bluuebunny/crossref_metadata_2025_split huggingface dataset:
Potential Implementation of Underbalanced Drilling Technique in Egyptian Oil Fields
Authors: Fattah K. A. , El-Katatney S. M. , Dahab A. A. 
Published: July 2010

Abstract
The need to increase productivity and to reduce drilling damage favors the use of underbalanced drilling (UBD) technology. In highly depleted reservoirs, extremely low-density fluids, such as foams or aerated mud, are used to achieve circulating densities lower than the pore pressure. In such cases, the induced modification of the in-situ stresses has to be supported mainly by the rock, with little contribution from the drilling fluid pressure. The application of underbalanced drilling depends on the mechanical stability of the drilled formation, among other factors. In general, poorly consolidated, depleted formations are not suited for that technology.
In this paper, twenty three UBD worldwide cases have been analyzed; two of which are from Egyptian fields and the others are from Iran, Algeria, Kuwait, Oman, Texas, Mexico, Indonesia, Canada, Libya, Middle East, Qatar, Saudi Arabia and Lithuania. From these analyses, the reasons of failure or success have been stated. The reasons of success included depleted reservoirs and highly fractured carbonates formation while, the reasons of failure include overpressurized shale, highly tectonic stress areas, and downhole failures. The main attractive application of this technology was proposed to be only in the reservoir section, and the target was to prevent the reservoir damage and hence increase the productivity and recovery factor.
A proposed underbalanced drilling program is developed based on these analyses to be used in the three main regions in oil and gas producing Egyptian fields. The aerated mud was selected as a drilling fluid to drill the reservoir section in Western Desert and Gulf of Suez region whereas the single phase fluid was selected as a drilling fluid in the Nile Delta region.
Mud Weight Design for Deviated Wells in Shallow Loose Sand Reservoirs with 3D FEM
Authors: Shen X. , Sikaneta S. , Ramadhin J. 
Published: July 2010

Abstract
Conventional mud weight designs are typically developed by using a 2D analytical solution. These methods, however, are unreliable in shallow, unconsolidated sands, which have very low cohesive strength and pressure-sensitive material properties, such as Young's modulus and Poisson's ratio. Using a 2D solution for these reservoirs can result in unnecessarily high mud weights and narrow mud weight windows, especially in deviated wells. In this case, a numerical method with a pressure-dependent material model becomes necessary for predicting a minimum safe mud weight. A fully coupled, nonlinear 3D finite element model for a shallow (1,000 ft TVD) horizontal well in Tambaredjo NW field of Suriname was built. The calculation of deformation of loose sand, which has pressure-dependent material properties, including cohesive strength, internal frictional coefficient, and Young's modulus, was combined with porous flow. We used this model to investigate wellbore stability and minimum safe mud weight gradient. Core samples from wells in the Tambaredjo NW field of Suriname were analyzed. The results of the analyses were used to develop a nonlinear relationship between material parameters, including cohesive strength, internal frictional coefficient, Young's modulus, and mean stress in effective stress space. Pattern of variation of these pressure sensitive parameters and other data were drawn from the multiple disciplines involved in the field development plan. The results of our study show the model-predicted minimum mud weight gradient required to drill the well without instability can differ from the conventional analytical solution by as much as 2 ppg. The use of this pressure-dependent material model for predicting minimum safe mud weight in shallow, unconsolidated sand reservoirs can result in significant savings in field development costs.
Design and Development of a Tubing Repair Solution Using an Expandable Metal Patch
Authors: Blane D. A. , Crossland A. J. 
Published: July 2010

Abstract
The paper presents a study of the design and development of a Hydraulically Expanded Tubular System (HETS) Internal Patch and Wireline Running Tool by READ Well Services, and qualification testing of the patch for oil and gas well applications. The HETS Internal Patch solutions enable tubing or other leaking downhole equipment to be repaired, or provide a method of strengthening corroded or damaged completion equipment.
The process involves expanding a metal sleeve (using hydraulic pressure) into the existing tubing to provide a continuous lining with a permanent seal. The restriction in the well is minimal (only the thickness of the patch) unlike straddle type solutions. A typical patch could be 5 mm (0.2”) thick. This allows the maximum possible production and for tools to be run through the patch for ongoing well maintenance requirements.
For a number of years HETS solutions, and their deployment systems, have been available to suit tubing sizes of 7” and larger. A Joint Industry Project (JIP) was created to downsize the technology to suit smaller sizes of tubing. READ Well Services and 5 major oil and gas sponsors used the inherent scalability of the available HETS technology and developed the SlimHETS system to provide a means of deployment for Internal Patches to suit 4 ½” to 5 ½” tubing. The deployment system was also required to be compatible with a tractor to suit high angle or horizontal wells. The project was created to develop, manufacture and test the the wireline deployment system and to design, manufacture and qualify corresponding Internal Patches.
The SlimHETS Internal Patch represents a new development for well design and offers significant advantages over alternative solutions. These advantages are further described in the paper.
Deriving Quantitative Fracture Properties from Whole Core Description: A Practical Link Between Geological Observation and Flow Simulation
Authors: Chen Jiajie (Jeff) 
Published: July 2010

Abstract
Fractured reservoirs have drawn more and more attention in the exploration and production business during the past decades. Oil and gas producers are now extensively worked on tight sand, carbonate, and shale reservoirs, all of which are impacted by the intensity and other properties of the fracture systems. When dealing with these reservoirs, two lines of advanced analyses need to be performed: fracture characterization and modeling.
This study explores the possibility of deriving quantitative fracture properties based on whole core description. The results show that in a given core slab, regardless of whether it is continuous or discontinuous, by making certain assumptions, it is possible to derive 0-D, 1-D, 2-D, and 3-D fracture intensities, estimate fracture porosity, and assess fracture openness and connectivity. The results can then calibrated with other geological and geophysical (G&G) data such as FMI and seismic interpretation (texture analysis, ant-tracking, and so on), and reservoir engineering analysis such as production ranking and well testing, possibly providing useful information for reservoir simulation and field development, as the permeability of fractures is closely related to fracture intensities and aperture. The methodology was applied to several producing fields in the Rocky Mountain area and it was concluded that adequate fracture assessment yielded consistent results between static and dynamic reservoir analyses. Although whole core is available only from certain intervals and certain locations of the fields, when integrated with regional structure, lithology, depositional facies, bed thickness, bed dip, and other data, the fracture parameters derived from cores generally provide a reliable assessment of the fractured reservoirs under evaluation.
This study provides a new workflow for quantitative fractured reservoir description, and application of such a data set to improve fractured reservoir simulation.
Recent Developments and Updated Screening Criteria of Enhanced Oil Recovery Techniques
Authors: Aladasani Ahmad , Bai Baojun 
Published: July 2010

Abstract
This paper reviews recent developments in enhanced oil recovery (EOR) techniques published in SPE conference proceedings for 2007 to 2009. It also updates the EOR criteria developed by Taber et al. in 1996 based on field applications reported in Oil & Gas Journal and at various SPE conferences. It classifies EOR methods into five main categories: gas-based, water-based, thermal, others, and combination technologies. New developments in EOR techniques, chemicals, and mechanisms are summarized to clarify advances in EOR criteria beyond previous limitations. Reservoirs that had previously been ruled out based on specific reservoir conditions are now candidates under updated EOR screening criteria. To demonstrate this potential, this work has established guidelines for the selection and optimization of chemical EOR methods for a specific reservoir.
Case Histories of International Partnerships for Training, Education, and Research Through Teams of NOCs, IOCs, and Universities
Authors: Van Kirk Craig W. , Baughman Gary L. 
Published: July 2010

Abstract
In order for universities to fulfill their roles and responsibilities to their many stakeholders within society, they must successfully address a multitude of tasks both internally and externally, domestically and internationally. This paper provides a summary of observations and recommendations, along with detailed examples, regarding successful collaborations and partnerships among universities, IOCs, NOCs, and other stakeholders, with a focus on the best practices in education, training, and research for petroleum engineering, geology, and geophysics programs within universities. Most of the experiences and conclusions presented address the university discipline of petroleum engineering (PE), with significant aspects tied to the other petroleum industry upstream E&P disciplines of geology (GE) and geophysics (GP). Most of the information and recommendations are widely applicable throughout the world, but emphasis will be placed on the experiences of the Colorado School of Mines (CSM) with partnerships in China.
The major theme is that while many traditional university programs and activities have been shown to be mutually rewarding to both universities and the industry, real success in these matters typically requires innovative collaborations between international universities as well as a stable relationship with one or more other partners. This additional partner, with a long-term interest in the success of the program, is essential in providing a continuous and adequate flow of financial resources, ensuring both the sustainability and long-term health of the university programs.
Also, the paper will clarify how all of the parties involved in these E&P education, training, and research activities can benefit from partnerships involving diverse international teams of experts, mentors, and students of all ages, thus demonstrating how PE-oriented entities can broaden and strengthen their collaborations with universities and other partners.
Development of the Next Generation of Phosphorus Tagged Polymeric Scale Inhibitors
Authors: Todd M. J. , Strachan C. J. , Moir G. , Aberdeen U. K. , Goulding J. 
Published: July 2010

Abstract
This paper reports a new method for the synthesis of phosphorus tagged polymeric scale inhibitors, laboratory based testing to validate these new molecules and their application in oil field reservoirs with comparison to existing commercially available technologies. Existing phosphorus tagged polymeric scale inhibitors are expensive to synthesise and result in low levels of phosphorus making detection difficult. With growing environmental concerns regarding incumbent phosphonate based scale inhibitor chemistries a shift to more environmentally benign polymeric scale inhibitors is required.
A new method for the synthesis of phosphorus tagged polymeric scale inhibitors has been developed. These novel molecules contain a greater level of phosphorus compared to existing techniques. This is achieved by polymerising new novel phosphonate monomers. These monomers may be polymerised or copolymerised with other species to yield phosphonate-functional polymers or oligomers. This results in highly detectable, environmentally friendly molecules with enhanced oilfield reservoir adsorption characteristics. These phosphorus tagged polymers are readily detected by ICP and HPLC techniques offering advantages over conventional phosphonate and polymeric scale inhibitors.
These new phosphorus tagged polymers have been developed as a range of new scale inhibitors to be deployed as down hole squeeze products. Due to their high detection by both polymer and elemental methods this makes them excellent candidates to replace both existing phosphonate and polymer inhibitors. The large range of monomers available allows the chemistries to be tailor made to specific wells and to a range of scaling conditions.
This paper will include laboratory evaluation of these new chemistries with coreflood data in comparison to existing chemistries. This new chemistry shows a significant step forward in the synthetic development of truly detectable phosphorus tagged polymers for an ever evolving industry.
How to Propagate Petrophysical Properties in a Fracture Network for Naturally Fractured Carbonate Reservoirs Case Study: Cretaceous Formations at Maracaibo Lake, Venezuela
Authors: Rodolfo Soto B. , Perez Sergio , Arteaga Duarry , Martin Cintia 
Published: July 2010

Abstract
A fuzzy-logic approach accurately characterizes spatial porosity and permeability for a complex, naturally fractured carbonate reservoir. The reservoir lies in the Cretaceous section alongside the fault damage and shear zone at the downthrown block to the west of the Icotea fault, Central North segment of the Maracaibo basin.
To identify the pore type in our characterization of this carbonate reservoir, we first used fuzzy logic to obtain fracture indexes from conventional well logs. Then we used a resistivity/porosity model with cementation factor, m, variable to determine fracture porosity, and calculated total porosity from neutron-density logs. After that, we developed a neuro-fuzzy logic permeability model with porosity, shale volume, fracture indexes, and pore type as independent variables.
Next, we used directional-statistics tool analysis to identify the five main fracture families and categorize them. The diagnosis of fracture orientation relies on the statistical analysis of fractures from four wells, three of them having image logs and one having a direct description of fractures from an oriented core. We also compared the fracture-orientation data from well data with the faults interpreted at seismic scale to unravel their structural connection.
Fracture lengths are obtained from curvature maps by direct measurement of lineaments matching the azimuth of each family. A logarithmic fit of the known values allows extrapolating values of fracture lengths and spacings below seismic resolution. To propagate porosity in our fracture system, where only a seismic P-wave volume was available, we found for each fracture family a general inverse functional relationship between fracture intensity and fracture porosity, introduced as the r-pi method of correlation.
With a sigmoidal function we correlate the neuro-fuzzy logic permeability variable with the aperture and intensity of the fractures. With a statistically based characterization we identify wheter the fractures display directionally or stratigraphically related anisotropies. Finally, to populate petrophysical properties in the fracture network we apply the functions devised starting with the size of the fractures as an independent variable.
CO2 Sequestration Monitoring in a Low Formation Water Salinity Reservoir
Authors: Murray Doug , Wang Yang Xing , Horie Tadashi , Yoshimura Tukasa , Mito Saeko 
Published: July 2010

Abstract
CO2 sequestration includes the injection of CO2 into permeable saline reservoirs. It has been shown that when water salinity is sufficiently high, in-situ monitoring of the CO2 front can be accurately described via traditional cased-hole time-lapsed Sigma (Σ) logging (Sakurai et al, 2005). However when the targeted reservoir's water salinity is not sufficiently saline uncertainty in the Σ approach increases and it becomes more qualitative than quantitative.
In this paper we summarize a CO2 monitoring project in Japan where formation water salinities were less than ideal for the pulsed neutron Σ based monitoring. To overcome this apparent complication, Σ and alternative measurements such as inelastic ratios and neutron porosity were acquired and combined with the open-hole resistivity, neutron-density and magnetic resonance logs to derive a robust interpretation.
The Hydrogen Index (HI) of CO2 is zero, hence neutron porosity in the presence of CO2 is low. In the presence of CO2 the carbon oxygen ratio (COR) is high due to changes in the carbon and oxygen yields.
The operational sequence of events involved the following; i.) resistivity, neutron-density and magnetic resonance logs were acquired in open-hole; ii.) well was completed, perforated and CO2 injected; iii.) pulsed neutron log data was acquired; iv.) saline water was injected and; v.) pulsed neutron log data was re-acquired.
The combined use of open-hole resistivity, neutron-density, magnetic resonance and cased-hole pulsed-neutron logs demonstrated that accurate CO2 front monitoring is viable in this relatively low salinity environment.
Modeling Well Performance for Fractured Horizontal Gas Wells
Authors: Lin Jiajing , Zhu Ding 
Published: July 2010

Abstract
In tight gas reservoirs, horizontal wells have been used to increase reservoir contact and hydraulic fracturing has been applied to further extend the contact of the reservoir. Point source solution has been used to describe the flow behavior. The method was advanced to the volumetric sources, and pressure change inside the source was considered. We have developed a method that can predict horizontal well performance, and the model can also be applied for fractured horizontal wells. The method solves the problem by superposing a series of slab sources under transient or pseudo-steady state flow conditions. The principle of the method comprises calculation of the semi-analytical response of a rectilinear reservoir with closed outer boundaries. The slab source approach assigns the source a geometry dimension, similar to the volumetric source method, but has the solution similar to the point source method by neglecting the effect of the flow inside the source. When solving the source problem the pressure/flow effect inside source is considered sequentially by superposition principle over multiple sources.
The pressure response is integrated over time to provide continuous pressure behavior. Flow effect inside of fractures can be studied by dividing the fracture into several segments, and each can be treated as a slab source. The method is validated by comparison with the results of analytical solutions of horizontal wells with uniform flux and infinite conductivity, and fractured wells with uniform flux, finite or infinite conductivity. The method provides an effective tool for horizontal well design and well stimulation design for gas reservoirs.
In this paper, we present the details of model development. The examples will be used to illustrate how the model can help to optimize wellbore and fracture design. The method in this paper is more accurate compared with conventional point-source solution, and can handle the transaction from transient flow to pseudo-steady state flow smoothly. The results of the study show that in low permeability formation, hydraulic fracturing has more impact on horizontal well performance.
Drainage Mechanism of Steam with Solvent Coinjection under Steam Assisted Gravity Drainage (SAGD) Process
Authors: Li Weiqiang , Mamora Daulat D. 
Published: July 2010

Abstract
Coinjecting solvent with steam under steam assisted gravity drainage (SAGD) process to reduce the required steam for production has gained importance in recent years. An extensive 2D simulation study to better understand the drainage mechanism of steam with solvent coinjection in the SAGD process shows that the relative condensation times of solvent and steam result in different films of gas solvent, liquid solvent, and water along the fluid interface. There is an optimal solvent type and concentration ratio range for a particular reservoir and operating condition. The solvent stays in or approaches the liquid phase ahead of steam along the fluid interface. Coinjecting the solvent at low concentration ratios can take advantage of the solvent solubility effect without losing too much heat effect from steam. In addition, this study indicates coinjection of suitable solvent mixtures leads to better performance than injection of pure solvent in the field.
Method and Utility of Well Productivity Estimation during Drilling
Authors: Zhang Lingyu , Jalali Younes 
Published: July 2010

Abstract
In this paper we describe two possible use cases of well productivity estimation obtained during the reservoir drilling process. The first concerns estimating a minimum and maximum value for the remaining reservoir footage that is required (beyond bit position) to achieve a target Productivity Index for the well. Thus the only criterion is well productivity not cost. The second concerns deciding within a pre-defined window the termination point of the well based on operator's cost-benefit criteria. The paper emphasizes description of use-case rather than description of the detailed methodology for obtaining these estimates. This is because feedback is required from teams involved in planning and execution of development wells on realistic and worthwhile use-cases, before deciding which option for productivity estimation is most appropriate and most efficient. In this paper, we present a basic method and simple examples based on synthetic data and mathematical solutions available in the literature. We place this in the context of reservoir drilling operations and decision-making.
A New Approach for Casing Program Design with Pressure Uncertainties of Deepwater Exploration Wells
Authors: Guan Zhichuan , Ke Ke , Lu Baoping 
Published: July 2010

Abstract
In exploration wells, particularly in deepwater exploration wells, the information regarding formation pressure has many uncertainties because of the lack of seismic data, logging data and daily drilling report. The present casing program design methods based on the deterministic formation pressure data did not take these uncertainties into account and the results could not satisfy field engineering requirements. This paper describes a method based on probabilistic theory for determining the formation pressure profile with credibility, and a new approach for casing program design has been also introduced. As a result, the formation pressure is not a deterministic value but a range with probability information, as the same with the casing set points selection. And then we describe a quantitative risk analysis method for quantitatively analyzing the risk of the casing point selection design. The model includes four sub-models for determining the quantitative risk due to lost circulation, kicking, collapse and sticking. The results can provide valuable information for designers. In one case study, we illustrate how this approach allows us to compute formation pressure profile with credibility and casing set points for a deep well with formation uncertainties. The risk of several casing program of this well has also been discussed finally.