bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Multi Laterolog Tool with Adaptive Borehole Correction
Authors: Zhou Z. , Corley B. , Khokhar R. , Maurer H. , Rabinovich M. 
Published: September 2008

Abstract
The Dual Laterolog (DLL) is one of the most commonly used resistivity logging devices in environments with highly conductive (salt-saturated) drilling mud and high formation resistivity. However, this device produces only two apparent resistivity logs with different radial depths of investigation, and it has a relatively low vertical resolution. Several array laterologs have been developed during the 1990s to improve both the vertical and radial resolution of measured formation resistivity. Each of these devices provides several depths-of-investigation measurements. However, most of these measurements, especially the shallow ones, are subject to borehole and eccentricity effects in very conductive muds and large boreholes. These effects can be severe. Therefore, conventional borehole corrections based only on borehole size, mud conductivity, and a fixed value of tool eccentricity (typically used for DLL measurements) become ineffective.
A newly developed array laterolog device, Multi Laterolog, is based on the Dual Laterolog principle but with four independent focused measurements. This device is effectively shorter in total length than the traditional DLL and provides higher vertical resolution. Four measurements with different depths of investigation yield a detailed radial resistivity profile. A hardware-based feedback loop is employed to ensure the required focusing.
To overcome the problems of the borehole and eccentricity effects on shallow measurements, we have developed a model-based adaptive borehole correction (ABC) technique. It is based on a radial 1-D inversion approach that properly corrects laterolog measurements for the borehole effect including determining and accounting for the unknown tool eccentricity. At every logging depth, we determine four earth-model parameters: tool eccentricity (Ecc), formation resistivity (Rt), invasion zone resistivity (Rxo), and invasion length (Lxo). After that, we apply the model-based correction by modifying the tool response in a borehole with mud resistivity Rm to a response in a borehole with virtual mud resistivity equal to Rxo (or to Rt if the formation is not invaded). This approach guarantees that in uninvaded intervals all four laterolog curves are properly "stacked", while in invaded intervals they show a reliable and consistent resistivity profile. The forward modeling used in inversion is based on the five-dimensional interpolation of pre-calculated look-up tables of various eccentered tool responses. Therefore, the inversion is very fast and the new borehole correction algorithm can be applied in real time. As a by-product, we output the length and resistivity of the invaded zone in invaded intervals. Thus, this correction scheme can provide Rt, Rxo and Lxo for thick beds together with borehole- and eccentricity-corrected curves at the wellsite. We illustrate the advantages of the Multi Laterolog and the model-based adaptive borehole corrections on synthetic data and on field data examples.
Nonisothermal and Productivity Behavior of High Pressure Reservoirs
Authors: App J. F. 
Published: September 2008

Abstract
High pressure, low permeability reservoirs have been encountered in various parts of the world within the past few years. Commercial development of these reservoirs may require high drawdowns, possibly in excess of 6,000 psi. The impacts of drawdown in this range are: 1) increases in near wellbore temperatures due to Joule-Thomson expansion of the reservoir fluids and, 2) significant reductions in oil viscosity. The effects of large drawdown are evaluated with a transient, single-phase thermal simulator in which the oil viscosity is modeled as both temperature and pressure dependent and Joule-Thomson expansion of the reservoir fluids is considered. Results indicate near wellbore temperature increases of 4 to 24°F for drawdowns between 2,000 to 10,000 psia due to Joule-Thomson expansion of the reservoir oil and connate water. Furthermore, if oil viscosity is not modeled as pressure dependent productivity indices will be under predicted and analysis of well tests will result in estimated skin values lower than actual. Temperature profiles within the formation are presented for a range of rates and drawdowns. Additionally, a comparison of maximum wellbore temperatures and profiles between transient, steady state and macroscopic energy models is presented. Technical rationale is also presented to explain the transient heating or cooling phenomena which occur immediately after a rate change. Synthetic well tests are generated to illustrate the impact of high drawdown on well test interpretation. These tests show a region of improved mobility in the near wellbore region due to the reduction in the oil viscosity.
Paraffin Deposition During the Flow of Water-in-Oil and Oil-in-Water Dispersions in Pipes
Authors: Bruno Antonio , Sarica Cem , Chen Hong , Volk Michael 
Published: September 2008

Abstract
Two different crude oils with significantly different physical properties, South Pelto Crude Oil and Garden Banks Condensate, were studied extensively in the small-scale flow loop of Tulsa University Paraffin Deposition Projects. A total of eight oil-water deposition tests, two single-phase deposition tests, and two inversion point tests were successfully conducted. Four different water cuts were selected for each fluid.
The deposit thickness showed a decreasing trend with increasing water cuts for both the South Pelto oil and Garden Banks condensate tests. In contrast to South Pelto's water continuous results, which showed no deposit, a Garden Banks condensate test with 85% water cut did generate a very thin and hard deposit film. This result indicates that there has to be a different deposition mechanism than the ones based on conventional diffusion theory. A reduction in Reynolds number caused by the increased apparent viscosity of the mixture also resulted in a lower paraffin content of the deposits. The volume fraction of water in the deposit is lower than the initial water cut of the mixture for both fluids. Garden Banks showed less water fraction in the deposit compared to South Pelto.
Couto's (2004) preliminary oil-water paraffin deposition model was validated against experimental data. Several modifications are proposed to account for water concentration in the deposit and changes in the diffusion coefficient for water dominated flows. Model predictions agree fairly well with experimental data acquired in this and previous studies.
Shale Volumes Have Large Uncertainties in the Lower Tertiary Deepwater
Authors: Wiltgen N. 
Published: September 2008

Abstract
Exploration in the Gulf of Mexico has progressively moved farther and farther offshore. Initially oil companies concentrated on the shelf and then moved into the deep water and the Miocene trend. With the acquisition and processing of data farther offshore, attention has switched to a new trend in the Lower Tertiary.
This is an emerging play in the deepwater Gulf of Mexico, to date there have been 12 announced discoveries out of 19 wells drilled. Geoscientists expect to see well developed stacked turbidites that define basin floor fans. This trend data is only for Alaminos Canyon, Keathley Canyon and Walker Ridge.
Shale is a mud rock that can have an extremely variable assortment of minerals, and is usually a nonreservoir rock. This kind of sedimentary rock contains a significant volume of clay minerals has many types of clay minerals with widely varying different compositions and log responses. So estimations of shale/clay volume carry large uncertainties. For our purposes we will assume the minerals in the shale are the clay minerals, plus the same minerals that are in the adjacent "sand" seen by the ECS mineral model.
With help from the integration of spectroscopy and triple-combo logs, the important variable the apparent grain density, can be calculated as a function of the 4 measured elements Si, Ca, Fe and S. This method becomes even more certain when the method is calibrated to a core data base to correlate the weight fractions of elements. We will convert bulk density, and with grain density from SI, FE, CA and S to porosity. Mr. Herron's paper SPE 77631 gives the formulas for this methodology for four types of combinations of non-arkose, sub-arkose and arkose.
The advantages and shortcomings of this method will be discussed and how they involve the spectrometer measurements with the element-mineral relationships. It is extremely important to have core with porosity, grain density, water saturation and permeability. But the key information from the core is quantitative XRD to truly have confidence in the significance of this method.
Interactions Between Acids and Water-Swelling Elastomers
Authors: Al-Yami A. S. , Nasr-El-Din H. A. , Al-Humaidi A. S. 
Published: September 2008

Abstract
Achieving successful zonal isolation during well completion is critical to minimize early water production. Recently, oilswelling packers were used in various carbonate reservoirs, and currently water swelling packers are being investigated for potential field application. Considering future matrix acid treatments of wells completed with water swelling packers is part of this investigation. To the best of the author's knowledge there is no previous work done to fully investigate best practices in stimulating wells completed with water swelling packers.
An earlier investigation by Al-Yami et al.1 showed that water-swelling elastomers withstood pressures up to 5,000 psi at 190°F after placing the elastomers in brines with salinities up to 200,000 mg/l. CaCl2 completion fluids at 72 pcf, a common completion fluid, failed to swell the elastomers..
The present study investigates different acids to effectively stimulate wells completed with water swelling packers. Lab testing was done in 3 steps that included swelling the elastomers in low salinity aquifer water, soaking in various acids for 2 hours and finally immersing elastomers in the aquifer water to mimic resumption of water injection after conducting a matrix acid treatment.
Hydrochloric, formic acids and combinations of these two acids resulted in significant reduction in the volume of the swelled coupons. Immersing the coupons after acid exposure in water did not regain their original volume prior to soaking in these acids. Citric and lactic acids slightly reduced the volume of swelled packers from vendors II and III. The elastomers swelled again in water after exposure to these acids. Acetic acid showed the least effect on water swelling elastomers and their size was swelled again after immersing in water. The shape of coupons obtained from vendor III changed almost in all acids examined. The change in shape will definitely impact the ability of this type of packer to isolate various zones.
Simplified Modeling of Turbidite Channel Reservoirs
Authors: Alpak Faruk O. , Barton Mark D. , van der Vlugt Frans F. , Pirmez Carlos , Prather Bradford E. , Tennant Steven H. 
Published: September 2008

Abstract
Effective properties can represent fine-scale geologic heterogeneities in simple full-field reservoir models without having to explicitly model them. A comprehensive simulation study tests the sensitivity of dynamic connectivity in turbidite channel reservoirs to a large number of stratigraphic and engineering parameters. Simulations performed using geologically realistic sector models at multiple levels of stratigraphic resolution show that dynamic connectivity is governed by large-scale architectural parameters such as meander belt size, net-to-gross, and degree of depositional storey amalgamation; and stratigraphic parameters that describe the shale architecture at multiple scales, e.g. shale drape coverage and frequency of occurrence.
We demonstrate how to rapidly generate effective properties at multiple geologic scales, incorporating the effect of channel architecture and reservoir connectivity into simple dynamic models. Use of simple dynamic models in conjunction with effective properties, principally, geologically based pseudo-relative permeabilities, significantly accelerates the simulation workflow. We show that a statistical distribution of the recovery factor can be produced within hours instead of days by combined use of Monte Carlo simulation and a simple dynamic model with effective properties. Recovery factors estimated via our simplified modeling method agree well with observed recovery factor distributions of turbidite channel reservoirs with significant production history.
Optimal Value Testing – Moving From Vision to Reality
Authors: Elshahawi Hani , Hite Robert H. , Hows Melton P. 
Published: September 2008

Abstract
Over the past few years, there has been a vision that Optimal Value Testing (OVT) will replace conventional drill stem tests for in-situ measurement of dynamic reservoir properties such as permeability and drainage volume. This vision was that OVT would be safer, less costly, and friendlier to the environment, but the key impediment to OVT was the concern that the quality of the results might be inadequate for the difficult development decisions that we face.
Definitions of OVT vary but, in general, it may be defined as any testing method that yields fit-for-purpose results with the lowest cost and Health, Safety, and Environmental (HSE) impact. In more pragmatic terms, an OVT is any pressure transient test in which live hydrocarbons do not have to be produced directly to surface. Our OVT toolbox currently includes three types of well tests – wireline formation testing (WFT), closed system testing with cleanup and repeat surges, and injection testing. Our recent examples of closed system tests and wireline formation tests have proven to us that we can get comparable data quality to a conventional DST. Injection testing, aimed at determining drainage volume, is still relatively immature, as we have executed only one injection test to date. However, there has been considerable design work that makes us believe that this technology is also promising.
Our experiences with OVT over the past several years suggest that the wireline formation tester solution is the best answer in a large proportion of our cases. We will therefore focus in this paper on describing its strengths, weaknesses, and opportunities. Our applications of this technology are still evolving, and there are clearly more issues to resolve than with a conventional drill stem test. However, by drawing on our increasing breadth of experience, future value of information decisions about doing in-situ dynamic measurements will more often include this cheaper, safer, and more environmentally friendly option.
Shallow Penetration Particle-Gel System for Water and Gas Shutoff Applications
Authors: Vasquez Julio , Eoff Larry , Dalrymple Dwyann , van Eijden Jip 
Published: September 2008

Abstract
This paper presents the development of a new system for water and gas shutoff operations. This system combines a conformance sealant (based on an organically crosslinked polymer) with non-cement particulates. The particulates provide leakoff control, which leads to shallow matrix penetration of the sealant. This filtrate from the leakoff is thermally activated. After exposure to the bottomhole temperature of the well, it forms a three-dimensional gel structure that effectively seals off the targeted interval. This system can be considered an alternative to standard cement squeeze operations, casing leak repairs, sealing of thief zones, and perhaps many other wellbore operations.
The system can be bullheaded into the well allowing for easy placement and calculation of treatment volume. The limited and controlled leakoff into the matrix during the squeeze results in a controlled depth of invasion. Selective perforation of the oil zones re-establishes the desired hydrocarbon production from the targeted interval. The system can be easily washed out of the wellbore, as compared to cement, which must be drilled out. The temperature range of the particle-gel system is 70 to 350°F (21 to 177°C). To date, more than 54 jobs have been performed with this system. This paper presents results obtained from laboratory evaluations, the methodology of the job design, and limited case history information.
Samarang Pipeline-Replacement Project: Application of an Innovative Approach for Shallow-Water Pipeline Installation
Authors: Rashdi Khairil Raezwan , Sainal Muhamad Rashid , M Yusoff M Nabil 
Published: September 2008

Abstract
This paper presents the approach adopted in the replacement of ageing pipelines at offshore Sabah, Malaysia by PETRONAS Carigali Sdn. Bhd. (PCSB), the E&P arm of PETRONAS. Several options were explored to best deliver the project considering the installation difficulties were exacerbated by the congested field, ageing offshore structures, spaghetti pipeline networks, monsoon wind and presence of corals on the seabed. On top of these, the field's shallow water provides further complexity to the construction and installation works. The paper also shares the means engaged to mitigate the challenges and lessons learnt during the project's planning and executing stages.
Subsequent to the preventive inspection findings, a project was initiated in 2006 – as part of PCSB's commitment to rejuvenate ageing offshore facilities, sustaining the field's integrity and assuring reliability of supply. The Samarang pipeline replacement project was initiated to address these issues and espouse the integrated field development within its block. As a fast track project, the construction method engaged has to be sound and capable for expeditious work completion to avoid jeopardizing production. Through a thorough evaluation process, an innovative pipeline installation approach utilizing a shallow draft work barge was chosen for the project.
The project was completed with the successful installation of all four pipelines in December 2007. Despite many challenges, the project progressed smoothly without major setbacks. It was successfully completed ahead of schedule, within budget and recorded zero LTI and zero TRCF. The new construction method which requires assimilation of both the conventional and new approaches for offshore installation, has demonstrated its effectiveness hence proving the plausibility of the method for other projects with similar circumstances.
In the pursuit of sustaining and revitalizing old offshore facilities, pipeline replacements are inevitable to prolong intra and interfield operation flow of hydrocarbon. The unique and uncertain offshore environment, particularly at the shallow water areas introduces many installation challenges. Although proven methods are available, exploring a new approach to pipeline installation is essential to safely and effectively deliver projects with minimum costs. By selecting a suitable approach for pipeline installation, new networks of hydrocarbon flow facilities can be developed, thus allowing continuous production for decades to come.
Real Time Well Diagnostic Using Slick Line Fiber-Optic Distributed Temperature Sensors: West Venezuela Applications
Authors: Gonzalez Y. J. , Azuaje A. J. , Duarte T. , Sapon R. , Madariaga M. N. , Rubio E. A , Montoya C. , Martinez Santiago Maryvi , Castillo Saluzzo G. L , O'shaughnessy P. , Perez Padron M. A , Berbin A. 
Published: September 2008

Abstract
Conventional slick-line temperature surveys enable successive temperature measurements at pre-determined depth stations along the well-bore. This method has two major drawbacks. The wellbore fluid flow dynamics impact the temperature accuracy while the uncertainty in depth leads to erroneous conclusions on spatial temperature distribution along the wellbore. Remedial actions based on these temperature measurements do not always help optimize productivity or injectivity. To overcome these measurement uncertainties and correctly evaluate the gas-lift system performance for the oil producer wells or to identify temperatures anomalies, such as flow behind casing for water injection wells, continuous temperature measurements with time and depth are needed.
The slick-line fiber optics distributed temperature sensors technology presented in this paper measure simultaneous temperature traces along the well-bore with time. This is widely used in oil wells located at Maracaibo Lake, where approximately 95% of the wells are produced using gas-lift and also applied in La Concepcion water injection wells for wellbore integrity. There are technical papers on fiber-optic technology applications as a qualitative monitoring tool but very few case histories where slick-line is used as the method of fiber deployment.
This paper will describe eight success histories where fiber-optic sensors have been deployed using slick-line. These case studies are grouped as follows: Gas-Lift System Evaluation in which four wells were subject to analysis: Completion leakages detection in producers and injectors; Identification of water entry as well as channeling of water behind casing.
This paper will also demonstrate the application of this technology to implement production enhancement techniques. The use of this technology for operational flexibility, time saving and data quality will be compared to conventional temperature logging. In addition, it will show how environmental risks are eliminated by deploying fiber on slick-line for leak detection services.
Formation Powered Jet Pump Use at Kuparuk Field in Alaska
Authors: Peirce J. W. , Burd J. A. , Schwartz G. L. , Pugh T. S. 
Published: September 2008

Abstract
Formation powered jet pumps (FPJP) were pioneered for use in Kuparuk Field wells on the North Slope of Alaska. Unlike conventional surface powered jet pumps, these pumps are hydraulically powered by a prolific producing upper zone called the C sand to generate greater drawdown on a less productive lower zone called the A sand. Formation powered jet pumps increase oil rate from the A sand while reducing the water rate from the C sand.
Gas lift can be used in formation powered jet pump wells to further enhance drawdown on a well while jet pumping. Many formation powered jet pumps are being used in Kuparuk wells with gas lift to increase the drawdown applied to the A sand.
An overview of formation powered jet pumps used at Kuparuk Field is presented. Formation powered jet pumps could be beneficial in other multi-zone oil fields around the world to increase oil production rate, while reducing water production rate and lifting costs.
Corrosion Consequences of Nitrate/Nitrite Additions to Oilfield Brines
Authors: Martin Richard L. 
Published: September 2008

Abstract
Because nitrate ions are sometimes added to oilfield brines for bacterial control, a laboratory study was conducted to determine the possible influence of nitrate and nitrite ions on steel corrosion. Corrosion consequences were suspected due to the oxidizing potential of these ions and some oxidizing agents are known to promote accelerated corrosion.
Results of this study indicated that nitrate ions did not influence corrosion or its inhibition. However, nitrite ions sometimes enter these systems and they can be influential. Nitrite ions caused sour (contains H2S) oilfield brines to become more corrosive and compromised corrosion inhibor effectiveness in both sweet (no significant H2S) and sour systems.