bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Generation Crossed Dipole Logging Tool: Design and Case Histories
Authors: Kessler Calvin , Varsamis Georgios L. 
Published: December 2007

Abstract
With the increase in deepwater exploration and production and the advances in logging-while-drilling formation evaluation (along with the high rig costs) the wireline formation evaluation is often limited to only one drill pipe conveyed logging run. A new monopole and crossed dipole acoustic logging tool was designed for the drill pipe conveyed environment. The robust mechanical design does not limit this sonic tool to the bottom of the tool string. NMR and pump-through formation testing tools can be located in the logging string below this tool on drill pipe-conveyed logging, or e-line conveyed logging.
This tool was designed utilizing a systems approach and most of the functions of the tool are surface programmable. For example, the pulse shape, duration, amplitude, and frequency of the on-depth crossed dipole bender bar sources is programmable. Likewise, the level of the monopole output signal is also surface selectable. The digitization of the 96 waveforms of data per depth sample is programmable for number of samples, sampling interval and waveform compression. With 96 waveforms per depth sample, a logging speed of approximately 1800 ft/hr (30 ft/min) can be achieved with a quad-combo logging suite acquiring sonic data at two samples per foot.
Case histories from a variety of formations demonstrate the tool's capability to obtain monopole P wave data, monopole refracted shear data, crossed dipole flexural wave slowness, and anisotropy. The following representative formations are included in the case histories: near-zero porosity carbonate with refracted shear wave slowness and flexural wave slowness of less than 100 μsec/ftporo-plastic Gulf Coast sandstones and shales with flexural wave travel times exceeding 700 μsec/ftformations with natural fractures that are detectable by the cross dipole flexural wave slowness and confirmed with open hole image dataa shale section with approximately 650 psi of stress anisotropy
Evaluation of CO2 Gas Injection For Major Oil Production Fields in Malaysia - Experimental Approach Case Study: Dulang Field
Authors: Md. Zain Zahidah , Kechut Nor Idah , Nadeson Ganesan , Ahmad Noraini , Raja D M Anwar 
Published: December 2007

Abstract
In meeting the challenge to improve oil recovery through implementation of IOR techniques, Dulang field was selected to study the possibility of CO2 injection as a potential recovery method. Dulang was chosen as the candidate because of the complete suite of information on this field and the availability of CO2 source within Dulang and nearby fields. The work focused on characterizing the oil and oil - CO2 interactions that was performed through phase behavior studies, vaporization test and displacement tests.
Studies conducted indicates that at the reservoir temperature of 215°F, CO2 injection would not be able to achieve miscibility with the crude oil at the current reservoir pressure, or even if the pressure is increased to the initial reservoir pressure. Equation-of-State (EOS) model also shows that the Multiple Contact Miscibility Pressure (MCMP) for CO2 and produced hydrocarbon gas is 3230 psig and 3340 psig respectively. This pressure is significantly higher than the initial reservoir pressure of 1800 psig.
Vaporization of Dulang crude by pure CO2 and the CO2-rich produced gas was studied. The laboratory study suggests significant vaporization of 15% of the stock tank oil with pure CO2. However, based on Equation of State, the vaporization ranges from 2 - 5 % with produced gas at operating reservoir pressure of 1400 - 1800 psig.
In view of the above, the potential recovery process is an immiscible process using produced gas containing high CO2 for cost optimization. In addition, the water alternating gas (WAG) process may improve mobility control and sweep efficiency. Detail studies involving WAG Composite Core, G & G Modeling and Numerical Simulation are currently on-going for identified location of a pilot project.
EOR Possibilities for Development of a Mature Light-Oil Reservoir in Oman
Authors: Babadagli T. , Al-Bemani A. , Boukadi F. , Iyoho A. W. 
Published: December 2007

Abstract
This paper presents the development plan using EOR techniques for a sandstone reservoir containing very light oil (45 oAPI, 0.5 cP at reservoir conditions) located in Oman. Due to low permeability (0.1 to 5 mD) of the upper part of the reservoir (Upper Haushi Sand, UHS), recovery factor was very low. However, original oil in place is quite significant in this formation and EOR application was targeted to increase the recovery factor. On the other hand, reservoir pressure is still high due to strong aquifer support. Another zone of high permeability (100-300 mD, Sand Drain, SD) has been watered out by the strong aquifer influx. Being operated by a small size oil company, the main concern was the economics – capital and operating expenditures. After a screening process the optimum solution was found to be nitrogen injection to overcome the low injectivity. The low viscosity of oil and relatively low cost of injectant also make the injection of nitrogen a favorable application.
The response of the two formations (UHS and SD) to nitrogen injection was tested in laboratory by injecting nitrogen into oil saturated core samples. The recovery obtained by immiscible displacement of oil was as high as 40 % in the tight UHS. Similarly, tests were carried out to understand the response of nitrogen injection into already waterflooded high permeability SD zone. The recovery was found to be 5 to 10 % after 75 % waterflood recovery. Next, the nitrogen injection performance was studied using a full-scale field simulator. After obtaining a history match, the option of using abandoned downdip wells as injectors and the updip wells as producers were evaluated. Relative permeability curves generated using the laboratory tests were applied and different injection scenarios were tested through a series of simulation runs. Also, the possibilities of injecting air without purifying from the oxygen were discussed from the economical, technical, additional oil recovery and safety points of view.
Determination of Residual Oil Saturation in A Carbonate Reservoir
Authors: Tang Joseph , Zhang Pei-Xin 
Published: December 2007

Abstract
Single-well tracer testing has been widely accepted as a standard method for measuring residual oil saturation to waterflood. Residual oil saturation is an important parameter in the evaluation of tertiary oil recovery potential for depleted reservoirs. At an advanced stage of depletion, Leduc, a Canadian carbonate reservoir, has been considered as a candidate for enhanced oil recovery. As part of the evaluation process, single-well tracer tests were conducted at two watered-out producers to determine residual oil saturation to waterflood. The tracer production profiles were found to be highly skewed with long tails and early arrival times, which are typical for carbonate reservoirs. Two different models, namely a double-porosity model where tracer could distribute between the flowing and non-flowing pores through mass transfer and a single-porosity model where a fictitious water drift rate was assumed in the test zone, were used to interpret the data. It was found that either model could match the data to the same degree of accuracy regardless of the flow mechanisms assumed and the residual oil saturation derived from these two models were 35% and 38% respectively. This demonstrates the robust nature of the test that the non-uniqueness of the match does not affect residual oil saturation determination. The residual oil saturation determined by simple analytical models including mass balance method, peak method and mean retention volume method were all in the range of 34% to 38%, in excellent agreement with the simulation results. As well, the Sorw obtained by the SWTT method compared favorably with those determined by interwell tracing (35%) and sponge coring (33%).
Pressure-Dependent Pore Volume Compressibility – A Cost Effective Log-Based Approach
Authors: Ong Seehong , Zheng Ziqiong , Chhajlani Richin 
Published: December 2007

Abstract
This paper presents an innovative log-based method of determining pore volume compressibility as a function of pore pressure depletion. The approach considers changes in reservoir stress associated with pore pressure change (stress path) and incorporates constraints that ensure deformations are within elastic bounds. The approach incorporates the effect of stress anisotropy by using elastic moduli derived from stress-strain curves under simulated triaxial loading conditions. The triaxial condition pore volume compressibility was then converted to that of unaxial strain equivalent, which best describes the existing reservoir characteristics. The proposed methodology is particularly useful for predicting pressure-dependent pore volume compressibility where core specimens are either not available or in situations where laboratory measurements are prohibitively laborious and time consuming.
For input, the method requires bulk modulus, compressive strength and other mechanical properties that characterize an elastic material, preferably predicted using a log-based mechanical property algorithm in order to generate a foot-by-foot profile of pore volume compressibility. A continuous profile of uniaxial strain pore volume compressibility with depth from log provides quick assessments of pore volume compressibility variations across the reservoir intervals. It is also useful and cost-effective for constraining pore volume compressibility of all the reservoirs penetrated by the well (and logged) but with only limited core data available for calibrations.
The example shallow oil well data illustrates that pore volume compressibility decreases with decreasing pore pressure (or increase effective stress). An inverse pore volume compressibility to strength relationship was also observed. It was also observed that pore volume compressibility decreases with increasing porosity until the effective porosity reaches a critical minimum value. At porosity higher than the critical value, the pore volume compressibility increases with increasing porosity. This may suggest that reservoirs with a porosity less than the critical value are more likely to be under pressure drive, while reservoirs with porosity higher than the critical value are more likely to be under compaction drive.
Research of Polyacrylamide Gel Application for Water Shutoff in High Temperature Fractured Granite Basement Reservoirs
Authors: Tung Nguyen Phuong , Hung Pham Viet , Vinh Ngo Quang , Long Bui Quang Khanh 
Published: December 2007

Abstract
Water shutoff and sweep efficiency improvement in crude oil production from high temperature fractured granite basement reservoirs, as White Tiger, have been poorly studied. For finding gels stable in severe working conditions like high temperature, high-pressure etc, variety compounds of polyacrylamide with inorganic and organic crosslinking agents have been tested. The effects of temperature, polymers, crosslinkers, brine salinity and pH on gelation and stability were found.
Base on the obtained results, proposed by the authors gelant compositions could be effectively applied for water shutoff in production wells of high temperature fractured granite basement reservoirs.
Prediction of IPR Curve of Oil Wells in Visco-Elastic Polymer Solution Flooding Reservoirs
Authors: Xia Huifen , Yue XiangAn , Wang Dexi , Li Qun , Zhang Xuebin 
Published: December 2007

Abstract
When developing water-flooding reservoirs, oil and water are regarded as Newtonian fluids in the study of inflow performance relationship of oil wells. But for polymer-flooding reservoirs, prediction of inflow performance relationship of oil wells must consider non-Newtonian behavior of the polymer solution. Based on present papers, descriptions about the flow behavior of non-Newtonian fluid in porous media are mainly concentrated on power-law fluids. These studies do not consider the variation of rheological parameters along seepage flow direction and also elastic effect of polymer solution, therefore these models or results can not be used to characterize the seepage behavior of polymer solution in porous media and predict the inflow performance relationship of oil wells in polymer flooding reservoirs.
Analysis of the samples from oil wells in polymer flooding reservoirs shows that polymer solution produced still appears visco-elastic effect even at a lower concentration of the polymer solution. In this paper, according to a great quantity of experiment data on core displacement and rheological property, a model about the variation of rheological parameters along the seepage flow direction is developed. A constitutive equation for visco-elastic fluid is constructed, in which the variation of the rheological parameters of polymer solutions in porous media is taken into account. A formula of critical elastic flow velocity is presented. Using the constitutive equation proposed in this paper, the seepage flow behavior of visco-elastic fluid with variable rheological parameters is investigated. A model for calculating IPR of oil well in polymer flooding is developed, in which variation of in-situ fluid rheological parameter, visco-elastic effect, formation damage near the wellbore, decrease in formation permeability and other factors are considered. This model is solved using finite difference method and IPR curves and pressure distributions are predicted. Some factors affecting inflow performance are analyzed. With this model, inflow performance relationship of two oil wells in polymer-flooding reservoir in Daqing oil field is calculated. The prediction result is coincident with the flow-after-flow data, the average relative error is less than 10%.
According to the predicted IPR results, the pumping equipment and working parameters can be optimized. It is of great significance for designing a reasonable working system for oil wells in polymer-flooding reservoir.
Benchmarking of Steamflood Field Projects in Light/Medium Crude Oils
Authors: Pérez-Pérez Alfredo , Gamboa Marjorie , Ovalles César , Manrique Eduardo 
Published: December 2007

Abstract
A benchmarking study on 43 steamflood of light/medium crude oils was performed, to find attractive reservoir characteristics and successful operational practices that are used worldwide. More than 30 successful projects were analyzed and summarized in a database, which included reservoir properties, best operational practices and results obtained. On average, an incremental oil recovery of 19% OOIP was obtained by steamflooding, during a project lifetime of up to seven years.
Based on the successful project characteristics, we developed a model to rank potential reservoirs. Reservoir data were analyzed using standard statistical methods for properties, such as: API gravity, initial oil saturation, reservoir temperature, porosity, initial pressure, depth, net pay, viscosity at reservoir condition, initial (at the beginning of steamdrive)-bubble pressure ratio and average permeability. The statistical model ranked the properties on a standardized score scale. A predicted score close to one hundred indicates a high probability of success. Supported by this numerical model, we selected the La Salina reservoir (La Rosa Formation, Lake Maracaibo, Western Venezuela) as a potentially successful reservoir to apply steamflood technology.
In addition, unsuccessful projects from two different reservoirs (the Naval Petroleum Reserve No. 1, and Buena Vista Hills, both in the USA) were analyzed, to understand the reasons for failure. Several reasons were identified, such as: poor reservoir characterization, thief zones and carbon dioxide formation by decomposition of reservoir minerals.
Successful Field Test of the First Ultra-Low Interfacial Tension Foam Flood
Authors: Wang Demin , Cheng Jiecheng , Yang Zhenyu , Qun Li , Wu Wenxiang , Yu Huiyu 
Published: December 2007

Abstract
An important method to increase the recovery of reservoirs is ASP (alkaline/surfactant/polymer) flooding to lower the IFT (interfacial tension) between the crude oil and displacing fluid to an ultra-low value (&lt;10-3 mN/m) to increase the displacement efficiency and at the same time to increase the viscosity of the displacing fluid in order to increase the volumetric sweep efficiency. However, the alkaline in the ASP fluid makes it difficult to increase the viscosity by polymers. Therefor, experiments were performed by adding natural gas to the ASP fluid to form an ASP foam (ASPF) displacing fluid. This ASPF fluid should have the characteristics of an ultra-low IFT, high displacement efficiency and also low mobility, which should increase the volumetric sweep efficiency also.
This paper introduces the results of ASPF tests in the laboratory and field. The experimental results in the lab include the foaming ability of the ASPF, the stability of the foam, its IFT, resistance to flow in cores, the incremental recovery of cores of different heterogeneity and the relationship between incremental recovery and residual oil saturation and polymer concentration. The field results include reservoir description, well pattern, composition of the injected ASPF, injection and production conditions and problems encountered.
Good results were obtained in the field. The current recovery factor is already 65.6% OOIP. The final recovery is estimated to reach 71.3% OOIP.
Simulation and Optimization of Continuous Gas Lift System in Aghajari Oil Field
Authors: Bahadori Alireza , Ayatollahi Sh. , Moshfeghian M. 
Published: December 2007

Abstract
Gas lift system is optimized by use of PVT data combined with fluid and multiphase flow correlations. The first step in the study is the selection of appropriate correlations followed by multiphase flow calculations at various points of injection. From actual pressure and temperature surveys and determining the point of injection, a gas lift performance curve is constructed for the well. In order to determine the optimal gas lift condition, Solution nodal method is used to determine optimum injection depth, optimum well-head pressure, optimum production rate and minimum injection gas volume. A considerable gain could be obtained from implementing recommendations. Finding the appropriate valve space is done in this work is new compared to others.
Optimizing Drilling Parameters Enhances Horizontal Drilling Performance
Authors: Eissa Walid Mohamed 
Published: December 2007

AbstractThe optimized selection of bits and mud type during any drilling operation improves significantly the drilling efficiency presented in high rates of penetration consequently less cost per meter.Hydraulics play also great part in optimization cycle by enhancing the ratio of the pressure loss across the bit nozzles to the circulating pressure., Utilizing bit hydraulic horsepower or jet impact force criteria which improving considerably the rate of penetration, due to the continuos cleaning below and through the bit cones.Geosteering drilling is considered as one of the optimizing tools that recently introduced to drilling operations, where it affected positively Petrobel horizontal drilling learning curve performance.This paper present a case study for group of horizontal wells drilled by Petrobel through last two years, summaries the good drilling performance achieved and analyzing difficulties encountered and describing implementation process of the lessons learned from old wells in planning recent ones.As a result of that, the cost per meter was decreased by about 50% in last two years, and average penetration rate was nearly doubled, moreover, the production rate increased approximately 10 times more each well.
Safeguarding Our Assets Through Contractor Partnership
Authors: Price J. G. , Vega T. A. , Wasden F. K. , Isbell G. C. , Cadwallader R. G. , Fontenette L. A. , Mc Rill M. C. , Shackelford E. J. 
Published: December 2007

Abstract
Company contractor safety performance has improved dramatically over the past 10 years (Appendix A, Chart 1) due to commitment from both the contracting community and the entire organization, particularly from senior leadership. The foundation upon which this success story is written is the company's Contractor HSE Management Process (CSMP). Utilizing a risk-based approach and a "fit-for-purpose" schema that is owned and driven by line management, CSMP principles provide the foundation for integration of health, safety and environment (HSE) into the company's everyday business.
At the heart of this process is "Stoplight", a tool that provides an initial assessment of contractors that have a medium to high degree of risk. First introduced into our midstream business and subsequently adopted throughout the company, Stoplight requires demonstration of alignment with the company's HSE Management System (HSE MS) as well as documented continuous performance improvement. This approach has provided the focus necessary to achieve the outstanding performance exhibited to date.
The integration of CSMP into the company's business strategy is key to its success. Through our Procurement Councils and Business Performance Reviews conducted in conjunction with our contractors, clear expectations and aligned messages become apparent. Both relationships and time are maximized when these and other "face-to-face" meetings are held on a regular basis between designated company contacts and their contractor counterparts. Contractors now share key learnings and collectively develop improved practices that benefit the entire industry.
Successful creation of a partnering atmosphere with our contractor community is crucial to safeguard people and our assets. This collaboration has provided the foundation for meeting the myriad of challenges that exist in the demanding oil and gas environment and in such diverse regions as South Texas, the Gulf of Mexico and Michigan.
Quality, Health, Safety and Environment Synergy by Creating Alliances Between Oil and Service Companies in Integrated Projects
Authors: Beyk S. , Paradas S. 
Published: December 2007

Abstract
Over the years, oil companies have invested significant resources looking for ways to assign projects to the most competent service companies in the different disciplines of the exploration and production business. Often this resulted in fragmented services because of the service company's capacities.
Continuous searching has resulted in the evolution of a relationship between oil and service companies to encompass anything from a simple service call to a more mature, contractual relationship developing integrated projects. The integrated project approach enables an oil company to award work to a service provider based on their capacity to economically manage various processes. It also provides the opportunity to produce outstanding results, while continuously improving processes.
In 1999 an oil company and an oilfield services company started a strategic alliance to drill and recomplete wells in Lake Maracaibo, Venezuela. This alliance enabled both organizations to be involved in the planning and design of "fit-for-purpose" rigs that operate at maximum efficiency in the specific conditions of the lake. Both engineering and operations solutions are based on an integrated services contract.
In this paper, we show how this alliance has created a combined quality, health, safety and environment (QHSE) management system, generating greater results than the operator and service company systems generated individually; and how this has benefited employees, the environment and the community.