bluuebunny/crossref_metadata_2025_split huggingface dataset:
New PDC Technology Improves Drilling Performance and Sets New Penetration Record in Raageshwari Field, Rajasthan, India
Authors: Upadhyay Abhishek , Chowdhury Ashabikash Roy , Borgaonkar Rohan 
Published: September 2011

Abstract
Raageshwari field is located in Rajasthan province in northwest India and an operator has been actively engaged in a development drilling campaign since 2009.
The ongoing drilling campaign involved drilling vertical wells of approximately 3000 m deep. The final 6–in. hole sections of these wells were approximately 600 m long and passed through abrasive claystone of about 5,000 psi unconfined compressive strength (UCS) and very hard and abrasive volcanic tuff of 23,000 psi UCS.
Initially, the operator used a PDC bit to drill the claystone, but it was unable to penetrate through the hard volcanic tuff resulting in a costly trip for bit change. To drill through the volcanic tuff, the operator used an impregnated bit with turbine resulting in a very slow penetration rate (ROP). It was apparent that new improved bit technology was required to save the trip and to improve the penetration rate.
After a detailed study of the formation properties and testing several bit design iterations, a new PDC bit with improved cutter technology was selected. Various technology features for balling prevention, stability, hydraulics efficiency, and depth of cut control were incorporated in the design to improve the drilling efficiency.
Upon deployment, the new PDC bit drilled the entire claystone section and 75% of the volcanic tuff section. A detailed design and run review of this bit resulted in an improved design with new wear-resistant cutters and higher sharpness retention capability. This bit drilled the entire 6-in. section of the target well with an overall penetration rate that was three times faster than before, setting a penetration record among the wells drilled in the field.
The authors will present the various technologies that were incorporated in the PDC design and demonstrate their benefit towards drilling efficiency improvement.
Pulsed Neutron Monitoring of the First CO2 EOR Pilot in the Middle East
Authors: Al-Aryani Fatema , Obeidi Adel , Brahmakulam Jacob , Ramamoorthy Raghu 
Published: September 2011

Abstract
Using borehole measurements to monitor carbon dioxide (CO2) floods in the reservoir is essential to properly understand the behavior of the injected fluids and the flow patterns. Pulsed Neutron logs provide essential measurements for the evaluation of saturation in the injectors, producers and observers. However, the CO2 environment is as yet uncharacterized in the industry. Hence, reliable inferences require that either the measurement is immune to the borehole environment or that the perturbation is minimal and can be easily corrected. Where corrections are required, suitable benchmarks should be planned in advance to verify the accuracy of the corrections. These corrections should be based on the physics of the measurement to the maximum extent possible.
On the first CO2 EOR pilot project in the Middle East—unique in the world because the CO2 flood was implemented with the reservoir at original oil saturation—several pulsed neutron surveys were recorded in the injector, observer, and producer wells. The surveys included capture and inelastic mode acquisition. Several novel techniques of data acquisition and interpretation were successfully tried. This paper presents the steps in planning and executing the jobs and the results of the surveys. Limitations of existing characterization and those imposed by the measurement environments in the subject wells are discussed and we show, through comparison with benchmarks, that correction for the unusual borehole environment is possible. The paper illustrates how the different modes of pulsed neutron data acquisition complement each other in the individual wells in assessing the borehole environment, providing adequate input data to enable a multiphase reservoir fluid analysis, and yielding independent fluid saturations for effective comparison. The results of the analysis are compared with an openhole evaluation to help create a coherent picture of the reservoir.
Pushing the Envelope for Polymer Flooding Towards High-temperature and High-salinity Reservoirs with Polyacrylamide Based Ter-polymers
Authors: Vermolen E. C. , van Haasterecht M. J. , Masalmeh S. K. , Faber M. J. , Boersma D. M. , Gruenenfelder M. 
Published: September 2011

Abstract
Polymer flooding is a mature EOR technique successfully applied in both sandstone and carbonate reservoirs and it is expected to have much wider applications in the future. However, it is currently limited mainly by a combination of reservoir temperature and make-up brine salinity and hardness, as synthetic polymers can chemically and thermally degrade at high temperature and salinity.
This paper reports the results of an ongoing study aimed at finding polymers that can enlarge the application envelope of polymer flooding to, for example, high-temperature and high-salinity Middle Eastern carbonate reservoirs. In this study thermal stability of a number of commercially available polymers was tested at 120°C in various brines. The polymers investigated are partially hydrolyzed polyacrylamide (HPAM) based co- and ter-polymers functionalized with 2-Acrylamido-2-Methylpropane Sulfonate (AMPS) and/or n-Vinyl Pyrrolidone (n-VP) monomers. These monomers provide tolerance to divalent ions and protection to hydrolysis at higher temperatures.
The thermal stability tests showed a clear relationship between the polymer stability and the concentration of the functionalizing monomer. Incorporation of the AMPS monomer alone does not stabilize the polymer in brines which contain divalent ions. The additional incorporation of n-VP demonstrates a stabilizing effect which is optimal at a concentration of 35-50%. The optimal ter-polymer is stable at 120°C in brines with salinity up to 200,000 ppm TDS and divalent ion concentration up to 18,000 ppm for more than 180 days.
Another challenge to polymer flooding is the adsorption of polymers onto the reservoir rock. The adsorption of the terpolymers on carbonate core material was investigated in this study as a function of the polymer type and pH.
This is the first work to prove the feasibility of polymer flooding at temperatures up to 120°C in high-salinity reservoirs in the presence of a high concentration of divalent ions. These results will significantly enlarge the application envelope for polymer flooding.
Identifying Minor Faults and Demarcating Compartments in Areas of Large Seismic Anomalies using Time-lapse OWC Mapping - Example From the Super Giant Greater Burgan Field, Kuwait
Authors: Al-Enezi Hamdah S. , Bardalaye Jayanta , Al-Azmi Khalid , Aqeel Anfal , Al-Humoud Jamal , Al-Haddad Saud M. , Belal Dawood 
Published: September 2011

Abstract
The Greater Burgan Field in Kuwait consists of three culminations – Burgan Dome in the south, Ahmadi in the northeast and Magwa in the northwest. The Cretaceous Burgan Formation is the main reservoir of the Greater Burgan Field. The major part of the reservoir consists of massive, stacked, fluvial channels with an active bottom water drive. The structure is dissected by a number of faults resulting in compartmentalization of the reservoir. The major faults are easily mappable with seismic data. However, mapping the minor faults is a challenge due to velocity anomalies present in the shallow formations masking the structural picture at the Burgan Formation level.
Hydrocarbon saturation logs are widely used in the field to monitor the movement of the oil-water contact (OWC). At many places, uneven OWC rise is observed, that cannot be attributed to different offtakes from the wells. Time-lapse mapping of the OWC by different vintages of hydrocarbon saturation logs, in combination with open hole logs, shows that these differences can only be explained by sub-compartmentalization along structural discontinuities. Such discontinuities are mostly observed in the Magwa area where shallow velocity anomalies are also more pronounced.
Mapping the trends of these discontinuities shows that they are aligned to the regional fault trends mapped seismically. Using this technique, a number of minor faults can be mapped that sub-divides the major compartments into smaller ones. This will help in better positioning of in-fill locations and also in refining the production strategy of the compartments.
Systemizing People - Systems to Manage People OR People to Manage Systems?
Authors: Ahmed Nabeel 
Published: September 2011

Abstract
"System is down, cannot approve your expenses!"; "You have missed the system deadline for performance evaluation!"
How many of us have heard one of the above or related remarks? Perhaps we all have and it truly reflects our reliance on technology and systems to manage our most important asset i.e. Human Capital. In our attempt to adapt technology and succeed in the race to improve productivity, the basic principles of Human Resources management may have been rather undermined.
The rigorous demands of the service industry and scarce time resources have enhanced our dependency on HR systems. Whilst the thought of using technology to efficiently manage processes impacting our employees is on the face of it an intellectual one, it is gradually steering us from the true rationale. For instance, a performance management system can provide for accurately recording employee’s goals and performance results; however, it cannot and should not replace the communication session an employee has with his or her manager which has the true potential of increasing performance.
This paper is an attempt to highlight the correlation between the number of HR systems used and its impact on managing human resources. And while evaluating the impact, the thought is in no way to suggest that computer based systems are worthless, but to examine if multiple systems in HR are really good for an organization.
Today’s services industry presents an increasingly challenging and competitive business environment. With these dynamics, the most significant differentiating feature of a successful organization will be a motivated and engaged workforce. It is therefore critical to avoid dependency on HR systems alone and focus on the basic principles of Human Resources management to connect with employees.
Numerical Interpretation of Single Well Chemical Tracer Tests for ASP Injection
Authors: de Zwart A. H. , Stoll W. M. , Boerrigter P. M. , van Batenburg D. W. , Al Harthy S. S. 
Published: September 2011

Abstract
A series of single well injection tests has been conducted to estimate the efficiency of Alkaline Surfactant Polymer (ASP) flooding. These injection tests comprised a Single Well Chemical Tracer (SWCT) test that was done after water injection to establish a baseline remaining oil saturation and a second SWCT test conducted after ASP injection to measure the Remaining Oil Saturation (ROS) after ASP.
Analytical methods are generally used to interpret SWCT tests and to determine the remaining oil saturation. These techniques work best when the response is close to an ideal, single peak. However, the responses from the SWCT tests in our single well tests sequences are complex, showing multiple peaks. This is indicative of complicating factors such as cross-flow between layers. To understand the complex response we used numerical simulation techniques to interpret the SWCT tests. The numerical model includes the physics of ASP, such as interfacial tension reduction, water viscosity modification, and the related reduction in ROS as wells as an accurate model for tracer dispersion. The model allows full control of physical dispersion and does not require the use of numerical diffusion to mimic the effect of physical dispersion. The numerical simulation sequence involves the full single well injection test history including SWCT tests before and after the ASP injection.
The key challenge in matching the tests results with the numerical simulations was to model the complex response, which was different for each well tested. Elaborate numerical simulations, different from the conventional interpretation method, were used to successfully match all tests. This paper presents the simulation work, an explanation of the parameters varied to obtain agreement between numerically predicted and actual SWCT responses and the numerical simulation tools used to match the SWCT tests.
Pressure Transient Testing Under Multiphase Flow Conditions
Authors: Kamal Medhat M. , Pan Yan 
Published: September 2011

Abstract
Although pressure transient testing technology was developed assuming single phase flow in the reservoir, multiphase flow conditions are the norm rather than the exception. The single-phase flow assumption is valid for oil reservoirs above the bubble point pressure with no water production and relatively dry gas reservoirs. For oil reservoirs below the bubble point pressure, gas condensate reservoirs below the dew point pressure and fields producing water, the multiphase flow effects should be considered in transient test analysis. Several attempts have been reported in the literature to handle multiphase flow effects (e.g., Perrine 1956, Martin 1959 and Raghavan 1976). A recent multiphase testing method to calculate the absolute permeability of the reservoir and the average fluid saturations at the time of a transient test has been proposed (Kamal and Pan 2010). This paper briefly describes the three methods, presents results of using them to analyze example synthetic data and shows a field example illustrating lessons learned and best practices to use the recent approach.
The recently proposed method has been validated through analyses of synthetic data and, as the field example shows, that the same absolute permeability calculated when a field was producing only oil above the bubble point pressure, was obtained when the reservoir pressure dropped below the bubble point and both oil and gas were being produced. Another example leads to the same conclusion when an oil field is producing under oil-water two-phase flow condition and water saturation changes at different stages of the field life. A major advantage of the method has also been illustrated (Kamal and Pan 2010) through yet another field example where it showed how to separate the effects of various factors (e.g., multiphase flow, compaction, etc.) on changing the value of permeability.
Novel Foamer Application for Enhanced Oil Production
Authors: Debord Saet Byul , Lehrer Scott , Means Nancy , Crosby Simon 
Published: September 2011

Abstract
As a well ages, the reservoir pressure decreases and the liquid starts to accumulate at the bottom hole. Without reducing the hydrostatic head via deliquification technology, production would more rapidly decrease than the natural decline curve and would cease completely. In gas fields, foamers are very attractive deliquification technology as they are relatively economic and flexible technology. Conventional water-based foamers have been very successful for deliquifying wells to enhance gas production and reducing hydrostatic pressure. However, there has been very little success in treating oil-loaded wells with foamer due to the difficulties in foaming crude oil.
Novel chemistry that foams crude oil was identified, and a new oil foamer was developed as a solution for oil-loaded wells. This oil foamer was tested in wide range of crude oils and water cuts to determine the type of liquid that the new oil foamer treats cost effectively. Lab tests showed that the new oil foamer effectively treated liquid with an API gravity range of 25~40 and a water cut up to 60 percent.
A field trial at an EOG well in South Texas proved that the new oil foamer increased gas and oil production. Historically, this well produced intermittently due to low reservoir pressure. The average production prior to the field trial was 40 BOPD and 250 Mcf/D when the well produced. Average oil and gas production for the 60-day period prior to oil foamer injection was only 13 BOPD and 122 Mcf/D.
Lab tests determined the recommended dosage of the oil foamer and defoamer, and the dosage was optimized during the field trial. The oil foamer was applied continuously through a capillary at a rate of 750 ppm after optimization. The defoamer was injected at the wellhead to control the foam issue at the surface equipment. The oil foamer application increased production from 7 days to 12 days. Gas production increased from 122 Mcf/D to 400 Mcf/D, and oil production increased from 13 BOPD to 100 BOPD. During the entire field trial, the defoamer successfully controlled the foam issue, and the foam did not pose any upset to surface equipment.
Case-Based Reasoning: Predicting Real-Time Drilling Problems and Improving Drilling Performance
Authors: Raja Hamayun , Sørmo Frode , Vinther Morten L. 
Published: September 2011

Abstract
Over the past decade, oil and gas service companies have implemented real-time operations and remote surveillance centers to reduce the non-productive time (NPT) associated with wellbore integrity and downhole failures. Despite these efforts, NPT remains at around 15 to 35% of the total well cost. Companies seek to reduce NPT with knowledge management systems collecting best practices, knowledge cubes along the wellbore, and lessons learned. On the other hand, drilling activities are inherently data intensive, and as the amount of available data increases, it makes it correspondingly difficult for engineers to interpret the situation in a short period of time.
Case-based reasoning (CBR) is a method that can use the real-time drilling data to index and automatically recall the various experiences that are now only available through dedicated knowledge management systems. Using this method, human experience can be collected in a company case base, linked to observed data, and automatically brought forward in real time when it is again relevant. In this paper, we introduce the CBR method and discuss some of the challenges in applying this method to drilling data. The DrillEdge computer system, based on this methodology is introduced, which uses the WITSML standard for drilling data acquisition, integration, and mass storage, making it possible to use in an integrated environment with current real-time operations and remote centers. It will also highlight the importance of a unique user interface to interpret the real-time results during drilling operations.
An evaluation of the system was performed in which the system learned to recognize and, subsequently, predict problems when historical data from several land-drilling operations in Latin America were played back as simulations. A rigorous testing routine was applied to evaluate the capability of the CBR system to correctly identify potential risks and provide the user with remedial actions within a specified time-critical window.
Experimental Study of CO2- and Methane- Foam Using Carbonate Core Material at Reservoir Conditions
Authors: Aarra M. G. , Ormehaug P. A. , Skauge A. , Masalmeh S. K. 
Published: September 2011

Abstract
Foam has been applied to improve sweep during gas injection or for gas shut-off, and also for cleaning of contaminated underground formations. In this paper, foam properties have been evaluated for applications in carbonate material. The emphasis has been to investigate CO2 foam, and therefore, methane and CO2 based foam has been compared. Several foam experiments have been performed at high temperature and high pressure, respectively 100 °C and 277 bars in Limestone outcrop and carbonate reservoir cores. The foams ability to block or reduce mobility of unwanted gas and water is also target of the investigation.
The surfactant, C14/16 Alpha Olefin Sulfonate (AOS), ability to generate foam was influenced by the salinity of the injection water. Moderate to strong foam was generated both for CO2 and CH4 foams in limestone core material using 0.5 wt% surfactant concentration at seawater salinity. Mobility reduction factors at end of experiments for the different core floodings were in the range of ~ 13 to 43. The generated foams showed good ability to reduce gas and water production at low pressure gradients. In high saline formation water foam formation failed in limestone outcrop core material.
For the carbonate reservoir core material, foam generation was influenced by the injection method. The preferred injection would be co-injection of gas and surfactant solution, but this method failed to generate foam. However, when pregenerated foam was injected, CO2 foam was observed at the outlet end of the reservoir core.
Quantification of Remaining Oil Saturation Using a New Wireline Dielectric Dispersion Measurement - A Case Study from Dukhan Field Arab Reservoirs
Authors: Al Qarshubi Ibrahim , Trabelsi Ali , Akinsanmi Mustapha , Polinski Ralf , Faivre Ollivier , Hizem Mehdi , Mosse Laurent 
Published: September 2011

Abstract
The accurate determination of remaining oil saturation (ROS) for Qatar Petroleum’s Dukhan oil field, under production since the 1940s, is a key requirement for an ongoing revision of the field development plan. In 2009 several dedicated observation wells were drilled and cored. Extensive wireline data acquisition of nuclear, resistivity, acoustic, and nuclear magnetic resonance (NMR) data was performed with the objective to quantify the remaining oil saturation from log measurements and compare these log-based results with remaining oil saturations from core analysis.
The Dukhan field is under water flooding for secondary recovery, and changing water salinities resulting from the mixing of salty formation and fresh injection water make any resistivity-based calculation of remaining oil saturation a difficult task. Faced with these challenges Qatar Petroleum chose to field-test a new wireline dielectric dispersion tool to obtain resistivity independent remaining oil saturation information. A second objective was to test the estimation of Archie’s cementation factor m from dielectric dispersion measurements, as Qatar Petroleum had evidence that m varies vertically and laterally across the reservoir.
Remaining oil saturations obtained from the dielectric dispersion tool are presented and compared with resistivity-based values, NMR diffusion-relaxation analysis results, and core-derived Dean-Stark oil saturation measurements. The results confirm the ability of the dielectric dispersion tool to give a reliable measurement of remaining oil in place. Estimation of Archie’s cementation factor m appears to confirm expected variations especially in the Arab-C reservoir in certain parts of the field, with the dielectric dispersion based remaining oil saturation agreeing with the observed fluid production.