bluuebunny/crossref_metadata_2025_split huggingface dataset:
Case History: Continuous Improvement in a Staggered Drilling Campaign
Authors: Gordon Jeanette 
Published: February 2011

Abstract
This paper will compare the operational performance of appraisal / exploration wells in the East Timor Sea for a Joint Venture Group. The paper will review operations using three different rigs; one semi-submersible and two jack ups, each deploying a different wellhead configuration / method to drill exploration / appraisal wells in the same field.
A review of the performance improvements progressed by the operations team over the three years of the staggered project will be provided including;
Field breaking records for drilling performance Comparison of motor and RSS systems with tricone and PDC bits in the field The use of a vibration dampening tool to effect drilling performance BOP and riser running operations compared between the three different rigs Sidetracking operations along with recommendations
Three operational phases were focused upon during the review and these were; drilling 17.1/2" and 12.1/4" hole sections along with open hole sidetracking operations. Drilling performance, engineering planning lessons and recommendations are captured in this paper. A brief review of the costs of deviated wells utilizing subsea wellheads deployed from a semi-submersible rig in comparison to directional wells utilizing subsea wellheads deployed from a jack up, and deviated subsea wells utilizing surface wellheads will be overviewed as there is minimal comparison of these operations currently available in the literature.
The lessons and recommendations contained within this paper can be applied during the well planning stage of any project. A detailed review of performance has been undertaken which highlights the importance of the planning process in operational optimization along with the necessity of clearly defining the expected well outcome as a means of managing the economic success of a project.
ESP Performances for Gas-Lifted High Water Cut Wells
Authors: Bagci A. Suat , Kece Murat , Nava Jocsiris 
Published: February 2011

Abstract
Electrical Submersible Pumping (ESP) and Gas lift (GL) are a part of the long term production sustainability solutions in the fields with increasing water cuts, and depleting reservoir energy. In order to increase the production from this type of fields and sustain the field target rates, production optimization and revisiting of the artificial lift selection proves to be the best cost effective solution.
This paper summarizes the methodology used and the results of a review of artificial lift strategy in a brown field environment with severe gaslift constraints. Potential use of alternative artificial lift technologies in selected high water cut wells was justified. ESP were shown to provide particular advantages related to high water cut oil well applications and easy surveillance access in addition to operating flexibility for changing conditions.
Present GL flow conditions were simulated to determine the operating envelope and the conditions at which GL flow ceases. GL vs. ESP performance comparisons were then carried out for each well over their lifecycle. The incremental revenue and cost impact of ESPs were demonstrated. For all design cases, ESPs can match or exceed the GL performance in this case for the present, middle and late life cases.
Lightweight Water-Based Mud Using Glass Bubbles for Drilling a 6-in. Horizontal Section in a Gunung Kembang Development Well
Authors: Edwin Pratama , Syahriza Ghany R. , Yose Martin , Arga Purwanto 
Published: February 2011

Abstract
A Gunung Kembang drilling campaign recently drilled three wells with 1,510-, 525-, and 283-ft MD horizontal section lengths. The landing point of these wells is 3,200 ft TVD in limestone formations. Failures from the first and third wells resulted from a total-loss circulation problem, and drilling was stopped following an uncontrolled loss rate and a diesel-oil stock shortage.
Two suspected factors are believed to be the cause of loss circulation in Gunung Kembang: 1) depleted formation pressure, which recorded 6.8 ppg and led to a narrow margin of overbalance mud weight and minimum stability mud weight, and 2) the presence of natural fractures. This factor requires further discussion owing to the geomechanic study results, which predicted several azimuths that natural fractures will most likely encounter while drilling.
Water-based mud then becomes an option for drilling a 6-in. horizontal section in the Baturaja limestone formation, as water supply is almost unlimited and is easy to acquire. A non-damaging fluid in combination with a glass-bubble lightweight additive is proposed for drilling this section to 1,600 ft MD. To minimize the possibility of loss circulation, mud density is designed to be slightly higher than the formation pressure. The formation pressure is recorded at 6.8 ppg, thus the mud weight will be 6.9–7.1 ppg (17–50-psi overbalance) using glass bubbles (hollow-glass spheres).
A laboratory test regarding this mud system was conducted to determine the optimum concentration of glass bubbles in waterbased mud using the value of PV so as to affect ECD and surface circulating equipment reliability. A return permeability test was also conducted against the Baturaja limestone core sample with a 15% reduction in permeability. This result offers a better solution for the Gunung Kembang drilling campaign owing to its lower operational cost and that it is more environmental friendly.
Drive Down Costs at Surface: Eliminate Contingency Strings in Deepwater
Authors: Nunzi Paolo , Molaschi Claudio , Beattie Scott , Feasey Guy , Odell Al , Twardowski Eric 
Published: February 2011

Abstract
As the expense of deepwater drilling increases, efforts to eliminate or reduce non-productive time (NPT) can have a significant effect on overall costs. Current standard practices for installing surface casing strings involve multiple trips to first drill the hole section, and then run casing, land the wellhead, and cement. In many instances these casing seats are set shallower than is optimal due to anticipated hazards such as shallow gas or water flows and wellbore stability issues. Although with the current deepwater drilling model these practices are safe and reasonably efficient, they can limit the depth at which the casing can be set, as compared to the optimal depth with respect to pore pressures and fracture gradients.
The use of current proven Casing While Drilling (CWD) techniques has effectively reduced NPT in several key areas including: flat-time reduction, shallow hazard mitigation, minimized/eliminated lost circulation, and improved cement placement and bond. Additionally, CWD provides the opportunity to push casing seats deeper, thus potentially eliminating contingency strings. Current CWD methods have not been applied to subsea surface casing applications, primarily because of the challenge of simultaneous drilling-in and landing the high pressure wellhead without damaging the seal surfaces on the wellhead housings. Additionally, many wellhead running tools are not designed to carry drilling torque.
This paper discusses the benefits associated with drilling-in the surface casing in a subsea application. Introduced is a new CWD method and enabling technology that can significantly improve this phase of deepwater drilling operations. The complete process of drilling-in and running casing, landing the wellhead, and cementing can be achieved in a single trip. The benefits of CWD and features of the new technology are presented. When compared with current deepwater "best practice" models, an immediate 25% time savings is achievable. This technology also enables the utilization of less expensive floating rigs for cost reduction by batch drilling and setting of surface casing.
Rapid Prediction of Carbon Dioxide and Nitrogen Adsorption Behavior at Cryogenic Temperatures
Authors: Bahadori A. , Vuthaluru H. B. 
Published: February 2011

Abstract
Conventionally, CO2 removal requires the use of a water-based amine solution and large absorber and regeneration towers. The capital and ongoing operational costs for this process are substantial, and the use (regeneration and disposal) of the amine solution can be problematic from the perspectives of both safety and the environment. Nitrogen can also be a problematic impurity in natural gas. In this work, a newly developed method is applied to accurately predict the carbon dioxide and nitrogen adsorption isotherms at low temperatures and pressures up to saturation for a com1mercial carbon molecular sieve as a function of temperature and partial pressure of these components. Accurate prediction of such data is useful in evaluating the feasibility of using pressure swing adsorption to separate nitrogen and carbon dioxide from natural gases at cryogenic temperatures for carbon dioxide and nitrogen. The proposed method showed consistently accurate results across the investigated wide pressure and temperature ranges with an average absolute deviation of less than 1% for both nitrogen and carbon dioxide. This is expected to benefit in making informed design decisions for the selection of adsorbents for a given application in any process industry.
Special Considerations for Drilling the Granite Heat Source of an EGS Well
Authors: Holland Brian E 
Published: February 2011

Abstract
A procedure was developed to allow manged temperature drilling of the granite heat source of an enhanced geothermal well. It was shown that the procedure created economies due to the removal of the MPD equipment, the requirement to stage-in and the need to circulate chilled water. It was determined that the procedure could be deployed in any well provided that it was considered at the outset. It is indicated that time spent on drilling the heat source can be reduced. The procedure involved the installation an additional casing called a parasite string. The installation of the parasite string allowed for the installation of temperature sensing equipment that is able to provide an accurate down hole temperature gradient. The installation of the parasite string also allowed for the automation of the temperature control. The installation of the parasite string made operations safer because super heated water was never allowed to the surface. It was shown that the installation of an additional string of casing did not interfere with the final hole diameter and that it was possible to drill into the hot dry rock with an 8 ½" bit and 7" production tubing for the hot water. It was shown that the heat source could be drilled with plain water resulting in significant savings in preparation and maintenance of a drilling fluid. The use of the parasite string resulted in a reduction in the area required for cooling ponds and in an area where cooling ponds may not be acceptable a refrigerated water chiller would be all that was required. It was determined that after the well was drilled and completed an insulating gel material could be installed in the two annuli created by the parasite string. The insulation would enhance the life of well by conserving the heat in the production tubing.
Pressure Buildup Analysis in Karstified Carbonate Reservoir
Authors: Djatmiko W. , Hansamuit V. 
Published: February 2011

Abstract
This paper describes techniques to identify vugs in a real pressure buildup data. The reservoir under study is an undersaturated carbonate reservoir dominated by vugs and karst. We analyse the 80 hours of pressure buildup following a 100 hour of pressure drawdown. We observe the pressure derivative behavior cannot be described using current naturally fracture reservoir models such as dual porosity and triple porosity models. This is because some pressure derivatives are obscured by reservoir boundaries and the matrix-to-fracture fluid transfer does not behave as it were in a multiple porosity reservoir. In this heterogeneous reservoir, we believe this corresponds to the number of matrix interporosity flow parameter, and thus degree of reservoir heterogeneity. If we force the data using dual porosity or triple porosity models, the error will be high (&gt;15%), because the pressure derivative cannot follow all the transition periods.
We use combined analytical and numerical methods to tackle this problem. First the dual porosity analytical solution is invoked to estimate the reservoir parameter (ω, λ and k). Next, a numerical triple porosity model is set up to represent the reservoir. The reservoir parameters initially follow analytical results as initial guesses. History matching procedures are performed to compare DST data with the calculated bottom-hole pressure. When these agree, reservoir flow capacity and storage capacity can be determined for fracture, matrix and vug respectively. We found volumes of vug cannot be ignored in a triple porosity system.
This technique can be used to quantify vugs or karst from well testing when analytical dual porosity or triple porosity model are unable to handle all matrix-to-fracture interporosity flow due to reservoir heterogeneity. Using this technique, we believe not all well test data in carbonate reservoirs (especially for high k.h) can be analyzed using current analytical models. Ignoring this, the estimated permeability is significantly different from the actual.
New Corrosion Inhibitor Reduces Overboard Oil in Water and Maintains Asset Integrity
Authors: Dunsmore B. , Charlesworth M. , Dunn R. , Licari C. , Ashiedu R. 
Published: February 2011

Abstract
A new corrosion inhibitor that can reduce oil in water (OIW) was selected for use in a field offshore on Australia’s North West Shelf. The selected product has allowed the achievement of the new stewardship OIW target of 17.5 ppm, enabling improvements in overall environmental impact. Laboratory tests showed that the selected product had similar corrosion inhibitor performance to the incumbent field product. Meanwhile, laboratory OIW measurements showed that 50 ppm of the selected product generated significantly less OIW (17 ppm OIW compared to 159 ppm OIW with 50 ppm of incumbent product). On-site tests were then performed with fresh produced fluids, demonstrating again that the selected product resulted in lower OIW (a 42%, 43% and 73% OIW reduction compared to incumbent product, at 20, 30 & 40 ppm of corrosion inhibitor, respectively). A full-field trial immediately demonstrated a decrease in OIW results corresponding to a decrease in overboard OIW from a daily average of 20.0 ppm to 8.8 ppm during the trial period, with no adverse impact on corrosion probe readings. The new product has now been in use on this facility for 10 months. Corrosion monitoring continues to show good inhibition while the OIW levels remain below 16 ppm average, and concurrently is allowing a reduction in the use of associated water treatment chemicals, further benefiting the environment.
Determining Production Casing and Tubing Size by Satisfying Completion: Stimulation and Production Requirements for Tight Gas Sand Reservoirs
Authors: Wei Y. , Cheng K. , Jin X. , Wu B. , Holditch S. A. 
Published: February 2011

Abstract
Producing natural gas from Tight Gas Sand (TGS) reservoirs will be of increasing importance to the global energy industry in the coming decades. One of the basic decisions concerning the development of TGS reservoirs is to determine the size of the production casing and tubing. Because of low permeability, virtually all of the wells completed in TGS reservoirs must be stimulated to achieve the desired production goals. Therefore, the casing and tubing size must be designed to satisfy the stimulation requirements. Because many TGS wells are completed in reservoirs that have many distinct layers that can contribute to production if adequately treated, it is important to select the optimal diversion techniques in completing these multilayered reservoirs. The casing and tubing size must be designed to allow the selected diversion technique to be used successfully. In addition, during the production period, it is important to continuously remove the liquids from the wellbore. Therefore, the casing and tubing size must also be designed to satisfy the production requirement. In summary, the casing and tubing size must be designed to satisfy the completion, stimulation and production requirements. In this paper, we will provide a methodology we have developed to select the appropriate casing and tubing size for the development of TGS reservoirs.
This work has been part of our effort to build software that we call TGS Advisor. TGS Advisor can be used to provide advice/best practices to engineers developing TGS reservoirs. The user enters the known reservoir data and the program provides advice on how to drill, complete and stimulate the reservoir. We have combined knowledge from the petroleum literature and interviews with experts with detailed calculations to build the TGS Advisor. We evaluated the results of the TGS Advisor with published case histories in the petroleum literature. Currently, the methodology of choosing casing and tubing size for TGS reservoirs has been programmed and incorporated into the TGS Advisor system. Finally, an example of using TGS Advisor to select the appropriate casing and tubing size in TGS reservoir is presented.
A Unique Framework for Developing and Mentoring the Next Generation of Reservoir Navigation Engineers
Authors: Bacon R. , Hearn F. , Skillings J. 
Published: February 2011

Abstract
In this day and age of rapidly evolving technologies coupled with a dynamic workforce environment, in terms of age, experience, and geographic diversity, it is becoming increasingly challenging to ensure quality personnel are available to meet the ever-increasing technical demands of the oilfield. With the growing trend toward precision wellbore placement in horizontal, highly-deviated and multilateral wellbores, advanced geosteering services are critical to a project’s success. Reservoir navigation has become a fundamental part of the modern field development program where simple geometric well targets do not capture the capabilities and value of today’s technologies.
Reservoir navigation refers to those activities designed to place the wellbore in a predetermined location and maintain it within a desired location within the reservoir. Proper geosteering optimizes wellbore placement in the productive reservoir, maximising both drilling efficiency and hydrocarbon production. It involves real-time interpretation and decisions while drilling to properly and accurately place the wellbore in the most productive zone in the reservoir. The process can be complex and requires a high level of expertise.
Historically, the industry has relied on field engineers with years of field experience and a geosciences background as a talent pool for reservoir navigation engineers. It can then take several months of classroom, on-the-job training, guidance, and mentoring before a reservoir navigation engineer can break out on his/her own.
A growing demand for these complex, precision wellbore placement applications are out-pacing our ability to fully develop the required competencies of reservoir navigation engineers using traditional training methods. The challenge is to decrease competency development time without compromising the technical proficiency of the individual (Hearn, et al., 2008). That is, how do you develop engineers to work with, and eventually step into the shoes of, existing experts? How is knowledge transferred, and how do we ensure the next generation of engineers can supply the same level of service with the same fundamental knowledge in this fast-paced world of answers while drilling?
While experience is always the best teacher, proper mentoring and a clearly defined framework of skills and processes for acquiring those skills is required. This paper maps out such a framework and explores the results of two years of development of several new reservoir navigation engineers.
Using High-Resolution LWD Resistivity Images for Carbonate Facies Identification and Steering
Authors: Bacon Robert , Morris Stephen , Fernandes Warren , Mahiout Said 
Published: February 2011

ABSTRACT
Experience to date shows that the drilling environment offers a good platform for high-definition electrical borehole imaging. At the time of drilling, invasion and borehole wall rugosity are often minimal and electrical images generated by sensors that rotate with the drillstring provide full coverage of the borehole. It also provides an opportunity for realtime geological analysis while drilling and the decision-making that is unavailable with wireline. Detailed analyses of images reveal discrete sedimentological and textural features aiding facies recognition in carbonate reservoirs. These facies can be up-scaled to facies associations and eventually used for depositional environment interpretation. This leads to wider prospect delineation and confirmation of the local geological model. The study also demonstrates the strength of early geological information in high resolution for reducing geological uncertainty at an early development drilling program.
We show case studies from several carbonate reservoirs in which high-resolution electrical images have been acquired in conjunction with reservoir navigation. From post-well analysis, we can define the key criteria that help in recognition of reservoir position: correlatable sedimentary surfaces and image facies/patterns. We test the distribution of facies and sedimentological features that can be recognised in horizontal boreholes by comparison to vertical offset wells, in addition to automated facies recognition from image log responses. The development of a sedimentary or carbonate facies steering technique using high-resolution images with a predictive and real-time interface will reduce uncertainties related to and better aid geosteering within the desired "sweet-spot" of a variety of clastic and carbonate reservoirs.
The Development of a Complete System to Allow Continuous Downhole Chemical Injection Without Affecting the Subsurface and Surface Safety Systems
Authors: Klompsma D. , Lugtmeier B. , Lacy R. , Hearn W. , Dennistoun S. , Calzoncinth E. , Jacob J. L. 
Published: February 2011

Abstract
As gas wells mature, the problem of liquid loading and the resultant intermittent flow can reduce production to rates below the anticipated decline curve. It has been demonstrated that the introduction of surfactants such as foamers can mitigate the problems caused by liquid loading, and experience has shown that the introduction of these production enhancing chemicals in a continuous stream at the perforations can significantly reduce critical velocity and extend the productive life of gas wells. At the same time, especially in offshore wells, Operators must maintain a fully functional safety system including the downhole safety valve and the surface master valves and actuators which are controlled by an operating panel and are an integral part of the emergency shutdown system. This is especially true for operators in the North Sea who must adhere to some of the most rigid safety requirements in the industry. Clearly a new system was needed to allow the continuous injection of production enhancing chemicals through the safety systems in the well while maintaining their full integrity.
This paper will detail the conception and development of a new downhole safety valve and wellhead penetration system, incorporating a capillary string, to allow an operator to inject production enhancing chemicals through the safety valve while maintaining full control of the surface and subsurface safety equipment. The new system, the deployment of which is also detailed in this paper, is installed by means of slick line and capillary string using a combination of proven intervention methods thus eliminating the need for a major rig operation and saving the operator substantial workover cost.