliable recovery factors. The accuracy in the determination of initial water saturation and absolute permeability shown on this work allow us to apply this technique in any numerical simulation model.
A Comparative Analysis of Pressure Transient Behaviour of Undulating and Horizontal Wells
Authors: Göktas Baris , Ertekin Turgay 
Published: December 2007

Abstract
Since the early 90&s, the use of horizontal wells has become increasingly more popular in the development of oil and gas fields. Advances in drilling technology such as Measurement While Drilling (MWD) and Logging While Drilling (LWD) with accumulated knowledge/experience enable cost effective and more sophisticated horizontal wells to be drilled. Nevertheless, drilling a horizontal well that is perfectly parallel to the bedding plane is still distant from reality. All horizontal wells, to a certain extent, follow a sinusoidal trajectory merely because of steering problems, natural undulation of layers as well as presence of non-uniform layer thickness. In horizontal well applications ten to fifteen feet amplitude undulations are often considered as precise placement. Although MWD and LWD procedures minimize the possibility of exiting pay zones, while drilling horizontal wells in relatively thin formations there is always a real possibility to leave the pay zone even for a short period of time.
A number of studies have appeared in the literature for pressure transient analysis of horizontal wells for rapid determination of permeability anisotropy, skin factors and average pressures. However, none of these forward and their accompanying inverse solutions discusses the validity and applicability of the offered protocols if the horizontal well in actuality is undulated. In this study, we analyse pressure transient response of undulating wells using a previously developed numerical model that can accommodate various types of well architectures including undulating wells. Our objective in this paper is to demonstrate when analytical solutions for pressure transient analysis of horizontal wells are still usable and when they become unusable for various undulation configurations studied, and show how numerical well test analysis procedures can be utilized when analytical models are inadequate.
Example scenarios investigated in this paper show that the presence of intensive undulations in well trajectories may significantly shorten and even may overshadow the transient flow period that is already endangered by the presence of wellbore storage affects. Under these conditions the use of a numerical model, with options for undulating well architectures, will be necessary for accurate analysis of pressure transient data.
Snubbing Provides Options for Broader Application of Underbalanced Drilling Lessons
Authors: Schmigel Kevin , MacPherson Larry 
Published: December 2007

Abstract
Abundant experience with underbalanced drilling technology shows that many reservoirs do not perform at maximum potential when exposed to overbalanced drilling fluids. Broadening this lesson to benefit a greater number of wells requires the adaptation of current snubbing technology to meet a growing range of applications.
This paper examines the hydraulic rig assist (HRA) snubbing technology commonly used in horizontal drilling and considers the methods and equipment required for other applications. Using field examples from drilling and well service operations, the paper identifies key procedures and components needed to control well pressure at the surface and still allow the movement of tools and equipment.
The Quantification of Hydrocarbon Reserves in Thinly Laminated Shaly-Sandstone Formations
Authors: Pritchard Tim , Colley Nick , Bedford Jonathan 
Published: December 2007

Abstract
Many deltaic and turbidite reservoirs contain significant hydrocarbon reserves within thinly laminated sand-shale intervals, often poorly characterized using conventional wireline technologies. This paper reviews the problems and existing methods of quantifying hydrocarbon reserves in these formations, and proposes a flexible integrated interpretation strategy used to both quantify hydrocarbon reserves and associated errors.